UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2002

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ________ to _________

Commission file number: 1-12079

CALPINE CORPORATION

(A Delaware Corporation)

I.R.S. Employer Identification No. 77-0212977

50 West San Fernando Street
San Jose, California 95113
Telephone: (408) 995-5115

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

Yes [X] No [ ]

Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date:

373,911,684 shares of Common Stock, par value $.001 per share, outstanding
on May 13, 2002

In the Company's 2001 Report on Form 10-K the Company disclosed that it
dismissed Arthur Andersen LLP effective March 29, 2002, as its independent
public accountants and appointed Deloitte and Touche LLP as its new independent
public accountants. Pursuant to Temporary Note 2T to Article 3 of Regulation
S-X, this Report on Form 10-Q is being filed prior to the completion of the
review by Deloitte and Touche LLP that would otherwise be required by Statement
on Auditing Standards No. 71, "Interim Financial Information."

CALPINE CORPORATION AND SUBSIDIARIES
Report on Form 10-Q
For the Quarter Ended March 31, 2002

INDEX

PAGE NO.
PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.
Consolidated Condensed Balance Sheets March 31, 2002 and December 31, 2001.................. 1
Consolidated Condensed Statements of Operations For the Three Months Ended March 31, 2002
and 2001.................................................................................... 3
Consolidated Condensed Statements of Cash Flows For the Three Months Ended March 31, 2002
and 2001.................................................................................... 5
Notes to Consolidated Condensed Financial Statements March 31, 2002......................... 6
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations....... 22
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................. 38

PART II - OTHER INFORMATION

Item 1. Legal Proceedings........................................................................... 38
Item 2. Changes in Securities and Use of Proceeds................................................... 39
Item 6. Exhibits and Reports on Form 8-K............................................................ 40
Signatures................................................................................................................ 42

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
March 31, 2002 and December 31, 2001
(in thousands, except share and per share amounts)

MARCH 31, DECEMBER 31,
2002 2001
------------ ------------
ASSETS (unaudited)

Current assets:
Cash and cash equivalents ................................................... $ 410,772 $ 1,525,417
Accounts receivable, net..................................................... 817,936 966,080
Margin deposits and other prepaid expense ................................... 304,564 480,656
Inventories ................................................................. 90,627 78,862
Current derivative assets ................................................... 549,155 763,162
Other current assets ........................................................ 133,056 193,525
------------ ------------
Total current assets ..................................................... 2,306,110 4,007,702
------------ ------------
Restricted cash ................................................................ 91,070 95,833
Notes receivable, net of current portion ....................................... 160,359 158,124
Project development costs ...................................................... 185,412 179,783
Investments in power projects .................................................. 380,558 378,614
Deferred financing costs ....................................................... 223,893 210,811
Property, plant and equipment, net ............................................. 16,211,489 15,200,498
Goodwill and other intangible assets, net ...................................... 221,786 228,673
Long-term derivative assets .................................................... 554,354 564,952
Other assets ................................................................... 308,504 304,562
------------ ------------
Total assets ............................................................. $ 20,643,535 $ 21,329,552
============ ============

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable ............................................................ $ 1,260,579 $ 1,283,843
Accrued payroll and related expense ......................................... 49,876 57,285
Accrued interest payable .................................................... 194,538 160,115
Notes payable and borrowings under lines of credit, current portion ......... 14,336 23,238
Capital lease obligation, current portion ................................... 2,279 2,206
Zero-Coupon Convertible Debentures Due 2021 ................................. 685,500 878,000
Current derivative liabilities .............................................. 450,865 625,339
Other current liabilities ................................................... 231,036 198,812
------------ ------------
Total current liabilities ................................................ 2,889,009 3,228,838
------------ ------------
Notes payable and borrowings under lines of credit, net of current portion ..... 10,000 74,750
Capital lease obligation, net of current portion ............................... 206,697 207,219
Construction/project financing ................................................. 3,424,097 3,393,410
Convertible Senior Notes Due 2006 .............................................. 1,200,000 1,100,000
Senior notes ................................................................... 7,039,516 7,049,038
Deferred income taxes, net ..................................................... 915,092 964,346
Deferred lease incentive ....................................................... 56,360 57,236
Deferred revenue ............................................................... 186,725 154,381
Long-term derivative liabilities ............................................... 497,916 822,848
Other liabilities .............................................................. 97,658 96,504
------------ ------------
Total liabilities ........................................................ 16,523,070 17,148,570
------------ ------------

-1-

Company-obligated mandatorily redeemable convertible preferred securities
of subsidiary trusts ........................................................ 1,123,275 1,123,024
Minority interests ............................................................. 39,319 47,389
------------ ------------
Stockholders' equity:
Preferred stock, $.001 par value per share; authorized 10,000,000
shares; issued and outstanding one share in 2002 and 2001 ................ -- --
Common stock, $.001 par value per share; authorized 1,000,000,000
shares in 2002 and 2001; issued and outstanding 307,604,929
shares in 2002 and 307,058,751 shares in 2001 ............................ 308 307
Additional paid-in capital .................................................. 2,043,816 2,040,836
Retained earnings ........................................................... 1,121,733 1,196,000
Accumulated other comprehensive loss ........................................ (207,986) (226,574)
------------ ------------
Total stockholders' equity ............................................... 2,957,871 3,010,569
------------ ------------
Total liabilities and stockholders' equity ............................... $ 20,643,535 $ 21,329,552
============ ============

The accompanying notes are an integral part of
these consolidated condensed financial statements.

-2-

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2002 and 2001
(in thousands, except per share amounts)
(unaudited)

THREE MONTHS ENDED
MARCH 31,
---------------------------------
2002 2001
------------ ------------

Revenue:
Electric generation and marketing revenue
Electricity and steam revenue.............................................. $ 620,179 $ 595,159
Sales of purchased power................................................... 908,301 453,602
Electric power derivative mark-to-market gain.............................. 4,166 1,306
------------ ------------
Total electric generation and marketing revenue............................... 1,532,646 1,050,067
Oil and gas production and marketing revenue
Oil and gas sales.......................................................... 67,488 156,687
Sales of purchased gas..................................................... 132,158 129,172
------------ ------------
Total oil and gas production and marketing revenue............................ 199,646 285,859
Income from unconsolidated investments in power projects...................... 1,444 563
Other revenue................................................................. 4,611 3,262
------------ ------------
Total revenue............................................................ 1,738,347 1,339,751
------------ ------------
Cost of revenue:
Electric generation and marketing expense
Plant operating expense.................................................... 115,157 84,460
Royalty expense............................................................ 4,155 11,009
Purchased power expense.................................................... 815,005 456,266
------------ ------------
Total electric generation and marketing expense............................... 934,317 551,735
Oil and gas production and marketing expense
Oil and gas production expense............................................. 26,940 34,283
Purchased gas expense...................................................... 123,694 118,628
------------ ------------
Total oil and gas production and marketing expense............................ 150,634 152,911
Fuel expense
Cost of oil and natural gas burned by power plants......................... 326,443 264,563
Natural gas derivative mark-to-market loss (gain).......................... 6,392 (7,549)
------------ ------------
Total fuel expense............................................................ 332,835 257,014
Depreciation, depletion and amortization expense.............................. 103,873 72,013
Operating lease expense....................................................... 36,134 28,011
Other expense................................................................. 2,590 2,499
------------ ------------
Total cost of revenue.................................................... 1,560,383 1,064,183
------------ ------------
Gross profit.................................................................. 177,964 275,568
Project development expense..................................................... 11,338 15,839
Equipment cancellation cost..................................................... 168,471 --
General and administrative expense.............................................. 60,261 36,085
Merger expense.................................................................. -- 6,021
------------ ------------
Income (loss) from operations................................................. (62,106) 217,623
Interest expense................................................................ 61,311 19,925
Distributions on trust preferred securities..................................... 15,386 15,175
Interest income................................................................. (12,176) (19,358)
Other income, net............................................................... (9,093) (5,727)
------------ ------------
Income (loss) before provision (benefit) for income taxes..................... (117,534) 207,608
Provision (benefit) for income taxes............................................ (41,137) 88,981
------------ ------------
Income (loss) before extraordinary gain and cumulative effect
of a change in accounting principle.......................................... (76,397) 118,627
Extraordinary gain, net of tax provision of $1,362 and $-- ..................... 2,130 --
Cumulative effect of a change in accounting principle,
net of tax provision of $-- and $669.......................................... -- 1,036
------------ ------------
Net income (loss)............................................................. $ (74,267) $ 119,663
============ ============
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding........................... 307,332 300,554
Income (loss) before extraordinary gain and cumulative effect of
a change in accounting principle............................................ $ (0.25) $ 0.39
Extraordinary gain............................................................ $ 0.01 $ --
Cumulative effect of a change in accounting principle......................... $ -- $ 0.01
------------ ------------
Net income (loss)............................................................. $ (0.24) $ 0.40
============ ============

-3-

Diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding before
dilutive effect of certain convertible securities............................ 307,332 316,832
Income (loss) before dilutive effect of certain convertible
securities, extraordinary gain and cumulative effect of a
change in accounting principle............................................... $ (0.25) $ 0.37
Dilutive effect of certain convertible securities (1)......................... $ -- $ (0.02)
------------ ------------
Income (loss) before extraordinary gain and cumulative effect
of a change in accounting principle.......................................... $ (0.25) $ 0.35
Extraordinary gain............................................................ $ 0.01 $ --
Cumulative effect of a change in accounting principle......................... $ -- $ 0.01
------------ ------------
Net income (loss)............................................................. $ (0.24) $ 0.36
============ ============

__________

(1) Includes the effect of the assumed conversion of certain convertible
securities in 2001. No convertible securities were included in the 2002
amounts as the securities were antidilutive. For the three months ended
March 31, 2001, the assumed conversion calculation added 44,882 shares of
common stock and $9,355 to the net income results.

The accompanying notes are an integral part of
these consolidated condensed financial statements.

-4-

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2002 and 2001
(in thousands)
(unaudited)

THREE MONTHS ENDED
MARCH 31,
---------------------------------
2002 2001
------------ ------------

Cash flows from operating activities:
Net income (loss) ........................................................... $ (74,267) $ 119,663
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization ................................. 114,136 77,594
Equipment cancellation cost....................... ....................... 168,471 --
Deferred income taxes, net ............................................... (94,247) 41,216
Gain on sale of assets.................................................... (9,667) (10,750)
Minority interests........................................................ 1 3,604
Income from unconsolidated investments in power projects.................. (1,444) (563)
Distributions from unconsolidated investments in power projects........... 9 1,213
Change in operating assets and liabilities, net
of effects of acquisitions:
Accounts receivable..................................................... 148,144 (10,316)
Notes receivable........................................................ (5,202) (7,959)
Current derivative assets............................................... 214,007 (391,291)
Other current assets.................................................... 231,918 (29,969)
Long-term derivative assets............................................. 10,598 (162,488)
Other assets............................................................ (7,241) 3,176
Accounts payable and accrued expense ................................... 24,073 (132,685)
Current derivative liabilities.......................................... (174,474) 408,781
Long-term derivative liabilities........................................ (324,906) 222,479
Other liabilities....................................................... 54,125 (9,969)
Other comprehensive income (loss) relating to derivatives .............. 71,911 (86,181)
------------ ------------
Net cash provided by operating activities ............................. 345,945 35,555
------------ ------------
Cash flows from investing activities:
Purchases of property, plant and equipment .................................. (1,289,615) (795,561)
Disposals of property, plant and equipment................................... 1,739 19,134
Advances to joint ventures .................................................. (23,121) (32,331)
Decrease (increase) in notes receivable ..................................... 12,914 (21,588)
Maturities of collateral securities ......................................... 3,325 2,885
Project development costs ................................................... (23,784) (19,210)
Decrease (increase) in restricted cash ...................................... 16,929 (51,964)
------------ ------------
Net cash used in investing activities ................................. (1,301,613) (898,635)
------------ ------------
Cash flows from financing activities:
Repurchase of Zero-Coupon Convertible Debentures Due 2021.................... (187,727) --
Repayments of notes payable and borrowings under lines of credit ............ (73,652) (134,493)
Borrowings from project financing ........................................... 122,885 609,354
Repayments of project financing ............................................. (92,198) (403,810)
Proceeds from issuance of Convertible Senior Notes Due 2006 ................. 100,000 --
Proceeds from issuance of senior notes ...................................... -- 1,150,000
Financing costs.............................................................. (31,479) (52,509)
Other ....................................................................... 3,685 (31,460)
------------ ------------
Net cash provided by (used in) financing activities ................... (158,486) 1,137,082
------------ ------------
Effect of exchange rate changes on cash and cash equivalents.................... (491) --
Net increase (decrease) in cash and cash equivalents ........................... (1,114,645) 274,002
Cash and cash equivalents, beginning of period ................................. 1,525,417 596,077
------------ ------------
Cash and cash equivalents, end of period ....................................... $ 410,772 $ 870,079
============ ============
Cash paid during the period for:
Interest, net of amounts capitalized ........................................ $ 6,218 $ 12,599
Income taxes ................................................................ $ 12,255 $ 65,745

The accompanying notes are an integral part of
these consolidated condensed financial statements.

-5-

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
March 31, 2002
(unaudited)

1. Organization and Operation of the Company

Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, "the Company") is engaged in the generation of electricity in the
United States, Canada and the United Kingdom. The Company is involved in the
development, acquisition, ownership and operation of power generation facilities
and the sale of electricity and its by-product, thermal energy, primarily in the
form of steam. The Company has ownership interests in and operates gas-fired
power generation and cogeneration facilities, gas fields, gathering systems and
gas pipelines, geothermal steam fields and geothermal power generation
facilities in the United States. In Canada, the Company has power facilities and
oil and gas operations. In the United Kingdom, the Company has a gas-fired power
cogeneration facility. Each of the generation facilities produces and markets
electricity for sale to utilities and other third party purchasers. Thermal
energy produced by the gas-fired cogeneration facilities is primarily sold to
industrial users. Gas produced and not physically delivered to the Company's
generating plants is sold to third parties.

2. Summary of Significant Accounting Policies

Basis of Interim Presentation -- The accompanying unaudited interim
consolidated condensed financial statements of the Company have been prepared by
the Company pursuant to the rules and regulations of the Securities and Exchange
Commission. In the opinion of management, the consolidated condensed financial
statements include the adjustments necessary to present fairly the information
required to be set forth therein. The Company's historical amounts have been
restated to reflect the pooling-of-interests transaction completed during the
second quarter of 2001 for the acquisition of Encal Energy Ltd. ("Encal").
Certain information and note disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
in the United States of America have been condensed or omitted from these
statements pursuant to such rules and regulations and, accordingly, these
financial statements should be read in conjunction with the audited consolidated
financial statements of the Company for the year ended December 31, 2001,
included in the Company's Annual Report on Form 10-K. The results for interim
periods are not necessarily indicative of the results for the entire year.

Use of Estimates in Preparation of Financial Statements -- The preparation
of financial statements in conformity with generally accepted accounting
principles in the United States of America requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities, and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expense during the reporting
period. Actual results could differ from those estimates. The most significant
estimates with regard to these financial statements relate to future development
costs, useful lives of the generation facilities, provision for income taxes,
fair value calculations of derivative instruments and depletion, depreciation
and impairment of natural gas and petroleum property and equipment. See the
"Critical Accounting Policies" subsection in the Management's Discussion and
Analysis of Financial Condition and Results of Operations in the Company's
Annual Report on Form 10-K for the year ended December 31, 2001 for a further
discussion of the Company's significant estimates.

Revenue Recognition -- The Company is primarily an electric generation
company, operating a portfolio of mostly wholly owned plants but also some
plants in which its ownership interest is 50% or less and which are accounted
for under the equity method. In conjunction with its electric generation
business, the Company also produces, as a by-product, thermal energy for sale to
customers, principally steam hosts at its cogeneration sites. In addition, the
Company acquires and produces natural gas for its own consumption and sells the
balance and oil produced to third parties. To protect and enhance the profit
potential of its electric generation plants, the Company, through its
subsidiary, Calpine Energy Services, L.P. ("CES"), enters into electric and gas
hedging, balancing, optimization, and trading transactions in which purchased
electricity and gas is resold to third parties. CES generally acts as a
principal, takes title to the commodities purchased for resale, and assumes the
risks and rewards of ownership. Therefore, in accordance with Staff Accounting
Bulletin No. 101, "Revenue Recognition in Financial Statements" and the Emerging
Issues Task Force ("EITF") Issue No. 99-19, "Reporting Revenue Gross as a
Principal Versus Net as an Agent," CES recognizes revenue on a gross basis,
except in the case of financial swap transactions, in which case the net gain or
loss from the financial swap is recorded in income when the effects of the risks
being managed are recognized. Managed risks typically include commodity price
risk associated with fuel purchases and power sales. The Company, through Power
Systems Mfg., LLC ("PSM"), designs and manufactures certain spare parts for gas
turbines. The Company also generates small amounts of revenue by occasionally
loaning funds to power projects, by providing operation and maintenance ("O&M")
services to unconsolidated power projects, and by performing engineering
services for data centers and other facilities requiring highly reliable power.
Further details of the Company's revenue recognition policy for each type of
revenue transaction are provided below:

-6-

Electric Generation and Marketing Revenue -- This includes electricity and
steam sales, mark-to-market gains and losses from electric power derivatives and
sales of purchased power. The Company actively manages the revenue stream for
its portfolio of electric generating facilities. The Company markets on a system
basis both power generated by its plants in excess of amounts under direct
contract between the plant and a third party, and power purchased from third
parties, through hedging, balancing and optimization transactions. CES performs
a market-based allocation of total electric generation and marketing revenue,
exclusive of mark-to-market activity, to electricity and steam sales (based on
electricity delivered by the Company's electric generating facilities to serve
CES contracts) and the balance is allocated to sales of purchased power. Sales
of purchased power also includes revenue from the settlement of contracts that
have been previously recorded in results of operations as electric power
derivative mark-to-market gains or losses

Oil and Gas Production and Marketing Revenue -- This includes sales to
third parties of oil, gas and related products that are produced by the
Company's Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and
also sales of purchased gas arising from hedging, balancing and optimization
transactions. Sales of purchased gas also includes revenue from the settlement
of contracts that have been previously recorded in results of operations as
natural gas derivative mark-to-market gains or losses. Oil and gas sales for
produced products are recognized pursuant to the sales method.

