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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION

                             Washington, D.C. 20549


                                    FORM 8-K

                                 CURRENT REPORT

                       Pursuant to Section 13 or 15(d) of
                       the Securities Exchange Act of 1934


      Date of Report (Date of earliest event reported): June 20, 2005


                               CALPINE CORPORATION
             (Exact name of registrant as specified in its charter)

                                    Delaware
                 (State or Other Jurisdiction of Incorporation)

                        Commission file number: 001-12079

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

                           50 West San Fernando Street
                           San Jose, California 95113
                            Telephone: (408) 995-5115
         (Address of principal executive offices and telephone number)

     Check the  appropriate  box below if the Form 8-K  filing  is  intended  to
simultaneously  satisfy the filing obligation of the registrant under any of the
following provisions:

     [ ]  Written communications pursuant to Rule 425 under the Securities Act
          (17 CFR 230.425)

     [ ]  Soliciting material pursuant to Rule 14a-12 under the Exchange Act
          (17 CFR 240.14a-12)

     [ ]  Pre-commencement communications pursuant to Rule 14d-2(b) under the
          Exchange Act (17 CFR 240.14d-2(b))

     [ ]  Pre-commencement communications pursuant to Rule 13e-4(c) under the
          Exchange Act (17 CFR 240.13e-4(c))


<PAGE>


ITEM 3.02     Unregistered Sales of Equity Securities

     On June 28, 2005, the Company issued 27,539,826  unregistered shares of its
common  stock,  par value  $.001,  in  exchange  for  $94,315,000  in  aggregate
principal amount at maturity of the Company's  Contingent  Convertible Notes due
2014 pursuant to the exemption  afforded by Section 3(a)(9) under the Securities
Act of 1933, as amended.  No commission or other remuneration was paid or given,
directly or indirectly, for soliciting such exchange.


ITEM 8.01     Other Events

     On June 23, 2005, Calpine Corporation (the "Company") completed an offering
of $650 million  aggregate  principal  amount of 7 3/4%  Contingent  Convertible
Notes Due June 1, 2015 (the "notes"),  in an  underwritten  offering  registered
under the  Securities  Act of 1933, as amended (the  "Securities  Act"). A press
release  regarding  the  offering,  dated June 23,  2005,  is filed  herewith as
Exhibit  99.1.  The  Company  expects  to use a portion of the  proceeds  of the
offering  of the  notes to  redeem  all of the  outstanding  5% HIGH  TIDES  III
preferred securities issued by its Calpine Capital Trust III subsidiary that are
not currently held by the Company.  A press release  regarding the redemption of
the HIGH TIDES III, dated June 24, 2005, is filed herewith as Exhibit 99.2.

     In  connection  with the offering of the notes,  the Company filed with the
Securities and Exchange Commission a prospectus supplement, dated June 20, 2005,
describing  the  terms  of the  offering.  The  prospectus  supplement  contains
information  that  updates  or  modifies  certain  information  included  in the
Company's  reports  filed  pursuant to the  Securities  Exchange Act of 1934, as
amended,  including its Annual  Report on Form 10-K for the year ended  December
31,  2004,  its  Quarterly  Report on Form 10-Q for the quarter  ended March 31,
2005, and its various  Current  Reports on Form 8-K filed during 2005. Set forth
below are excerpts from the following portions of the prospectus supplement:

     "Summary - Our  Business" "- Our Strategy" "- Recent  Developments"  and "-
     Repurchases of Outstanding Debt": These sections provide additional details
     regarding the Company's recent activities;

     "Summary  -   Unaudited   Pro  Forma   Consolidated   Condensed   Financial
     Statements":  This section presents pro forma financial  information giving
     effect to the pending  disposition  by the Company of Saltend  Cogeneration
     Company Limited and Calpine UK Operations  Limited to be accounted for as a
     discontinued  operation in accordance with Financial  Accounting  Standards
     Board Statement of Financial  Accounting Standards No. 144, "Accounting for
     the Impairment or Disposal of Long-Lived Assets"; and

     "Risk Factors": This section reflects updates and modifications to the risk
     factors  contained in the Company's Annual Report on Form 10-K for the year
     ended December 31, 2004.

This  Current  Report  on Form  8-K is filed  solely  to make  available  to the
Company's  investors  the  information  referred  to  above  and to  allow  such
information  to be  incorporated  by  reference  into  the  Company's  currently
effective Registration Statements on Form S-3 (including Registration Statements
Nos.  333-76880 and  333-116510).  In providing  this  information,  the Company
undertakes no duty to update this or any other  information  except as otherwise
required by  applicable  law. The Company  also  directs  readers to its annual,
quarterly  and other  reports  that have been filed with or furnished to the SEC
subsequent to the date of the prospectus  supplement,  or that may be filed with
or furnished to the SEC after the date of this Current Report on Form 8-K, which
may contain  information  that  updates or otherwise  modifies  the  information
contained herein.

     Unless we have  indicated  otherwise,  references in this Current Report on
Form 8-K to "Calpine,"  "the Company," "we," "us" and "our" or similar terms are
to Calpine  Corporation and its  consolidated  subsidiaries,  excluding  Calpine
Capital Trust V, Calpine  Capital Trust IV, Calpine  Capital Trust III,  Calpine
Capital Trust II and Calpine Capital Trust.

________________________________________________________________________________


SUMMARY - OUR BUSINESS

     We are an integrated  power company with a comprehensive  and growing power
services  business.  Based in San Jose,  California,  we were  established  as a
corporation in 1984 and operate through a variety of divisions, subsidiaries and
affiliates. We own and operate power generation facilities and sell electricity,
predominantly  in the United  States  but also in Canada.  We also own one power
generation facility in the United Kingdom but recently entered into an agreement
to sell the  facility.  See "-- Recent  Developments  -- Sale of Saltend  Energy
Centre."  We  focus  on two  efficient  and  clean  types  of  power  generation
technologies:  natural gas-fired combustion turbine and geothermal. We lease and
operate  a  significant  fleet of  geothermal  power  plants at The  Geysers  in
California,  and have a net operating  portfolio of 95 clean burning natural gas
and geothermal  power plants capable of producing 27,799 megawatts ("MW") and an
additional  10  plants  in  construction.  We  recently  announced  that  we are
contemplating the sale of up to eight plants, and in connection therewith,  have
entered  into  non-binding  asset sale  agreements  with  respect to four of our
plants.  See "-- Recent  Developments  -- Potential  Sales of Certain  Gas-Fired
Power Plants." We offer to third parties  energy  procurement,  liquidation  and
risk management  services through Calpine Energy  Services,  L.P.  ("CES"),  and
offer  combustion  turbine  component parts and repair and maintenance  services
world-wide through Calpine Turbine Services,  which includes Power Systems Mfg.,
LLC  ("PSM"),  located in  Jupiter,  Florida,  and  Netherlands-based  Thomassen
Turbine  Systems  B.V.  We also  offer  engineering,  procurement,  construction
management,  commissioning  and  operations  and  maintenance  ("O&M")  services
through Calpine Power Services, Inc.

     Our integrated  operating  capabilities have given us a proven track record
in the  development  and  construction  of new  power  facilities.  Our  Calpine
Construct   organization   consists  of  an  experienced  team  of  construction
management  professionals  who  ensure  that our  projects  are built  using our
standard design specifications reflecting our exacting operational standards. We
have established  relationships  with leading  equipment  manufacturers  for gas
turbine generators, steam turbine generators, heat recovery steam generators and
other key equipment.  While future  projects will be developed only when we have
attractive  power  contracts  in  place,  we will  continue  to  leverage  these
capabilities and  relationships to ensure that our power plants are completed on
time and are the best built and lowest cost energy facilities possible.

     We have a sophisticated O&M organization based in Folsom, California, which
staffs and oversees the commissioning  and operations of our power plants.  With
the objective of enhancing the performance of our modern  portfolio of gas-fired
power  plants and lowering  our  replacement  parts and  maintenance  costs,  we
capitalize on PSM's  capabilities  to design and  manufacture  high  performance
combustion  system and turbine blade parts. PSM manufactures new vanes,  blades,
combustors  and other  replacement  parts for our plants and for those owned and
operated  by third  parties  as well.  It offers a wide  range of Low  Emissions
Combustion   systems  and  advanced  airfoils  designed  to  be  compatible  for
retrofitting or replacing existing combustion systems or components operating in
General Electric and Siemens Westinghouse turbines.

     We also have in place an experienced  gas  production  and management  team
which gives us a broad range of fuel  sourcing  options  and, as of December 31,
2004, we owned  approximately  389 billion  cubic feet  equivalent of net proved
natural gas reserves and 499 net wells located primarily in the Sacramento Basin
of California and Gulf Coast regions of the United  States.  For the four months
ended  April 30,  2005,  our  natural  gas  assets  produced,  net to  Calpine's
interest,  an  average of  approximately  90 million  cubic feet  equivalent  of
natural gas per day. We recently  commenced a process with  potential  buyers to
sell  our oil  and natural gas assets.  See "--Recent  Developments -- Potential
Sale of Certain Oil and Natural Gas Assets."

     CES  provides us with the trading and risk  management  services  needed to
schedule power sales and to ensure fuel is delivered to our power plants on time
to meet  delivery  requirements  and to  manage  and  optimize  the value of our
physical power generation and gas production  assets. CES currently manages over
3% of the U.S.  gas and power  demand.  Our  marketing  and  sales  organization
complements  CES's activities and is organized not only to serve our traditional
load serving client base of local utilities, municipalities and cooperatives but
also to meet  the  needs of our  growing  list of  wholesale  and  large  retail
customers. As a general goal, we seek to have 65% of our available capacity sold
under  long-term  contracts or hedged by our risk  management  group.  As of May
2005, we had 58% of our available capacity sold or hedged for 2005. In addition,
we  recently  announced  that we are in  discussions  with a  leading  financial
institution to form a partnership  that we anticipate would lower our collateral
requirements and establish a significant third party customer business.  See "--
Recent  Developments  -- Strategic  Initiative to Accelerate  Debt Reduction and
Increase Cash Flow."

     Additionally,  we continue to strengthen our system  operations  management
and information  technology  capabilities to enhance the economic performance of
our portfolio of assets in our major markets and to provide  load-following  and
ancillary  services to our customers.  These operational  optimization  systems,
combined with our sales, marketing and risk management  capabilities,  enable us
to add value to traditional commodity products.


SUMMARY - OUR STRATEGY

     Our vision is to become North  America's most efficient,  cost  competitive
and  environmentally  friendly power company with a comprehensive and profitable
service  business.  We believe that with our efficient fleet of power generation
facilities and economies of scale,  we are positioned to operate  profitably and
with  reasonable  volatility  as the supply and demand  picture  improves and we
increase  the  proportion  of  contractual  sales.  In achieving  our  corporate
strategic objectives, the number one priority for our company is maintaining the
highest level of integrity in all of our endeavors.

     Our timeline to achieve our strategic objectives is partially a function of
improvement in market  fundamentals.  When necessary,  we will slow or delay our
growth activities in order to ensure that our financial health is secure and our
investment opportunities meet our long-term rate of return requirements.

Near-Term Objectives

     Our ability to adapt as needed to market  dynamics  has led us to develop a
set of near-term  strategic  objectives that will guide our activities as market
fundamentals improve. These include:

     o    Continue  to focus on our  liquidity  position  as our second  highest
          priority after integrity;

     o    Continue to improve our balance  sheet through the  extinguishment  or
          repurchase of debt;

     o    Complete our current  construction  program and start  construction of
          new  projects in strategic  locations  only when power  contracts  and
          financing are available and attractive returns are expected;

     o    Put  excess  gas  turbines  to work in new  projects,  subject  to the
          conditions stipulated above, or sell them;

     o    Continue to lower  operating  and  overhead  costs per  megawatt  hour
          ("MWh")   produced   and  improve   operating   performance   with  an
          increasingly efficient power plant fleet;

     o    Utilize our marketing and sales  capabilities to selectively  increase
          our power contract portfolio; and

     o    Grow our  services  businesses  to  complement  our  integrated  power
          operations.

Longer-Term Objectives

     We plan,  through our strategy to (1) achieve the  lowest-cost  position in
the  industry  by  applying  our  fully  integrated  areas of  expertise  to the
cost-effective development,  construction,  financing,  fueling and operation of
the most modern and  efficient  power  generation  facilities  and by  achieving
economies of scale in general,  administrative  and other support costs, and (2)
enhance the value of the power we generate in the  marketplace  by (a) operating
our plants as a system,  (b) selling  directly to load-serving  entities and, to
the extent allowable,  to industrial customers,  in each of the markets in which
we participate,  (c) offering load-following and other ancillary services to our
customers,  and (d) providing  effective  marketing,  risk  management and asset
optimization activities through our CES and marketing and sales organizations.

     Our "system  approach"  refers to our ability to cluster our  standardized,
highly  efficient  power  generation  assets within a given energy market and to
sell the energy  from that  system of power  plants,  rather  than  using  "unit
specific" marketing  contracts.  The clustering of standardized power generation
assets allows for significant  economies of scale to be achieved.  Specifically,
construction  costs,  supply chain  activities such as inventory and warehousing
costs,  labor, and fuel procurement costs can all be reduced with this approach.
The choice to focus on highly efficient and clean technologies  reduces our fuel
consumption,  a major  expense when  operating  power plants.  Furthermore,  our
lower-than-market   heat  rate  (high  efficiency   advantage)   provides  us  a
competitive  advantage in times of rising fuel prices,  and our systems approach
to fuel  purchases  reduces  imbalance  charges  when a plant is  forced  out of
service. Finally, utilizing our system approach in a sales contract allows us to
provide  power  to a  customer  from  whichever  plant  in the  system  is  most
economical at a given period of time.  In addition,  the operation of plants can
be coordinated when increasing or decreasing power output  throughout the day to
enhance  overall system  efficiency,  thereby  enhancing the heat rate advantage
already enjoyed by the plants.  In total,  this approach lays a foundation for a
sustainable competitive cost advantage in operating our plants.

     The integration of hedging,  optimization and marketing activities achieves
additional cost reductions while simultaneously enhancing revenues. Our fleet of
natural gas burning power plants requires a large amount of gas to operate.  Our
CES risk management  organization provides procurement and price risk management
activities  associated  with our gas supply  using a portfolio  of physical  gas
supply  contracts  and both  financial  exchange  traded  and  over the  counter
products.

     Recent trends confirm that both buyers and sellers of power and gas benefit
from signing  long-term power  contracts.  By signing  long-term power contracts
with fixed or heat-rate  based  pricing (a component of which is the gas index),
we are able to reduce  our  exposure  to the severe  volatility  often seen with
power and gas prices. The trend towards signing long-term  contracts is creating
opportunities  for companies,  such as ours,  that own power plants to negotiate
directly with buyers (end users and load-serving entities) that need power.

