CPN 2011 Citi Credit Conference v2.0

8/2/2019 CPN 2011 Citi Credit Conference v2.0

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Cit i 2011 North AmericanCredit Conference

Zamir RaufChief Financial Of f icer

November 16, 2011


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2

Safe Harbor Statement

Forward-Looking StatementsThe informat ion contained in t his presentation includes cert ain est imates, project ions and other forward-lookinginformation that reflect Calpines current views with respect to future events and financial performance. Theseest imates, project ions and other f orward-looking informat ion are based on assumptions t hat Calpine beli eves, as oft he date hereof , are reasonable. Inevit ably, t here wil l be dif ferences between such est imates and actual result s, andt hose dif ferences may be material.

There can be no assurance that any est imates, proj ect ions or forward-looking informat ion wil l be real ized.

Al l such est imates, project ions and f orward-looking inf ormat ion speak only as of t he date hereof . Calpine undert akesno duty to update or revise the informat ion contained herein other t han as required by law.

You are caut ioned not t o place undue reliance on the est imates, project ions and other forward-looking informat ion in

t his presentat ion as t hey are based on current expectat ions and general assumpt ions and are subject t o various risks,uncert aint ies and other factors, including those set fort h in Calpine s Annual Report on Form 10-K for t he year endedDecember 31, 2010, Quart erl y Report on Form 10-Q for each of t he quart ers ended March 31, June 30, and September30, 2011, and in other documents t hat Calpine f i les wit h the SEC. Many of t hese risks, uncert aint ies and other factorsare beyond Calpine s cont rol and may cause actual result s t o dif fer material ly f rom the views, bel iefs and est imatesexpressed herein. Calpine s report s and other informat ion f i led wit h the SEC, including t he risk factors ident if ied init s Annual Report on Form 10-K for t he year ended December 31, 2010, can be found on the SECs websit e atwww.sec.gov and on Calpine s websit e at www.calpine.com.

Reconciliation to U.S. GAAP Financial InformationThe following presentat ion includes cert ain non-GAAP f inancial measures as defined in Regulat ion G under t heSecurit ies Exchange Act of 1934, as amended. Schedules are included herein and/ or on the Investor Relat ions sect ionof our website (www.calpine.com) that reconcile the non-GAAP financial measures included in the following

presentat ion to the most direct ly comparable f inancial measures calculated and presented in accordance wit h U.S.GAAP.


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St rat egical ly posit ioned wit hin U.S. power indust ry value chain

3

Calpine Overview

Fuel Supply

Transportation

Power Generat ion

Transmission& Distr ibuti on

Retail

Calpine (NYSE: CPN)

2,000+ employees

28,000+ MWgeneration capacity

92 operating plants

Calpine (NYSE: CPN)

2,000+ employees

28,000+ MWgeneration capacity

92 operating plants


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4

National Portfolio of More Than 28,000 MW

Geographic Diversi t y

Dispatch Flexibility

As of November 2011

Southeast6,083 MW

22%

Texas7,239 MW

26%West

6,898 MW24%

North7,914 MW

28%

Baseload5,267 MW

19%

Intermediate16,393 MW

58%

Peaking6,474 MW

23%


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-

2

4

6

8

10

CPN DYN NRG GEN

SO2lbs./MWh

6,000

8,000

10,000

12,000

14,000

CPN DYN GEN NRG

HeatRate(btu/KWh

)

-

20,000

40,000

60,000

80,000

100,000

CPN NRG GEN DYN

2010Generation(M

Wh)

(000)

-

10

20

30

40

50

CPN DYN NRG GEN

Wtd.-Avg.

Age(Years)

5

Source: Energy Velocit y (2010).Source: Energy Velocit y (2010).

CleanModern

Source: 2010 SEC f i l ings.

Efficient

Source: Energy Velocit y (2010). Not adjusted for steam, and excluding non-fossil fuel generat ion. Steam-adjust ed heat rat e does not i nclude peakers.