Income from Unconsolidated Investments in Power Projects -- The Company
uses the equity method to recognize as revenue its pro rata share of the net
income or loss of the unconsolidated investment until such time, if applicable,
that the Company's investment is reduced to zero, at which time equity income is
generally recognized only upon receipt of cash distributions from the investee.

Other Revenue -- This includes O&M contract revenue, interest income on
loans to power projects, PSM revenue from sales to third parties, engineering
revenue and miscellaneous revenue.

Purchased Power and Purchased Gas Expense -- The cost of power purchased
from third parties for hedging, balancing, and optimization activities, along
with costs from the subsequent settlement of contracts that have been previously
recorded in results of operations as electric power derivative mark-to-market
gains or losses, is recorded as purchased power expense, a component of electric
generation and marketing expense.

The Company records the cost of gas consumed in its power plants as cost of
oil and natural gas burned by power plants, while gas purchased from third
parties for hedging, balancing, and optimization activities, along with costs
from the subsequent settlement of contracts that have been previously recorded
in results of operations as natural gas derivative mark-to-market gains or
losses, is recorded as purchased gas expense, a component of oil and gas
production and marketing expense.

Derivative Instruments -- Financial Accounting Standards Board ("FASB")
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities" as amended by SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities -- Deferral of the
Effective Date of FASB Statement No. 133 -- an Amendment of FASB Statement No.
133," SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities -- an Amendment of FASB Statement No. 133" and related
guidance from the Derivatives Implementation Group established accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge criteria are met, and requires that
a company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting.

SFAS No. 133 provides that the effective portion of the gain or loss on a
derivative instrument designated and qualifying as a cash flow hedging
instrument be reported as a component of other comprehensive income and be
reclassified into earnings in the same period during which the hedged forecasted
transaction affects earnings. The remaining gain or loss on the derivative
instrument, if any, must be recognized currently in earnings. SFAS No. 133
provides that the changes in fair value of derivatives designated as fair value
hedges and the corresponding changes in the fair value of the hedged risk
attributable to a recognized asset, liability, or unrecognized firm commitment
be recorded in earnings. If the fair value hedge is effective, the amounts
recorded will offset in earnings.

SFAS No. 133 requires that as of the date of initial adoption, the
difference between the fair value of derivative instruments and the previous
carrying amount of these derivatives be recorded in net income or other
comprehensive income, as appropriate, as the cumulative effect of a change in
accounting principle. Upon adoption of SFAS No. 133 effective January 1, 2001,
the Company recorded cumulative effects of a change in accounting principle of
$1.0 million (net of a $0.7 million tax provision) to net income and $39.8
million (net of a $25.7 million tax provision) to other comprehensive income.

-7-

New Accounting Pronouncements -- In June 2001, the Company adopted SFAS No.
141, "Business Combinations," which supersedes Accounting Principles Board
("APB") Opinion No. 16, "Business Combinations" and SFAS No. 38, "Accounting for
Preacquisition Contingencies of Purchased Enterprises." SFAS No. 141 eliminated
the pooling-of-interests method of accounting for business combinations and
modified the recognition of intangible assets and disclosure requirements.
Adoption of SFAS No. 141 did not have a material effect on the Company's
consolidated financial statements.

On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which supersedes APB Opinion No. 17, "Intangible Assets."
See Note 4 for more information.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which amends SFAS No. 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies." SFAS No. 143 addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. SFAS No.
143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made. SFAS No. 143 is effective for financial
statements issued for fiscal years beginning after June 15, 2002. The Company
has not completed its analysis of the impact that SFAS No. 143 will have on its
consolidated financial statements.

On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the accounting and reporting provisions of APB Opinion No.
30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," for the disposal of a segment of a business (as
previously defined in that APB Opinion). SFAS No. 144 establishes a single
accounting model, based on the framework established in SFAS No. 121, for
long-lived assets to be disposed of by sale. SFAS No. 144 also resolves several
significant implementation issues related to SFAS No. 121, such as eliminating
the requirement to allocate goodwill to long-lived assets to be tested for
impairment and establishing criteria to define whether a long-lived asset is
held for sale. Adoption of SFAS No. 144 did not have a material effect on the
Company's consolidated financial statements.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses
from Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No.
145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to
eliminate an inconsistency between the required accounting for sale-leaseback
transactions and the required accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions. SFAS No.
145 also amends other existing authoritative pronouncements to make various
technical corrections, clarify meanings, or describe their applicability under
changed conditions. The provisions related to the rescission of SFAS No. 4 shall
be applied in fiscal years beginning after May 15, 2002. The provisions related
to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002.
All other provisions shall be effective for financial statements issued on or
after May 15, 2002, with early application encouraged. The Company does not
believe that SFAS No. 145 will have a material effect on its results of
operations.

Reclassifications -- Prior period amounts in the consolidated condensed
financial statements have been reclassified where necessary to conform to the
2002 presentation.

-8-

3. Property, Plant and Equipment, Net, and Capitalized Interest

Property, plant and equipment, net, consisted of the following (in
thousands):

MARCH 31, DECEMBER 31,
2002 2001
------------ ------------

Buildings, machinery and equipment ............. $ 4,966,818 $ 4,585,139
Oil and gas properties, including pipelines .... 2,327,040 2,283,344
Geothermal properties .......................... 382,134 375,156
Other .......................................... 240,997 223,675
------------ ------------
7,916,989 7,467,314
Less: accumulated depreciation, depletion and
amortization.................................... (935,600) (843,778)
------------ ------------
6,981,389 6,623,536
Land ........................................... 80,680 80,506
Construction in progress ....................... 9,149,420 8,496,456
------------ ------------
Property, plant and equipment, net ............. $ 16,211,489 $ 15,200,498
============ ============

Construction in progress is primarily attributable to gas-fired power
projects under construction including prepayments on gas turbine generators.
Upon commencement of plant operation, these costs are transferred to the
applicable property category, generally buildings, machinery and equipment. In
March 2002, the Company announced a new turbine and construction program that
will slow the growth in the Company's construction in progress. See Note 11 for
a discussion of the turbine order cancellations during the quarter.

Capitalized Interest -- The Company capitalizes interest on capital
invested in projects during the advanced stages of development and the
construction period in accordance with SFAS No. 34, "Capitalization of Interest
Cost," as amended by SFAS No. 58, "Capitalization of Interest Cost in Financial
Statements That Include Investments Accounted for by the Equity Method (an
Amendment of FASB Statement No. 34)." The Company's qualifying assets include
construction in progress, certain oil and gas properties under development,
construction costs related to unconsolidated investments in power projects under
construction, and advanced stage development costs. For the three months ended
March 31, 2002 and 2001, the total amount of interest capitalized was $163.1
million and $104.0 million, including $35.1 million and $34.7 million,
respectively, of interest incurred on funds borrowed for specific construction
projects and $128.0 million and $69.3 million, respectively of interest incurred
on general corporate funds used for construction. Upon commencement of plant
operation, capitalized interest, as a component of the total cost of the plant,
is amortized over the estimated useful life of the plant. The increase in the
amount of interest capitalized during the three months ended March 31, 2002
reflects the significant increase in the Company's power plant construction
program.

In accordance with SFAS No. 34, the Company determines which debt
instruments best represent a reasonable measure of the cost of financing
construction assets in terms of interest cost incurred that otherwise could have
been avoided. These debt instruments and associated interest cost are included
in the calculation of the weighted average interest rate used for capitalizing
interest on general funds. The primary debt instruments included in the rate
calculation are the Company's senior notes and the corporate revolvers.

4. Goodwill and Other Intangible Assets

On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which requires that all intangible assets with finite useful
lives be amortized and that goodwill and intangible assets with indefinite lives
not be amortized, but rather tested upon adoption and at least annually for
impairment. The Company is required to complete the initial step of a
transitional impairment test within six months of adoption of SFAS No. 142 and
to complete the final step of the transitional impairment test by the end of the
fiscal year. Any impairment loss resulting from the transitional impairment test
would be recorded as a cumulative effect of a change in accounting principle for
the quarter ended March 31, 2002. Subsequent impairment losses will be reflected
in operating income or loss in the consolidated statements of operations. We
will complete a transitional goodwill impairment test as required prior to June
30, 2002. In accordance with the standard, the Company discontinued the
amortization of its recorded goodwill as of January 1, 2002 and identified
reporting units based on its current segment reporting structure and allocated
all recorded goodwill, as well as other assets and liabilities, to the reporting
units. A reconciliation of previously reported net income and earnings per share
to the amounts adjusted for the exclusion of goodwill amortization is provided
below (in thousands except per share amounts):

-9-

Three Months Ended March 31,
----------------------------------------------------------------------
2002 2001
------------------------------ ------------------------------
Per Share Per Share
------------------ -----------------
Amount Diluted Basic Amount Diluted Basic
--------- ------- ------- --------- ------- -------

Reported income (loss) before extraordinary
gain and cumulative effect of a change
in accounting principle........................... $(76,397) $(0.25) $(0.25) $ 118,627 $ 0.35 $ 0.39

Add: Goodwill amortization, net of tax............ -- -- -- 136 -- --

Income (loss) before extraordinary gain and
cumulative effect of a change in accounting
principle, as adjusted............................ (76,397) (0.25) (0.25) 118,763 0.35 0.39

Extraordinary gain and cumulative effect of a
change in accounting principle, net of tax........ 2,130 0.01 0.01 1,036 0.01 0.01
-------- ------ ------ --------- ------- -------
Net income (loss), as adjusted.................... $(74,267) $(0.24) $(0.24) $ 119,799 $ 0.36 $ 0.40
======== ====== ====== ========= ======= =======

Recorded goodwill, by segment, as of March 31, 2002 was (in thousands):

Electric Generation and Marketing ............................ $29,348
Oil and Gas Production and Marketing.......................... --
Corporate, Other and Eliminations ............................ --
-------
Total ..................................................... $29,348
=======

The Company also reassessed the useful lives and the classification of its
identifiable intangible assets and determined that they continue to be
appropriate. The components of the amortizable intangible assets consist of the
following (in thousands):

As of March 31, 2002 As of December 31, 2001
------------------------ ------------------------
Weighted
Average
Useful
Life/Contract Carrying Accumulated Carrying Accumulated
Life Amount Amortization Amount Amortization
------------- ---------- ------------ ---------- ------------

Patents .................. 5 $ 485 $ (158) $ 485 $ (134)
Power sales agreements.... 14 173,479 (93,779) 173,479 (87,823)
Fuel supply and fuel
management contracts..... 33 127,543 (15,477) 127,543 (14,503)
Other..................... 5 381 (36) 277 (25)
--------- ---------- --------- ---------
Total..................... $ 301,888 $ (109,450) $ 301,784 $(102,485)
========= ========== ========= =========

Amortization expense of other intangible assets was $7.0 million and $6.9
million in the three months ended March 31, 2002 and 2001, respectively.
Assuming no future impairments of these assets or additions as the result of
acquisitions, annual amortization expense will be $25.0 million for the twelve
months ended December 31, 2002, $8.9 million in 2003, $8.4 million in 2004, $8.3
million in 2005 and $8.2 million in 2006.

5. Investments in Power Projects

On March 29, 2002, the Company sold its 11.4% interest in the Lockport
Power Plant in exchange for a $27.3 million note receivable from Fortistar
Tuscarora LLC, a wholly owned subsidiary of Fortistar LLC, the project's
managing general partner. The note is scheduled to be repaid in the second
quarter of 2002. This transaction resulted in a pre-tax other income gain of
$9.7 million.

-10-

6. Financing

In January 2002, the Company entered into a letter of intent with ING Bank
on the debt portion of a proposed California peaker sale/leaseback, including 11
California peaker facilities. This transaction is expected to generate $500
million of cash that will be received throughout 2002 as the power facilities
enter commercial operation.

Between January 2, 2002, and February 11, 2002, the Company repurchased an
additional $192.5 million of its Zero-Coupon Convertible Debentures Due 2021
("Zero Coupons"), bringing total repurchases to $314.5 million, and bringing the
amount of Zero Coupons outstanding as of March 31, 2002 to $685.5 million. The
Zero Coupons were repurchased at a discount, resulting in an extraordinary gain
of $2.1 million, after the write-off of related financing costs and provision
for tax. See Note 14 for additional repurchases subsequent to March 31, 2002.

On January 3, 2002, the Company sold $100 million in aggregate principal
amount of 4% Convertible Senior Notes Due 2006 ("Convertible Notes"), pursuant
to the exercise of the initial purchaser's remaining $100 million option to
purchase additional Convertible Notes. These securities will be convertible into
shares of Calpine common stock at a price of $18.07.

In March 2002, the Company closed a new secured credit agreement comprised
of (a) a $1.0 billion revolving credit facility expiring on May 24, 2003 and (b)
a two-year term loan facility for up to $600 million, which as previously
reported, was only to be made available to the Company upon satisfaction of
certain conditions to borrowing on or before June 8, 2002. On May 10, 2002, the
Company borrowed $500 million of the term loan facility and, subject to certain
conditions, may borrow the remaining $100 million in one or two remaining
tranches on or before June 8, 2002. At the March 2002 closing, the Company also
amended its existing $400 million revolving credit agreement to provide, among
other things, security for borrowings under that agreement. The security for the
revolving and term loan facilities as originally provided included (a) a pledge
of the capital stock of the Company's subsidiary holding, directly or
indirectly, (i) the interests in its natural gas properties, (ii) the Saltend
power plant located in the United Kingdom and (iii) the Company's equity
investment in nine U.S. power plants, and (b) a pledge by certain of the
Company's subsidiaries of a total of 65% of the capital stock of Calpine Canada
Energy Ltd. As part of the recent funding of the $500 million term loan, the
Company expanded the security for the revolving credit and term loan facilities
under both the $1.6 billion and the $400 million credit agreements by pledging
to the lenders substantially all of the Company's remaining first tier domestic
subsidiaries (excluding CES).

On March 13, 2002, the Company repaid the Michael Petroleum note payable,
which had a balance of $64.8 million at repayment.

7. Derivative Instruments

As an independent power producer primarily focused on generation of
electricity using gas-fired turbines, the Company's natural physical commodity
position is "short" fuel (i.e., natural gas consumer) and "long" power (i.e.,
electricity seller). To manage forward exposure to price fluctuation in these
and (to a lesser extent) other commodities, the Company enters into derivative
commodity instruments. All transactions are subject to the Company's risk
management policy which prohibits positions that exceed total portfolio
generation and fuel requirements. Any hedging, balancing, or optimization
activities that the Company engages in are directly related to the Company's
asset-based business model of owning and operating gas-fired electric power
plants and are designed to protect the Company's "spark spread" (the difference
between the Company's fuel cost and the revenue it receives for its electric
generation). The Company hedges exposures that arise from the ownership and
operation of power plants and related sales of electricity and purchases of
natural gas, and the Company utilizes derivatives to optimize the returns the
Company is able to achieve from these assets for the Company's shareholders.
While certain of the Company's contracts are considered energy trading contracts
as defined in EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities," the Company's traders have low capital
at risk and value at risk limits for energy trading, and its risk management
policy limits, at any given time, its net sales of power to its generation
capacity and limits its net purchases of gas to its fuel consumption
requirements on a total portfolio basis. This model is markedly different from
that of companies that engage in significant commodity trading operations that
are unrelated to underlying physical assets. Derivative commodity instruments
are accounted for under the requirements of SFAS No. 133.

The Company enters into various foreign currency swap agreements to hedge
against changes in exchange rates on certain of its senior notes denominated in
currencies other than the U.S. dollar. The foreign currency swaps effectively
convert floating exchange rates into fixed exchange rates so that the Company
can predict with greater assurance what its U.S. dollar cost will be for
purchasing foreign currencies to satisfy the interest and principal payments on
these senior notes.

-11-

The Company also enters into various interest rate swap agreements to hedge
against changes in floating interest rates on certain of its project financing
facilities. The interest rate swap agreements effectively convert floating rates
into fixed rates so that the Company can predict with greater assurance what its
future interest costs will be and protect itself against increases in floating
rates.

In conjunction with its capital markets activities, the Company enters into
various forward interest rate agreements to hedge against interest rate
fluctuations that may occur after the Company has decided to issue long-term
fixed rate debt but before the debt is actually issued. The forward interest
rate agreements effectively prevent the interest rates on anticipated future
long-term debt from increasing beyond a certain level, allowing the Company to
predict with greater assurance what its future interest costs on fixed rate
long-term debt will be.