     Our marketing and sales  organization is dedicated to serving wholesale and
industrial customers with reliable,  cost-effective electricity and a full range
of services.  The organization offers customers:  (1) wholesale bulk energy; (2)
firm supply energy; (3) fully dispatchable energy; (4) full service requirements
energy; (5) renewable energy; (6) energy scheduling  services;  (7) engineering,
construction,  O&M services;  and (8) turbine  parts and  long-term  maintenance
agreements.  Our physical,  financial and intellectual assets and our generating
facilities,  pooled  into unique  energy  centers in key  markets,  enable us to
create customizable  energy solutions for our customers,  delivering power when,
where and in the capacity our customers  need.  Our power  marketing  experience
gives us the know-how to  structure  innovative  deals that meet our  customers'
particular  requirements.  For  example,  we work with our  customers  to tailor
energy contracts to help them offset pricing risk and other  variables.  We have
developed our "Virtual  Power Plant"  product which  provides  customers with an
energy  resource  that is reliable and flexible.  It gives  customers all of the
advantages of owning and operating  their own plants  without many of the risks,
by gaining access to a portfolio of highly  efficient  generation  assets and by
implementing  our IT solutions to allow power to be dispatched as needed.  As of
June 2,  2005,  our  marketing  and sales team is  pursuing  20,688 MW of active
opportunities  with 142  customers  across the United  States and  Canada.  This
customer base includes municipalities,  cooperatives,  investor owned utilities,
industrial customers and commercial customers.

     The ultimate objective of our financing strategy is to achieve and maintain
an investment  grade credit and bond rating from the major rating  agencies.  In
order to achieve this  objective we have reduced  capital  expenditures  and are
continuing to seek ways to reduce our debt and improve our liquidity.  We intend
to employ  various  approaches  for  extending or  refinancing  existing  credit
facilities and for financing new plants, with a goal of retaining maximum system
operating   flexibility.   The  availability  of  capital  at  attractive  terms
consistent  with  achieving our  liquidity  goals will be a key  requirement  to
enable us to develop and construct new plants. We have adjusted to recent market
conditions  by taking  near-term  actions  focused  on  liquidity.  We have been
successful  throughout the last few years at selling certain less  strategically
important assets,  monetizing several  contracts,  buying back our debt, issuing
convertible and non-convertible  senior notes, and raising  non-recourse project
financing.

     For more information  about our near-term and longer-term  objectives,  and
the  challenges  facing us in achieving  those  objectives,  see "Risk  Factors"
below,  and see our Annual  Report on Form 10-K for the year ended  December 31,
2004,  and our  Quarterly  Report on Form 10-Q for the  quarter  ended March 31,
2005, which are incorporated by reference herein.


SUMMARY - RECENT DEVELOPMENTS

     Credit  Rating  Actions.  On May 9,  2005,  Standard & Poor's  lowered  its
corporate  credit rating on Calpine  Corporation  to single B- from single B and
maintained its negative outlook. In addition,  the ratings on Calpine's debt and
the ratings on the debt of its subsidiaries were also lowered by one notch, with
a few exceptions.

     On May 12, 2005, Moody's Investor Service lowered its senior implied issuer
rating on Calpine Corporation to B3 from B2 and maintained its negative outlook.
In addition,  Moody's ratings on our debt and the debt of our subsidiaries  were
also lowered by either one or two notches, with a few exceptions.

     On May 25, 2005,  following the  announcement  of our strategic  initiative
described below under " -- Strategic Initiative to Accelerate Debt Reduction and
Increase  Cash Flow," Fitch Ratings  placed our credit  ratings on "rating watch
evolving,"  which  means  that  Fitch may  lower,  maintain  or raise its credit
ratings of our debt securities in the near-term.

     Such  downgrades,  and any further  downgrades,  could increase the cost of
future  borrowings  and other  costs of doing  business.  See "Risk  Factors  --
Capital  Resources;  Liquidity -- Our credit  ratings have been  downgraded  and
could be downgraded further."

     Strategic  Initiative to Accelerate  Debt Reduction and Increase Cash Flow.
On May 25, 2005,  we  announced a strategic  initiative  aimed at enhancing  our
financial strength by:

     o    Optimizing  our power plant  portfolio  by selling  certain  power and
          natural gas assets to reduce  debt,  lower  annual  interest  cost and
          increase  cash flow.  In addition to  previously  announced  potential
          asset  sales  (including  the sale of  Saltend  Energy  Centre and the
          potential sale of certain oil and natural gas assets described below),
          we  announced  that we are  targeting  the sale of up to eight  plants
          (including the four plants described  below),  however there can be no
          assurance  that we will be  successful  in selling  all or any of such
          additional plants.

     o    Decreasing  operating and maintenance costs and lowering fuel costs to
          improve the operating  performance  of our power  plants,  which would
          boost  operating  cash  flow  and  liquidity.   In  addition,  we  are
          considering  temporarily shutting down power plants with negative cash
          flow until market conditions  warrant start-up to further reduce costs
          and more effectively focus our financial and sales resources.

     o    Enhancing our credit.  We announced that we are in discussions  with a
          leading financial institution to form a partnership that we anticipate
          would lower our  collateral  requirements  and establish a significant
          third party customer business.

     o    Reducing  total debt by more than $3  billion,  or 16%,  by the end of
          2005,  which we  estimate  would  result  in $275  million  of  annual
          interest savings,  through such asset sales, credit  enhancement,  and
          fuel and operating cost reductions.

     There can be no assurance, however, that we will be successful in achieving
all or any of such asset sales,  credit  enhancements and cost reductions to the
extent  anticipated,  or at all. If we do not, then we may not be able to reduce
our debt to the extent planned.

     Potential  Sale of Certain Oil and Natural Gas Assets.  On May 17, 2005, we
announced  that we are  evaluating  strategic  alternatives  for our natural gas
assets, including the potential sale of all or a portion of such assets. On June
9,  2005,  in  connection  with the tender  offer for our 9 5/8% First  Priority
Senior  Secured  Notes due 2014,  we announced  that we commenced a process with
potential  buyers to sell our oil and  natural  gas assets but have not  entered
into  definitive  documentation  related  to  any  such  sale.  There  can be no
assurance that we will be able to consummate  any such sale on terms  acceptable
to us or at all,  or that we will not make a  determination  to abandon the sale
process.  Our oil and natural gas assets  include land  interests  consisting of
386,674 net developed and undeveloped  acres located primarily in the Sacramento
Basin of  California,  south  Texas  and the  Gulf of  Mexico,  with  additional
significant activity in Colorado,  New Mexico and Utah. As of December 31, 2004,
we owned  approximately  389 billion cubic feet equivalent of net proved natural
gas  reserves and 499 net wells.  For the four months  ended April 30, 2005,  we
produced,  net to Calpine's  interest,  an average of  approximately  90 million
cubic feet  equivalent of natural gas per day.  These assets had a book value of
approximately $604.8 million at December 31, 2004, and contributed $57.6 million
in third party  revenues in 2004.  For more  information  concerning our oil and
natural  gas  assets,  see our  Annual  Report on Form  10-K for the year  ended
December 31, 2004, which is incorporated by reference herein,  including Item 2.
"Properties"  and Note 26 of the  Notes  to  Consolidated  Financial  Statements
included  therein.  Net proceeds from any sale of the oil and natural gas assets
will be used in accordance  with our existing bond  indentures.  See " -- Tender
Offer for First Priority Notes" below.

     Sale of Saltend  Energy  Centre.  On May 28, 2005,  we entered into a Share
Sale and Purchase  Agreement for the sale of our 1,200  megawatt  Saltend Energy
Centre  cogeneration  plant located in Hull,  England,  to Normantrail (UK CO 3)
Limited, a partnership  between  International  Power plc and Mitsui & Co., Ltd,
for a total  purchase  price of  (Pound)490  million,  or  approximately  US$906
million, plus adjustments for working capital expected to be approximately US$19
million. The expected closing date for the sale is July 26, 2005, subject to the
receipt of regulatory  approvals  and the  satisfaction  of other  conditions of
closing.  We plan to use the net  proceeds  from the sale to redeem the existing
$360.0  million of Two-Year  Redeemable  Preferred  Shares and $260.0 million of
Redeemable  Preferred  Shares Due July 30, 2005. The remaining net proceeds will
be used as permitted by our existing bond indentures.

     Tender  Offer for First  Priority  Notes.  On June 9, 2005,  we commenced a
tender offer for any and all of our $785 million aggregate principal amount of 9
5/8% First Priority  Senior Secured Notes due 2014, or the First Priority Notes,
as are  validly  tendered  and not  withdrawn,  at a price of $1,000  per $1,000
principal  amount of First Priority  Notes,  plus accrued and unpaid interest up
to, and including,  the purchase date for the tender offer.  The expiration date
will be July 8, 2005, unless extended or earlier terminated.  As described above
under " -- Potential Sale of Certain Oil and Gas Assets," we recently  commenced
a process with potential buyers to sell our oil and natural gas assets.  If that
sale is  consummated,  it will  qualify as an "Asset  Sale" under the  indenture
governing  the First  Priority  Notes and would  require  us to make an offer to
purchase the First  Priority Notes with the net proceeds of the sale not applied
in  accordance  with the other  permitted  uses under the First  Priority  Notes
indenture.  The tender offer for our First Priority Notes is being made in order
to comply with our  obligations  under the First Priority Notes indenture and to
reduce our  indebtedness  by applying the proceeds of the potential  sale of our
United  States oil and natural gas assets to the purchase of the First  Priority
Notes.  We  currently  anticipate  using  any net  proceeds  arising  from  such
potential oil and natural gas asset sale  remaining  after  consummation  of the
tender  offer to  acquire  new  natural  gas  and/or  geothermal  energy  assets
permitted to be acquired under the First Priority Notes indenture;  however,  we
are not  required  to acquire  such new assets  under the First  Priority  Notes
indenture,  and  there  can be no  assurance  that  we  will  be  successful  in
identifying or acquiring any new assets on acceptable terms, or at all. If we do
not,  within 180 days of receipt of the net proceeds  from the potential oil and
natural gas asset sale,  acquire such new assets, or do not, at our option,  use
all of the net  proceeds  arising from the  potential  oil and natural gas asset
sale  remaining  after  consummation  of  the  tender  offer  in  the  purchase,
redemption or prepayment of First Priority  Notes  remaining  outstanding  after
consummation of the tender offer, then we will, to the extent that the remaining
net proceeds exceed $50 million,  be required under the terms of our second lien
secured  financing  documents to use all remaining net proceeds to make an offer
to purchase our outstanding second priority senior secured indebtedness.

     Although  we expect to  consummate  the sale of the  United  States oil and
natural  gas assets on or prior to the  purchase  date under the First  Priority
Notes  tender  offer,  we have not yet  entered  into  definitive  documentation
related  to the sale of the oil and  natural  gas  assets  and  there  can be no
assurance  that we (i) will be able to do so by the purchase date, or at all, or
be able to do so on terms acceptable to us or (ii) will not make a determination
to abandon the sale of the United States oil and natural gas assets. In any such
event,  we may, among other things,  extend or otherwise  amend or terminate the
First Priority Notes tender offer.

     SEC Informal Inquiry and Request for Documents and Information.  On June 9,
2005,  we filed a Current  Report on Form 8-K with the SEC to disclose  that, in
April 2005,  the  Division  of  Enforcement  of the SEC  informed us that it was
conducting an informal inquiry and asked us to voluntarily provide documents and
information  related  to: (a) our  downward  revision  of our proved oil and gas
reserve  estimates  at year-end  2004 as compared to such  estimates at year-end
2003,  and a  corresponding  impairment  of the  value of  certain  assets,  all
previously  disclosed by us, (b) certain  statements made to various  regulatory
agencies by a terminated  former employee  regarding our  determination of state
sales  and use  taxes,  and (c) our  upward  restatement  in  April  2005 of our
previously  disclosed  net income  for the third  quarter,  and the first  three
quarters, of 2004. We are fully cooperating with the SEC's request for documents
and information.

     Potential  Sales of Certain  Gas-Fired  Power Plants.  On June 14, 2005, we
announced  that we have  entered  into four  separate,  non-binding  asset  sale
agreements for the sale of four of our gas-fired  power plants for a total price
of approximately $357 million. These potential power plant sales are part of our
strategic initiative, described above, to accelerate debt reduction and increase
cash flow.  Three of the four  agreements are with Tenaska Power Fund,  L.P. The
fourth  agreement is with Diamond  Generating  Corporation.  Completion of these
four asset sales is dependent upon the execution of definitive purchase and sale
agreements for each plant and other terms and conditions,  including  regulatory
approvals.  Net proceeds from any power  plantsale  would be used to reduce debt
and as  permitted by our  indentures.  Preliminarily,  we estimate  that we will
record a loss of approximately $250 million as a result of these asset sales.

     $155  Million  Redeemable  Preferred  Share  Offering and $100 Million Loan
Refinancing.  On June 20, 2005, our indirect  subsidiary  Metcalf Energy Center,
LLC,  consummated  the sale of $155  million of  5.5-Year  Redeemable  Preferred
Shares  priced at LIBOR plus 900 basis points.  The proceeds will  ultimately be
used as permitted by our existing bond  indentures.  Concurrent with the closing
of  the  sale  of  the  Redeemable  Preferred  Shares,  Metcalf  entered  into a
five-year,  $100  Million  Senior  Term  Loan at LIBOR  plus 300  basis  points.
Proceeds  from the  Senior  Term  Loan were used to  refinance  all  outstanding
indebtedness under the existing $100 million  non-recourse  construction  credit
facility,  and will be used to pay fees and expenses related to the transaction,
and as otherwise  permitted  by our existing  bond  indentures.  The  Redeemable
Preferred  Shares  were  offered  in the  United  States in a private  placement
transaction  pursuant to Regulation D under the  Securities  Act. The Redeemable
Preferred  Shares have not been registered under the Securities Act, and may not
be offered or sold in the United  States  absent  registration  or an applicable
exemption from registration requirements.

     Amendment of Certificate of Incorporation.  On June 20, 2005, we filed with
the Secretary of State of the State of Delaware an amendment to our  Certificate
of Incorporation declassifying our board of directors.


SUMMARY - REPURCHASES OF OUTSTANDING DEBT

     During the second  quarter of 2005 (through June 15, 2005),  we repurchased
in open  market  transactions  $116.3  million  of the  principal  amount of our
outstanding debt as listed below:

10 1/2% Senior Notes Due 2006..............................   $      3,485,000
7 5/8% Senior Notes Due 2006...............................          1,335,000
8 3/4% Senior Notes Due 2007...............................          3,000,000
7 3/4% Senior Notes Due 2009...............................         35,000,000
8 5/8% Senior Notes Due 2010...............................         37,468,000
8 1/2% Senior Notes Due 2011...............................         36,000,000
                                                              ----------------
  Total....................................................   $    116,288,000

     The  securities,  which  were  trading at a  discount  to par  value,  were
repurchased for approximately $69.6 million in cash.