Our st eam-adj ust edheat rat e is 7,338

Scale

Unique Independent Power Producer

Calpine is t he nat ion s largest baseload renewable,natural gas and cogenerat ion power pr ovider

Calpine is t he nat ion s largest baseload renewable,natural gas and cogenerat ion power pr ovider


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ValueDrivers

Experi enced management t eam possesses vi sion and ski l l t o execute st rat egy

TheInvest ment

EnhancingValue through

EffectiveCapital

Allocation

UnlockingIntrinsic

Value

Calpine Value Proposition:Compell ing Risk-Adjusted Total Return

6

Modern, clean and rel iable nat ural gas-f ired and geot hermal powergenerat ion f leet , current ly t rading at a deep discount t o replacement cost

Gas-fired generation will displace a material amount of coal generation

Cleaner, more efficient and more economic technology

Stable fuel supply at low prices

Market heat rates (spark spreads) are set to rise

Environmental compliance costs

Retirements of existing supply: age, economics, compliance

Where new capacity needed, power prices must increase to incent investment

Calpine: poised to benefit from higher utilization and market heat rates

Highly underutilized in todays market: CCGT capacity factor of 50%1

As excellent stewards of your capital, we will enhance value by:

Pursuing a pipeline of financially disciplined growth

Monetizing appropriate assets through sale or contract

Returning capital to shareholders over time

Our capital structure offers the flexibility necessary to act in ourshareholders best interest

1 Calpines average annual CCGT capacity factor, 2007 2010.


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$610

$977

$304

$308$341

$238

$845$635

3Q10 3Q11

Revolver / LC Availability

Restricted Cash

Cash and Cash Equivalents, Non-corporate

Cash and Cash Equivalents, Corporate

$213

$1,544

$1,000

$1,488

$682

$1,100

$2,000

$1,200

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Senior Secured Term Loan Senior Secured Notes CCFC Project Debt

$381

$499

$361 $381

$663

$1,326

$638

$1,347

1

A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Recurring Free Cash Flow to Net Income (Loss), the most

comparable U.S. GAAP measure, are included in the appendix.2

2010 Adjusted Recurring Free Cash Flow has been recast to confirm with current year presentation, which excludes settlements of

non-hedging interest rate swaps.3 The debt maturity schedules shown here are not prepared on a U.S. GAAP basis and do not conform to the debt maturity schedule presented in Calpines Form 10-K. (Refer to the Form 10-K for further

information regarding U.S. GAAP-basis debt maturities). Assumptions used in debt maturity charts shown here are as follows: (i) excludes letter of credit facilities; (ii) maturity balances assume cashsweeps; and (iii) all other debt maturities are paid from operating cash flows at the project level. Project debt in 2019 represents projected balance for OMEC. Put price in the PPA approximates theprojected debt balance.

3Q11 Financial Overview

7

Key Messages:

On track to meet 2011 guidance

$2B+ of liquidity with nosignificant near-term maturities

Key Drivers: 3Q11 v 3Q10

Sale of Colorado plants andFreestone

Lower margins in West andSoutheast

Recent Achievements:

Corporate secured debt upgradedto BB-

credit rating

Announced and commenced$300M share repurchase program

Completed $373M Los Esterosproject financing at veryattractive terms

Completed reserve sharedistributions

Adj ust ed EBITDA1

3Q10 3Q11 YTD10 YTD11

Adj ust ed Recurr ing FCF1

St rong Liquidi t y No Signi f icant Near Term Mat ur i t ies 3

3Q102 3Q11 YTD102 YTD11

($ millions)

$2,100 $2,158Plus:Flexibl e covenant sNo corporate matur it ies >$2B per year


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Guidance Update as of October 28, 2011

8

(in millions)

1

A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Recurring Free Cash Flow to Net Income (Loss), the most

comparable U.S. GAAP measure, are included in the appendix.2

Includes major maintenance expense of $235 million and $185 million in 2011 and 2012, respectively, and maintenance capital expenditures of $155 million and $165 million in 2011 and 2012,respectively. Major maintenance expense includes that of unconsolidated investments. 2012 figures exclude amounts to be funded by project debt.3

Includes fees for letters of credit.4

Adjusted Recurring Free Cash Flow, a non-GAAP financial measure, is Earnings Before Interest, Tax, Depreciation and Amortization, as adjusted, less operating lease payments, major maintenanceexpense and capital expenditures, net cash interest, cash taxes, working capital and other adjustments.