The Company enters into commodity financial instruments to convert floating
or indexed electricity and gas (and to a lesser extent oil and refined product)
prices to fixed prices in order to lessen its vulnerability to reductions in
electric prices for the electricity it generates, to reductions in gas prices
for the gas it produces, and to increases in gas prices for the fuel it consumes
in its power plants. The Company seeks to "self-hedge" its gas consumption
exposure to an extent with its own gas production position.

The Company also routinely enters into physical commodity contracts for
sales of its generated electricity and sales of its natural gas production to
ensure favorable utilization of generation and production assets. Such contracts
often meet the criteria of SFAS No. 133 as derivatives but are generally
eligible for the normal purchase and sales exception under SFAS No. 138. Some of
those that are not deemed normal purchases and sales, can be designated as
hedges of the underlying consumption of gas or production of electricity.

During 2001, the FASB issued SFAS No. 133 Implementation Issue No. C15,
dealing with a proposed electric industry normal purchases and sales exception
for capacity sales transactions ("The Eligibility of Option Contracts in
Electricity for the Normal Purchases and Normal Sales Exception"). As a result
of Issue No. C15, as revised, most of the Company's capacity sales contracts
qualify for the normal purchases and sales exception.

The Company also enters into physical options for short-term periods
(typically one month) to balance its short-term generating position. The
options, which the Company may write or purchase, typically provide for a
premium component and firm price for energy when exercised.

In 2001 the FASB cleared SFAS No. 133 Implementation Issue No. C16
"Applying the Normal Purchases and Normal Sales Exception to Contracts That
Combine a Forward Contract and a Purchased Option Contract" ("C16"). The
guidance in C16 applies to fuel supply contracts that require delivery of a
contractual minimum quantity of fuel at a fixed price and have an option that
permits the holder to take specified additional amounts of fuel at the same
fixed price at various times. Under C16, the volumetric optionality provided by
such contracts is considered a purchased option that disqualifies the entire
derivative fuel supply contract from being eligible to qualify for the normal
purchases and normal sales exception in SFAS No. 133. The Company has adopted
the guidance provided by C16 effective April 1, 2002, and Issue C16 is expected
to increase the volatility of the Company's reported earnings in the future.

The changes in fair values of derivative instruments designated as cash
flow hedges are recorded in other comprehensive income ("OCI") for the effective
portion and in current earnings, using the dollar offset method, for the
ineffective portion. The changes in fair values of derivative instruments
designated as fair value hedges are recorded in current earnings, as are the
changes in fair values of the hedged risk attributable to the recognized asset,
liability or unrecognized firm commitment being hedged. The changes in fair
values of derivative instruments that are not designated as hedges are recorded
in current earnings.

-12-

The table below reflects the amounts (in thousands) that are recorded as
assets and liabilities at March 31, 2002 for the Company's derivative
instruments:

Commodity
Interest Rate Currency Derivative Total
Derivative Derivative Instruments Derivative
Instruments Instruments Net Instruments
------------ ----------- ----------- ------------

Current derivative assets .............. $ -- $ -- $ 549,155 $ 549,155
Long-term derivative assets ............ -- -- 554,354 554,354
-------- --------- ---------- ----------
Total assets ......................... $ -- $ -- $1,103,509 $1,103,509
======== ========= ========== ==========
Current derivative liabilities ......... $(10,927) $ (1,971) $ (437,967) $ (450,865)
Long-term derivative liabilities ....... (6,136) (12,690) (479,090) (497,916)
-------- --------- ---------- ----------
Total liabilities ............... $(17,063) $ (14,661) $ (917,057) $ (948,781)
======== ========= ========== ==========
Net derivative assets (liabilities)..... $(17,063) $ (14,661) $ 186,452 $ 154,728
======== ========= ========== ==========

At any point in time, it is highly unlikely that total net derivative
assets and liabilities will equal accumulated OCI, net of tax from derivatives,
for three primary reasons:

o Tax effect of OCI -- When the values and subsequent changes in values of
derivatives that qualify as effective hedges are recorded into OCI, they
are initially offset by a derivative asset or liability. Once in OCI,
however, these values are tax effected against a deferred tax liabiality,
thereby creating an imbalance between net OCI and net derivative assets and
liabilities.

o Derivatives not designated as cash flow hedges and hedge ineffectiveness --
Only derivatives that qualify as effective cash flow hedges will have an
offsetting amount recorded in OCI. Derivatives not designated as cash flow
hedges and the ineffective portion of derivatives designated as cash flow
hedges will be recorded into earnings instead of OCI, creating a difference
between net derivative assets and liabilities and pre-tax OCI from
derivatives.

o Termination of effective cash flow hedges prior to maturity -- Following
the termination of a cash flow hedge and subsequent settlement with a
counterparty, the derivative asset or liability is liquidated and removed
from the books. At this point, no asset or liability exists on the books
for the hedge but a balance remains in OCI, which is not recognized in
earnings until the forecasted transactions occur. As a result, there will
be a temporary difference between OCI and derivative assets and liabilities
on the books until the remaining OCI balance is recognized in earnings.

Below is a reconciliation from the Company's net derivative assets to its
accumulated other comprehensive loss, net of tax from derivative instruments at
March 31, 2002 (in thousands):

Net derivative assets ............................................. $ 154,728
Derivatives not designated as cash flow hedges and
recognized hedge ineffectiveness ................................ (126,740)
Terminated cash flow hedges, prior to maturity .................... (255,817)
Deferred tax asset attributable to accumulated other
comprehensive loss on cash flow hedges .......................... 88,210
---------
Accumulated other comprehensive loss from
derivative instruments, net of tax ............................... $(139,619)
=========

The asset and liability balances for the Company's commodity derivative
instruments represent the net totals after offsetting certain assets against
certain liabilities under the criteria of FASB Interpretation No. 39,
"Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB
Opinion No. 10 and FASB Statement No. 105)" ("FIN 39"). For a given contract,
FIN 39 will allow the offsetting of assets against liabilities so long as four
criteria are met: (1) each of the two parties under contract owes the other
determinable amounts; (2) the party reporting under the offset method has the
right to set off the amount it owes against the amount owed to it by the other
party; (3) the party reporting under the offset method intends to exercise its
right to set off; and; (4) the right of set-off is enforceable by law. The table
below reflects both the amounts (in thousands) recorded as assets and
liabilities by the Company and the amounts that would have been recorded had the
Company's commodity derivative instrument contracts not qualified for offsetting
as of March 31, 2002.

-13-

MARCH 31, 2002
------------------------------
GROSS NET
----------- ------------

Current derivative assets .................. $ 1,182,400 $ 549,155
Long-term derivative assets ................ 957,666 554,354
----------- -----------
Total derivative assets .................. $ 2,140,066 $ 1,103,509
=========== ===========
Current derivative liabilities ............. $(1,071,212) $ (437,967)
Long-term derivative liabilities ........... (882,402) (479,090)
----------- -----------
Total derivative liabilities ............. $(1,953,614) $ (917,057)
=========== ===========
Net commodity derivative assets .......... $ 186,452 $ 186,452
=========== ===========

The table above excludes the value of interest rate and currency derivative
instruments.

The table below reflects the impact of the Company's derivative instruments
on its pre-tax earnings, both from cash flow hedge ineffectiveness and from the
changes in market value of derivatives not designated as hedges of cash flows,
for the three months ended March 31, 2002 and 2001, respectively (in thousands):

Three Months Ended
March 31,
-------------------------------------------------------------------------------------
2002 2001
------------------------------------------ ---------------------------------------
Hedge Undesignated Hedge Undesignated
Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total
--------------- ------------ -------- --------------- ------------ -------

Natural gas derivatives (1)................. $ (2,596) $(3,796) $(6,392) $ 526 $ 7,023 $ 7,549
Power derivatives .......................... (222) 4,388 4,166 (1,217) 2,523 1,306
Interest rate derivatives (2) .............. (152) -- (152) -- -- --
Foreign currency derivatives ............... -- -- -- -- -- --
--------- --------- --------- --------- --------- --------
Total..................................... $ (2,970) $ 592 $(2,378) $ (691) $ 9,546 $ 8,855
========= ========= ========= ========= ========= ========

(1) Composed of gas contracts and crude oil costless collar arrangements

(2) Recorded within Other Income

For the three months ended March 31, 2002 and 2001, the Company's realized
commodity cash flow hedge activity contributed $50.7 million and $17.0 million,
respectively, to pre-tax earnings based on the reclassification adjustment from
OCI to earnings. For the three months ended March 31, 2002 and 2001, power
hedges contributed $86.5 million and $(9.3) million, respectively, to pre-tax
earnings. For the three months ended March 31, 2002 and 2001, gas and crude oil
hedges contributed $(35.8) million and $26.3 million, respectively, to pre-tax
earnings.

As of March 31, 2002, the maximum length of time over which the Company was
hedging its exposure to the variability in future cash flows for forecasted
transactions was 6, 7, and 16 1/2 years, for commodity, foreign currency and
interest rate derivative instruments, respectively. The company estimates that
pre-tax gains of $80.1 million would be reclassified from accumulated OCI into
earnings during the twelve months ended March 31, 2003 as the hedged
transactions affect earnings assuming constant gas and power prices, interest
rates, and exchange rates over time; however, the actual amounts that will be
reclassified will likely vary based on the probability that gas and power prices
as well as interest rates and exchange rates will, in fact, change. Therefore,
management is unable to predict what the actual reclassification from OCI to
earnings (positive or negative) will be for the next twelve months.

-14-

The table below presents (in thousands) the pre-tax gains (losses)
currently held in OCI that will be recognized annually into earnings, assuming
constant gas and power prices, interest rates, and exchange rates over time.

2007
2002 2003 2004 2005 2006 & After Total
--------- ---------- --------- ---------- --------- --------- ----------

Crude oil OCI..................... $ (129) $ -- $ -- $ -- $ -- $ -- $ (129)
Gas OCI........................... (88,344) (183,131) (69,772) (63,121) (22,540) -- (426,908)
Power OCI......................... 206,945 66,583 353 1,320 1,898 (652) 276,447
Interest rates OCI................ (14,119) (12,118) (8,779) (7,612) (6,951) (18,937) (68,516)
Foreign currency OCI.............. (1,971) (1,831) (1,700) (1,588) (1,500) (133) (8,723)
--------- ---------- --------- --------- --------- --------- ----------
Total OCI....................... $ 102,382 $ (130,497) $ (79,898) $ (71,001) $ (29,093) $ (19,722) $ (227,829)
========= ========== ========= ========= ========= ========= ==========

8. Comprehensive Income (Loss)

Comprehensive income (loss) is the total of net income (loss) and all other
non-owner changes in equity. Comprehensive income (loss) includes net income
(loss) and unrealized gains and losses from derivative instruments that qualify
as hedges. The Company reports accumulated other comprehensive loss in its
consolidated balance sheet. The tables below detail the changes in the Company's
accumulated OCI balance and the components of the Company's comprehensive income
(loss) (in thousands):

Accumulated Other Comprehensive Loss
at March 31, 2002
------------------------------------- Comprehensive
Foreign Loss for the Three
Cash Flow Currency Months Ended
Hedges Translation Total March 31, 2002
--------- ----------- --------- ------------------

Net loss .......................................................... $ (74,267)
Accumulated other comprehensive loss at beginning of period ....... $(183,377) $ (43,197) $(226,574) --
Cash flow hedges:
Comprehensive pre-tax gain on cash flow hedges before
reclassification adjustment during the three months
ended March 31, 2002 ........................................ 120,610 -- 120,610 120,610
Reclassification adjustment for gain included in net
loss for the three months ended March 31, 2002 .............. (48,699) -- (48,699) (48,699)
Income tax provision for the three months ended
March 31, 2002 .............................................. (28,153) -- (28,153) (28,153)
--------- --------- ---------
43,758 -- 43,758 43,758
Foreign currency translation loss for the three months
ended March 31, 2002 ........................................ -- (25,170) (25,170) (25,170)
--------- --------- --------- ---------
Accumulated other comprehensive loss at end of period ............. $(139,619) $ (68,367) $(207,986) --
========= ========= =========
Comprehensive loss ................................................ $ (55,679)
=========

-15-

Accumulated Other Comprehensive Loss
at March 31, 2001
------------------------------------- Comprehensive
Foreign Income for the Three
Cash Flow Currency Months Ended
Hedges Translation Total March 31, 2001
--------- ----------- --------- ------------------

Net income......................................................... $ 119,663
Accumulated other comprehensive loss at beginning of period........ $ -- $ (23,085) $ (23,085) --
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges before
reclassification adjustment during the three months
ended March 31, 2001......................................... (69,134) -- (69,134) (69,134)
Reclassification adjustment for gain included in net
income for the three months ended March 31, 2001............. (17,047) -- (17,047) (17,047)
Income tax benefit for the three months ended
March 31, 2001............................................... 32,611 -- 32,611 32,611
--------- --------- ---------
(53,570) -- (53,570) (53,570)
Foreign currency translation gain for the three months
ended March 31, 2001......................................... -- 14,694 14,694 14,694
--------- --------- --------- ---------
Accumulated other comprehensive loss at end of period.............. $ (53,570) $ (8,391) $ (61,961) --
========= ========= =========
Comprehensive income .............................................. $ 80,787
=========

9. Customers

Enron

During 2001, the Company, primarily through its CES subsidiary, transacted
a significant volume of business with units of Enron Corp. ("Enron"), mainly
Enron Power Marketing, Inc. ("EPMI") and Enron North America Corp. ("ENA"). ENA
is the parent corporation of EPMI. Enron is the direct parent corporation of
ENA. Most of these transactions were contracts for sales and purchases of power
and gas for hedging purposes, some of which extended out as far as 2009. On
December 2, 2001, Enron Corp. and certain of its subsidiaries filed voluntary
petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court for the
Southern District of New York. EPMI and ENA are among the subsidiaries of Enron
that filed for reorganization on December 2, 2001.

The Company conducted a limited amount of business with EPMI and ENA during
December of 2001 on a collateralized or prepaid basis and has conducted no
business with EPMI or ENA since December 31, 2001. The following table sets
forth information regarding the Company's settled physical transactions and
non-hedging mark-to-market gains with Enron for the three months ended March 31,
2002 and 2001, (in thousands of dollars and thousands of MWh's, in the case of
electricity transactions, and thousands of MMBtu's, in the case of oil and gas
transactions):

For the Three Months Ended For the Three Months Ended
March 31, 2002 March 31, 2001
-------------------------- --------------------------
Dollar Volume Dollar Volume
--------- ------ --------- ------

Electric generation and marketing revenue (electricity and
steam revenue and sales of purchased power) ................... $ -- -- $ 84,175 1,293
Oil and gas production and marketing revenue (sales of
purchased gas) ................................................ -- -- 53,290 4,719
Other revenue .................................................. -- -- 1,348 --
------- ---------
Total power and fuel and other revenue from Enron .............. $ -- $ 138,813
------- ---------
Electric generation and marketing expense (Purchased power
expense) ...................................................... $ -- -- $ 110,886 1,283
Fuel expense (cost of oil and natural gas burned by power
plants and natural gas derivative mark-to-market gain) ........ -- -- 16,930 2,417
------- ---------
Total CES power and fuel expenses related to Enron (1) ......... $ -- $ 127,816
======= =========

__________

(1) Expenses of CES only, as other Enron expenses incurred are not material.

-16-

The Company has terminated all of its open forward positions with ENA and
EPMI as of March 31, 2002, and will settle with ENA and EPMI based on the value
of the terminated contracts at the termination or replacement date, as
applicable. Accordingly, all amounts associated with terminated ENA and EPMI
forward contracts have been included within the Company's accounts payable. As
of March 31, 2002, unrealized pre-tax losses on derivatives designated as
effective cash flow hedges recorded in OCI associated with terminated ENA and
EPMI contracts were $161.6 million. These amounts will be recognized in future
earnings as the original hedged forecasted transactions occur.

The sales to and purchases from various Enron subsidiaries were mostly for
hedging, balancing and optimization transactions, and in most cases the
purchases and sales are not related and should not be netted to try to gauge the
profitability of transactions with Enron subsidiaries.

On November 14, 2001, CES, ENA and EPMI entered into a Master Netting,
Setoff and Security Agreement (the "Netting Agreement"). The Netting Agreement
permits CES, on the one hand, and ENA and EPMI, on the other hand, to set off
amounts owed to each other under an ISDA Master Agreement between CES and ENA,
an Enfolio Master Firm Purchase/Sale Agreement between CES and ENA and a Master
Energy Purchase/Sale Agreement between CES and EPMI (in each case, after giving
effect to the netting provisions contained in each of these agreements). Based
on legal analysis of the Netting Agreement, the Company believes it has no net
collection exposure to Enron. Following are the accounts receivable and accounts
payable balances, presented on both a gross and net basis, with ENA and EPMI at
March 31, 2002 (in millions):

Receivables/Payables
--------------------
Gross Gross Net Receivable
Receivable Payable (Payable)
---------- ---------- --------------

Enron North America ........... $ 1,125.6 $ (1,404.7) $ (279.1)
Enron Power Marketing ......... 836.7 (701.1) 135.6
---------- ---------- --------
Total ....................... $ 1,962.3 $ (2,105.8) $ (143.5)
========== ========== ========

After netting the receivables and payables from ENA and EPMI, the Company
has an existing or future obligation of $143.5 million as of March 31, 2002,
which obligation will be offset by CES' losses, damages, attorneys' fees and
other expenses arising from the default by Enron.