     We have  agreed,  subject to the  completion  of the offering of our 7 3/4%
Contingent  Convertible  Notes due 2015, to repurchase a total of $338.0 million
in principal  amount of our 8 1/2% Senior  Notes due 2011,  the holders of which
are expected to purchase a portion of the 7 3/4%  Contingent  Convertible  Notes
due 2015. We will use  approximately  $232.3  million of the net proceeds of the
offering  of the 7 3/4%  Contingent  Convertible  Notes  due 2015 to  repurchase
approximately $313.9 million of that total.

     In addition, we have separately agreed, in a transaction not subject to the
completion of the offering of the 7 3/4% Contingent  Convertible Notes due 2015,
to issue to  certain  of the  anticipated  purchasers  of the 7 3/4%  Contingent
Convertible  Notes due 2015 up to approximately  29,000,000 shares of our common
stock  pursuant  to  Section  3(a)(9)  of the  Securities  Act in  exchange  for
approximately  $94,315,000  in  aggregate  principal  amount at  maturity of our
outstanding  Contingent  Convertible Notes due 2014 held by such purchasers.  We
expect to complete this transaction  shortly after the anticipated  closing date
of the sale of the 7 3/4% Contingent Convertible Notes due 2015.

________________________________________________________________________________


SUMMARY - UNAUDITED PRO FORMA CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

     The  following   Unaudited  Pro  Forma  Consolidated   Condensed  Financial
Statements  give  effect to the  pending  disposition  of  Saltend  Cogeneration
Company  Limited  ("SCCL") and Calpine UK  Operations  Limited ("UK OpCo") to be
accounted  for  as  a  discontinued   operation  in  accordance  with  Financial
Accounting  Standards Board ("FASB") Statement of Financial Accounting Standards
("SFAS")  No. 144,  "Accounting  for the  Impairment  or Disposal of  Long-Lived
Assets" ("SFAS No. 144"). The Unaudited Pro Forma Consolidated Condensed Balance
Sheet  reflects the pending  disposition  of SCCL and UK OpCo at March 31, 2005.
Such pro forma  information is based upon the  historical  balance sheet data of
Calpine  Corporation,  SCCL and UK OpCo as of that date. The Unaudited Pro Forma
Consolidated  Condensed  Statements of Operations give effect to the disposition
of SCCL and UK OpCo as if the  disposition  occurred  on January  1,  2002.  The
Unaudited Pro Forma Consolidated  Condensed Financial  Statements should be read
in conjunction with Calpine's Financial Statements and related Notes included in
Calpine Corporation's  Quarterly Report on Form 10-Q for the quarter ended March
31,  2005 and Annual  Report on Form 10-K for the year ended  December  31, 2004
filed with the SEC.

<TABLE>
                      Calpine Corporation and Subsidiaries
           Unaudited Pro Forma Consolidated Condensed Balance Sheet(1)
                                 March 31, 2005
           (In thousands, except for per share amounts and unaudited)
<CAPTION>
                                                                                            Actual      Adjustments    Pro Forma
                                                                                        -------------   -----------   ------------
<S>                                                                                     <C>             <C>           <C>
Assets:
Current assets
  Cash and cash equivalents...........................................................  $     812,612   $   (38,542)  $     774,070
  Accounts receivable, net............................................................      1,034,141       (51,295)        982,846
  Margin deposits and other prepaid expense...........................................        461,097       (19,762)        441,335
  Inventories.........................................................................        148,770        (5,374)        143,396
  Restricted cash.....................................................................        513,753            --         513,753
  Current derivative assets...........................................................        472,643            --         472,643
  Current assets held for sale........................................................             --       114,973         114,973
  Other current assets................................................................        169,068            --         169,068
                                                                                        -------------   -----------   -------------
Total current assets..................................................................  $   3,612,084   $        --   $   3,612,084
                                                                                        -------------   -----------   -------------
  Restricted cash, net of current portion.............................................        194,476            --         194,476
  Notes receivable, net of current portion............................................        200,443            --         200,443
  Project development costs...........................................................        152,407            --         152,407
  Unconsolidated investments..........................................................        387,639            --         387,639
  Deferred financing costs............................................................        423,122            --         423,122
  Prepaid lease, net of current portion...............................................        431,600       (12,930)        418,670
  Property, plant and equipment, net..................................................     20,712,038    (1,056,269)     19,655,769
  Goodwill............................................................................         45,160            --          45,160
  Other intangible assets, net........................................................         72,009        (4,544)         67,465
  Long-term derivative assets.........................................................        658,440            --         658,440
  Long-term assets held for sale......................................................             --     1,077,263       1,077,263
  Other assets........................................................................        690,049        (3,520)        686,529
                                                                                        -------------   -----------   -------------
Total assets..........................................................................  $  27,579,467   $        --   $  27,579,467
                                                                                        =============   ===========   =============
Liabilities and stockholders' equity:
Current liabilities
  Accounts payable....................................................................        945,578       (42,127)        903,451
  Accrued payroll and related expense.................................................         65,555          (291)         65,264
  Accrued interest payable............................................................        396,175            --         396,175
  Income taxes payable................................................................         79,163            --          79,163
  Notes payable and borrowings under lines of credit, current  portion................        209,652            --         209,652
  Preferred interests, current portion(2).............................................        268,794            --         268,794
  Capital lease obligation, current portion...........................................          5,780            --           5,780
  CCFC I financing, current portion...................................................          3,208            --           3,208
  Construction/project financing, current portion.....................................        100,773            --         100,773
  Senior notes and term loans, current portion........................................        922,489            --         922,489
  Current derivative liabilities......................................................        626,125       (43,291)        582,834
  Current liabilities held for sale...................................................             --        93,169          93,169
  Other current liabilities...........................................................        287,940        (7,460)        280,480
                                                                                        -------------   -----------   -------------
Total current liabilities.............................................................  $   3,911,232   $        --   $   3,911,232
                                                                                        -------------   -----------   -------------
  Notes payable and borrowings under lines of credit, net of current portion..........        682,429            --         682,429
  Convertible debentures payable to Calpine Capital Trust  III........................        517,500            --         517,500
  Preferred interests, net of current portion(3)......................................        493,396            --         493,396
  Capital lease obligation, net of current portion....................................        281,756            --         281,756
  CCFC I financing, net of current portion............................................        782,020            --         782,020
  CalGen/CCFC II financing............................................................      2,395,795            --       2,395,795
  Construction/project financing, net of current portion..............................      2,003,443            --       2,003,443
  Convertible Senior Notes Due 2006...................................................          1,311            --           1,311
  Convertible Notes Due 2014..........................................................        623,429            --         623,429
  Convertible Senior Notes Due 2023...................................................        633,775            --         633,775
  Senior notes and term loans, net of current portion.................................      8,218,408            --       8,218,408
  Deferred income taxes, net of current portion.......................................        925,365       (51,725)        873,640
  Deferred revenue....................................................................        116,041            --         116,041
  Long-term derivative liabilities....................................................        903,824       (13,006)        890,818
  Long-term liabilities held for sale.................................................             --        82,611          82,611
  Other liabilities...................................................................        351,389       (17,880)        333,509
                                                                                        -------------   -----------   -------------
Total liabilities.....................................................................  $  22,841,113   $        --   $  22,841,113
                                                                                        -------------   -----------   -------------
  Minority Interests..................................................................        388,499            --         388,499
                                                                                        -------------   -----------   -------------
Stockholders' equity
  Preferred stock, $.001 par value per share; authorized 10,000,000 shares;
   none issued and outstanding in 2005................................................             --            --              --
  Common stock, $.001 par value per share; authorized 2,000,000,000 shares;
   issued and outstanding 538,017,458 shares in 2005..................................            538            --             538
  Additional paid-in capital..........................................................      3,159,385            --       3,159,385
  Additional paid-in capital, loaned shares...........................................        258,100            --         258,100
  Additional paid-in capital, returnable shares.......................................       (258,100)           --        (258,100)
  Retained earnings...................................................................      1,157,317            --       1,157,317
  Accumulated other comprehensive income..............................................         32,615            --          32,615
                                                                                        -------------   -----------   -------------
Total stockholders' equity............................................................  $   4,349,855   $        --   $   4,349,855
                                                                                        -------------   -----------   -------------
Total liabilities and stockholders' equity............................................  $  27,579,467   $        --   $  27,579,467
                                                                                        =============   ===========   =============
------------
<FN>
(1)  The Pro Forma  Consolidated  Condensed  Balance Sheet  reflects the pending
     disposition of SCCL and UK OpCo at March 31, 2005. The balances of SCCL and
     UK OpCo as of March 31, 2005 have been  reclassified  as "held for sale" on
     the Pro Forma Consolidated Condensed Balance Sheet. Gross proceeds from the
     sale are expected to be (Pound)490  million plus an adjustment  for working
     capital  which was  estimated to be US$19  million as of May 28, 2005,  the
     date the Share Sale and Purchase  Agreement was entered into.  Actual sales
     proceeds in U.S.  dollars may fluctuate due to exchange rate  variances and
     changes  in  working  capital  prior  to the  close of the  sale,  which is
     expected to occur on July 26, 2005.

(2)  Includes $260 million of Redeemable Preferred Shares due July 30, 2005. The
     offerings of the $260 million Redeemable Preferred Shares due July 30, 2005
     and the two-year, $360 million Redeemable Preferred Shares will be redeemed
     using  the  proceeds  of the sale of SCCL and UK OpCo,  which is  currently
     anticipated  to close on July 26, 2005.  Remaining  proceeds  from the sale
     will be used as permitted by our existing bond indentures.

(3)  Includes  $360  million  of  two-year  Redeemable   Preferred  Shares.  The
     offerings of the two-year, $360 million Redeemable Preferred Shares and the
     $260 million Redeemable Preferred Shares due July 30, 2005 will be redeemed
     using the proceeds of the sale of SCCL and UK OpCo as described in Note 2.
</FN>
</TABLE>


<PAGE>

<TABLE>
                      Calpine Corporation and Subsidiaries
      Unaudited Pro Forma Consolidated Condensed Statement of Operations(1)
                    For the Three Months Ended March 31, 2005
                  (In thousands, except for per share amounts)
<CAPTION>
                                                                                   Actual          Adjustments(4)        Pro Forma
                                                                                -----------        --------------       -----------
<S>                                                                             <C>                 <C>                 <C>
Revenue:
Electric generation and marketing revenue
  Electricity and steam revenue ........................................        $ 1,403,549         $  (125,270)        $ 1,278,279
  Transmission sales revenue ...........................................              3,744                  --               3,744
  Sales of purchased power for hedging and optimization ................            356,130              (8,720)            347,410
                                                                                -----------         -----------         -----------
   Total electric generation and marketing revenue .....................          1,763,423            (133,990)          1,629,433
Oil and gas production and marketing revenue
  Oil and gas sales ....................................................             10,820                  --              10,820
  Sales of purchased gas for hedging and optimization ..................            420,296                  --             420,296
                                                                                -----------         -----------         -----------
   Total oil and gas production and marketing revenue ..................            431,116                  --             431,116
Mark-to-market activities, net .........................................             (3,531)                 --              (3,531)
Other revenue ..........................................................             21,670                (484)             21,186
                                                                                -----------         -----------         -----------
Total revenue ..........................................................          2,212,678            (134,474)          2,078,204
                                                                                -----------         -----------         -----------
Cost of revenue:
Electric generation and marketing expense
  Plant operating expense ..............................................            195,626             (13,377)            182,249
  Transmission purchase expense ........................................             23,510              (2,636)             20,874
  Royalty expense ......................................................             10,329                  --              10,329
  Purchased power expenses for hedging and optimization ................            288,787              (7,592)            281,195
                                                                                -----------         -----------         -----------
   Total electric generation and marketing expense .....................            518,252             (23,605)            494,647
Oil and gas operating and marketing expense
  Oil and gas operating expense ........................................             13,000                  --              13,000
  Purchased gas expense for hedging and optimization ...................            413,259                  --             413,259
                                                                                -----------         -----------         -----------
   Total oil and gas operating and marketing expense ...................            426,259                  --             426,259
Fuel expense ...........................................................            921,349             (66,817)            854,532
Depreciation, depletion and amortization expense .......................            143,228              (7,398)            135,830
Operating lease expense ................................................             24,777                  --              24,777
Other cost of revenue ..................................................             38,171                  --              38,171
                                                                                -----------         -----------         -----------
Total cost of revenue ..................................................          2,072,036             (97,820)          1,974,216
                                                                                -----------         -----------         -----------
Gross Profit ...........................................................            140,642             (36,654)            103,988
(Income) loss from unconsolidated investments ..........................             (6,064)                 --              (6,064)
Equipment cancellation and impairment cost .............................                (73)                 --                 (73)
Project development expense ............................................              8,720                  --               8,720
Research and development expense .......................................              7,034                  --               7,034
Sales, general and administrative expense ..............................             57,137                (723)             56,414
                                                                                -----------         -----------         -----------
Income (loss) from operations ..........................................             73,888             (35,931)             37,957
Interest expense .......................................................            348,937             (14,479)            334,458
Interest (income) ......................................................            (14,331)                340             (13,991)
Minority interest expense ..............................................             10,614                  --              10,614
(Income) from repurchase of various issuances of debt ..................            (21,772)                 --             (21,772)
Other expense (income), net ............................................              3,980              (9,122)             (5,142)
                                                                                -----------         -----------         -----------
Income (Loss) before provision or benefit for income taxes .............           (253,540)            (12,670)           (266,210)
Provision (Benefit) for income taxes(2) ................................            (84,809)             (3,801)            (88,610)
                                                                                -----------         -----------         -----------
Income (Loss) from continuing operations(3) ............................        $  (168,731)        $    (8,869)        $  (177,600)
                                                                                ===========         ===========         ===========
Basic and diluted loss per common share:
  Weighted average shares of common stock outstanding ..................            447,599                                 447,599
  Loss from continuing operations(3) ...................................              (0.38)                                  (0.40)

------------
<FN>
(1)  The Pro Forma Consolidated  Condensed  Statement of Operations assumes that
     SCCL and UK OpCo were sold by Calpine on  January 1, 2002.  The  results of
     SCCL  and UK  OpCo  have  been  removed  from  the Pro  Forma  Consolidated
     Condensed  Statement of Operations.  The anticipated  gain/loss  associated
     with the sales  transaction is not included  within Pro Forma  Consolidated
     Condensed Statement of Operations.

(2)  The Pro Forma adjustments in the Pro Forma Consolidated Condensed Statement
     of Operations are tax effected at a rate of 30%, which represents Calpine's
     statutory tax rate in the United Kingdom.  Actual  adjustments to Calpine's
     Consolidated Financial Statements to reflect this disposition may reflect a
     different effective tax rate.

(3)  Represents income before discontinued operations and cumulative effect of a
     change in accounting principle.