5 Interest payments related to legacy LIBOR hedges associated with floating rate First Lien Credit Facility, which has been refinanced. 2011 figures do not include $17 million in interest rate swapbreakage costs related to the repayment of project debt in June 2011.

6 Assumes exercise of purchase option by customer, for which a deposit is required in the fourth quarter of 2012. Amount based upon customers public disclosures of estimated purchase price.

Affirmed2011 Guidance

Provided2012 Guidance

Adjusted EBITDA1 $1,700 - 1,750 $1,550 1,750

Less:

Operating lease payments 30 35

Major maintenance expense & CapEx2 390 350

Recurring cash interest, net3 780 770

Cash taxes 15 10

Other 10 10

Adjusted Recur r ing Free Cash Flow1,4 $475 525 $375 575

Non-recurring interest rate swap payments5 $(175) $(150)

Growth CapEx (net of funding) $(155) $(10)

Riverside sale proceeds6 $375

2013 Knowns:

Russell City

Los Esteros PJM RPM

Payments

AB32

Riverside saleAdj. EBITDA

Cash proceeds Contract rolloff

2013 Knowns:

Russell City

Los Esteros PJM RPM

Payments

AB32

Riverside saleAdj. EBITDA

Cash proceeds Contract rolloff


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$1,700 - $1,750

$1,550 - $1,750

$(55)

($220)

$170 $30

FY11 AdjustedEBITDA Guidance

RegulatoryCapacityContracts(CA, PJM)

2012 Market vs.2011 Realized

Benefit ofHedges

Feb 2011ERCOT Event

FY12 AdjustedEBITDA Guidance

$(400)

$(120)

$(150) $(10)

$(270)

$375

$1,575-$1,775

$625 - $1,200

Cash SourcesMin. CorpLiquidity

(CashComponent)

Amortizations& CashSweeps

LegacySwaps

CommittedGrowth

ShareRepurchase

Program

RiversideSale Proceeds Excess Cash

1 A non-GAAP financial measure. Reconciliations of Adjusted EBITDA and Adjusted Recurring Free Cash Flow to Net Income (Loss), the most comparable U.S. GAAP measure, are included in the appendix.2 Includes net change in contracts.3 Prices shown for E-MAAC.

2012 Sources and Uses of Capi t al

($ millions)

Conservat ively Managing Capi t alUncert aint ies remaining:

Sources

Alliant exercise of call option to purchase Riverside

Market structure and pricing

Uses

Future growth: $450 -

$550 MM (equity funding)

Amount and timing of share repurchases

Cash Uses

Adj ust ed EBITDA1 Bridge

2012 Guidance Key Messages:

Regulatory capacity changes impact CA and PJM

CA: Less capacity under Resource Adequacy contracts PJM: Average annual RPM prices3

decline from~$142/MW-day (2011) to $125/MW-day (2012)

Market impact largely driven by 2011 weather extremes

2012 hedge position

More open PJM and ERCOT, especially summer Less open California and natural gas

9

UnrestrictedCashonHand

A

dj.Recurr.

FCFGuidance

2

2012 Guidance: A Closer Look(Guidance as provided on October 28, 2011)


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Calpine: Posit ioned for the Future

Soli d f inancialresul t s and

posi t ive cash f lowgeneration

Poised to respond t o future opport unit ies

St rat egic and

financialf lexibi l i ty:invest mentgrade-likecovenant s

Capital availablef or invest ment

or r et urn

No envi ronmentalli abil it ies t o fundor environmental

invest ments t o make

10


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APPENDIX

11


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5.3

0.1

1.92.4

2.42.93.0

0.30.9

1.5

2.6

1.9

West - Gas West - Geo Texas North Southeast CPN

3Q10 3Q11

7,410

1,504

9,895

5,0686,065

5,035

1,505

11,251

5,5885,919

West - Gas West - Geo Texas North Southeast

3Q11 Sold in 2010 3Q10

0.270.24

0.50

4-Yr. Avg. YTD11 BLS Top Quartile

1 NAICS 221112 Fossil Fuel Electric Power Generation 1,000+ Employees. Most recent First Quartile data available (2006).2 As compared to our SEC filings, generation shown here includes net interest in generation from deconsolidated projects, plants owned but not operated, and plants/interests sold or retired during 2010.