Although the Company had no net collection exposure to ENA and EPMI at
March 31, 2002, the Company established a $13.1 million reserve in December 2001
related to unrealized mark to market gains generated by Enron's insolvency,
which caused earnings recognition for contracts that had previously been
exempted from SFAS No. 133 accounting and which caused cash flow hedges to cease
to be effective and marked-to-market in earnings until termination.

The Company's treasury department includes a credit group focused on
monitoring and managing counterparty risk. The credit group monitors the net
exposure with each counterparty on a daily basis. The analysis is performed on a
mark-to-market basis using the forward curves audited by the Company's Risk
Controls group. The net exposure is compared against a counterparty credit risk
threshold which is determined based on the counterparty's credit ratings,
evaluation of the financial statements and bond values. The credit department
monitors these thresholds to determine the need for additional collateral or an
adjustment to activity with the counterparty.

Nevada Power and Sierra Pacific Resources

During the first quarter of 2002, two subsidiaries of Sierra Pacific
Resources Corporation, Nevada Power Company ("NPC") and Sierra Pacific Resources
("SPR"), received credit downgrades to sub-investment grades from the major
credit rating agencies. The credit downgrades resulted from short-term liquidity
problems created when the Public Utilities Commission of Nevada disallowed a
rate adjustment requested by NPC to cover the increased cost of buying power
during the 2001 energy crisis. NPC and SPR have requested that their power
suppliers extend payment terms to help them overcome their short-term liquidity
problems. As of March 31, 2002, the Company had net collection exposures of
approximately $30.7 million and $21.3 million with NPC and SPR, respectively.
The Company's exposures include open forward power position contracts that are
reported at fair value in the Company's balance sheet as well as receivable and
payable balances relating to settled power deliveries. Management is continuing
to monitor the exposure and its effect on the Company's financial condition. The
table below details the components of the Company's exposure position at March
31, 2002 (in millions of dollars). The positive net positions represent
realization exposure while the negative net positions represent the Company's
existing or potential obligations.

-17-

Receivables/Payables Fair Values
-------------------------------- --------------------------------
Net Gross Gross Net Open
Gross Gross Receivable Fair Fair Positions
Receivable Payable (Payable) Value(+) Value(-) Value Total
---------- ------- ---------- -------- -------- --------- ------

Nevada Power Company ................... $ 3.5 $ (4.6) $ (1.1) $ 91.0 $ (59.2) $ 31.8 $ 30.7
Sierra Pacific Resources ............... 1.0 -- 1.0 20.3 -- 20.3 21.3
----- ------ ------ ------- ------- ------ ------
Total ................................ $ 4.5 $ (4.6) $ (0.1) $ 111.3 $ (59.2) $ 52.1 $ 52.0
===== ====== ====== ======= ======= ====== ======

Under the terms of its contracts with NPC and SPPC, the Company believes
that it has the right to offset asset and liability positions.

10. Earnings (loss) per Share

Basic earnings (loss) per common share were computed by dividing net income
(loss) by the weighted average number of common shares outstanding for the
period. The dilutive effect of the potential exercise of outstanding options to
purchase shares of common stock is calculated using the treasury stock method.
The dilutive effect of the assumed conversion of certain convertible securities
into the Company's common stock is based on the dilutive common share
equivalents and the after tax distribution expense avoided upon conversion. The
reconciliation of basic earnings (loss) per common share to diluted earnings
(loss) per share is shown in the following table (in thousands except per share
data).

PERIODS ENDED MARCH 31,
-----------------------------------------------------------------
2002 2001
------------------------------- ------------------------------
NET NET
INCOME INCOME
(LOSS) SHARES EPS (LOSS) SHARES EPS
-------- ------- ------ -------- ------- --------

THREE MONTHS:
Basic earnings (loss) per common share:
Income (loss) before extraordinary gain and cumulative
effect of a change in accounting principle .................... $(76,397) 307,332 $(0.25) $118,627 300,554 $ 0.39
Extraordinary gain, net of tax .................................. 2,130 -- 0.01 -- -- --
Cumulative effect of a change in accounting principle,
net of tax .................................................... -- -- -- 1,036 -- 0.01
-------- ------- ------ -------- ------- --------
Net income (loss) ............................................... $(74,267) 307,332 $(0.24) $119,663 300,554 $ 0.40
-------- ------- ------ -------- ------- --------
Diluted earnings (loss) per common share:
Common shares issuable upon exercise of stock options
using treasury stock method ................................... -- 16,278
------- -------
Income (loss) before dilutive effect of certain convertible
securities, extraordinary gain and cumulative effect
of a change in accounting principle ........................... $(76,397) 307,332 $(0.25) $118,627 316,832 $ 0.37
Dilutive effect of certain convertible securities ............... -- -- -- 9,355 44,882 (0.02)
-------- ------- ------ -------- ------- --------
Income (loss) before extraordinary gain and cumulative
effect of a change in accounting principle .................... (76,397) 307,332 (0.25) 127,982 361,714 0.35
Extraordinary gain, net of tax .................................. 2,130 -- 0.01 -- -- --
Cumulative effect of a change in accounting principle,
net of tax .................................................... -- -- -- 1,036 -- 0.01
-------- ------- ------ -------- ------- --------
Net income (loss) ............................................... $(74,267) 307,332 $ (0.24) $129,018 361,714 $ 0.36
======== ======= ======== ======== ======= ========

The effect of 151,353,196 and 280,849 unexercised employee stock options,
Company-obligated mandatorily redeemable convertible preferred securities of
subsidiary trusts, Zero Coupons and Convertible Notes were not included in the
computation of diluted shares outstanding for the three months ended March 31,
2002 and 2001, because such inclusion would have been antidilutive. Because of
the Company's loss for the three months ended March 31, 2002, basic shares were
used in the calculation of fully diluted loss per share, under the guidelines of
SFAS No. 128, "Earnings per Share," as using the basic shares produced the more
dilutive effect on the loss per share.

-18-

11. Commitments and Contingencies

Capital Expenditures -- On March 12, 2002, the Company announced a new
turbine program that reduces previously forecasted capital spending by
approximately $1.2 billion in 2002 and $1.8 billion in 2003. The revision
includes adjusted timing of turbine delivery and related payment schedules and
also turbine cancellation orders. As a result of the turbine order cancellations
and the cancellation of certain other equipment, the Company recorded a pre-tax
charge of $168.5 million in the first quarter of 2002, based primarily on
forfeited prepayments to date and an immaterial cash payment pursuant to
contract terms.

Litigation --

Calpine Corporation v. Automated Credit Exchange ("ACE"). On March 5, 2002,
Calpine sued ACE in the Superior Court of the State of California for the County
of Alameda for negligence and breach of contract to recover reclaim trading
credits, a form of emission reduction credits that should have been held in
Calpine's account with U.S. Trust Company (US Trust). ACE is a broker in
emission reduction credits based in Pasadena, California. Calpine had paid ACE
for Nitrogen oxide (NOx) coastal credits that were to be purchased by ACE and
held by US Trust. The credits were to be held by US Trust pursuant to a Credit
Holding Agreement, which provided, among other things, that US Trust was to hold
the credits until receiving instructions from ACE to disburse the credits. ACE
had agreed that (i) upon prior written instruction from Calpine, to instruct US
Trust to take such actions as may be directed by Calpine to disburse the credits
held in escrow pursuant to the Credit Holding Agreement and (ii) not to take any
action, or otherwise instruct US Trust to take any action, concerning the
credits held in escrow pursuant to the Credit Holding Agreement without prior
written instruction from Calpine. Calpine and ACE entered into a settlement
agreement that resolved all issues on March 29, 2002. The settlement provided
for a partial recovery of $7 million and for the rights to the emission
reduction credits to be held by ACE. The Company expects to recognize the $7
million in the second quarter of 2002, after all realization uncertainties are
cleared. In accordance with the settlement agreement, Calpine has dismissed its
complaint against ACE.

Ben Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder
filed a derivative lawsuit on behalf of Calpine against its directors and one of
its senior officers. This lawsuit is styled Johnson vs. Cartwright, et al. (No.
CV803872), and is pending in the California Superior Court, Santa Clara County.
Calpine is a nominal defendant in this lawsuit, which alleges claims relating to
purportedly misleading statements about Calpine and stock sales by certain of
the director defendants and the officer defendant. Calpine has filed a demurrer
asking the court to dismiss the complaint on the ground that the shareholder
plaintiff lacks standing to pursue claims on behalf of Calpine. The individual
defendants have filed a demurrer asking the court to dismiss the complaint on
the ground that it fails to state any claims against them.

Securities Class Action Lawsuits. Since March 11, 2002, fourteen
shareholder lawsuits have been filed against Calpine and certain of its officers
in the United States District Court, Northern District of California. The
actions captioned Weisz vs. Calpine Corp., et al., filed March 11, 2002, and
Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002 are
purported class actions on behalf of purchasers of Calpine stock between March
15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18,
2002 is a purported class action on behalf of purchasers of Calpine stock
between February 6, 2001 and December 13, 2001. The eleven other actions,
captioned Local 144 Nursing Home Pension Fund vs. Calpine Corp., Lukowski vs.
Calpine Corp., Hart vs. Calpine Corp., Atchison vs. Calpine Corp. and Laborers
Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp.
Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp, and
Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The
complaints in these eleven actions are virtually identical--they were filed by
three law firms, in conjunction with other law firms as co-counsel. All eleven
lawsuits are purported class actions on behalf of purchasers of Calpine's
securities between January 5, 2001 and December 13, 2001.

The complaints in these fourteen actions allege that, during the purported
class periods, certain senior executives issued false and misleading statements
about Calpine's financial condition in violation of Sections 10(b) and 20(1) of
the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek
an unspecified amount of damages, in addition to other forms of relief. We
expect that these actions, as well as any related actions that may be filed in
the future, will be consolidated by the court into a single securities class
action. We consider the lawsuits to be without merit, and we intend to defend
vigorously against these allegations.

-19-

contracts entered into between CES and DWR are subject to the complaint (see,
Risk Factors - California Long-Term Supply Agreements). As part of Calpine's
successful renegotiation of its long-term power contracts with DWR announced on
April 22, 2002, the Office of the Governor, the CPUC, the EOB and the California
Attorney General ("AG") agreed to settle this action and drop all challenges to
Calpine's long-term contracts with DWR. On May 2, 2002 each of the CPUC, the
EOB, and the AG filed a Notice of Partial Withdrawal with Prejudice of Complaint
as to Calpine Energy Services, L.P. with the FERC. Pursuant to its respective
notice each of the CPUC and the EOB withdrew all of their respective claims
against CES which had been alleged in the above-for-mentioned complaints
(EL02-60-000 and ELO2-62-000) concerning the justness and reasonableness of the
terms under the long-term contracts with DWR. In addition, pursuant to its
notice, the AG withdrew all claims as to CES in its complaint (EL02-71-000)
wherein it had alleged that public utility sellers of energy and ancillary
services to DWR and into markets operated by the California Independent System
Operator and the California Power Exchange were not in compliance with their
disclosure obligations under Section 205 of the Federal Power Act.

The Company is involved in various other claims and legal actions arising
out of the normal course of business. The Company does not expect that the
outcome of these proceedings will have a material adverse effect on the
Company's financial position or results of operations.

12. Operating Segments

The Company's primary operating segments are electric generation and
marketing; oil and gas production and marketing; and corporate activities and
other. Electric generation and marketing includes the development, acquisition,
ownership and operation of power production facilities, the sale of electricity
and steam and electricity hedging and related activity. Oil and gas production
and marketing includes the ownership and operation of gas fields, gathering
systems and gas pipelines for internal gas consumption, third party sales and
oil and gas hedging and related activity. Corporate activities and other
consists primarily of financing activities, general and administrative costs and
consolidating eliminations. Certain costs related to company-wide functions are
allocated to each segment. However, interest on corporate debt is maintained at
corporate and is not allocated to the segments. Due to the integrated nature of
the business segments, estimates and judgments have been made in allocating
certain revenue and expense items. The Company evaluates performance of these
operating segments based upon several criteria including profits before tax.

ELECTRIC OIL AND GAS
GENERATION PRODUCTION CORPORATE, OTHER
AND MARKETING AND MARKETING AND ELIMINATIONS TOTAL
----------------------- ------------------- -------------------- -----------------------
2002 2001 2002 2001 2002 2001 2002 2001
---------- ---------- -------- -------- -------- -------- ---------- ----------
(in thousands)

For the three months ended
March 31, 2002 and 2001:
Revenue......................... $1,534,143 $1,050,629 $236,348 $331,828 $(32,144) $(42,706) $1,738,347 $1,339,751
Income before taxes and
extraordinary charge.......... (46,186) 127,791 13,064 116,535 (84,412) (36,718) (117,534) 207,608
Merger expense.................. -- -- -- 6,021 -- -- -- 6,021
Equipment cancellation cost..... 168,471 -- -- -- -- -- 168,471 --

ELECTRIC OIL AND GAS
GENERATION PRODUCTION CORPORATE, OTHER
AND MARKETING AND MARKETING AND ELIMINATIONS TOTAL
------------- ------------- ---------------- -----------
(in thousands)

Total assets:
March 31, 2002.................. $14,010,815 $3,714,004 $2,918,716 $20,643,535
December 31, 2001............... $12,572,848 $3,503,075 $5,253,629 $21,329,552

For the three months ended March 31, 2002 and 2001, there were intersegment
revenues of approximately $36.7 million and $46.0 million, respectively. The
elimination of these intersegment revenues, which primarily relate to the use of
internally procured gas for the Company's power plants, are included in the
Corporate and Other reporting segment.

13. California Power Market

On February 25, 2002, both the CPUC and the EOB filed complaints under
Section 206 of the Federal Power Act with FERC (EL02-60-000 and EL02-62-000,
respectively) alleging that the prices and terms of the long-term contracts with
DWR are unjust and unreasonable and counter to the public interest. Calpine was
a respondent and the four long-term contracts entered into by Calpine were
subject to the complaint.

-20-

On March 6, 2002, in accordance with the state legislation that authorized
DWR to enter into the long-term power contracts, the CPUC issued a Rate
Agreement, which dedicates a portion of the retail rate paid by electricity
customers of the California investor-owned utilities to a fund to pay
bondholders of bonds to be issued by DWR and to a fund to pay electricity
suppliers such as Calpine. The proceeds from those bonds will be used in part to
fund the Electric Power Fund established by the state legislation authorizing
DWR to enter into long-term power contracts with the power suppliers whose
recourse in the event of a default by DWR is to the Electric Power Fund.
Proceeds from the bonds will also be used to repay the state of California
General Fund. The bonds have not been issued, but representatives of the State
have indicated that the bonds should be issued in the near future.

FERC Investigation into California Wholesale Markets -- On February 13,
2002, FERC initiated an investigation of potential manipulation of electric and
natural gas prices in the western United States. This investigation was
initiated as a result of allegations that Enron Corp. through its affiliates
used its market position to distort electric and natural gas markets in the
West. The scope of the investigation is to consider whether as a result of any
manipulation in the short-term markets for electric energy or natural gas or
other undue influence on the wholesale markets by any party since January 1,
2000, the rates of the long-term contracts subsequently entered into in the West
are potentially unjust and unreasonable. In connection with its investigation,
FERC has, and may in the future, issue data requests seeking information
regarding trading practices in California and the western electricity markets.
FERC has stated that it may use the information gathered in connection with the
investigation to determine how to proceed on any existing or future complaint
brought under Section 206 of the Federal Power Act involving long-term power
contracts entered into in the West since January 1, 2000, or to initiate a
Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding on its own
initiative.

14. Subsequent Events

On April 22, 2002, the Company announced that it had renegotiated CES'
long-term power contracts with the DWR. The Office of the Governor, the CPUC,
the EOB and the AG have endorsed the renegotiated contracts and have agreed to
drop all pending claims against the Company and its affiliates, including
withdrawing the complaint under Section 206 of the Federal Power Act recently
filed by the CPUC and EOB with FERC and the CPUC and the EOB have agreed to
terminate their efforts to seek refunds from the Company and its affiliates
through FERC refund proceedings. In connection with the renegotiation, the
Company has agreed to pay $6 million over three years to the AG to resolve any
and all possible claims against the Company and its affiliates brought by the
AG.

The renegotiation includes the shortening of the duration of the two
ten-year, baseload energy contracts by two years and of the 20-year peaker
contract by ten years. These changes reduce DWR's long-term purchase
obligations. In addition, CES agreed to reduce the energy price on one baseload
contract from $61.00 to $59.60 per megawatt-hour, and to convert the energy
portion of the peaker contract to gas index pricing from fixed energy pricing.
CES has also agreed to deliver up to 12.2 million megawatt-hours of additional
energy pursuant to the baseload energy contracts in 2002 and 2003. In connection
with the renegotiation, CES has also agreed with DWR that DWR will have the
right to assume and complete four of our projects currently planned for
California and in the advanced development stage if the Company does not meet
certain milestones with respect to each project assumed, provided that DWR
reimburses the Company for all construction costs and certain other costs
incurred by the Company to the date DWR assumes the relevant project.