(4)  The Pro Forma adjustments in the Unaudited Pro Forma Consolidated Condensed
     Statement of Operations  include certain sales,  general and administrative
     expenses allocated to SCCL and UK OpCo based on a proportion of base wages.
     These  expenses were  originally  recorded in the accounts of other Calpine
     subsidiaries.  Accordingly,  these  expenses have been included  within the
     SCCL and UK OpCo income figures to determine the Pro Forma totals.  For the
     three months ended March 31, 2005, these expenses totaled $0.6 million. The
     Pro Forma  adjustments  also  include  interest  expense  that we expect to
     allocate to discontinued operations in accordance with Emerging Issues Task
     Force  ("EITF") Issue No. 87-24,  "Allocation  of Interest to  Discontinued
     Operations"  ("EITF Issue No. 87-24").  We include interest expense on debt
     which is  required  to be repaid as a result of a disposal  transaction  in
     discontinued operations.  Additionally,  other interest expense that cannot
     be  attributed  to other  operations  of Calpine is allocated  based on the
     ratio of net assets to be sold less debt that is  required  to be paid as a
     result  of the  disposal  transaction  to the sum of total  net  assets  of
     Calpine plus the  consolidated  debt of Calpine,  excluding (a) debt of the
     discontinued  operation that will be assumed by the buyer, (b) debt that is
     required to be paid as a result of the  disposal  transaction  and (c) debt
     that can be directly  attributed to other  operations  of Calpine.  For the
     three months ended March 31, 2005, the interest  expense  allocated  within
     the Unaudited Pro Forma Consolidated  Condensed  Statement of Operations is
     $12.4 million.
</FN>
</TABLE>


<PAGE>

<TABLE>
                      Calpine Corporation and Subsidiaries
      Unaudited Pro Forma Consolidated Condensed Statement of Operations(1)
                          Year Ended December 31, 2004
                  (In thousands, except for per share amounts)
<CAPTION>
                                                                                   Actual          Adjustments(4)        Pro Forma
                                                                                -----------        --------------       -----------
<S>                                                                             <C>                 <C>                 <C>
Revenue:
Electric generation and marketing revenue
  Electricity and steam revenue ........................................        $ 5,683,063         $  (385,244)        $ 5,297,819
  Transmission sales revenue ...........................................             20,003                  --              20,003
  Sales of purchased power for hedging and optimization ................          1,651,767              (3,775)          1,647,992
                                                                                -----------         -----------         -----------
   Total electric generation and marketing revenue .....................          7,354,833            (389,019)          6,965,814
Oil and gas production and marketing revenue
  Oil and gas sales ....................................................             63,153                  --              63,153
  Sales of purchased gas for hedging and optimization ..................          1,728,301                  --           1,728,301
                                                                                -----------         -----------         -----------
   Total oil and gas production and marketing revenue ..................          1,791,454                  --           1,791,454
Mark-to-market activities, net .........................................             13,532                (127)             13,405
Other revenue ..........................................................             70,069                (880)             69,189
                                                                                -----------         -----------         -----------
Total revenue ..........................................................          9,229,888            (390,026)          8,839,862
                                                                                -----------         -----------         -----------
Cost of revenue:
Electric generation and marketing expense
  Plant operating expense ..............................................            795,975             (50,271)            745,704
  Transmission purchase expense ........................................             85,514             (10,697)             74,817
  Royalty expense ......................................................             28,673                  --              28,673
  Purchased power expenses for hedging and optimization ................          1,487,020              (4,758)          1,482,262
                                                                                -----------         -----------         -----------
   Total electric generation and marketing expense .....................          2,397,182             (65,726)          2,331,456
Oil and gas operating and marketing expense
  Oil and gas operating expense ........................................             56,843                  --              56,843
  Purchased gas expense for hedging and optimization ...................          1,716,714                  --           1,716,714
                                                                                -----------         -----------         -----------
   Total oil and gas operating and marketing expense ...................          1,773,557                  --           1,773,557
Fuel expense ...........................................................          3,731,108            (228,279)          3,502,829
Depreciation, depletion and amortization expense .......................            574,200             (28,862)            545,338
Oil and gas impairment .................................................            202,120                  --             202,120
Operating lease expense ................................................            105,886                  --             105,886
Other cost of revenue ..................................................             90,742                  --              90,742
                                                                                -----------         -----------         -----------
Total cost of revenue ..................................................          8,874,795            (322,867)          8,551,928
                                                                                -----------         -----------         -----------
Gross Profit ...........................................................            355,093             (67,159)            287,934
(Income) loss from unconsolidated investments ..........................             13,525                  --              13,525
Equipment cancellation and impairment cost .............................             42,374                  --              42,374
Long-term service agreement cancellation charge ........................             11,334                  --              11,334
Project development expense ............................................             24,409                  --              24,409
Research and development expense .......................................             18,396                  --              18,396
Sales, general and administrative expense ..............................            239,347              (1,870)            237,477
                                                                                -----------         -----------         -----------
Income (loss) from operations ..........................................              5,708             (65,289)            (59,581)
Interest expense .......................................................          1,140,802             (16,384)          1,124,418
Interest (income) ......................................................            (56,412)              1,598             (54,814)
Minority interest expense ..............................................             34,735                  --              34,735
(Income) from repurchase of various issuances of debt ..................           (246,949)                 --            (246,949)
Other expense (income), net ............................................           (149,093)             24,520            (124,573)
                                                                                -----------         -----------         -----------
Income (Loss) before provision or (benefit) for income taxes ...........           (717,375)            (75,023)           (792,398)
Provision (Benefit) for income taxes(2) ................................           (276,549)            (22,507)           (299,056)
                                                                                -----------         -----------         -----------
Income (Loss) from continuing operations(3) ............................        $  (440,826)        $   (52,516)        $  (493,342)
                                                                                ===========         ===========         ===========
Basic and diluted loss per common share:
  Weighted average shares of common stock outstanding...................            430,775                                 430,775
  Loss from continuing operations(3)....................................              (1.02)                                  (1.15)

------------
<FN>
(1)  The Pro Forma Consolidated  Condensed  Statement of Operations assumes that
     SCCL and UK OpCo were sold by Calpine on  January 1, 2002.  The  results of
     SCCL  and  UK  OpCo  have  been  removed  from  the   Unaudited  Pro  Forma
     Consolidated  Condensed Statement of Operations.  The anticipated gain/loss
     associated with the sales  transaction is not included within the Unaudited
     Pro Forma Consolidated Condensed Statement of Operations.

(2)  The Pro Forma adjustments in the Unaudited Pro Forma Consolidated Condensed
     Statement of Operations are tax effected at a rate of 30%, which represents
     Calpine's  statutory tax rate in the United Kingdom.  Actual adjustments to
     Calpine's Consolidated Financial Statements to reflect this disposition may
     reflect a different effective tax rate.

(3)  Represents income before discontinued operations and cumulative effect of a
     change in accounting principle.

(4)  The Pro Forma adjustments in the Unaudited Pro Forma Consolidated Condensed
     Statement of Operations  include certain sales,  general and administrative
     expenses allocated to SCCL and UK OpCo based on a proportion of base wages.
     These  expenses were  originally  recorded in the accounts of other Calpine
     subsidiaries.  Accordingly,  these  expenses have been included  within the
     SCCL and UK OpCo income figures to determine the Pro Forma totals. In 2004,
     these expenses totaled $1.7 million. The Pro Forma adjustments also include
     interest  expense that we expect to allocate to discontinued  operations in
     accordance with EITF Issue No. 87-24. We include  interest  expense on debt
     which is  required  to be repaid as a result of a disposal  transaction  in
     discontinued operations.  Additionally,  other interest expense that cannot
     be  attributed  to other  operations  of Calpine is allocated  based on the
     ratio of net assets to be sold less debt that is  required  to be paid as a
     result  of the  disposal  transaction  to the sum of total  net  assets  of
     Calpine plus the  consolidated  debt of Calpine,  excluding (a) debt of the
     discontinued  operation that will be assumed by the buyer, (b) debt that is
     required to be paid as a result of the  disposal  transaction  and (c) debt
     that can be directly  attributed to other operations of Calpine.  For 2004,
     the interest expense allocated within the Unaudited Pro Forma  Consolidated
     Condensed Statement of Operations is $14.8 million.
</FN>
</TABLE>


<PAGE>

<TABLE>
                      Calpine Corporation and Subsidiaries
      Unaudited Pro Forma Consolidated Condensed Statement of Operations(1)
                          Year Ended December 31, 2003
                  (In thousands, except for per share amounts)
<CAPTION>
                                                                                   Actual          Adjustments(4)        Pro Forma
                                                                                -----------        --------------       -----------
<S>                                                                             <C>                 <C>                 <C>
Revenue:
Electric generation and marketing revenue
  Electricity and steam revenue ........................................        $ 4,680,397         $  (286,936)        $ 4,393,461
  Transmission sales revenue ...........................................             15,347                  --              15,347
  Sales of purchased power for hedging and optimization ................          2,714,187              (1,896)          2,712,291
                                                                                -----------         -----------         -----------
   Total electric generation and marketing revenue .....................          7,409,931            (288,832)          7,121,099
Oil and gas production and marketing revenue
 Oil and gas sales .....................................................             59,156                  --              59,156
  Sales of purchased gas for hedging and optimization ..................          1,320,902                  --           1,320,902
                                                                                -----------         -----------         -----------
   Total oil and gas production and marketing revenue ..................          1,380,058                  --           1,380,058
Mark-to-market activities, net .........................................            (26,439)                 --             (26,439)
Other revenue ..........................................................            107,483              (1,246)            106,237
                                                                                -----------         -----------         -----------
Total revenue ..........................................................          8,871,033            (290,078)          8,580,955
                                                                                -----------         -----------         -----------
Cost of revenue:
Electric generation and marketing expense
  Plant operating expense ..............................................            663,045             (46,607)            616,438
  Transmission purchase expense ........................................             46,455             (11,765)             34,690
  Royalty expense ......................................................             24,932                  --              24,932
  Purchased power expenses for hedging and optimization ................          2,690,069              (6,781)          2,683,288
                                                                                -----------         -----------         -----------
   Total electric generation and marketing expense .....................          3,424,501             (65,153)          3,359,348
Oil and gas operating and marketing expense
  Oil and gas operating expense ........................................             75,453                  --              75,453
  Purchased gas expense for hedging and optimization ...................          1,279,568                  --           1,279,568
                                                                                -----------         -----------         -----------
   Total oil and gas operating and marketing expense ...................          1,355,021                  --           1,355,021
Fuel expense ...........................................................          2,665,620            (185,696)          2,479,924
Depreciation, depletion and amortization expense .......................            504,383             (31,511)            472,872
Oil and gas impairment .................................................              2,931                  --               2,931
Operating lease expense ................................................            112,070                  --             112,070
Other cost of revenue ..................................................             42,270                  26              42,296
                                                                                -----------         -----------         -----------
Total cost of revenue ..................................................          8,106,796            (282,334)          7,824,462
                                                                                -----------         -----------         -----------
Gross Profit ...........................................................            764,237              (7,744)            756,493
(Income) loss from unconsolidated investments ..........................            (75,804)                 --             (75,804)
Equipment cancellation and impairment cost .............................             64,384                  --              64,384
Long-term service agreement cancellation charge ........................             16,355                  --              16,355
Project development expense ............................................             21,803                  --              21,803
Research and development expense .......................................             10,630                  --              10,630
Sales, general and administrative expense ..............................            216,471              (2,225)            214,246
                                                                                -----------         -----------         -----------
Income from operations .................................................            510,398              (5,519)            504,879
Interest expense .......................................................            706,307              (6,313)            699,994
Distributions on trust preferred securities ............................             46,610                  --              46,610
Interest (income) ......................................................            (39,716)                425             (39,291)
Minority interest expense ..............................................             27,330                  --              27,330
(Income) from repurchase of various issuances of debt ..................           (278,612)                 --            (278,612)
Other expense (income), net ............................................            (46,126)               (925)            (47,051)
                                                                                -----------         -----------         -----------
Income (loss) before provision or benefit for income taxes .............             94,605               1,294              95,899
Provision (benefit) for income taxes(2) ................................              8,495                 388               8,883
                                                                                -----------         -----------         -----------
Income from continuing operations(3) ...................................        $    86,110         $       906         $    87,016
                                                                                ===========         ===========         ===========
Basic earnings per common share:
  Weighted average shares of common stock outstanding ..................            390,772                                 390,772
  Income from continuing operations(3) .................................               0.22                                    0.22
Diluted earnings per common share:
  Weighted average shares of common stock outstanding before
   dilutive effect of certain convertible securities (3)................            396,219                                 396,219
  Income from continuing operations(3)..................................               0.22                                    0.22

------------
<FN>
(1)  The  Unaudited  Pro Forma  Consolidated  Condensed  Statement of Operations
     assumes that SCCL and UK OpCo were sold by Calpine on January 1, 2002.  The
     results of SCCL and UK OpCo have been removed from the  Unaudited Pro Forma
     Consolidated  Condensed Statement of Operations.  The anticipated gain/loss
     associated with the sales  transaction is not included within the Unaudited
     Pro Forma Consolidated Condensed Statement of Operations.

(2)  The Pro Forma adjustments in the Unaudited Pro Forma Consolidated Condensed
     Statement of Operations are tax effected at a rate of 30%, which represents
     Calpine's  statutory tax rate in the United Kingdom.  Actual adjustments to
     Calpine's Consolidated Financial Statements to reflect this disposition may
     reflect a different effective tax rate.

(3)  Represents income before discontinued operations and cumulative effect of a
     change in accounting principle.