Focused on Best-in-Class Operations

Generat ion in Key Markets (000 MWh)2Employee Lost-Ti me Incident Rate

Forced Out age Fact or (FOF, %)

Agnews Edge Moor Otay Mesa

Baytown Freestone Pine Bluff

Bethlehem Geysers* Riverside

Carlls Corner Greenleaf 1 Riverview

Carville Hermiston Rockgen

Channel Hidalgo Santa Rosa

Clear Lake Kennedy Solano Peakers

Columbia King City Stony Brook

Corpus Christi Los Esteros Sutter

Decatur Mankato Texas City

Deep Water Metcalf Westbrook

Deer Park Oneta York

Delta Osprey Zion

Plant s wit h no recordable inj uri es and < 2 % FOF for 3Q11

1

12

Calpine

* Geysers incl udes Bear Canyon, Big Geysers, Cali stoga, Cobb Creek, Eagle Rock, Grant , Lakeview,McCabe, Quicksil ver, Ridge Line, Socrat es, Sonoma, Sulphur Spri ngs and West Ford Flat .

Good performance on a relat ive basis;No lost t ime incidents in 3Q11

Signif icant improvements during import ant 3Q

Generat ed 29 mi l l ion MWh: Plant sales (),Hydro in CA (), Ext reme summer i n TX ()


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1 Generation has been adjusted to include net interest in generation from deconsolidated projects and from plants and interest sold or retired during 2010 in all periods.

13

Selected Operat ing Stat ist ics: Full Year Results

2010 2009 2008 2010 2009 2008

Total MWh Generated (in thousands)1

94,287 91,156 89,033 Average Capacity Factor, excl. Peakers 46.0% 48.2% 47.6%

West 33,968 36,033 37,135 West 56.5% 64.0% 66.5%

Texas 31,674 31,091 33,683 Texas 48.1% 47.4% 51.6%

Southeast 17,987 17,370 12,374 Southeast 38.0% 37.9% 26.6%

North 10,658 6,662 5,840 North 32.8% 31.1% 32.8%

Average Availability 90.4% 92.1% 90.3% Steam Adj usted Heat Rate (Btu/ KWh) 7,338 7,264 7,231

West 91.5% 92.1% 88.2% West 7,316 7,314 7,271

Texas 87.6% 90.0% 88.8% Texas 7,236 7,142 7,082Southeast 92.5% 93.2% 93.6% Southeast 7,315 7,299 7,388

North 90.7% 94.7% 92.6% North 7,819 7,614 7,584


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3Q11 3Q10 3Q11 3Q10

Total MWh Generated (i n thousands)1

29, 297 29, 942 Average Capacit y Factor, excl. Peakers 53. 8% 54. 3%

West 6, 540 8, 913 West 47.4% 58.7%

Texas 11, 251 9, 896 Texas 70.1% 60.0%

North 5, 588 5, 068 North 43.4% 43.7%

Southeast 5, 918 6, 065 Southeast 48.9% 49.3%

Average Availability 95. 9% 95. 9% Steam Adj usted Heat Rate (Btu/ KWh) 7, 464 7, 415

West 91.2% 92.9% West 7,479 7,345

Texas 98.2% 96.5% Texas 7,296 7,305

North 97.5% 96.8% North 8,003 7,865

Southeast 96.6% 97.4% Southeast 7,344 7,366

YTD 11 YTD 10 YTD 11 YTD 10

Total MWh Generated (i n thousands)1

68, 295 72, 511 Average Capacit y Factor, excl. Peakers 42. 9% 47. 9%

West 16,189 25,376 West 39.6% 55.7%

Texas 25,172 25,530 Texas 52.5% 51.9%

North 12,445 7,893 North 34.4% 36.8%

Southeast 14,489 13,712 Southeast 41.0% 38.4%

Average Availability 89. 8% 91. 5% Steam Adj usted Heat Rate (Btu/ KWh) 7, 434 7, 328