The negotiation resolved the dispute with DWR concerning payment of the
capacity payment on the 495-megawatt peaking contract dated February 28, 2001.
The contract provides that through December 31, 2002, CES may earn a capacity
payment by committing to supply electricity to DWR from a source other than the
peaker units designated in the contract. DWR made certain assertions challenging
CES' right to substitute units or provide replacement energy and had withheld
capacity payments in the amount of approximately $15.0 million since December
2001. As part of the renegotiation, the Company has received payment in full on
these withheld capacity payments and will have the right to provide replacement
capacity through December 31, 2002, based on the original contract terms. On May
2, 2002, each of the CPUC and the EOB filed a Notice of Partial Withdrawal with
Prejudice of Complaint as to Calpine Energy Services, L.P. with the FERC in the
EL02-60-000 and EL02-62-000 dockets, respectively.

In April 2002 the Company entered into letters of intent for Wisconsin
Public Service to purchase its 180-megawatt De Pere Energy Center and for
Wisconsin Public Service to enter into a power purchase agreement for up to 235
megawatts of capacity and energy for 10 years from Calpine's Sherry Energy
Center located near Marshfield, Wisconsin. Wisconsin Public Service will pay
Calpine $120 million for the De Pere facility and termination of the existing
power purchase agreement. The cost of the capacity purchases from the Sherry
Energy Center will be approximately $250 million over the 10-year period.
Wisconsin Public Service will be responsible for supplying the fuel to produce
the energy it receives from the Sherry Energy Center.

-21-

On April 30, 2002, the Company completed a public offering of common stock
of 66 million shares and priced the offering at $11.50 per share. The proceeds
from the offering, after underwriting fees, were $734.3 million. Calpine has
granted the underwriters an over-allotment option for an additional 9.9 million
shares of its common stock, which may be exercised for up to 30 days. As of the
date of this report, this option had not been exercised. Management cannot
predict whether the underwriters will exercise this option in whole or in part.

On April 30, 2002, the Company repurchased the remaining $685.5 million of
Zero Coupons at par pursuant to a scheduled put provided for by the terms of the
securities.

Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.

In addition to historical information, this report contains forward-looking
statements. Such statements include those concerning Calpine Corporation's ("the
Company's") expected financial performance and its strategic and operational
plans, as well as all assumptions, expectations, predictions, intentions or
beliefs about future events. You are cautioned that any such forward-looking
statements are not guarantees of future performance and involve a number of
risks and uncertainties that could cause actual results to differ materially
from the forward-looking statements such as, but not limited to, (i)
unseasonable weather patterns that reduce demand for power and natural gas, (ii)
systemic economic slowdowns, which can adversely affect consumption of power by
businesses and consumers, (iii) the timing and extent of deregulation of energy
markets and the rules and regulations adopted on a transitional basis with
respect thereto, (iv) the timing and extent of changes in commodity prices and
derivative values for energy, particularly natural gas and electricity, (v)
commercial operations of new plants that may be delayed or prevented because of
various development and construction risks, such as a failure to obtain
financing and the necessary permits to operate or the failure of third-party
contractors to perform their contractual obligations, (vi) cost estimates are
preliminary and actual costs may be higher than estimated, (vii) a competitor's
development of a lower-cost gas-fired power plant, (viii) risks associated with
marketing and selling power from power plants in the newly-competitive energy
market, or (ix) the successful exploitation of an oil or gas resource that
ultimately depends upon the geology of the resource, the total amount and cost
to develop recoverable reserves, and operational factors relating to the
extraction of natural gas. All information set forth in this filing is as of May
15, 2002, and Calpine undertakes no duty to update this information. Readers
should carefully review the "Risk Factors" section in documents filed with the
Securities and Exchange Commission.

Selected Operating Information

Set forth below is certain selected operating information for our power
plants and steam fields, for which results are consolidated in our statements of
operations. Results vary for the three months ended March 31, 2002, as compared
to the same period in 2001, primarily due to the consolidation of acquisitions
and increased production as a result of acquired plants and bringing new plants
under construction on line. Electricity revenue is composed of fixed capacity
payments, which are not related to production, and variable energy payments,
which are related to production. Capacity revenue includes, besides traditional
capacity payments, other revenues such as reliability must run and ancillary
service revenues. The information set forth under thermal and other revenue
consists of host thermal sales and other revenue (revenues in thousands).

Three months ended March 31,
(in thousands, except ----------------------------
production and pricing data) 2002 2001
----------- ----------

Power Plants:
Electricity and steam ("E&S") revenues:
Energy ............................................. $ 513,103 $ 435,382
Capacity ........................................... 75,391 117,727
Thermal and other .................................. 31,685 42,050
----------- ----------
Subtotal ........................................... $ 620,179 $ 595,159
Spread on sales of purchased power (1) ............... 93,139 (1,348)
----------- ----------
Adjusted E&S revenues ................................ $ 713,318 $ 593,811
Megawatt hours produced .............................. 14,714,000 7,239,000
All-in electricity price per megawatt hour generated . $ 48.48 $ 82.03

_________

(1) From hedging, balancing and optimization activities related to our
generating assets. The spread on trading activities is excluded.

-22-

Megawatt hours produced at the power plants increased 103.3% for the three
months ended March 31, 2002 as compared to the same period in 2001. This was
primarily due to the addition of power plants that were either acquired or
commenced commercial operation subsequent to March 31, 2001. Lower average
market prices caused the all-in electricity price per megawatt hour generated to
decrease between periods.

Results of Operations

Set forth below is a table summarizing the dollar amounts and percentages
of our total revenue for the three months ended March 31, 2002 and 2001 that
represent purchased power and purchased gas sales and the costs we incurred to
purchase the power and gas that we resold during these periods (in thousands,
except for percentage data):

THREE MONTHS ENDED
MARCH 31,
-----------------------------
2002 2001
---------- -----------

Total revenue .............................. $1,738,347 $1,339,751
Sales of purchased power ................... 908,301 453,602
As a percentage of total revenue ........... 52.3% 33.9%
Sale of purchased gas ...................... 132,158 129,172
As a percentage of total revenue ........... 7.6% 9.6%
Total cost of revenue ("COR") .............. 1,560,383 1,064,183
Purchased power expense .................... 815,005 456,266
As a percentage of total COR ............... 52.2% 42.9%
Purchased gas expense ...................... 123,694 118,628
As a percentage of total COR ............... 7.9% 11.1%

The accounting requirements under Staff Accounting Bulletin ("SAB") 101,
"Revenue Recognition in Financial Statements" and EITF 99-19, "Reporting Revenue
Gross as a Principal versus Net as an Agent" require us to show most of our
hedging contracts on a gross basis (as opposed to netting sales and cost of
revenue). The primary reason for the significant increase in these sales and
cost of revenue in 2002 as compared with 2001 is the growth of our generation
activity in 2002 as compared with 2001 and the corresponding increase in
hedging, balancing, optimization, and trading activities.

Rules in effect throughout 2002 and 2001 associated with the NEPOOL market
in New England require that all power generated in NEPOOL be sold directly to
the Independent System Operator ("ISO") in that market; we then buy from the ISO
to serve our customer contracts. Generally accepted accounting principles in the
United States of America require us to account for this activity, which applies
to three of our merchant generating facilities, as the aggregate of two distinct
sales and one purchase. This gross basis presentation increases revenues but not
gross profit. The table below details the financial extent of our transactions
with NEPOOL for the period indicated. The decrease in 2002 is primarily due to
lower prices in 2002, partially offset by increased volume.

THREE MONTHS ENDED
MARCH 31,
------------------
(in thousands) 2002 2001
------- -------

Sales into NEPOOL ISO from power we generated ............ $50,581 $59,564
Sales into NEPOOL ISO from hedging and other activity .... 24,657 34,956
------- -------
Total sales into NEPOOL ................................ $75,238 $94,520

Total purchases from NEPOOL ISO .......................... $75,834 $85,243

Three Months Ended March 31, 2002, Compared to Three Months Ended March 31,
2001.

Revenue -- Total revenue increased to $1,738.3 million for the three months
ended March 31, 2002, compared to $1,339.8 million for the same period in 2001.

Electric generation and marketing revenue increased to $1,532.6 million in
2002 compared to $1,050.1 million in 2001. Sales of purchased power grew by
$454.7 million due to increased price hedging, balancing, optimization and
trading activity as a result of the growth of our subsidiary, Calpine Energy
Services, LP ("CES") and our operating plant portfolio during the three months
ended March 31, 2002. Approximately $25.0 million of the $482.5 million variance
was due to electricity and steam sales, which increased due to our growing
portfolio. Generation more than doubled but pricing dropped almost by half to
moderate revenue growth. Our revenue for the period ended March 31, 2002,
includes the consolidated results of additional facilities that we acquired or

-23-

completed construction on subsequent to March 31, 2001. We also recognized a
$2.9 million increase in mark-to-market gains on power derivatives to $4.2
million in 2002.

Oil and gas production and marketing revenue decreased to $199.6 million in
2002 compared to $285.9 million in 2001. The decrease is primarily due to an
$89.2 million decrease in oil and gas sales to third parties because of much
lower average pricing in 2002.

Cost of revenue -- Cost of revenue increased to $1,560.4 million in 2002
compared to $1,064.2 million in 2001. Approximately $358.7 million of the $496.2
million increase relates to the cost of power purchased by our energy services
organization due to increased price hedging, balancing, optimization and trading
activities. Fuel expense increased 29.5%, from $257.0 million in 2001 to $332.8
million in 2002, due to a doubling of megawatt hours generated as offset by
significantly lower gas prices in 2002. Plant operating expense increased by
36.3% from $84.5 million to $115.2 million but, expressed per mwh of generation,
decreased from $11.67/mwh to $7.83/mwh as economies of scale are being realized
due to the increase in the average size of our plants. Depreciation, depletion
and amortization expense increased by 44.3%, from $72.0 million to $103.9
million, due primarily to additional power facilities in consolidated operations
at March 31, 2002, as compared to the same period in 2001.

Project development expense -- Project development expense decreased 28.4%
as a result of a deceleration of our efforts in identifying new development
opportunities due to overall market and liquidity issues.

Equipment cancellation cost -- The pre-tax equipment cancellation charge of
$168.5 million in the three months ended March 31, 2002 was as a result of the
turbine order cancellations and the cancellation of certain other equipment
based primarily on forfeited prepayments to date and an immaterial cash payment
pursuant to contract terms.

General and administrative expense -- General and administrative expense
increased 67.0% to $60.3 million for the three months ended March 31, 2002, as
compared to $36.1 million for the same period in 2001. The increase was
attributable to continued growth in personnel and associated overhead costs
necessary to support the overall growth in our operations and due to recent
acquisitions, including power facilities and natural gas operations. General and
administrative expense expressed per mwh of generation decreased to $4.10/mwh in
2002 from $4.98/mwh in 2001.

Interest expense -- Interest expense increased 208.0% to $61.3 million for
the three months ended March 31, 2002, from $19.9 million for the same period in
2001. Interest expense increased primarily due to the issuance of the
Convertible Notes and additional senior notes in 2001. The associated
incremental interest expense was partially offset by interest capitalized in
connection with our growing construction portfolio. Interest capitalized
increased from $104.0 million in the three months ended 2001 to $163.1 million
in the three months ended 2002.

Interest income -- Interest income decreased to $12.2 million for the three
months ended March 31, 2002, compared to $19.4 million for the same period in
2001. This decrease is due to lower interest rates in 2002.

Other income (expense) -- Other income (expense) increased to $9.1 million
in 2002 from $5.7 million in 2001 primarily due to the $9.7 million gain on the
sale of our 11.4% interest in the Lockport Power Plant.

Provision for income taxes -- The effective income tax rate was
approximately 35.0% and 42.9% for the three months ended March 31, 2002 and
2001, respectively. The decrease in rates was due to our expansion into Canada
and the United Kingdom and our cross border financings, which reduced our
effective blended tax rates. The 35% rate in 2002 was the same as the full year
rate for 2001.

Extraordinary charge, net -- The $2.1 million charge in 2002 (net of tax of
$1.4 million) represents the repurchase of $192.5 million aggregate principal
amount of our Zero Coupon Convertible Debentures Due 2021 ("Zero Coupons"),
which was comprised primarily of a $4.8 million gain from the repurchase of the
Zero Coupons at a discount, partially offset by a loss due to the write-off of
unamortized deferred financing costs.

Selected Balance Sheet Information

Unconsolidated Investments in Power Projects -- Although our preference is
to own 100% of the power plants we acquire or develop, there are situations when
we take less than 100% ownership. Reasons why we may take less than a 100%
interest in a power plant may include, but are not limited to: (a) our
acquisitions of other IPP's such as Cogeneration Corporation of America in 1999
and SkyGen Energy LLC in 2000 in which minority interest projects were included
in the portfolio of assets owned by the acquired entities (Grays Ferry Power
Plant (40% now owned by Calpine) and Androscoggin Energy Center (32.3% now owned
by Calpine) respectively); (b) opportunities to co-invest with non-regulated
subsidiaries of regulated electric utilities, which under the Public Utility
Regulatory Policies Act of 1978, as amended are restricted to 50% ownership of
cogeneration qualifying facilities -- such as our investment in Gordonsville

-24-

Power Plant (50% owned by Calpine and 50% owned by Edison Mission Energy, which
is wholly-owned by Edison International Company); and (c) opportunities to
invest in merchant power projects with partners who bring marketing, funding,
permitting or other resources that add value to a project. An example of this is
Acadia Energy Center, which is under construction in Louisiana (50% owned by
Calpine and 50% owned by Cleco Midstream Resources, an affiliate of Cleco
Corporation). None of our equity investment projects have nominal carrying
values as a result of material recurring losses. Further, there is no history of
impairment in any of these investments.

Accumulated other comprehensive loss -- Accumulated other comprehensive
loss at March 31, 2002 decreased from $(226.6) million at December 31, 2001 to
$(208.0) million at March 31, 2002. The change resulted from unrealized gains on
derivatives designated as cash flow hedges of $43.8 million, net of amounts
reclassified to net loss and income taxes, and foreign currency translation
losses of $25.2 million. See Note 8 for further information.

Liquidity and Capital Resources

General -- The latter half of 2001, and particularly the fourth quarter,
saw a significant contraction in the availability of capital for participants in
the energy sector. This was due to a range of factors, including uncertainty
arising from the collapse of Enron. While we have continued to be able to access
the capital and bank credit markets, as discussed below, we recognize that terms
of available financing in the future may not be attractive to us. To protect
against this possibility, we have scaled back our capital expenditure program
for 2002 and 2003 to enable us to conserve our available capital resources, but
remain ready to access the capital markets as attractive opportunities arise.

To date, we have obtained cash from our operations; borrowings under our
credit facilities and other working capital lines; sale of debt, equity, trust
preferred securities and convertible debentures; proceeds from sale/leaseback
transactions and project financing. We have utilized this cash to fund our
operations, service debt obligations, fund acquisitions, develop and construct
power generation facilities, finance capital expenditures, support our hedging,
balancing and optimization activities at CES, and meet our other cash and
liquidity needs. Our business is capital intensive. Our ability to capitalize on
growth opportunities is dependent on the availability of capital on attractive
terms. Our strategy is also to reinvest our cash from operations into our
business development and construction program, rather than to pay cash
dividends.

Cash Flow Activities -- The following table summarizes our cash flow
activities for the periods indicated:

THREE MONTHS ENDED MARCH 31,
----------------------------
(in thousands) 2002 2001
----------- -----------

Beginning cash and cash equivalents ............... $ 1,525,417 $ 596,077
Net cash provided by (used in):
Operating activities ............................ 345,945 35,555
Investing activities ............................ (1,301,613) (898,635)
Financing activities ............................ (158,486) 1,137,082
Effect of exchange rates changes
on cash and cash equivalents................... (491) --
----------- -----------
Net increase (decrease) in cash
and cash equivalents .......................... (1,114,645) 274,002
----------- -----------
Ending cash and cash equivalents .................. $ 410,772 $ 870,079
=========== ===========

Operating activities for the three months ended March 31, 2002 provided net
cash of $345.9 million, compared to $35.6 million for the three months ended
March 31, 2001. The cash provided by operating activities for the three months
ended March 31, 2002 consisted primarily of a $592.2 million decrease in
operating assets, mainly in derivative activity, accounts receivable and other
current assets. The decrease in accounts receivable was primarily due to the
collection from escrow of $222.3 million for the PG&E past due pre-petition
receivables that were sold at a discount to a third party in December 2001. The
decrease in other current assets is primarily due to reducing CES margin
deposits and replacing them with letters of credit. This was offset by a $421.2
million decrease in operating liabilities, primarily related to derivative
activity.

Investing activities for the three months ended March 31, 2002 consumed net
cash of $1.3 billion, primarily due to $1.3 billion for construction costs and
capital expenditures including gas turbine generator costs and associated
capitalized interest, $23.1 million of advances to joint ventures including
associated capitalized interest for investments in power projects under
construction, $23.8 million of capitalized project development costs including
associated capitalized interest. This was partially offset by a $16.9 million
decrease in restricted cash and a $12.9 million decrease in notes receivable.

-25-

Financing activities for the three months ended March 31, 2002 consumed
$158.5 million of net cash consisting of $187.7 million for repurchase of Zero
Coupons, $73.7 million for the repayment of notes payable and borrowings under
lines of credit, $92.2 million for repayments of project financing and $31.5
million of additional financing costs. This was partially offset by $100.0
million of proceeds from the issuance of the Convertible Senior Notes Due 2006
pursuant to exercise of the initial purchasers' option and $122.9 million of
proceeds from project financing.

We continue to evaluate current and forecasted cash flow as a basis for
financing operating requirements and capital expenditures. We believe that we
will have sufficient liquidity from cash flow from operations, borrowings
available under the lines of credit, access to the capital markets and working
capital to satisfy all obligations under outstanding indebtedness, to finance
anticipated capital expenditures and to fund working capital requirements for
the next twelve months.