(4)  The Pro Forma adjustments in the Unaudited Pro Forma Consolidated Condensed
     Statement of Operations  include certain sales,  general and administrative
     expenses allocated to SCCL and UK OpCo based on a proportion of base wages.
     These  expenses were  originally  recorded in the accounts of other Calpine
     subsidiaries.  Accordingly,  these  expenses have been included  within the
     SCCL and UK OpCo income figures to determine the Pro Forma totals. In 2003,
     these expenses totaled $2.1 million. The Pro Forma adjustments also include
     interest  expense that we expect to allocate to discontinued  operations in
     accordance with EITF Issue No. 87-24. We include  interest  expense on debt
     which is  required  to be repaid as a result of a disposal  transaction  in
     discontinued operations.  Additionally,  other interest expense that cannot
     be  attributed  to other  operations  of Calpine is allocated  based on the
     ratio of net assets to be sold less debt that is  required  to be paid as a
     result  of the  disposal  transaction  to the sum of total  net  assets  of
     Calpine plus the  consolidated  debt of Calpine,  excluding (a) debt of the
     discontinued  operation that will be assumed by the buyer, (b) debt that is
     required to be paid as a result of the  disposal  transaction  and (c) debt
     that can be directly  attributed to other operations of Calpine.  For 2003,
     the interest expense allocated within the Unaudited Pro Forma  Consolidated
     Condensed Statement of Operations is $6.3 million.
</FN>
</TABLE>


<PAGE>

<TABLE>
                      Calpine Corporation and Subsidiaries
      Unaudited Pro Forma Consolidated Condensed Statement of Operations(1)
                          Year Ended December 31, 2002
                  (In thousands, except for per share amounts)
<CAPTION>
                                                                                   Actual          Adjustments(4)        Pro Forma
                                                                                -----------        --------------       -----------
<S>                                                                             <C>                 <C>                 <C>
Revenue:
Electric generation and marketing revenue
Electricity and steam revenue ..........................................        $ 3,237,510         $  (205,779)        $ 3,031,731
  Sales of purchased power for hedging and optimization ................          3,145,991                  (2)          3,145,989
                                                                                -----------         -----------         -----------
   Total electric generation and marketing revenue .....................          6,383,501            (205,781)          6,177,720
Oil and gas production and marketing revenue
  Oil and gas sales ....................................................             63,514                  --              63,514
  Sales of purchased gas for hedging and optimization ..................            870,466                   1             870,467
                                                                                -----------         -----------         -----------
   Total oil and gas production and marketing revenue ..................            933,980                   1             933,981
Mark-to-market activities, net .........................................             21,485                  --              21,485
Other revenue ..........................................................             10,787                (104)             10,683
                                                                                -----------         -----------         -----------
Total revenue ..........................................................          7,349,753            (205,884)          7,143,869
                                                                                -----------         -----------         -----------
Cost of revenue:
Electric generation and marketing expense
  Plant operating expense ..............................................            522,906             (39,740)            483,166
  Transmission purchase expense ........................................             25,486             (10,179)             15,307
  Royalty expense ......................................................             17,615                  --              17,615
  Purchased power expenses for hedging and optimization ................          2,618,445                  --           2,618,445
                                                                                -----------         -----------         -----------
   Total electric generation and marketing expense .....................          3,184,452             (49,919)          3,134,533
                                                                                -----------         -----------         -----------
Oil and gas operating and marketing expense
  Oil and gas operating expense ........................................             69,840                  --              69,840
  Purchased gas expense for hedging and optimization ...................            821,065                  --             821,065
                                                                                -----------         -----------         -----------
   Total oil and gas operating and marketing expense ...................            890,905                  --             890,905
Fuel expense ...........................................................          1,792,323            (161,048)          1,631,275
Depreciation, depletion and amortization expense .......................            398,889             (32,082)            366,807
Oil and gas impairment .................................................              3,399                  --               3,399
Operating lease expense ................................................            111,022                  --             111,022
Other cost of revenue ..................................................              7,279                  --               7,279
                                                                                -----------         -----------         -----------
Total cost of revenue ..................................................          6,388,269            (243,049)          6,145,220
                                                                                -----------         -----------         -----------
Gross Profit ...........................................................            961,484              37,165             998,649
(Income) loss from unconsolidated investments ..........................            (16,552)                 --             (16,552)
Equipment cancellation and impairment cost .............................            404,737                  --             404,737
Project development expense ............................................             66,981                  --              66,981
Research and development expense .......................................              9,986                  --               9,986
Sales, general and administrative expense ..............................            186,056              (2,057)            183,999
                                                                                -----------         -----------         -----------
Income from operations .................................................            310,276              39,222             349,498
Interest expense .......................................................            402,677              (5,295)            397,382
Distributions on trust preferred securities ............................             62,632                  --              62,632
Interest (income) ......................................................            (43,086)                654             (42,432)
Minority interest expense ..............................................              2,716                  --               2,716
(Income) from repurchase of various issuances of debt ..................           (118,020)                 --            (118,020)
Other expense (income), net ............................................            (34,200)             (2,130)            (36,330)
                                                                                -----------         -----------         -----------
Income (loss) before provision or benefit for income taxes .............             37,557              45,993              83,550
Provision (benefit) for income taxes(2) ................................             10,835              13,797              24,632
                                                                                -----------         -----------         -----------
Income (loss) from continuing operations(3) ............................        $    26,722         $    32,196         $    58,918
                                                                                ===========         ===========         ===========
Basic earnings per common share:
  Weighted average shares of common stock outstanding ..................            354,822                                  354,822
  Income from continuing operations(3) .................................               0.07                                     0.17
Diluted earnings per common share:
  Weighted average shares of common stock outstanding before
   dilutive effect of certain convertible securities (3) ...............            362,533                                  362,533
  Income from continuing operations(3) .................................               0.07                                     0.16

------------
<FN>
(1)  The  Unaudited  Pro Forma  Consolidated  Condensed  Statement of Operations
     assumes that SCCL and UK OpCo were sold by Calpine on January 1, 2002.  The
     results of SCCL and UK OpCo have been removed from the  Unaudited Pro Forma
     Consolidated  Condensed Statement of Operations.  The anticipated gain/loss
     associated with the sales  transaction is not included within the Unaudited
     Pro Forma Consolidated Condensed Statement of Operations.

(2)  The Pro Forma adjustments in the Unaudited Pro Forma Consolidated Condensed
     Statement of Operations are tax effected at a rate of 30%, which represents
     Calpine's  statutory tax rate in the United Kingdom.  Actual adjustments to
     Calpine's Consolidated Financial Statements to reflect this disposition may
     reflect a different effective tax rate.

(3)  Represents income before discontinued operations and cumulative effect of a
     change in accounting principle.

(4)  The Pro Forma adjustments in the Unaudited Pro Forma Consolidated Condensed
     Statement of Operations  include certain sales,  general and administrative
     expenses allocated to SCCL and UK OpCo based on a proportion of base wages.
     These  expenses were  originally  recorded in the accounts of other Calpine
     subsidiaries.  Accordingly,  these  expenses have been included  within the
     SCCL and UK OpCo income figures to determine the Pro Forma totals. In 2002,
     these expenses totaled $2.1 million. The Pro Forma adjustments also include
     interest  expense that we expect to allocate to discontinued  operations in
     accordance with EITF Issue No. 87-24. We include  interest  expense on debt
     which is  required  to be repaid as a result of a disposal  transaction  in
     discontinued operations.  Additionally,  other interest expense that cannot
     be  attributed  to other  operations  of Calpine is allocated  based on the
     ratio of net assets to be sold less debt that is  required  to be paid as a
     result  of the  disposal  transaction  to the sum of total  net  assets  of
     Calpine plus the  consolidated  debt of Calpine,  excluding (a) debt of the
     discontinued  operation that will be assumed by the buyer, (b) debt that is
     required to be paid as a result of the  disposal  transaction  and (c) debt
     that can be directly  attributed to other operations of Calpine.  For 2002,
     the interest expense allocated within the Unaudited Pro Forma  Consolidated
     Condensed Statement of Operations is $5.1 million.
</FN>
</TABLE>
________________________________________________________________________________

RISK FACTORS

Risks Relating to Our Common Stock

     The effect of the issuance of our shares upon conversion of our convertible
notes may lower the market price of our common stock. The effect of the increase
in the number of shares of our common stock issued or issuable  upon  conversion
of our convertible notes could have a negative effect on the market price of our
common stock.  Because the right of a holder of contingent  convertible notes to
convert such notes into cash and shares of our common stock depends, in part, on
the market price of our common  stock,  such a holder may not be able to convert
its contingent  convertible  notes or may receive fewer shares upon  conversion.
The market price of our common stock also could be negatively  affected by short
sales of our common stock by the  purchasers of our  convertible  notes to hedge
investments in such convertible notes.

     The price of our common stock is volatile.  The market price for our common
stock has been volatile in the past,  and several  factors could cause the price
to  fluctuate  substantially  in  the  future.  These  factors  include  without
limitation:

     o    general  conditions  in our  industry,  the power  markets in which we
          participate, or the worldwide economy;

     o    announcements of developments related to our business or sector;

     o    fluctuations in our results of operations;

     o    our debt-to-equity ratios and other leverage ratios;

     o    effects  of  significant  events  relating  to the  energy  sector  in
          general;

     o    issuances,   including  through  sales  or  lending   facilities,   of
          substantial  amounts of our common stock or other  securities into the
          marketplace;

     o    dilution or potential  dilution caused by stock-for-debt  exchanges or
          issuances of indebtedness convertible into our common stock, including
          any exchanges or convertible debt  transactions,  such as the offering
          of the 7 3/4% Contingent Convertible Notes due 2015;

     o    an outbreak of war or hostilities;

     o    a shortfall in revenues or earnings  compared to securities  analysts'
          expectations;

     o    changes in analysts' recommendations or projections; and

     o    announcements of new acquisitions or development projects by us.

     The market price of our common  stock may  fluctuate  significantly  in the
future,  and these  fluctuations  may be unrelated to our  performance.  General
market price declines or market  volatility in the future could adversely affect
the  price  of our  common  stock,  and  the  current  market  price  may not be
indicative of future market prices.

Capital Resources; Liquidity

     To service our indebtedness and other potential  liquidity  requirements we
will require a significant amount of cash. Our cash requirements  (including our
refinancing  obligations) are expected to exceed our  unrestricted  cash on hand
and cash from  operations  for the next twelve  months.  Our ability to generate
cash depends on many factors beyond our control. Our ability to make payments on
and to refinance our indebtedness  and to fund planned capital  expenditures and
research and development  efforts will depend on our ability to generate cash in
the future.  This, to a certain extent,  is subject to industry  conditions,  as
well as general economic, financial,  competitive,  legislative,  regulatory and
other  factors  that are  beyond  our  control.  We may not be able to  generate
sufficient cash to meet all of our commitments.

     Satisfying all obligations under our outstanding indebtedness,  and funding
anticipated capital  expenditures and working capital  requirements for the next
twelve months presents us with several challenges over the near term as our cash
requirements (including our refinancing  obligations) are expected to exceed our
unrestricted  cash on hand and cash  from  operations.  Accordingly,  we have in
place a liquidity-enhancing  program which includes possible sales of certain of
our assets, and whether we will have sufficient liquidity will depend in part on
the success of that program.  See "Summary -- Recent  Developments  -- Strategic
Initiative  to Accelerate  Debt  Reduction and Increase Cash Flow." No assurance
can be given that our  liquidity-enhancing  program will be  successful.  If our
cash  flow  is  insufficient   and   refinancing  or  additional   financing  is
unavailable,  we may be forced to  default  on our  senior  notes and other debt
obligations.  Such a default or other breach of the  covenants  or  restrictions
contained in any of our existing or future debt  instruments  could result in an
event  of  default  under  those  instruments  and,  due  to  cross-default  and
cross-acceleration  provisions, under our other debt instruments.  Upon an event
of default under our debt  instruments,  the debt holders could elect to declare
the entire debt outstanding thereunder to be due and payable and could terminate
any  commitments  they had made to supply us with further funds. If any of these
events occur, we cannot assure you that we will have sufficient  funds available
to repay in full the total amount of obligations  that become due as a result of
any such acceleration, or that we will be able to find additional or alternative
financing to refinance  any  accelerated  obligations.  See the  remaining  risk
factors set forth under " -- Capital Resources; Liquidity" below.

     We must meet ongoing debt  obligations.  We have  substantial  indebtedness
that we incurred to finance the acquisition and development of power  generation
facilities  that we may be unable to service and that restricts our  activities.
As of March  31,  2005,  on an as  adjusted  basis as set  forth in the  summary
balance sheet under the heading "Summary--Summary of Consolidated Financial Data
and Other Data" in our  prospectus  supplement  dated June 20,  2005,  our total
consolidated  funded debt was $18.0 billion,  our total consolidated assets were
$27.5 billion and our stockholders' equity was $4.4 billion.  Whether we will be
able to meet our debt service  obligations and repay,  extend,  or refinance our
outstanding  indebtedness will depend primarily upon the operational performance
of our power generation  facilities and of our oil and natural gas properties to
the extent we  continue  to own them (see  "Summary  -- Recent  Developments  --
Potential  Sale of Certain Oil and  Natural  Gas Assets" and  "Summary -- Recent
Developments  -- Strategic  Initiative to Accelerate Debt Reduction and Increase
Cash  Flow"),  movements  in electric  and  natural  gas prices  over time,  our
marketing  and  risk  management  activities  and our  ability  to  successfully
implement  our strategic  initiative  to increase  liquidity and reduce debt, as
well as general economic, financial,  competitive,  legislative,  regulatory and
other factors that are beyond our control.

     This high level of indebtedness has important consequences, including:

     o    limiting our ability to borrow additional amounts for working capital,
          capital  expenditures,  debt  service  requirements,  execution of our
          growth strategy, or other purposes;

     o    limiting our ability to use operating  cash flow in other areas of our
          business because we must dedicate a substantial portion of these funds
          to service the debt;

     o    increasing our  vulnerability to general adverse economic and industry
          conditions;

     o    limiting our ability to  capitalize on business  opportunities  and to
          react to  competitive  pressures  and  adverse  changes in  government
          regulation;

     o    limiting   our   ability  or   increasing   the  costs  to   refinance
          indebtedness; and

     o    limiting our ability to enter into  marketing,  hedging,  optimization
          and trading transactions by reducing the number of counterparties with
          whom we can transact as well as the volume of those transactions.

     Our  debt   instruments   impose   significant   operating   and  financial
restrictions on us; any failure to comply with these  restrictions  could have a
material adverse effect on our liquidity and our operations.  The indentures and
other instruments  governing our outstanding debt impose  significant  operating
and financial  restrictions on us. These  restrictions could adversely affect us
by limiting our ability to plan for or react to market conditions or to meet our
capital needs.  These restrictions limit or prohibit our ability to, among other
things:

     o    incur additional indebtedness and issue preferred stock;

     o    make prepayments on or purchase indebtedness in whole or in part;

     o    pay  dividends  and other  distributions  with  respect to our capital
          stock  or  repurchase  our  capital  stock  or make  other  restricted
          payments;

     o    make certain investments;

     o    enter into transactions with affiliates;

     o    create or incur liens to secure debt;

     o    consolidate  or  merge  with  another  entity,  or  allow  one  of our
          subsidiaries to do so;

     o    lease,  transfer or sell assets and use  proceeds of  permitted  asset
          leases, transfers or sales;

     o    incur  dividend  or  other  payment  restrictions   affecting  certain
          subsidiaries;

     o    make capital expenditures;

     o    engage in certain business activities; and

     o    acquire facilities or other businesses.