West 86.4% 91.5% West 7,488 7,315

Texas 88.8% 89.1% Texas 7,256 7,222

North 92.3% 93.1% North 7,939 7,773

Southeast 92.0% 93.4% Southeast 7,323 7,331

1 Generation has been adjusted to include net interest in generation from deconsolidated projects and from plants and interest sold or retired during 2010 in all periods.

Selected Operat ing Stat ist ics

14


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18

145 235281

(15) (123)

(211) (256)

($400)

($300)

($200)

($100)

$0

$100

$200

$300

$400

2011 BOY 2012 2013 2014

Heat Rate +500 btu/KWh Heat Rate -500 btu/KWh

80%

63%

39%32%

20%

37%

61%68%

2011 BOY 2012 2013 2014

Hedged Volume Open Volume

15 132

254363

(16) (149)(340)

(366)

($400)

($300)

($200)

($100)

$0

$100

$200

$300

$400

2011 BOY 2012 2013 2014

Natural Gas +$1/mmbtu Natural Gas -$1/mmbtu

1

Energy Margin + Regulatory & Other Margin = Total Commodity Margin.2

Estimated as of 10/14/11. Hedged margin excludes unconsolidated projects. Changing market heat rates will change delta volumes andgas price exposures. Sensitivities are assumed to occur across the portfolio and the sensitivities on strategic options only captureintrinsic value.

3

Volumes are on a delta hedge basis. Delta volumes are the expected volume based on the probability of economic dispatch at a futuredate based on current market prices for that future date. This is lower than the notional volume, which is plant capacity, less knownperformance and operating constraints. Volumes assume sale of Riverside and addition of Los Esteros and 75% of Russell City in 2013.

4 Amounts represent natural gas hedge value in addition to natural gas hedge value already captured in hedged margin.5 Represents Calpines forecasted average annual capacity of net ownership interest with peaking capacity. Capacity additions or

15

Energy Hedge Prof i le2

Pro Forma Energy Margin1: Posit ioned to Respondto Favorable Secular Trends

2011 2012 2013 2014

Hedged Margin ($/MWh)2 $22 $22 $27 $26

Current M-t-M on Natural GasHedge Swaps ($MM)4 $28 $83 $ -- $ --

Avg. Total MW in Operation 2,5 28,020 28,182 28,254 28,210

$ Energy Margin1,2 as %of Total Commodit y Margin (by year):

79% 80% 77% 78%

Use in conjuncti on wit h modeling t ips in appendix

deletions are reflected in the anticipated month of completion.

3 3

Does not include option premiums.

ChangetoC

ommodityMargin

ChangetoCo

mmodityMargin

Added 2014disclosure: baseof longer-termcontracts

Added hedges in2012, primarily inwinter/ shouldermonths

Implementing gasoption strategyfor 2013

Natural Gas Price Sensitivity2

Opt ion Premiums Coll ected (by year, $MM):$8 $85 $68 $ --

Market Heat Rate Sensit ivi ty2

Hedgelevel,2Q11


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Net Debt / Adj ust ed EBITDA2

= 5.1xNet Debt / Adj ust ed EBITDA2

= 5.1x

17

Capital St ructure Chart

Total Debt: $10,404

Add: Net Debt from Unconsolidated Projects 1 202Less: Cash, Cash Equivalents & Restr. Cash (1,523)

Net Debt $9,083

$59

Notes Payable &Other

Note: All balances shown as of 9/30/11.1 Equal to our net interest in total debt, less cash and cash equivalents and restricted cash from unconsolidated projects.2 Figures based upon mid-point of 2011 Adj. EBITDA guidance range. Calculation excludes project debt associated with Russell City and Los Esteros while under construction.