PG&E and Enron Bankruptcies -- As stated above, in January 2002 we received
the cash from escrow related to the December 2001 sale of past due
pre-bankruptcy PG&E receivables to a third party.

As discussed in Note 9 of the Notes to Consolidated Condensed Financial
Statements, there is considerable uncertainty surrounding the Enron bankruptcy.
Regardless of the resolution of the current situation, we believe, based on
legal analysis, that we have no net collection exposure to Enron.

Nevada Power and Sierra Pacific Resources -- During the first quarter of
2002, two subsidiaries of Sierra Pacific Resources Corporation, Nevada Power
Company ("NPC") and Sierra Pacific Resources ("SPR"), received credit downgrades
to sub-investment grades from the major credit rating agencies. The credit
downgrades resulted from short-term liquidity problems created when the Public
Utilities Commission of Nevada disallowed a rate adjustment requested by NPC to
cover the increased cost of buying power during the 2001 energy crisis. NPC and
SPR have requested that their power suppliers extend payment terms to help them
overcome their short-term liquidity problems. As of March 31, 2002, we had net
collection exposures of approximately $30.7 million and $21.3 million with NPC
and SPR, respectively. Our exposures include open forward power position
contracts that are reported at fair value in the Company's balance sheet as well
as receivable and payable balances relating to settled power deliveries. We are
continuing to monitor our exposure and its effect on our financial condition.

CES Margin Deposits and Other Credit Support -- As of March 31, 2002, CES
had $177.2 million in cash on deposit as margin deposits with third parties
related to its business activities and letters of credit outstanding in support
of CES business activities of $365.4 million. As of December 31, 2001, CES had
deposited $345.5 million in cash as margin deposits with third parties related
to its business activities and letters of credit outstanding in support of CES
business activities of $259.4 million. The Company is evaluating various
relationships with potential partners to strengthen its ability to conduct risk
management activities and to support the credit requirements of its trading
activities. While we believe that we have adequate liquidity to support CES'
operations at this time, it is difficult to predict how these various factors
will develop in 2002 and beyond. Therefore, it is difficult to predict the
amount of credit support that the Company may need to provide as part of its
business operations.

Working Capital Position -- At March 31, 2002, working capital, defined as
current assets less current liabilities, was $(582.9) million. This negative
position was primarily the result of the $685.5 million of Zero Coupons, which
were classified as a current liability until repaid in full on April 30, 2002.

Letter of credit facilities -- At March 31, 2002, we had approximately
$776.4 million in letters of credit outstanding under various credit support
facilities, including facilities related to CES risk management activities. The
remainder related to other operational and construction activities. Of the total
letters of credit, $156.0 million was temporary coverage in excess of
requirements due to transitioning certain of the letters of credit under the
$400 million revolver to the new $1.0 billion revolver. At December 31, 2001, we
had $642.5 million in letters of credit outstanding, including facilities
relating to CES risk management activities.

Revised Capital Expenditure Program -- Following a comprehensive review of
our power plant development program, we announced in January 2002 the adoption
of a revised capital expenditure program, which contemplates the completion of
27 power projects (representing 15,200 MW) then under construction. Three of
these facilities achieved full or partial commercial operations as of March 31,
2002. Construction of an additional 34 advanced-stage development projects
(representing 15,100 MW) will be placed on "hot standby" following completion of
advanced development activities pending further review, reducing previously
forecasted 2002 capital spending by as much as $2 billion. Construction of these
advanced stage development projects is expected to proceed when there is an
established market need for additional generating resources at prices that will
allow us to meet our established investment criteria, and when capital is
available to us on attractive terms. However, our entire development and
construction program is flexible and subject to continuing review and revision
based upon such criteria.

-26-

On March 12, 2002, we announced a new turbine program that reduces
previously forecasted capital spending by approximately $1.2 billion in 2002 and
$1.8 billion in 2003. The revision includes adjusted timing of turbine delivery
and related payment schedules and also cancellation orders. As a result of these
turbine cancellations and other equipment cancellations, we recorded a pre-tax
charge of $168.5 million in the first quarter of 2002.

Capital Availability -- Notwithstanding recent uncertainties in the
domestic energy and capital markets, we have continued to raise substantial
capital. In the first quarter of 2002, we closed a $1.6 billion secured working
capital credit facility (see below for more information). We also issued in
separate closings in December 2001 and January 2002 $1.2 billion in aggregate
principal amount of Convertible Senior Notes due 2006. Proceeds from this
offering and cash from general working capital were used to fully retire the
Zero Coupons that remained outstanding at December 31, 2001. On April 30, 2002,
we completed a public offering of common stock of 66 million shares and priced
the offering at $11.50 per share. The proceeds after underwriting fees totaled
$734.3 million. We granted the underwriters an over-allotment option for an
additional 9.9 million shares of our common stock, which may be exercised for up
to 30 days. As of the date of this report, this option had not been exercised.
Management cannot predict whether the underwriters will exercise this option in
whole or in part. The proceeds from the offering are expected to be used to
repay debt and for general corporate purposes.

In March 2002, we entered into a letter of intent with ING Bank on the debt
portion of a proposed California peaker sale/leaseback, including 11 California
peaker facilities. This transaction is expected to generate $500 million of cash
that will be received throughout 2002 as the power facilities enter commercial
operation.

New Working Capital Credit Agreement -- In March 2002, the Company closed a
new secured credit agreement comprised of (a) a $1.0 billion revolving credit
facility expiring on May 24, 2003 and (b) a two-year term loan facility for up
to $600 million, which as previously reported, was only to be made available to
the Company upon satisfaction of certain conditions to borrowing on or before
June 8, 2002. On May 10, 2002, the Company borrowed $500 million of the term
loan facility and, subject to certain conditions, may borrow the remaining $100
million in one or two remaining tranches on or before June 8, 2002. At the March
2002 closing, the Company also amended its existing $400 million revolving
credit agreement to provide, among other things, security for borrowings under
that agreement. The security for the revolving and term loan facilities as
originally provided included (a) a pledge of the capital stock of the Company's
subsidiary holding, directly or indirectly, (i) the interests in its natural gas
properties, (ii) the Saltend power plant located in the United Kingdom and (iii)
the Company's equity investment in nine U.S. power plants, and (b) a pledge by
certain of the Company's subsidiaries of a total of 65% of the capital stock of
Calpine Canada Energy Ltd. As part of the recent funding of the $500 million
term loan, the Company expanded the security for the revolving credit and term
loan facilities under both the $1.6 billion and the $400 million credit
agreements by pledging to the lenders substantially all of the Company's
remaining first tier domestic subsidiaries (excluding CES).

Credit Considerations -- On March 12, 2002, Fitch downgraded our senior
unsecured debt to BB. On March 25, 2002, Standard & Poor's downgraded our
corporate credit rating from BB+ to BB and our investor unsecured debt from BB+
to B+. Many other issuers in the power generation sector have also been
downgraded by one or more of the ratings agencies during this period. Such
downgrades can have a negative impact on our liquidity by reducing attractive
financing opportunities and increasing the amount of collateral required by
trading counterparties.

Off-Balance Sheet Commitments -- In accordance with SFAS No. 13 and SFAS
No. 98, "Accounting for Leases" our operating leases are not reflected on our
balance sheet. We have also entered into several sale/leaseback transactions.
All counterparties in these transactions are third parties that are unrelated to
Calpine. The sale/leaseback transactions involving Tiverton, Rumford, South
Point, Broad River, and RockGen utilize special-purpose entities formed by the
equity investors with the sole purpose of owning a power generation facility.
Some of the Company's operating leases contain customary restrictions on
dividends, additional debt and further encumbrances similar to those typically
found in project finance instruments. Calpine has no ownership or other interest
in any of these special-purpose entities.

In accordance with APB Opinion No. 18 "The Equity Method of Accounting For
Investments in Common Stock" and FASB Interpretation No. 35, "Criteria for
Applying the Equity Method of Accounting for Investments in Common Stock (An
Interpretation of APB Opinion No. 18)," the debt on the books of our
unconsolidated investments in power projects is not reflected on our balance
sheet. At March 31, 2002, investee debt is approximately $673.0 million. Based
on our pro rata ownership share of each of the investments, our share would be
approximately $248.8 million. However, all such debt is non-recourse to us. For
the Aries Power Plant construction debt, we and Aquila Energy, a wholly owned
subsidiary of Aquila Inc, have provided support arrangements until construction
is completed to cover cost overruns, if any.

-27-

Performance Metrics

In understanding our business, we believe that certain performance metrics
are particularly important. These include:

o Average gross profit margin based on pro forma (non-GAAP) revenue and pro
forma (non-GAAP) cost of revenue. A high percentage of our revenue consists
of CES hedging, balancing, optimization, and trading activity undertaken
primarily to enhance the value of our generating assets (see "Marketing,
Hedging, Optimization, and Trading" subsection of the Business Section of
our 2001 Form 10-K). CES's hedging, balancing, optimization, and trading
activity is primarily accomplished by buying and selling electric power and
buying and selling natural gas or by entering into gas financial
instruments such as exchange-traded swaps or forward contracts. Under SAB
No. 101 and EITF No. 99-19, we must show the purchases and sales of
electricity and gas on a gross basis in our statement of operations when we
act as a principal, take title to the electricity and gas we purchase for
resale, and enjoy the risks and rewards of ownership. This is
notwithstanding the fact that the net gain or loss on certain financial
hedging instruments, such as exchange-traded forward contracts for natural
gas, is shown as a net item in our GAAP financials. Because of the
inflating effect on revenue of much of our hedging, balancing,
optimization, and trading activity, we believe that revenue levels and
trends do not reflect our performance as accurately as gross profit, and
that it is analytically useful to look at our results on a pro forma,
non-GAAP basis with all hedging, balancing, optimization, and trading
activity netted. This analytical approach nets the sales of purchased power
with purchased power expense (with the exception of net realized sales and
expenses on electrical trading activity, which is shown on a net basis in
sales of purchased power) and includes that net amount as an adjustment to
electricity and steam ("E&S") revenue for our generation assets. Similarly,
we believe that it is analytically useful to net the sales of purchased gas
with purchased gas expense (with the exception of net realized sales and
expenses on gas trading activity, which is shown on a net basis in sales of
purchased gas) and include that net amount as an adjustment to cost of oil
and natural gas burned by power plants, a component of fuel expense. This
allows us to look at all hedging, balancing, optimization, and trading
activity consistently (net presentation) and better understand our
performance trends. It should be noted that in this non-GAAP analytical
approach, total gross profit does not change from the GAAP presentation,
but the gross profit margins as a percent of revenue do differ from
corresponding GAAP amounts because the inflating effects on our revenue of
hedging, balancing, optimization, and trading activities are removed.

o Average availability and average capacity factor or operating rate.
Availability represents the percent of total hours during the period that
our plants were available to run after taking into account the downtime
associated with both scheduled and unscheduled outages. The capacity
factor, sometimes called operating rate, is calculated by dividing (a)
total megawatt hours generated by our power plants (excluding peakers) by
multiplying (b) the weighted average megawatts in operation during the
period by (c) the total hours in the period. The capacity factor is thus a
measure of total actual generation as a percent of total potential
generation. If we elect not to generate during periods when electricity
pricing is too low or gas prices too high to operate profitably, the
capacity factor will reflect that decision as well as both scheduled and
unscheduled outages due to maintenance and repair requirements.

o Average heat rate for gas-fired fleet of power plants expressed in Btu's of
fuel consumed per kWh generated. We calculate the average heat rate for our
gas-fired power plants (excluding peakers) by dividing (a) fuel consumed in
Btu's by (b) kilowatt-hours generated. The resultant heat rate is a measure
of fuel efficiency, so the lower the heat rate, the better. We also
calculate a "steam-adjusted" heat rate, in which we adjust the fuel
consumption in Btu's down by the equivalent heat content in steam or other
thermal energy exported to a third party, such as to steam hosts for our
cogeneration facilities. Our goal is to have the lowest average heat rate
in the industry.

o Average all-in realized electric price expressed in dollars per MWh
generated. We calculate the all-in realized electric price per MWh
generated by dividing (a) adjusted E&S revenue, which includes capacity
revenues, energy revenues, thermal revenues and the spread on sales of
purchased electricity for hedging, balancing, and optimization activity, by
(b) total generated MWh's in the period.

o Average cost of natural gas expressed in dollars per millions of Btu's of
fuel consumed. At Calpine, the fuel costs for our gas-fired power plants
are a function of the price we pay for fuel purchased and the results of
the fuel hedging, balancing, and optimization activities by CES.
Accordingly, we calculate the cost of natural gas per millions of Btu's of
fuel consumed in our power plants by dividing (a) adjusted cost of oil and
natural gas burned by power plants which includes the cost of fuel consumed
by our plants (adding back cost of intercompany "equity" gas from Calpine
Natural Gas, which is eliminated in consolidation), and the spread on sales
of purchased gas for hedging, balancing, and optimization activity by (b)
the heat content in millions of Btu's of the fuel we consumed in our power
plants for the period.

-28-

o Average spark spread expressed in dollars per MWh generated. Our risk
management activities focus on managing the spark spread for our portfolio
of power plants, the spread between the sales price for electricity
generated and the cost of fuel. We calculate the spark spread per MWh
generated by subtracting (a) adjusted cost of oil and natural gas burned by
power plants from (b) adjusted E&S revenue and dividing the difference by
(c) total generated MWh's in the period.

The table below presents, side-by-side, both our GAAP and pro forma
non-GAAP netted revenue, costs of revenue and gross profit showing the purchases
and sales of electricity and gas for hedging, balancing, optimization, and
trading activity on a net basis. It also shows the other performance metrics
discussed above.

Non-GAAP Netted
GAAP Presentation Presentation
Three Months Ended March 31, Three Months Ended March 31,
---------------------------- ----------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In thousands)

Revenue, Cost of Revenue and Gross Profit
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue(1) ................................ $ 620,179 $ 595,159 $ 713,318 $ 593,811
Sales of purchased power(1) ..................................... 908,301 453,602 157 (1,316)
Electric power derivative mark-to-market gain .................... 4,166 1,306 4,166 1,306
----------- ----------- ----------- -----------
Total electric generation and marketing revenue .................... 1,532,646 1,050,067 717,641 593,801
Oil and gas production and marketing revenue
Oil and gas sales ............................................... 67,488 156,687 67,488 156,687
Sales of purchased gas(1) ....................................... 132,158 129,172 6,072 3,169
----------- ----------- ----------- -----------
Total oil and gas production and marketing revenue ................. 199,646 285,859 73,560 159,856
Income from unconsolidated investments in power projects ........... 1,444 563 1,444 563
Other revenue ...................................................... 4,611 3,262 4,611 3,262
----------- ----------- ----------- -----------
Total revenue ................................................. 1,738,347 1,339,751 797,256 757,482
----------- ----------- ----------- -----------

Cost of revenue:
Electric generation and marketing expense
Plant operating expense ......................................... 115,157 84,460 115,157 84,460
Royalty expense ................................................. 4,155 11,009 4,155 11,009
Purchased power expense(1) ...................................... 815,005 456,266 -- --
----------- ----------- ----------- -----------
Total electric generation and marketing expense .................... 934,317 551,735 119,312 95,469
Oil and gas production and marketing expense
Oil and gas production expense .................................. 26,940 34,283 26,940 34,283
Purchased gas expense(1) ........................................ 123,694 118,628 -- --
----------- ----------- ----------- -----------
Total oil and gas production and marketing expense ................. 150,634 152,911 26,940 34,283
Fuel expense
Cost of oil and natural gas burned by power plants(1) ........... 326,443 264,563 324,051 257,188
Natural gas derivative mark-to-market loss (gain) ............... 6,392 (7,549) 6,392 (7,549)
----------- ----------- ----------- -----------
Total fuel expense ................................................. 332,835 257,014 330,443 249,639
Depreciation, depletion and amortization expense ................... 103,873 72,013 103,873 72,013
Operating lease expense ............................................ 36,134 28,011 36,134 28,011
Other expense ...................................................... 2,590 2,499 2,590 2,499
----------- ----------- ----------- -----------
Total cost of revenue ......................................... 1,560,383 1,064,183 619,292 481,914
----------- ----------- ----------- -----------
Gross profit .................................................... $ 177,964 $ 275,568 $ 177,964 $ 275,568
=========== =========== =========== ===========
Gross profit margin ............................................. 10% 21% 22% 36%

-29-

Non-GAAP Netted
Presentation
Three Months December 31,
--------------------------
2002 2001
-------- --------
(In thousands)