     In  particular,  the covenants in certain of our existing  debt  agreements
currently impose the following restrictions on our activities:

     o    Certain of our  indentures  place  conditions  on our ability to issue
          indebtedness  if our  interest  coverage  ratio (as  defined  in those
          indentures) is below 2:1.  Currently,  our interest coverage ratio (as
          so defined) is below 2:1 and, consequently,  we generally would not be
          allowed  to  issue  new  debt,  except  for (i)  certain  types of new
          indebtedness  that refinances or replaces existing  indebtedness,  and
          (ii)  non-recourse  debt and preferred  equity interests issued by our
          subsidiaries  for  purposes  of  financing  certain  types of  capital
          expenditures,   including   plant   development,    construction   and
          acquisition  expenses.  In  addition,  if and so long as our  interest
          coverage  ratio is below 2:1,  our  ability to invest in  unrestricted
          subsidiaries  and  non-subsidiary  affiliates  and make certain  other
          types of restricted payments will be limited. Moreover, certain of our
          indentures  will prohibit any further  investments  in  non-subsidiary
          affiliates  if and for so  long as our  interest  coverage  ratio  (as
          defined  therein)  is below  1.75:1 and,  as of March 31,  2005,  such
          interest coverage ratio was below 1.75:1.

     o    Certain  of our  indebtedness  issued  in the  last  half of 2004  was
          incurred  in  reliance  on  provisions  in  certain  of  our  existing
          indentures  pursuant  to which we are able to incur  indebtedness  if,
          after  giving  effect to the  incurrence  and the  repayment  of other
          indebtedness with the proceeds therefrom,  our interest coverage ratio
          (as  defined in those  indentures)  is greater  than 2:1.  In order to
          satisfy the interest coverage ratio requirement in connection with the
          2004  issuance,  the proceeds are required to be used to repurchase or
          redeem other existing  indebtedness.  While we completed a substantial
          portion of such repurchases  during the fourth quarter of 2004 and the
          first quarter of 2005,  we are still in the process of completing  the
          required  amount  of  repurchases  and  expect  to do so  as  soon  as
          practicable.  While the  amount  of  indebtedness  that must  still be
          repurchased  will  ultimately  depend  on  the  market  price  of  our
          outstanding  indebtedness at the time the indebtedness is repurchased,
          based on current market conditions,  we estimate that, as of March 31,
          2005,  as  adjusted  for  market  conditions  and  financial  covenant
          calculations,  we would be  required  to  spend  approximately  $294.0
          million  on  additional  repurchases  in order to fully  satisfy  this
          requirement.  This amount has been classified as Senior Notes, current
          portion,  on our Consolidated  Condensed Balance Sheet as of March 31,
          2005.  Subsequent  to March 31,  2005,  we satisfied a portion of such
          requirement  such that,  as of June 1, 2005,  as adjusted as described
          above, we would be required to spend  approximately  $211.0 million on
          additional repurchases.

     o    When we or one of our subsidiaries sells a significant asset or issues
          preferred  equity,  our  indentures  generally  require  that  the net
          proceeds of the transaction be used to make capital expenditures or to
          repurchase or repay certain types of subsidiary indebtedness,  in each
          case within 365 days of the closing date of the transaction.  In light
          of this  requirement,  and taking  into  account the amount of capital
          expenditures   currently   budgeted  for  2005,  we  anticipate   that
          subsequent to March 31, 2005, we will need to use approximately $250.0
          million of the net proceeds of the $360.0 million Two-Year  Redeemable
          Preferred Shares issued by our Calpine (Jersey) Limited  subsidiary on
          October 26, 2004 and approximately  $180.0 million of the net proceeds
          of the  $260.0  million  Redeemable  Preferred  Shares  issued  by our
          Calpine European  Funding  (Jersey) Limited  subsidiary on January 31,
          2005,  to  repurchase  or  repay  certain   subsidiary   indebtedness.
          Accordingly, $430.0 million of long-term debt has been reclassified as
          Senior Notes,  current portion, on our Consolidated  Condensed Balance
          Sheet as of March 31, 2005. The actual amount of the net proceeds that
          will be required to be used to  repurchase  or repay  subsidiary  debt
          will depend upon the actual amount of the net proceeds that is used to
          make capital  expenditures,  which may be more or less than the amount
          currently budgeted. In addition, the net proceeds from the sale of the
          Saltend Energy Centre,  after repayment of the two outstanding  series
          of  Redeemable  Preferred  Shares,  as  well  as the  proceeds  of the
          offering by Metcalf of Redeemable  Preferred Shares, will similarly be
          required to be used within 365 days of the applicable  closing date to
          make capital expenditures or to repurchase or repay certain subsidiary
          indebtedness. We expect that the proceeds of the sale of our remaining
          United  States  oil  and  natural  gas  assets,  if any  such  sale is
          consummated,  will be used as described above under "Summary -- Recent
          Developments  -- Potential Sale of Certain Oil and Natural Gas Assets"
          and " -- Tender Offer for First Priority Notes."

     In addition:  (a) if Calpine  Corporation's  ownership changes, as of March
31,   2005,   on  an  as  adjusted   basis  as   described   under  the  heading
"Capitalization"  in  our  prospectus   supplement  dated  June  20,  2005,  the
indentures and other instruments  governing  approximately  $10.4 billion of our
outstanding  notes and term loans may  require  us to make an offer to  purchase
those notes and term loans,  (b) pursuant to the terms of the  indentures  under
which our  contingent  convertible  notes were issued,  upon the  occurrence  of
certain  defined  triggering  events  (which  include our common stock  reaching
certain price levels),  the holders of such notes have the right to require that
their notes be converted  into a combination  of cash (in an amount equal to the
par value of the notes so converted)  and our common shares (with respect to any
additional  value  required to be delivered to the holders) and (c) with respect
to  our  Contingent  Convertible  Notes  due  2014  and  our 7  3/4%  Contingent
Convertible Notes due 2015, we may not make such payments upon conversion unless
we meet a specified ratio of consolidated cash flow to fixed charges; currently,
we do not satisfy such ratio. We may not have the financial  resources necessary
or may otherwise be restricted  from  purchasing  those notes and term loans, or
making such cash payments to holders of those  contingent  convertible  notes in
these events.

     Our ability to comply with these covenants may be affected by events beyond
our control,  and any material deviations from our forecasts could require us to
seek waivers or amendments of covenants or  alternative  sources of financing or
to reduce  expenditures.  We cannot assure you that such waivers,  amendments or
alternative  financing  could be  obtained,  or if  obtained,  would be on terms
acceptable to us.

     If we are unable to comply with the terms of our  indentures and other debt
agreements,  or if we fail to generate sufficient cash flow from operations,  or
to refinance our debt as described below, we may be required to refinance all or
a portion of our senior notes and other debt or to obtain  additional  financing
or sell  additional  assets.  However,  we may be unable to  refinance or obtain
additional  financing  because of our  already  high levels of debt and the debt
incurrence restrictions under our existing indentures and other debt agreements.
If our cash flow is  insufficient  and  refinancing  or additional  financing is
unavailable,  we may be forced to  default  on our  senior  notes and other debt
obligations.  Such a default or other breach of the  covenants  or  restrictions
contained in any of our existing or future debt  instruments  could result in an
event  of  default  under  those  instruments  and,  due  to  cross-default  and
cross-acceleration  provisions, under our other debt instruments.  Upon an event
of default under our debt  instruments,  the debt holders could elect to declare
the entire debt outstanding thereunder to be due and payable and could terminate
any  commitments  they had made to supply us with further funds. If any of these
events occur, we cannot assure you that we will have sufficient  funds available
to repay in full the total amount of obligations  that become due as a result of
any such acceleration, or that we will be able to find additional or alternative
financing to refinance any accelerated obligations.

     We must either repay or refinance our debt maturing in 2005 and 2006. Since
the  latter  half of 2001,  there  has  been a  significant  contraction  in the
availability of capital for participants in the energy sector. This has been due
to a range of factors,  including uncertainty arising from the collapse of Enron
and a perceived  surplus of electric  generating  capacity.  These  factors have
continued through 2005,  during which  contracting  credit markets and decreased
spark spreads have adversely impacted our liquidity and earnings.  While we have
been  able to  access  the  capital  and  bank  credit  markets,  it has been on
significantly  different  terms  than in the past.  We  recognize  that terms of
financing  available  to us in the  future  may not be  attractive.  To  protect
against this  possibility and due to current market  conditions,  we scaled back
our capital  expenditure  program to enable us to conserve our available capital
resources.

     In 2005, the following  payments will be due on our outstanding  debt as of
March 31,  2005:  (i) $186.1  million in  aggregate  principal  amount of 8 1/4%
Senior Notes Due 2005, (ii) $74.0 million  aggregate  principal  amount of notes
issued by our subsidiary Power Contract Financing,  L.L.C. ("PCF") in connection
with the  monetization of a power contract with  California  Department of Water
Resources  ("CDWR")  and (iii) $260.0  million in  Redeemable  Preferred  Shares
issued by our subsidiary Calpine European Funding (Jersey) Limited. In 2006, the
following  payments will be due on our  outstanding  debt: (i) $111.6 million in
aggregate  principal amount of 7 5/8% Senior Notes Due 2006, (ii) $152.7 million
in aggregate  principal  amount of 10 1/2% Senior  Notes Due 2006,  (iii) $360.0
million in Two-Year Redeemable Preferred Shares issued by our subsidiary Calpine
(Jersey) Limited,  and (iv) $155.9 million in aggregate  principal amount of the
notes issued by PCF in connection with the CDWR power contract monetization.  In
addition,  as of March 31, 2005, we have approximately $136.0 million and $161.3
million of miscellaneous debt and capital lease obligations that are maturing or
for  which  scheduled  principal  payments  will  be  made  in  2005  and  2006,
respectively.  As discussed above, as of March 31, 2005, we are also required to
repurchase  or  redeem  approximately  $724  million  of  indebtedness  (current
estimate) in the  aggregate  pursuant to our  indentures,  approximately  $543.0
million  and $181.0  million  which we expect  will be  repurchased  or redeemed
during  2005  and  2006,  respectively.  See "--  Our  debt  instruments  impose
significant  operating and financial  restrictions  on us; any failure to comply
with these  restrictions  could have a material  adverse effect on our liquidity
and our operations."

     In addition,  our $517.5  million of  outstanding  HIGH TIDES III (of which
$115.0 million have been repurchased and are currently held by us) are scheduled
to be remarketed during July 2005, which would cause certain terms thereof to be
reset on August 1, 2005. We currently  anticipate  repurchasing or redeeming all
of the outstanding  HIGH TIDES III not held by us prior to the remarketing  with
the proceeds from the issuance of the 7 3/4%  Contingent  Convertible  Notes due
2015.  In the event that any HIGH TIDES III are not  repurchased  or redeemed by
the scheduled remarketing date, such remaining HIGH TIDES III will be remarketed
and, if the remarketing fails, will remain outstanding as convertible securities
at a term  rate  equal to the  treasury  rate  plus 6% per annum and with a term
conversion  price equal to 105% of the average closing price of our common stock
for the five consecutive trading days after the final failed remarketing date.

     We cannot assure you that our business will generate  sufficient  cash flow
from  operations or that future  borrowings will be available to us in an amount
sufficient to enable us to pay our  indebtedness  when due, or to fund our other
liquidity needs. We may need to refinance all or a portion of our  indebtedness,
on or before  maturity.  While we believe we will be  successful  in repaying or
refinancing all of our debt on or before maturity,  we cannot assure you that we
will be  able  to do so.  See  "Summary  --  Recent  Developments  --  Strategic
Initiative to Accelerate Debt Reduction and Increase Cash Flow."

     We may not have  sufficient  cash to  service  our  indebtedness  and other
liquidity  requirements.  Our ability to make  payments on and to refinance  our
indebtedness,  and  to  fund  planned  capital  expenditures  and  research  and
development efforts,  will depend on our ability to generate cash in the future.
To date,  we have  obtained cash from our  operations;  borrowings  under credit
facilities; issuance of debt, equity, trust preferred securities and convertible
debentures  and  contingent  convertible  notes;  proceeds  from  sale/leaseback
transactions; sale or partial sale of certain assets; contract monetizations and
project  financing.  Taking  into  account  our  construction  program and other
planned capital expenditures and research and development,  our debt service and
repayment  obligations and our bond repurchase  obligations  described above, we
are currently  projecting that unrestricted cash on hand together with cash from
operations will not by itself be sufficient to meet our cash and liquidity needs
for the year. We have therefore continued, and expanded, our liquidity-enhancing
program,  which program includes the possible sale of certain of our assets. See
"Summary -- Recent  Developments  -- Strategic  Initiative  to  Accelerate  Debt
Reduction  and Increase  Cash Flow," and "--  Potential  Sale of Certain Oil and
Natural Gas  Assets." The success of this  liquidity  program will depend on our
being  able  to  complete  these   anticipated   asset  sale  and   monetization
transactions,  which may in turn be impacted  by a number of factors,  including
general  economic and capital market  conditions;  conditions in energy markets;
regulatory  approvals  and  developments;  limitations  imposed by our  existing
agreements;  and other factors,  many of which are beyond our control.  See also
"-- We may be unable to secure additional  financing in the future." Some of the
anticipated  liquidity  transactions  involve the  monetization or prepayment of
future revenues and could therefore negatively impact cash flow in the near term
and the  future.  While  we  believe  we  will be  successful  in  completing  a
sufficient number of these anticipated  transactions,  we cannot assure you that
we will be able to do so. Accordingly, we may not be able to generate sufficient
cash to meet all of our commitments.

     We may be unable to secure additional  financing in the future.  Each power
generation  facility that we acquire or develop will require substantial capital
investment.  Our  ability to  arrange  financing  (including  any  extension  or
refinancing) and the cost of the financing are dependent upon numerous  factors.
Access to capital  (including any extension or refinancing)  for participants in
the energy sector,  including for us, has been  significantly  restricted  since
late 2001. Other factors include:

     o    general economic and capital market conditions;

     o    conditions in energy markets;

     o    regulatory developments;

     o    credit  availability  from  banks  or  other  lenders  for us and  our
          industry peers, as well as the economy in general;

     o    investor confidence in the industry and in us;

     o    the continued success of our current power generation facilities; and

     o    provisions  of tax and  securities  laws that are conducive to raising
          capital.

     We have financed our existing power  generation  facilities using a variety
of leveraged  financing  structures,  consisting of senior secured and unsecured
indebtedness,  including construction  financing,  project financing,  revolving
credit facilities,  term loans and lease  obligations.  As of March 31, 2005, we
had approximately $18.1 billion of total consolidated funded debt, consisting of
$5.3 billion of secured  construction/project  financing  (including the Calpine
Construction  Finance Company,  L.P. ("CCFC I") and Calpine Generating  Company,
LLC ("CalGen,"  formerly  Calpine  Construction  Finance  Company II, LLC ("CCFC
II")) financings  described below),  $0.3 billion of capital lease  obligations,
$9.1  billion in senior  notes and  institutional  term loans,  $1.3  billion in
convertible senior notes, $0.8 billion in preferred  interests,  $0.5 billion of
HIGH TIDES III and $0.9  billion of secured  and  unsecured  notes  payable  and
borrowings under lines of credit. Additionally,  we had operating leases with an
aggregate  present value of future minimum lease payments of $1.2 billion.  Each
project  financing  and lease  obligation  is structured to be fully paid out of
cash flow  provided by the  facility or  facilities  financed or leased.  In the
event of a default under a financing agreement which we do not cure, the lenders
or lessors would  generally have rights to the facility and any related  assets.
In the event of foreclosure after a default, we might not retain any interest in
the facility.  While we intend to utilize  non-recourse  or lease financing when
appropriate,  market  conditions and other factors may prevent similar financing
for  future  facilities.  It is  possible  that we may be unable  to obtain  the
financing  required  to  develop  our  power  generation   facilities  on  terms
satisfactory  to us.  In  addition,  if new debt is added  to our  current  debt
levels,  the risks  associated  with our  substantial  leverage that we now face
could intensify.