($ in mil li ons)

$7,542

Corporate Revolver

First Lien Credit Facility

Senior Secured Notes

Total Corporate Debt

Corporate Debt

$5,892

$1,650

Projects

Steamboat

Freeport

Mankato Bethpage Otay Mesa Agnews Pasadena Calpine BRSP Russell City Los Esteros

Projects

Hidalgo King City Stony Brook Other

Projects

Gilroy Cogen Other

Projects

Brazos Valley Magic Valley Sutter Hermiston Osprey Westbrook

Proj ect Debt

$1,599

CCFC

$970

Capital LeaseObligations

$234


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Calpine1 Continues to Benefit fromFederal NOL Positions

Federal NOLs at Dec. 31, 2010: $7.4 billion

$4.9 billion of NOLs not subject to limitations, not including 2011 loss

$2.5 billion of NOLs subject to annual IRC Section 382 limitations.Average annual limitation for the next 4 years is approximately $403million/year- Subject to certain limitations, any amount not utilized in any year

can be carried forward and applied in succeeding years

181 Includes CCFC.


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Full Year 2011 Range: Low High

(in millions)

GAAP Net Income (Loss)(1) $ (150) $ (100)Plus:

(Gain) loss on interest rate derivatives, net 149 149Debt extinguishment costs 94 94

Interest expense, net of interest income 760 760Depreciation and amortization expense 560 560Major maintenance expense 230 230Operating lease expense 35 35Other(2) 22 22

Adjusted EBITDA $ 1,700 $ 1,750Less:

Operating lease payments 30 30

Major maintenance expense and maintenance capital expenditures(3)

390 390Recurring cash interest, net(4) 780 780Cash taxes 15 15Other 10 10

Adjusted Recurring Free Cash Flow $ 475 $ 525

Non-recurring interest rate swap payments(5) 175 175__________(1) For purposes of Net Income guidance reconciliation, unrealized mark-to-market adjustments are assumed to be nil.(2) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax

expense and other items.(3) Includes projected major maintenance expense of $235 million and maintenance capital expenditures of $155 million. Capital expenditures

exclude major construction and development projects.(4) Includes fees for letters of credit, net of interest income.(5) Interest payments related to legacy LIBOR hedges associated with floating rate First Lien Credit Facility, which has been refinanced. Does not

include $17 million in interest rate swap breakage costs related to the repayment of project debt in June 2011.

22

Reg G Reconci liat ion: 2011 Adj usted EBITDAand Adjusted Recurring Free Cash Flow Guidance

Note: Guidance as provided on October 28, 2011.


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23

Reg G Reconci liat ion: 2012 Adj usted EBITDAand Adjusted Recurring Free Cash Flow Guidance

Full Year 2012 Range: Low High

(in millions)

GAAP Net Income (Loss)(1) $ (80) $ 120Plus:

Interest expense, net of interest income 765 765Depreciation and amortization expense 555 555

Major maintenance expense 185 185Operating lease expense 35 35Other(2) 90 90

Adjusted EBITDA $ 1,550 $ 1,750Less:

Operating lease payments 35 35Major maintenance expense and maintenance capital expenditures(3) 350 350Recurring cash interest, net(4) 770 770Cash taxes 10 10Other 10 10

Adjusted Recurring Free Cash Flow $ 375 $ 575

Non-recurring interest rate swap payments(5) 150 150__________(1) For purposes of Net Income guidance reconciliation, unrealized mark-to-market adjustments are assumed to be nil.(2) Other includes stock-based compensation expense, adjustments to reflect Adjusted EBITDA from unconsolidated investments, income tax

expense and other items.(3) Includes projected major maintenance expense of $185 million and maintenance capital expenditures of $165 million. Capital expenditures

exclude major construction and development projects. 2012 figures exclude amounts to be funded by project debt.(4) Includes fees for letters of credit, net of interest income.(5) Interest payments related to legacy LIBOR hedges associated with floating rate First Lien Credit Facility, which has been refinanced.

Note: Guidance as provided on October 28, 2011.


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CPN 2011 Citi Credit Conference v2.0

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