Other Non-GAAP Performance Metrics
Average availability and capacity factor:
Average availability ........................................................................... 94% 92%
Average capacity factor or operating rate based on total hours (excluding peakers) ............. 71% 69%
Average heat rate for gas-fired power plants (excluding peakers) (Btu's/kWh):
Not steam adjusted ............................................................................. 8,173 8,670
Steam adjusted ................................................................................. 7,374 7,506
Average all-in realized electric price:
Adjusted electricity and steam revenue (in thousands) .......................................... $713,318 $593,811
MWh generated (in thousands) ................................................................... 14,714 7,239
Average all-in realized electric price per MWh ................................................. $ 48.48 $ 82.03
Average cost of natural gas:
Cost of oil and natural gas burned by power plants (in thousands) .............................. $324,051 $257,188
Fuel cost elimination .......................................................................... 36,702 43,216
-------- --------
Adjusted cost of oil and natural gas burned by power plants .................................... $360,753 $300,404
MMBtu of fuel consumed by generating plants (in thousands) ..................................... 106,524 47,992
Average cost of natural gas per MMBtu .......................................................... $ 3.39 $ 6.26
MWh generated (in thousands) ................................................................... 14,714 7,239
Average cost of oil and natural gas burned by power plants per MWh ............................. $ 24.52 $ 41.50
Average spark spread:
Adjusted electricity and steam revenue (in thousands) .......................................... $713,318 $593,811
Less: Adjusted cost of oil and natural gas burned by power plants (in thousands) ............... 360,753 300,404
-------- --------
Spark spread (in thousands) .................................................................... $352,565 $293,407
MWh generated (in thousands) ................................................................... 14,714 7,239
Average spark spread per MWh ................................................................... $ 23.96 $ 40.53

The non-GAAP presentation above also facilitates a look at the total
"trading" activity impact on gross profit. For the three months ended March 31,
2002 and 2001, trading activity consisted of:

Three Months Ended
March 31,
------------------------
2002 2001
------- --------

ELECTRICITY Electric generation and marketing revenue
Realized gain (loss) Sales of purchased power .............................. $ 157 $ (1,316)
Unrealized Electric power derivative mark-to-market gain ......... 4,166 1,306
------- --------
Subtotal........................................................................ $ 4,323 $ (10)

GAS Oil and gas production and marketing revenue
Realized gain (loss) Sales of purchased gas ................................ $ 6,072 $ 3,169
Fuel Expense
Unrealized Natural gas derivative mark-to-market gain (loss)...... (6,392) 7,549
------- --------
Subtotal........................................................................ $ (320) $ 10,718

Three Months Three Months
Ended Percent of Ended Percent of
March 31, Gross March 31, Gross
2002 Profit 2001 Profit
------------ ---------- ------------ ----------

Total trading activity gain....................... $ 4,003 2.2% $ 10,708 3.9%
Realized gain (loss).............................. $ 6,229 3.5% $ 1,853 0.7%
Unrealized (mark-to-market) gain (loss)(2)........ $ (2,226) (1.3)% $ 8,855 3.2%

__________

-30-

(1) Following is a reconciliation of GAAP to non-GAAP presentation further
to the narrative set forth under this Performance Metrics section ($ in
thousands):

To Net
Hedging,
Balancing & To Net Netted
GAAP Optimization Trading Non-GAAP
Balance Activity Activity Balance
---------- ------------ --------- ----------

Three months ended March 31, 2002
Electricity and steam revenue.......................... $ 620,179 $ 93,139 $ -- $ 713,318
Sales of purchased power............................... 908,301 (842,606) (65,538) 157
Sales of purchased gas................................. 132,158 (132,158) 6,072 6,072
Purchased power expense................................ 815,005 (749,467) (65,538) --
Purchased gas expense.................................. 123,694 (123,694) -- --
Cost of oil and natural gas burned by power plants..... 326,443 (8,464) 6,072 324,051

Three months ended March 31, 2001
Electricity and steam revenue.......................... $ 595,159 $ (1,348) $ -- $ 593,811
Sales of purchased power............................... 453,602 (443,482) (11,436) (1,316)
Sales of purchased gas................................. 129,172 (129,172) 3,169 3,169
Purchased power expense................................ 456,266 (444,830) (11,436) --
Purchased gas expense.................................. 118,628 (118,628) -- --
Cost of oil and natural gas burned by power plants..... 264,563 (10,544) 3,169 257,188

(2) For the three months ended March 31, 2002, the mark-to-market gains
shown above as "trading" activity include a net loss on hedge ineffectiveness of
$(2,818), consisting of an ineffectiveness loss on power hedges of $(222), an
ineffectiveness loss on crude oil costless collar arrangements of $(5,042) and
an ineffectiveness gain on gas hedges of $2,446. For the three months ended
March 31, 2001, the mark-to-market gains shown above as "trading" activity
include a net loss on hedge ineffectiveness of $(691), consisting of an
ineffectiveness loss on power hedges of $1,217 and an ineffectiveness gain on
gas hedges of $526.

Outlook

At May 15, 2002, we had 22 projects under construction, representing an
additional 13,412 megawatts of net capacity. We have also announced plans to
develop 34 additional power generation projects, representing a net capacity of
15,100 megawatts.

Our new $2 billion revolving credit and term loan facilities and April 2002
issuance of 66 million shares of common stock have ameliorated our 2002
liquidity concerns. We have made significant progress in reducing our operations
and maintenance costs and general and administrative expenses per unit of
electrical generation as we have doubled our generation of electricity from the
first quarter of 2001 to the first quarter of 2002. Our outlook for 2002 is
stable and profitable, but we recognize that the pace of pricing and spark
spread improvement is dependent on the nation's economic recovery and on
weather, particularly in the summer and winter periods. We remain confident in
our strategy, as outlined in our 2001 Form 10-K, and optimistic about our future
performance.

Overview

Summary of Key Activities

Power Plant Development and Construction:

Date Project Description
- ---- ------------------------------------- ----------------------------

1/02 Gilroy Peaking Energy Center Commercial operation
2/02 Magic Valley Generating Station Commercial operation
2/02 King City Energy Center (Peaker Unit) Commercial operation
3/02 Aries Power Project Partial commercial operation
4/02 Island Cogeneration Commercial operation
4/02 Channel Energy Center Combined-cycle operation

Finance

Note Repayments:

Date Amount Description
- ------- ------------- ------------------------------

3/13/02 $64.8 million Michael Petroleum Note Payable
4/1/02 $10.0 million Silverado Note Payable

-31-

Repurchases of Zero-Coupon Convertible Debentures Due 2021:

Date Amount
- --------------------------------------- --------------

January 2, 2002, through April 30, 2002 $878.0 million

Calpine Corporation's Sale of 4% Convertible Senior Notes Due 2006 and
Common Stock:

Date Offering Description Use of Proceeds
- ------- ------------------- --------------------------- -------------------------------

1/3/02 $100 million Conversion price of $18.07 For general corporate purposes
per common share
4/30/02 $759 million, gross 66 million shares at $11.50 For general corporate purposes,
per share including debt repayment

Working Capital Credit Facility:

Date Amount Security Use of Proceeds
- ------- ------------ ----------------------------------- -------------------------------

3/12/02 $2.0 billion Natural gas properties, Saltend Finance capital expenditures and
Power Plant, our equity other general corporate purposes
investment in 9 U.S. power plants,
65% of the capital stock of
Calpine Canada Ltd., and our
remaining first tier domestic
subsidiaries (excluding CES)

Turbine Cancellations:

Date of Reduction in Capital
Announcement Spending Earnings Effect
- ------------ -------------------- -------------------------------------

3/12/02 $1.2 billion in 2002 $168.5 million pre-tax charge in 2002
$1.8 billion in 2003

Other:

Date Description
- ------- -------------------------------------------

1/02 Letter of intent for sale/leaseback of 11 California peaker facilities
3/12/02 Fitch, Inc. lowered the credit rating on senior unsecured debt from BB+ to BB, and it lowered the rating on
convertible trust preferred securities from BB- to B
3/25/02 Standard & Poor's downgraded corporate credit rating from BB+ to BB, and senior unsecured debt from BB+ to B+
3/29/02 Sale of 11.4% interest in Lockport Power Plant for $27.3 million
4/2/02 Proposed sale of De Pere Energy Center for $120 million, including termination of existing power purchase agreement
4/22/02 Renegotiation of California Department of Water Resources long-term power contracts

California Power Market

California Long-Term Supply Contracts --

On February 25, 2002, both the California Public Utilities Commission
("CPUC") and the California Electric Oversight Board ("EOB")filed complaints
under Section 206 of the Federal Power Act with the Federal Energy Regulatory
Commission ("FERC") (EL02-60-000 and EL02-62-000, respectively) alleging that
the prices and terms of the long-term contracts with the California Department
of Water Resources ("DWR") are unjust and unreasonable and counter to the public
interest. Calpine was a respondent and the four long-term contracts entered into
by Calpine were subject to the complaint.

-32-

fund the Electric Power Fund established by the state legislation authorizing
DWR to enter into long-term power contracts with the power suppliers whose
recourse in the event of a default by DWR is to the Electric Power Fund.
Proceeds from the bonds will also be used to repay the state of California
General Fund. The bonds have not been issued, but representatives of the State
have indicated that the bonds should be issued in the near future.

On April 22, 2002, the Company announced that it had renegotiated CES'
long-term power contracts with DWR. The Office of the Governor, the CPUC, the
EOB and the California Attorney General ("AG") have endorsed the renegotiated
contracts and have agreed to drop all pending claims against the Company and its
affiliates, including withdrawing the complaint under Section 206 of the Federal
Power Act recently filed by the CPUC and EOB with FERC and the CPUC and the EOB
have agreed to terminate their efforts to seek refunds from the Company and its
affiliates through FERC refund proceedings. In connection with the
renegotiation, the Company has agreed to pay $6 million over three years to the
AG to resolve any and all possible claims against the Company and its affiliates
brought by the AG.

capacity payments in the amount of approximately $15.0 million since December
2001. As part of the renegotiation, the Company has received payment in full on
these withheld capacity payments and will have the right to provide replacement
capacity through December 31, 2002 based on the original contract terms. On May
2, 2002, each of the CPUC and the EOB filed a Notice of Partial Withdrawal with
Prejudice of Complaint as to Calpine Energy Services, L.P. with the FERC in the
EL02-60-000 and EL02-62-000 dockets, respectively.

Financial Market Risks

Energy price fluctuations -- As an independent power producer primarily
focused on generation of electricity using gas-fired turbines, our natural
physical commodity position is "short" (we require) gas and "long" (we own)
power capacity. To manage forward exposure to price fluctuation in these and (to
a lesser extent) other commodities, we enter into derivative commodity
instruments. All transactions are subject to our risk management policy which
prohibits positions that exceed production capacity and fuel requirements on a
total portfolio basis. Any hedging, balancing, or optimization activities that
we engage in are directly related to our asset-based business model of owning
and operating gas-fired electric power plants. We hedge exposures that arise
from the ownership and operation of power plants and related sales of
electricity and purchases of natural gas, and we utilize derivatives to optimize
the returns we are able to achieve from these assets for our shareholders. This
model is markedly different from that of companies that engage in significant
commodity trading operations that are unrelated to underlying physical assets.
Derivative commodity instruments are accounted for under the requirements of
SFAS No. 133, as amended.

-33-

The change in fair value of outstanding commodity derivative instruments
from January 1, 2002 through March 31, 2002 is summarized in the table below (in
thousands):

Fair value of contracts outstanding at January 1, 2002 $ (88,123)
(Gains) losses realized or otherwise settled during the period (1)............................... (56,928)
Changes in fair value attributable to changes in valuation techniques and assumptions............ --
Other changes in fair value (2).................................................................. 331,503
---------
Fair value of contracts outstanding at March 31, 2002 (3)........................................ $ 186,452
=========

__________

(1) Realized cash flow hedges of $50.7 million reported in Note 7 of the
financial statements and $6.2 million realized gain on trading activity
reported in the performance metrics section of the management discussion
and analysis, both included in this filing.

(2) Includes $204.0 million for the reclassification of Enron obligations from
derivative assets and liabilities to Accounts Payable as a result of the
termination of Calpine's contracts with Enron.

(3) Net assets reported in Note 7 of the Notes to Consolidated Financial
Statements included in this filing.

The fair value of outstanding derivative commodity instruments at March 31,
2002, based on price source and the period during which the instruments will
mature (i.e., be realized) are summarized in the table below (in thousands):

Fair Value Source 2002 2003-2004 2005-2006 After 2006 Total
- ----------------- -------- -------- -------- ---------- --------

Prices actively quoted ....................................... $ 7,498 $(14,593) $(30,746) $ -- $(37,841)
Prices provided by other external sources .................... 1,334 44,071 16,159 -- 61,564
Prices based on models and other valuation methods ........... 103,605 34,886 26,298 (2,060) 162,729
-------- -------- -------- -------- --------
Total fair value ............................................. $112,437 $ 64,364 $ 11,711 $ (2,060) $186,452
======== ======== ======== ======== ========

The Company's traders maintain fair value price information derived from
various sources in the Company's trading and risk management systems. The
propriety of that information is validated by the Company's Risk Control
function. Prices actively quoted include validation with prices sourced from
commodities exchanges (e.g., New York Mercantile Exchange). Prices provided by
other external sources include quotes from commodity brokers and electronic
trading platforms. Prices based on models and other valuation methods are
validated using quantitative methods. Validation methods have been independently
reviewed for propriety.

The counterparty credit quality associated with the fair value of
outstanding derivative commodity instruments at March 31, 2002, and the period
during which the instruments will mature (i.e., be realized) are summarized in
the table below (in thousands):

Credit Quality (based on April 22, 2002 ratings) 2002 2003-2004 2005-2006 After 2006 Total
- ------------------------------------------------ -------- --------- --------- ---------- --------

Investment grade.............................................. $114,854 $ 73,794 $ 18,678 $ (2,078) $205,248
Non-investment grade.......................................... 40,463 (42,852) (17,819) -- (20,208)
No external ratings........................................... (1,029) 2,307 116 18 1,412
-------- -------- -------- -------- --------
Total fair value.............................................. $154,288 $ 33,249 $ 975 $ (2,060) $186,452
======== ======== ======== ======== ========

-34-

The fair value of outstanding derivative commodity instruments and the
change in fair value that would be expected from a ten percent adverse price
change are shown in the table below (in thousands):

CHANGE IN FAIR
VALUE FROM
10% ADVERSE
FAIR VALUE PRICE CHANGE
---------- --------------

At March 31, 2002:
Crude oil ....................... $ (2,132) $ (4,746)
Electricity ..................... 286,181 (29,715)
Natural gas ..................... (97,597) (134,607)
--------- ---------
Total ....................... $ 186,452 $(169,068)
========= =========

Derivative commodity instruments included in the table are those included
in Note 7 to the unaudited Consolidated Condensed Financial Statements. The fair
value of derivative commodity instruments included in the table is based on
present value adjusted quoted market prices of comparable contracts. The
positive fair value of electricity derivative commodity instruments includes the
effect of decreased power prices versus our derivative forward commitments.
Conversely, the negative fair value of the natural gas derivatives reflects a
general decline in gas prices versus our derivative forward commitments.
Derivative commodity instruments offset physical positions exposed to the cash
market. None of the offsetting physical positions are included in the table
above.

Price changes were calculated by assuming an across-the-board ten percent
adverse price change regardless of term or historical relationship between the
contract price of an instrument and the underlying commodity price. In the event
of an actual ten percent change in prices, the fair value of Calpine's
derivative portfolio would typically change by more than ten percent for earlier
forward months and less than ten percent for later forward months because of the
higher volatilities in the near term and the effects of discounting expected
future cash flows.

The primary factors affecting the fair value of the Company's derivatives
at any point in time are (1) the volume of open derivative positions (MMBtu and
Mwh), and (2) changing commodity market prices, principally for electricity and
natural gas. The total volume of open gas derivative positions decreased 53%
from December 31, 2001 to March 31, 2002, while the total volume of open power
derivative positions decreased 12% for the same period. In that prices for
electricity and natural gas are among the most volatile of all commodity prices,
there may be material changes in the fair value of the Company's derivatives
over time, driven both by price volatility and the increases in volume of open
derivative transactions. Under SFAS No. 133, the change since the last balance
sheet date in the total value of the derivatives (both assets and liabilities)
is reflected either in OCI, net of tax, or in the statement of operations as an
item (gain or loss) of current earnings. As of March 31, 2002, the majority of
the balance in accumulated OCI represented the unrealized net loss associated
with commodity cash flow hedging transactions. As noted above, there is a
substantial amount of volatility inherent in accounting for the fair value of
these derivatives, and the Company's results during the three months ended March
31, 2002 have reflected this. See Note 7 for additional information on
derivative activity and also the 2001 Form 10-K for a further discussion of the
Company's accounting policies related to derivative accounting. This treatment
depends upon whether the derivative is designated as a cash flow or fair value
hedge or whether the derivative is not designated in a hedge relationship. The
following accounting applies:

o Changes in the value of derivatives designated as cash flow hedges, net of
any ineffectiveness, are recorded to OCI.

o Changes in the value of derivatives designated as fair value hedges are
recorded in the statement of operations with the offsetting change in value
of the hedge item also recorded in the statement of operations. Any
difference between these two entries to the statement of operations
represents hedge ineffectiveness.

o The change in value of derivatives not designated in hedge relationships is
recorded to the statement of operations.

-35-

purchases and normal sales exception in SFAS No. 133. The Company has adopted
the guidance provided by C16 effective April 1, 2002, and Issue C16 is expected
to increase the volatility of the Company's reported earnings in the future.