     We  have  from  time  to  time  guaranteed   certain   obligations  of  our
subsidiaries and other affiliates.  Our lenders or lessors may also seek to have
us guarantee  the  indebtedness  for future  facilities.  Guarantees  render our
general  corporate funds vulnerable in the event of a default by the facility or
related  subsidiary.  Additionally,  certain of our  indentures may restrict our
ability to guarantee  future debt,  which could adversely  affect our ability to
fund new  facilities.  Our indentures  generally do not limit the ability of our
subsidiaries  to incur  non-recourse  or lease  financing or to issue  preferred
stock for investment in new facilities.

     Our credit ratings have been downgraded and could be downgraded further. On
May 9, 2005,  Standard & Poor's  lowered its corporate  credit rating on Calpine
Corporation  to  single B- from  single  B. The  outlook  remains  negative.  In
addition,  the  ratings  on  Calpine's  debt and the  ratings on the debt of its
subsidiaries were also lowered by one notch, with a few exceptions.  The ratings
for the following debt issues remained unchanged: the BBB- SPUR rating on Gilroy
Energy Center bonds,  the BB- rating on the Rocky Mountain Energy Center and the
Riverside  Energy Center loans, the CCC+ rating on the third lien debt of CalGen
and the BBB rating on the PCF bonds.

     On May 12, 2005, Moody's Investor Service lowered its senior implied issuer
rating on Calpine  Corporation to B3 from B2. The outlook remains  negative.  In
addition,  the  ratings  on  Calpine's  debt and the  ratings on the debt of its
subsidiaries were also lowered by two notches, with a few exceptions,  including
the ratings for CalGen debt (which were lowered one notch as follows:  its first
priority senior secured  revolving  credit and term loan facilities were lowered
to B2 from B1, its second priority term loans and floating rate notes lowered to
B3 from B2, and its third priority term loans and floating rate notes lowered to
Caa1 from B3), and the ratings for the pass through  certificates issued by each
of South Point Energy Center,  LLC, Broad River Energy,  LLC, and RockGen Energy
Center,  LLC,  which were also lowered to B3 from B2.  Ratings for the following
debt issues were  affirmed  with the outlook  changed to negative  from  stable:
Rocky Mountain Energy Center and the Riverside Energy Center at Ba3. The ratings
for the following debt issues remain  unchanged:  the Gilroy Energy Center,  LLC
senior secured notes at Baa3, and the PCF senior secured notes at Baa2.

     On  October 4, 2004,  Fitch  Ratings  assigned  our first  priority  senior
secured  debt a rating of BB-. At that time,  Fitch also  downgraded  our second
priority  senior secured debt from BB- to B+,  downgraded  our senior  unsecured
debt rating from B- to CCC+, and  reconfirmed our preferred stock rating at CCC.
On May 25, 2005 following the  announcement  of our strategic plan to accelerate
the $3 billion debt  reduction  target to  year-end,  Fitch  Ratings  placed the
credit ratings of Calpine  Corporation on "rating watch  evolving,"  which means
that  Fitch may lower,  maintain,  or raise  their  ratings  on  Calpine's  debt
securities in the near-term.

     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. We cannot assure you that Moody's, Fitch and
S&P will not further  downgrade our credit ratings in the future.  If our credit
ratings  are  downgraded,  we could be required  to,  among  other  things,  pay
additional   interest  under  our  credit  agreements,   or  provide  additional
guarantees,   collateral,   letters  of  credit  or  cash  for  credit   support
obligations,  and it could  increase  our cost of  capital,  make our efforts to
raise capital more difficult and have an adverse impact on our subsidiaries' and
our business, financial condition and results of operations.

     In  light  of  our  current  credit  ratings,  many  of our  customers  and
counterparties  are  requiring  that our and our  subsidiaries'  obligations  be
secured by letters of credit or cash. Banks issuing letters of credit for our or
our  subsidiaries'  accounts  are  similarly  requiring  that the  reimbursement
obligations be cash-collateralized.  In a typical commodities  transaction,  the
amount  of  security   that  must  be  posted  can  change   depending   on  the
mark-to-market  value  of the  transaction.  These  letter  of  credit  and cash
collateral  requirements  increase our cost of doing  business and could have an
adverse impact on our overall liquidity, particularly if there were a call for a
large  amount  of  additional  cash or letter  of  credit  collateral  due to an
unexpectedly large movement in the market price of a commodity. We are exploring
with counterparties and financial institutions various alternative approaches to
credit support,  including the utilization of liens on our generating facilities
and other assets to secure our  subsidiaries'  obligations  under  certain power
purchase  agreements  and  other  commercial  arrangements,   in  lieu  of  cash
collateral  or  letter of  credit  posting  requirements.  On May 25,  2005,  we
announced,  among  other  things,  that  we are in  discussions  with a  leading
financial  institution to form a partnership  that we anticipate would lower our
collateral  requirements.  See  "Summary  -- Recent  Developments  --  Strategic
Initiative  to  Accelerate   Debt   Reduction  and  Increase  Cash  Flow."  Such
alternative arrangements could, however, also add to our cost of doing business.

     Our  ability  to  repay  our  debt  depends  upon  the  performance  of our
subsidiaries.   Almost  all  of  our  operations   are  conducted   through  our
subsidiaries and other  affiliates.  As a result, we depend almost entirely upon
their earnings and cash flow to service our indebtedness,  including our ability
to pay the interest and principal of our senior notes. The financing  agreements
of certain of our  subsidiaries and other  affiliates  generally  restrict their
ability to pay dividends, make distributions,  or otherwise transfer funds to us
prior to the payment of their other  obligations,  including  their  outstanding
debt,  operating  expenses,  lease  payments and reserves.  While certain of our
indentures and other debt instruments limit our ability to enter into agreements
that restrict our ability to receive dividends and other  distributions from our
subsidiaries,   these  limitations  are  subject  to  a  number  of  significant
exceptions  (including  exceptions  permitting such restrictions  arising out of
subsidiary financings).

     We may  utilize  project  financing,  preferred  equity and other  types of
subsidiary financing transactions when appropriate in the future. Our indentures
and other debt instruments  place  limitations on our ability and the ability of
our  subsidiaries to incur  additional  indebtedness.  However,  they permit our
subsidiaries to incur additional construction/project financing indebtedness and
to issue preferred stock to finance the acquisition and development of new power
generation facilities and to engage in certain types of non-recourse  financings
and issuance of preferred  stock.  If new subsidiary debt and preferred stock is
added to our current  debt levels,  the risks  associated  with our  substantial
leverage that we now face could intensify.

     Our senior notes and our other senior debt are effectively  subordinated to
all indebtedness and other  liabilities of our subsidiaries and other affiliates
and may be  effectively  subordinated  to our secured  debt to the extent of the
assets securing such debt. Our  subsidiaries  and other  affiliates are separate
and  distinct  legal  entities  and,  except in limited  circumstances,  have no
obligation  to  pay  any  amounts  due  with  respect  to  our  indebtedness  or
indebtedness  of other  subsidiaries  or  affiliates,  and do not  guarantee the
payment of interest on or  principal of such  indebtedness.  In the event of our
bankruptcy,  liquidation or  reorganization  (or the bankruptcy,  liquidation or
reorganization  of a  subsidiary  or  affiliate),  such  subsidiaries'  or other
affiliates'  creditors,  including trade creditors and holders of debt issued by
such subsidiaries or affiliates,  will generally be entitled to payment of their
claims from the assets of those subsidiaries or affiliates before any assets are
made available for  distribution  to us or the holders of our  indebtedness.  In
addition,  we are also permitted to reorganize our subsidiaries in a manner that
allows  creditors of one subsidiary to collect against assets  currently held by
another subsidiary. As a result, holders of our indebtedness will be effectively
subordinated  to all present and future debts and other  liabilities  (including
trade payables) of our subsidiaries  and affiliates,  and holders of debt of one
of our  subsidiaries  or affiliates  will  effectively be so  subordinated  with
respect to all of our other  subsidiaries and affiliates.  As of March 31, 2005,
our  subsidiaries  had $5.3  billion of secured  construction/project  financing
(including  the CCFC I and  CalGen  financings  described  below).  We may incur
additional  project  financing   indebtedness  in  the  future,  which  will  be
effectively senior to our other secured and unsecured debt.

     In  addition,  our  unsecured  notes  and  our  other  unsecured  debt  are
effectively subordinated to all of our secured indebtedness to the extent of the
value  of the  assets  securing  such  indebtedness.  Our  secured  indebtedness
includes our First  Priority Notes and our $3.7 billion  second-priority  senior
secured term loans and notes.  As described  above,  we have  commenced a tender
offer for our First  Priority  Notes.  See  "Summary -- Recent  Developments  --
Tender  Offer  for  First   Priority   Notes."  The  First  Priority  Notes  and
second-priority   senior   secured   notes  and  term  loans  are   secured  by,
respectively,  first-priority and second-priority  liens on, among other things,
substantially all of the assets owned directly by Calpine Corporation, including
its natural gas and power plant assets and the equity in all of the subsidiaries
directly  owned by Calpine  Corporation.  Our  $785.2  million of CCFC I secured
institutional  term  loans  and notes as of March 31,  2005 are  secured  by the
assets  and  contracts  associated  with the seven  natural  gas-fired  electric
generating  facilities  owned by CCFC I and its  subsidiaries  (as  adjusted for
approved dispositions and acquisitions, such as the completed sale of Lost Pines
Power Project and the acquisition of the Brazos Valley Power Plant) and the CCFC
I lenders'  and note  holders'  recourse is limited to such  security.  Our $2.6
billion of CalGen secured  institutional  term loans, notes and revolving credit
facility are secured, through a combination of direct and indirect stock pledges
and asset liens, by CalGen's 14 power  generating  facilities and related assets
located  throughout the United States, and the CalGen lenders' and note holders'
recourse is limited to such security.  We have additional  non-recourse  project
financings, secured in each case by the assets of the project being financed. We
may  incur  additional  secured  indebtedness  in  the  future,  which  will  be
effectively  senior,  to the extent of the  assets  securing  that debt,  to our
unsecured debt and to our other secured debt not secured by those assets.

     Accounting rules may require us to treat our contingent  convertible  notes
as a derivative and would require us to include the effects of the conversion of
our contingent  convertible notes (if dilutive) in our earnings per share, which
could significantly  impact our earnings per share. As of March 31, 2005, we had
outstanding  $1.3  billion of  contingent  convertible  notes in addition to the
$650.0 million of 7 3/4%  Contingent  Convertible  Notes due 2015 issued on June
23, 2005.  Accounting rules require certain conversion  provisions of contingent
convertible  notes  to be  separated  from  the debt  agreements  in  which  the
conversion features are contained and accounted for as a derivative  instrument,
and therefore  reflected in our financial  statements based upon the fair market
value of the derivative. Due to our current stock price and the number of shares
into which such  contingent  convertible  notes  would  currently  convert,  the
conversion  provisions in our contingent  convertible notes are not considered a
derivative  instrument and/or have no significant  value.  However,  significant
changes in the fair value of these  provisions would be required to be reflected
in our financial statements.

     Also,  our  earnings  per share may be  significantly  impacted  due to the
issuance of our contingently convertible instruments. EITF Issue No. 04-08, "The
Effect of Contingently  Convertible Debt on Diluted Earnings per Share" requires
companies that have issued  contingently  convertible  instruments with a market
price trigger to include the effects of the  conversion in diluted  earnings per
share if it is dilutive, regardless of whether the price trigger had been met.

Operations

     Revenue may be reduced  significantly upon expiration or termination of our
PSAs.  Some of the  electricity we generate from our existing  portfolio is sold
under long-term power sales agreements ("PSAs") that expire at various times. We
also sell power under short to  intermediate  term (one to five year) PSAs. When
the terms of each of these  various PSAs expire,  it is possible  that the price
paid to us for the generation of electricity  under subsequent  arrangements may
be reduced significantly.

     Our power  sales  contracts  have an  aggregate  value in excess of current
market prices (measured over the next five years) of approximately  $3.3 billion
at  December  31,  2004.  Values  for  our  long-term  commodity  contracts  are
calculated  using  discounted  cash  flows  derived  as the  difference  between
contractually based cash flows and the cash flows to buy or sell similar amounts
of  the  commodity  on  at  market  terms.  Inherent  in  these  valuations  are
significant   assumptions  regarding  future  price  curves,   correlations  and
volatilities,  as  applicable.  Because our power sales  contracts are marked to
market,  the  aggregate  value of the  contracts  noted above could  decrease in
response  to  changes  in the  market.  We are at risk of loss in margins to the
extent  that  these  contracts  expire or are  terminated  and we are  unable to
replace  them on  comparable  terms.  We have two  customers  with which we have
multiple  contracts  that,  when combined,  constitute  greater than 10% of this
value: CDWR, $1.4 billion,  and Pacific Gas and Electric Company,  or PG&E, $0.4
billion.  The values by customer  are  comprised  of these  multiple  individual
contracts  that  expire  beginning  in 2009 and contain  termination  provisions
standard to contracts in our industry such as negligence, performance default or
prolonged events of force majeure.

     Use of commodity  contracts,  including  standard  power and gas  contracts
(many of which constitute  derivatives),  can create  volatility in earnings and
may require significant cash collateral. During 2004 we recognized $13.5 million
in  mark-to-market  gains on electric  power and natural gas  derivatives  after
recognizing $26.4 million in losses in 2003. In the three months ended March 31,
2005 and 2004, we  recognized  $3.5 million in  mark-to-market  losses and $12.5
million in mark-to-market gains, respectively, on electric power and natural gas
derivatives.  Additionally,  we recognized as a cumulative effect of a change in
accounting principle, an after-tax gain of approximately $181.9 million from the
adoption of Derivatives  Implementation  Group Issue No. C20, "Scope Exceptions:
Interpretation  of the Meaning of Not Clearly and Closely  Related in  Paragraph
10(b) regarding  Contracts with a Price Adjustment  Feature" on October 1, 2003.
See Item 7.  "Management's  Discussion  and Analysis of Financial  Condition and
Results of  Operation --  Application  of Critical  Accounting  Policies" in our
Annual  Report on Form  10-K for the year  ended  December  31,  2004,  which is
incorporated by reference  herein,  for a detailed  discussion of the accounting
requirements  relating  to  electric  power  and  natural  gas  derivatives.  In
addition,  U.S. generally accepted  accounting  principles ("GAAP") treatment of
derivatives in general,  and particularly in our industry,  continues to evolve.
We may enter into other  transactions  in future periods that require us to mark
various  derivatives to market through earnings.  The nature of the transactions
that we enter into and the  volatility of natural gas and electric  power prices
will  determine the  volatility of earnings  that we may  experience  related to
these transactions.