Interest rate swaps and cross currency swaps -- From time to time, we use
interest rate swap and cross currency swap agreements to mitigate our exposure
to interest rate and currency fluctuations associated with certain of our debt
instruments. We do not use interest rate swap and currency swap agreements for
speculative or trading purposes. In regards to foreign currency denominated
senior notes, the swap notional amounts equal the amount of the related
principal debt. The following tables summarize the fair market values of our
existing interest rate swap and currency swap agreements as of March 31, 2002
(dollars in thousands):

Notional Principal Weighted Average Weighted Average Fair Market
Maturity Date Amount Interest Rate Interest Rate Value
- ------------- ------------------ ---------------- ---------------- -----------
(Pay) (Receive)

2009 .............................. $ 14,862 6.9% 3-month US LIBOR $ (940)
2011 .............................. 53,126 6.9% 3-month US LIBOR (3,324)
2012 .............................. 118,692 6.5% 3-month US LIBOR (5,554)
2014 .............................. 67,929 6.7% 3-month US LIBOR (4,086)
2015 .............................. 22,500 7.0% 3-month US LIBOR (1,728)
2018 .............................. 17,500 7.0% 3-month US LIBOR (1,431)
-------- --- --------
Total ........................... $294,609 6.7% 3-month US LIBOR $(17,063)
======== === ========

Frequency of
Fixed Currency Currency Fair Market
Maturity Date Notional Principal Exchange Exchange Value
- ------------- ----------------------------------- ------------------------------- ------------- -----------
(Pay/Receive) (Pay/Receive)

2007........... US$127,763/C$200,000 US$5,545/C$8,750 Semi-annually $ (3,929)
2008........... Pound sterling 109,550/Euro 175,000 Pound sterling 5,152/Euro 7,328 Semi-annually (10,732)
--------
Total.... $(14,661)
========

Long-term senior notes and construction/project financing -- Because of the
significant capital requirements within our industry, additional financing is
often needed to fund our growth. We use two primary forms of debt to raise this
financing -- long-term senior notes and construction/project financing. Our
Senior Notes bear fixed interest rates and are generally used to fund
acquisitions, replace construction financing for power plants once they achieve
commercial operations, and for general corporate purposes. Our
construction/project financing is funded through two separate credit agreements,
Calpine Construction Finance Company L.P. and Calpine Construction Finance
Company II, LLC. Borrowings under these credit agreements bear variable interest
rates, and are used exclusively to fund the construction of our power plants.

-36-

The following table summarizes the fair market value of our existing long-term
senior notes and construction/project financing as of March 31, 2002 (dollars in
thousands):

Outstanding Weighted Average Fair Market
Maturity Date Balance Interest Rate Value
- ------------- ----------- ---------------- -----------

Long-term senior notes:
Senior Notes Due 2005 ........................... $ 250,000 8.3% $ 205,000
Senior Notes Due 2006 ........................... 171,750 10.5% 152,858
Senior Notes Due 2006 ........................... 250,000 7.6% 200,000
Convertible Senior Notes Due 2006 ............... 1,200,000 4.0% 924,000
Senior Notes Due 2007 ........................... 275,000 8.8% 222,750
Senior Notes Due 2007 ........................... 125,500 8.8% 100,400
Senior Notes Due 2008 ........................... 400,000 7.9% 312,000
Senior Notes Due 2008 ........................... 2,030,000 8.5% 1,745,800
Senior Notes Due 2008 ........................... 152,446 8.4% 121,957
Senior Notes Due 2009 ........................... 350,000 7.8% 269,500
Senior Notes Due 2010 ........................... 750,000 8.6% 585,000
Senior Notes Due 2011 ........................... 2,000,000 8.5% 1,570,000
Senior Notes Due 2011 ........................... 284,820 8.9% 219,311
---------- --- ----------
Total long-term senior notes................. $8,239,516 7.8% $6,628,576
========== === ==========
Construction/project financing:
Calpine Construction Finance Company L.P. ....... $ 981,400 1-month US LIBOR $ 981,400
Calpine Construction Finance Company II, LLC .... 2,442,697 1-month US LIBOR 2,442,697
---------- ---------------- ----------
Total long-term construction/
project financing.......................... $3,424,097 1-month US LIBOR $3,424,097
========== ================ ==========

Short-term investments -- As of March 31, 2002, we had short-term
investments of $14.1 million. These short-term investments consist of highly
liquid investments with maturities of less than three months. We have the
ability to hold these investments to maturity, and as a result, we would not
expect the value of these investments to be affected to any significant degree
by the effect of a sudden change in market interest rates.

New Accounting Pronouncements

In June 2001, we adopted SFAS No. 141, "Business Combinations," which
supersedes Accounting Principles Board ("APB") Opinion No. 16, "Business
Combinations" and SFAS No. 38, "Accounting for Preacquisition Contingencies of
Purchased Enterprises." SFAS No. 141 eliminated the pooling-of-interests method
of accounting for business combinations and modified the recognition of
intangible assets and disclosure requirements. Adoption of SFAS No. 141 did not
have a material effect on the consolidated financial statements.

In Management's Discussion and Analysis of Financial Condition and Results
of Operations in our Annual Report on Form 10-K for the year ended December 31,
2001, the subsection entitled "SFAS No. 141" in the Impact of Recent Accounting
Pronouncements section was inadvertently overwritten with an outdated draft of
the SFAS No. 142 accounting pronouncement paragraph. The paragraph above
discussing SFAS No. 141 supersedes the discussion in the 2001 Form 10-K.

In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets," which supersedes APB Opinion No. 17, "Intangible Assets." SFAS No. 142
eliminates the current requirement to amortize goodwill and indefinite-lived
intangible assets, extends the allowable useful lives of certain intangible
assets, and requires impairment testing and recognition for goodwill and
intangible assets. SFAS No. 142 will apply to goodwill and other intangible
assets arising from transactions completed both before and after its effective
date. The provisions of SFAS No. 142 are required to be applied starting with
fiscal years beginning after December 15, 2001. See Note 4 for more information.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which amends SFAS No. 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies." SFAS No. 143 addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. SFAS No.
143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made. SFAS No. 143 is effective for financial
statements issued for fiscal years beginning after June 15, 2002. We have not
completed our analysis of the impact that SFAS No. 143 will have on our
consolidated financial statements.

On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets," which supersedes SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," and the accounting and reporting provisions of APB Opinion No. 30,
"Reporting the Results of Operations -- Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring

-37-

Events and Transactions," for the disposal of a segment of a business (as
previously defined in that APB Opinion). SFAS No. 144 establishes a single
accounting model, based on the framework established in SFAS No. 121, for
long-lived assets to be disposed of by sale. SFAS No. 144 also resolves several
significant implementation issues related to SFAS No. 121, such as eliminating
the requirement to allocate goodwill to long-lived assets to be tested for
impairment and establishing criteria to define whether a long-lived asset is
held for sale. Adoption of SFAS No. 144 did not have a material effect on the
consolidated financial statements.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt" and an amendment of that statement, SFAS No. 64,
"Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No.
145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor
Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to
eliminate an inconsistency between the required accounting for sale-leaseback
transactions and the required accounting for certain lease modifications that
have economic effects that are similar to sale-leaseback transactions. SFAS No.
145 also amends other existing authoritative pronouncements to make various
technical corrections, clarify meanings, or describe their applicability under
changed conditions. The provisions related to the rescission of SFAS No. 4 shall
be applied in fiscal years beginning after May 15, 2002. The provisions related
to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002.
All other provisions shall be effective for financial statements issued on or
after May 15, 2002, with early application encouraged. We do not believe that
SFAS No. 145 will have a material effect on our results of operations.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

See "Financial Market Risks" in Item 2.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

-38-

three law firms, in conjunction with other law firms as co-counsel. All eleven
lawsuits are purported class actions on behalf of purchasers of Calpine's
securities between January 5, 2001 and December 13, 2001.

Public Utilities Commission of the State of California v. Sellers of Long
Term Contracts to the California Department of Water Resources; California
Electricity Oversight Board v. Sellers of Long Term Contracts to the California
Department of Water Resources. In February 2002 both the CPUC and the EOB filed
complaints under Section 206 of the Federal Power Act with FERC (EL02-60-000 and
EL02-62-000, respectively) alleging that the prices and terms of the long-term
contracts with DWR are unjust and unreasonable and counter to the public
interest. CES is a respondent and the four long-term contracts entered into
between CES and DWR are subject to the complaint (see, Risk Factors - California
Long-Term Supply Agreements). As part of Calpine's successful renegotiation of
its long-term power contracts with DWR announced on April 22, 2002, the Office
of the Governor, the CPUC, the EOB and the AG agreed to settle this action and
drop all challenges to Calpine's long-term contracts with DWR. On May 2, 2002
each of the CPUC, the EOB, and the AG filed a Notice of Partial Withdrawal with
Prejudice of Complaint as to Calpine Energy Services, L.P. with the FERC.
Pursuant to its respective notice each of the CPUC and the EOB withdrew all of
their respective claims against CES which had been alleged in the
above-for-mentioned complaints (EL02-60-000 and ELO2-62-000) concerning the
justness and reasonableness of the terms under the long-term contracts with DWR.
In addition, pursuant to its notice, the AG withdrew all claims as to CES in its
complaint (EL02-71-000) wherein it had alleged that public utility sellers of
energy and ancillary services to DWR and into markets operated by the California
Independent System Operator and the California Power Exchange were not in
compliance with their disclosure obligations under Section 205 of the Federal
Power Act.

Item 2. Changes in Securities and Use of Proceeds.

4% Convertible Senior Notes due 2006. On December 26, 2001, we completed a
private placement of $1,000,000,000 aggregate principal amount of 4% Convertible
Senior Notes due 2006 (the "senior notes due 2006"). The initial purchaser of
the senior notes due 2006 was Deutsche Bank Alex. Brown Inc. (the "initial
purchaser"). The initial purchaser exercised its option to acquire an additional
$200,000,000 aggregate principal amount of the senior notes due 2006 by
purchasing an additional $100,000,000 aggregate principal amount of the senior
notes due 2006 on each of December 31, 2001 and January 3, 2002. The offering
price of the senior notes due 2006 was 100% of the principal amount of the
senior notes due 2006, less an aggregate underwriting discount of $30,000,000.
Each sale of the senior notes due 2006 to the initial purchaser was exempt from
registration in reliance on Section 4(2) and Regulation D under the Securities
Act of 1933, as amended, as a transaction not involving a public offering. The
senior notes due 2006 were re-offered by the initial purchaser to qualified
institutional buyers in reliance on Rule 144A under the Securities Act.

The senior notes due 2006 are convertible into shares of our common stock
at a conversion price of $18.07 per share. The conversion price is subject to
adjustment in certain circumstances. We have reserved 66,408,411 shares of our
authorized common stock for issuance upon conversion of the senior notes due
2006. The senior notes due 2006 are convertible at any time on or before the
close of business on the day that is two business days prior to the maturity
date, December 26, 2006, unless we have previously repurchased the senior notes
due 2006. Holders of the senior notes due 2006 have the right to require us to
repurchase their senior notes due 2006 on December 26, 2004. We may choose to
pay the repurchase price in cash or shares of common stock, or a combination
thereof.

-39-

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits

The following exhibits are filed herewith unless otherwise indicated:

EXHIBIT INDEX

EXHIBIT
NUMBER DESCRIPTION

*3.1 Amended and Restated Certificate of Incorporation of Calpine
Corporation (a)

*3.2 Certificate of Correction of Calpine Corporation (b)

*3.3 Certificate of Amendment of Amended and Restated Certificate
of Incorporation of Calpine Corporation (c)

*3.4 Certificate of Designation of Series A Participating Preferred
Stock of Calpine Corporation (b)

*3.5 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (b)

*3.6 Amended Certificate of Designation of Series A Participating
Preferred Stock of Calpine Corporation (c)

*3.7 Certificate of Designation of Special Voting Preferred Stock
of Calpine Corporation(d)

3.8 Certificate of Ownership and Merger Merging Calpine Natural
Gas GP, Inc. into Calpine Corporation.

3.9 Certificate of Ownership and Merger Merging Calpine Natural
Gas Company into Calpine Corporation.

*3.10 Amended and Restated By-laws of Calpine Corporation (f)

*4.1 Indenture dated as of August 10, 2000, between Calpine
Corporation and Wilmington Trust Company, as Trustee.(f)

*4.2 First Supplemental Indenture dated as of September 28, 2000,
between Calpine Corporation and Wilmington Trust Company, as
Trustee.(b)

*4.3 Amended and Restated Rights Agreement, dated as of September
19, 2001, between Calpine Corporation and EquiServe Trust
Company, N.A., as Rights Agent.(g)

*10.1 Second Amended and Restated Credit Agreement ("Second Amended
and Restated Credit Agreement") dated as of May 23, 2000,
among the Company, Bayerische Landesbank, as Co-Arranger and
Syndication Agent, The Bank of Nova Scotia, as Lead Arranger
and Administrative Agent, and the Lenders named therein.(h)

*10.2 First Amendment and Waiver to Second Amended and Restated
Credit Agreement, dated as of April 19, 2001, among the
Company, The Bank of Nova Scotia, as Administrative Agent, and
the Lenders named therein.(e)

*10.3 Second Amendment to Second Amended and Restated Credit
Agreement, dated as of March 8, 2002, among the Company, The
Bank of Nova Scotia, as Administrative Agent, and the Lenders
named therein.(e)

10.4 Third Amendment to Second Amended and Restated Credit
Agreement, dated as of May 9, 2002, among the Company, The
Bank of Nova Scotia, as Administrative Agent, and the Lenders
named therein.

*10.5 Credit Agreement, dated as of March 8, 2002, among the
Company, the Lenders named therein, The Bank of Nova Scotia
and Bayerische Landesbank Girozentrale, as lead arrangers and
bookrunners, Salomon Smith Barney Inc. and Deutsche Banc Alex.
Brown Inc., as lead arrangers and bookrunners, Bank of
America, National Association, and Credit Suisse First Boston,
Cayman Islands Branch, as lead arrangers and syndication
agents, TD Securities (USA) Inc., as lead arranger, The Bank
of Nova Scotia, as joint administrative agent and funding
agent, and Citicorp USA, Inc., as joint administrative
agent.(e)

10.6 First Amendment to Credit Agreement, dated as of May 9, 2002,
among the Company, The Bank of Nova Scotia, as Joint
Administrative Agent and Funding Agent, Citicorp USA, Inc., as
Joint Administrative Agent, and the Lenders named therein.

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*10.7 Assignment and Security Agreement, dated as of March 8, 2002,
by the Company in favor of The Bank of Nova Scotia, as
administrative agent for each of the Lender Parties named
therein.(e)

*10.8 Pledge Agreement, dated as of March 8, 2002, by the Company in
favor of The Bank of Nova Scotia, as Agent for the Lender
Parties named therein.(e)

10.9 Amendment Number One to Pledge Agreement, dated as of May 9,
2002, among the Company and The Bank of Nova Scotia, as Joint
Administrative Agent and Funding Agent.

*10.10 Pledge Agreement, dated as of March 8, 2002, by Quintana
Minerals (USA), Inc., JOQ Canada, Inc. and Quintana Canada
Holdings, LLC in favor of The Bank of Nova Scotia, as Agent
for the Lender Parties named therein.(e)

10.11 First Amendment Pledge Agreement, dated as of May 9, 2002,
by the Company in favor of The Bank of Nova Scotia, as Agent
for each of the Lender Parties named therein.

10.12 First Amendment Pledge Agreement (Membership Interests), dated
as of May 9, 2002, by the Company in favor of The Bank of Nova
Scotia, as Agent for each of the Lender Parties named therein.

10.13 Note Pledge Agreement, dated of May 9, 2002, by the Company
in favor of The Bank of Nova Scotia, as Agent for each of the
Lender Parties named therein.
________________

* Incorporated by reference.

(a) Incorporated by reference to Calpine Corporation's Registration
Statement on Form S-3 (Registration No. 333-40652), filed with the SEC
on June 30, 2000.

(b) Incorporated by reference to Calpine Corporation's Annual Report on
Form 10-K for the year ended December 31, 2000, filed with the SEC on
March 15, 2001.

(c) Incorporated by reference to Calpine Corporation's Registration
Statement on Form S-3 (Registration No. 333-66078), filed with the SEC
on July 27, 2001.

(d) Incorporated by reference to Calpine Corporation's Quarterly Report on
Form 10-Q dated March 31, 2001, filed with the SEC on May 15, 2001.

(e) Incorporated by reference to Calpine Corporation's Annual Report on
Form 10-K for the year ended December 31, 2001, filed with the SEC on
March 29, 2002.

(f) Incorporated by reference to Calpine Corporation's Registration
Statement on Form S-3 (Registration No. 333-76880), filed with the SEC
on January 17, 2002.

(g) Incorporated by reference to Calpine Corporation's Registration
Statement on Form 8-A/A filed with the SEC on September 28, 2001.

(h) Incorporated by reference to Calpine Corporation's Current Report on
Form 8-K dated July 25, 2000, filed with the SEC on August 9, 2000.

(b) Reports on Form 8-K

The registrant filed the following reports on Form 8-K during the quarter
ended March 31, 2002:

DATE OF REPORT DATE FILED ITEM REPORTED
- -------------- ---------- -------------

December 24, 2001 ..................... January 16, 2002 5,7
November 14, 2001 ..................... January 17, 2002 5,7
January 31, 2002 ...................... February 8, 2002 5,7
March 12, 2002 ........................ March 13, 2002 5,7
March 13, 2002 ........................ March 13, 2002 5
March 25, 2002 ........................ March 26, 2002 4,7

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

CALPINE CORPORATION

By: /s/ Robert D. Kelly Date: May 15, 2002
- -------------------------------
Robert D. Kelly
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

By: /s/ Charles B. Clark, Jr. Date: May 15, 2002
- -------------------------------
Charles B. Clark, Jr.
Senior Vice President and
Corporate Controller
(Principal Accounting Officer)

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