     As a result, in part, of the fallout from Enron's declaration of bankruptcy
on December 2, 2001,  companies using  derivatives,  many of which are commodity
contracts,   have  become  more   sensitive  to  the  inherent   risks  of  such
transactions.  Consequently (and for us, as a result of our recent  downgrades),
many  companies,  including us, are required to post cash collateral for certain
commodity  transactions in excess of what was previously  required.  As of March
31, 2005, we had $291.2 million in margin deposits with  counterparties,  net of
deposits  posted by  counterparties  with us,  $82.7  million in prepaid gas and
power payments and had posted $109.0  million of letters of credit,  compared to
$248.9 million, $78.0 million and $115.9 million,  respectively, at December 31,
2004.  Future cash collateral  requirements  may increase based on the extent of
our involvement in commodity  transactions and movements in commodity prices and
also based on our credit ratings and general perception of  creditworthiness  in
this market. On May 25, 2005, we announced,  among other things,  that we are in
discussions with a leading  financial  institution to form a partnership that we
anticipate  would  lower our  collateral  requirements.  See  "Summary -- Recent
Developments  -- Strategic  Initiative to Accelerate Debt Reduction and Increase
Cash Flow."

     We may be unable to obtain an adequate supply of natural gas in the future.
To date, our fuel acquisition  strategy has included various combinations of our
own gas reserves, gas prepayment contracts,  short-, medium-and long-term supply
contracts  and gas  hedging  transactions.  In our gas supply  arrangements,  we
attempt  to  match  the  fuel  cost  with the  fuel  component  included  in the
facility's PSAs in order to minimize a project's exposure to fuel price risk. In
addition,  the focus of CES is to manage the spark  spread for our  portfolio of
generating plants and we actively enter into hedging transactions to lock in gas
costs and spark  spreads.  We believe  that there will be  adequate  supplies of
natural gas  available  at  reasonable  prices for each of our  facilities  when
current gas supply agreements expire. However, gas supplies may not be available
for  the  full  term  of the  facilities'  PSAs,  and gas  prices  may  increase
significantly.  Additionally,  our credit  ratings  may  inhibit  our ability to
procure gas supplies  from third  parties.  If gas is not  available,  or if gas
prices  increase  above the level that can be recovered in  electricity  prices,
there  could be a negative  impact on our  results of  operations  or  financial
condition.  In addition, we recently announced that we may sell all or a portion
of our United States natural gas assets. See "Summary -- Recent  Developments --
Potential  Sale of Certain  Oil and Natural  Gas  Assets."  Any such sales could
potentially exacerbate these issues.

     For the year ended December 31, 2004, we obtained  approximately  7% of our
physical  natural gas supply needs through owned natural gas reserves.  However,
if the potential  sale of our oil and natural gas assets is completed,  upon the
transfer of our oil and  natural  gas assets,  we expect that we will not obtain
any of our natural gas supply needs  through  owned  natural gas  reserves.  See
"Summary -- Recent Developments -- Potential Sale of Certain Oil and Natural Gas
Assets." We obtain the  remainder  of our  physical  natural gas supply from the
market and utilize the natural gas  financial  markets to hedge our exposures to
natural gas price risk.  Our current less than  investment  grade credit  rating
increases the amount of collateral  that certain of our suppliers  require us to
post for purchases of physical  natural gas supply and hedging  instruments.  To
the extent that we do not have cash or other means of posting credit,  we may be
unable to  procure an  adequate  supply of natural  gas or natural  gas  hedging
instruments.  In addition,  the fact that our  deliveries  of natural gas depend
upon the natural gas pipeline  infrastructure  in markets where we operate power
plants  exposes us to supply  disruptions in the unusual event that the pipeline
infrastructure is damaged or disabled.

     Our  power  project  development  and  acquisition  activities  may  not be
successful.  The  development  of power  generation  facilities  is  subject  to
substantial  risks.  In connection  with the  development of a power  generation
facility, we must generally obtain:

     o    necessary power generation equipment;

     o    governmental permits and approvals;

     o    fuel supply and transportation agreements;

     o    sufficient equity capital and debt financing;

     o    electrical transmission agreements;

     o    water supply and wastewater discharge agreements; and

     o    site agreements and construction contracts.

     We may be unsuccessful in accomplishing any of these matters or in doing so
on a timely  basis.  In  addition,  project  development  is  subject to various
environmental,  engineering and  construction  risks relating to  cost-overruns,
delays and performance.  Although we may attempt to minimize the financial risks
in the development of a project by securing a favorable  power sales  agreement,
obtaining  all  required  governmental  permits  and  approvals,  and  arranging
adequate financing prior to the commencement of construction, the development of
a power  project  may  require  us to expend  significant  sums for  preliminary
engineering,  permitting,  legal and  other  expenses  before  we can  determine
whether a project is feasible, economically attractive or financeable. If we are
unable  to  complete  the  development  of a  facility,  we might not be able to
recover  our  investment  in the  project.  The process  for  obtaining  initial
environmental,   siting  and  other   governmental   permits  and  approvals  is
complicated  and  lengthy,  often  taking more than one year,  and is subject to
significant  uncertainties.  We cannot  assure you that we will be successful in
the development of power generation  facilities in the future or that we will be
able to  successfully  complete  construction  of our  facilities  currently  in
development,  nor  can we  assure  you  that  any of  these  facilities  will be
profitable or have value equal to the investment in them even if they do achieve
commercial operation.

     We  have  grown  substantially  in  recent  years  partly  as a  result  of
acquisitions  of  interests in power  generation  facilities,  geothermal  steam
fields  and  natural  gas  reserves  and   facilities.   The   integration   and
consolidation  of  our  acquisitions   with  our  existing   business   requires
substantial  management,  financial and other  resources  and,  ultimately,  our
acquisitions may not be successfully  integrated.  In addition, as we transition
from a  development  company  to an  operating  company,  we are not  likely  to
continue to grow at historical  rates due to reduced  acquisition  activities in
the near future. We have also substantially curtailed our development efforts in
response to our reduced  liquidity.  Although  the  domestic  power  industry is
continuing to undergo  consolidation and may offer acquisition  opportunities at
favorable  prices,  we  believe  that  we are  likely  to  confront  significant
competition  for  those  opportunities  and,  due  to  the  constriction  in the
availability of capital  resources for acquisitions and other expansion,  to the
extent that any  opportunities  are  identified,  we may be unable to effect any
acquisitions.  Similarly,  to the extent we seek to divest assets, we may not be
able to do so at attractive prices. See also "Summary -- Recent  Developments --
Strategic  Initiative to Accelerate Debt Reduction and Increase Cash Flow" for a
discussion of potential asset sales.

     Our projects under  construction  may not commence  operation as scheduled.
The commencement of operation of a newly constructed  power generation  facility
involves many risks, including:

     o    start-up problems;

     o    the breakdown or failure of equipment or processes; and

     o    performance below expected levels of output or efficiency.

     New plants have no operating history and may employ recently  developed and
technologically  complex  equipment.  Insurance  (including a layer of insurance
provided by a captive  insurance  subsidiary)  is maintained to protect  against
certain risks, warranties are generally obtained for limited periods relating to
the  construction  of each  project and its  equipment in varying  degrees,  and
contractors  and equipment  suppliers are obligated to meet certain  performance
levels. The insurance, warranties or performance guarantees, however, may not be
adequate to cover lost revenues or increased  expenses.  As a result,  a project
may be  unable to fund  principal  and  interest  payments  under its  financing
obligations  and may  operate  at a  loss.  A  default  under  such a  financing
obligation,  unless  cured,  could  result in our losing our interest in a power
generation facility.

     In  certain  situations,  PSAs  entered  into with a  utility  early in the
development phase of a project may enable the utility to terminate the PSA or to
retain security posted as liquidated  damages under the PSA.  Currently,  six of
our 10 projects under  construction are party to PSAs containing such provisions
and could be materially  affected if these  provisions were  triggered.  The six
projects are our  Freeport,  Valladolid,  Mankato,  Bethpage,  Fox and Otay Mesa
facilities.  The  situations  that could  allow a utility to  terminate a PSA or
retain posted security as liquidated damages include:

     o    the  cessation  or  abandonment  of  the  development,   construction,
          maintenance or operation of the facility;

     o    failure of the facility to achieve  construction  milestones by agreed
          upon deadlines, subject to extensions due to force majeure events;

     o    failure of the facility to achieve commercial operation by agreed upon
          deadlines, subject to extensions due to force majeure events;

     o    failure of the facility to achieve certain output minimums;

     o    failure  by the  facility  to make  any of the  payments  owing to the
          utility under the PSA or to establish,  maintain,  restore, extend the
          term of, or increase the posted security if required by the PSA;

     o    a material  breach of a  representation  or warranty or failure by the
          facility  to  observe,  comply  with or  perform  any  other  material
          obligation under the PSA;

     o    failure of the  facility to obtain  material  permits  and  regulatory
          approvals by agreed upon deadlines; or

     o    the liquidation,  dissolution, insolvency or bankruptcy of the project
          entity.

     Our power generation facilities may not operate as planned. Upon completion
of our projects  currently  under  construction,  we will operate 100 of the 103
power plants in which we currently have an interest.  The continued operation of
power generation  facilities,  including,  upon completion of construction,  the
facilities owned directly by us, involves many risks, including the breakdown or
failure of power generation  equipment,  transmission lines,  pipelines or other
equipment or  processes,  and  performance  below  expected  levels of output or
efficiency.  From time to time our power generation  facilities have experienced
equipment  breakdowns  or failures,  and in 2004 we recorded  expenses  totaling
approximately  $54.3 million for these breakdowns or failures  compared to $11.0
million in 2003.  Continued  high failure rates of Siemens  Westinghouse  ("SW")
provided equipment  represent the highest risk for such breakdowns,  although we
have  programs in place that we believe  will  eventually  substantially  reduce
these  failures  and  provide  plants  with SW  equipment  availability  factors
competitive with plants using other manufacturers' equipment.

     Although  our  facilities   contain   various   redundancies   and  back-up
mechanisms,  a  breakdown  or failure may prevent  the  affected  facility  from
performing  under any  applicable  PSAs.  Although  insurance is  maintained  to
partially  protect against operating risks, the proceeds of insurance may not be
adequate to cover lost revenues or increased expenses.  As a result, we could be
unable  to  service   principal  and  interest   payments  under  our  financing
obligations  which  could  result in losing  our  interest  in one or more power
generation facility.

     We  cannot  assure  you  that our  estimates  of oil and gas  reserves  are
accurate. Estimates of proved oil and gas reserves and the future net cash flows
attributable  to those  reserves  are  prepared  by  independent  petroleum  and
geological engineers.  There are numerous  uncertainties  inherent in estimating
quantities  of proved oil and gas reserves and cash flows  attributable  to such
reserves,  including  factors  beyond  our  control  and that of our  engineers.
Reserve   engineering  is  a  subjective   process  of  estimating   underground
accumulations  of oil and gas that cannot be measured  in an exact  manner.  The
accuracy of an estimate of quantities of reserves, or of cash flows attributable
to such reserves,  is a function of the available  data,  assumptions  regarding
future  oil  and  gas  prices  and  expenditures  for  future   development  and
exploitation  activities,  and of engineering and geological  interpretation and
judgment.  Additionally,  reserves  and  future  cash  flows may be  subject  to
material   downward  or  upward  revisions,   based  upon  production   history,
development and exploration  activities and prices of oil and gas. Actual future
production,  revenue,  taxes,  development  expenditures,   operating  expenses,
underlying information, quantities of recoverable reserves and the value of cash
flows  from  such  reserves  may vary  significantly  from the  assumptions  and
underlying  information  set  forth  herein.  In  addition,   different  reserve
engineers may make  different  estimates of reserves and cash flows based on the
same available data. We recorded impairment charges of $202.1 million related to
reduced  proved  reserve  projections  at year  end 2004  based on the  year-end
independent  engineer's  report.  See also "-- The ultimate outcome of the legal
proceedings  relating  to  our  activities  cannot  be  predicted.  Any  adverse
determination  could have a material  adverse effect on our financial  condition
and results of operations."

     Our geothermal  energy reserves may be inadequate for our  operations.  The
development  and  operation  of  geothermal  energy  resources  are  subject  to
substantial  risks  and  uncertainties  similar  to  those  experienced  in  the
development  of  oil  and  gas  resources.  The  successful  exploitation  of  a
geothermal energy resource ultimately depends upon:

     o    the heat content of the extractable steam or fluids;

     o    the geology of the reservoir;

     o    the total amount of recoverable reserves;

     o    operating expenses relating to the extraction of steam or fluids;

     o    price levels  relating to the  extraction  of steam or fluids or power
          generated; and

     o    capital expenditure requirements relating primarily to the drilling of
          new wells.

     In  connection   with  each   geothermal   power  plant,  we  estimate  the
productivity   of  the   geothermal   resource  and  the  expected   decline  in
productivity.  The  productivity of a geothermal  resource may decline more than
anticipated,  resulting in  insufficient  reserves being available for sustained
generation of the electrical power capacity desired. An incorrect estimate by us
or an unexpected  decline in productivity  could, if material,  adversely affect
our results of operations or financial condition.

     Geothermal reservoirs are highly complex. As a result, there exist numerous
uncertainties  in determining  the extent of the reservoirs and the quantity and
productivity of the steam reserves.  Reservoir engineering is an inexact process
of  estimating  underground  accumulations  of steam or  fluids  that  cannot be
measured in any precise  way,  and depends  significantly  on the  quantity  and
accuracy of  available  data.  As a result,  the  estimates  of other  reservoir
specialists may differ materially from ours. Estimates of reserves are generally
revised  over  time  on the  basis  of the  results  of  drilling,  testing  and
production that occur after the original estimate was prepared. We cannot assure
you that we will be able to successfully manage the development and operation of
our geothermal  reservoirs or that we will  accurately  estimate the quantity or
productivity of our steam reserves.

Market

     Competition  could adversely affect our  performance.  The power generation
industry is characterized by intense competition,  and we encounter  competition
from utilities, industrial companies, marketing and trading companies, and other
IPPs. In recent years, there has been increasing competition among generators in
an effort to obtain PSAs, and this competition has contributed to a reduction in
electricity prices in certain markets. In addition, many states are implementing
or considering  regulatory  initiatives  designed to increase competition in the
domestic  power  industry.   For  instance,   the  California  Public  Utilities
Commission  ("CPUC") issued decisions that provided that all California electric
users taking  service  from a regulated  public  utility  could elect to receive
direct access service  commencing  April 1998;  however,  the CPUC suspended the
offering of direct access to any customer not receiving direct access service as
of September 20, 2001, due to the problems  experienced in the California energy
markets during 2000 and 2001. As a result,  uncertainty  exists as to the future
course for direct  access in California in the aftermath of the energy crisis in
that state. In Texas,  legislation  phased in a deregulated power market,  which
commenced  on January 1, 2001.  This  competition  has put  pressure on electric
utilities to lower their costs, including the cost of purchased electricity, and
increasing  competition in the supply of electricity in the future will increase
this pressure.

     Our international  investments may face uncertainties.  We have investments
in  operating  power  projects in Canada,  an  investment  in an energy  service
business in the Netherlands and an investment in a power generation  facility in
construction in Mexico.  In addition,  we recently  entered into an agreement to
sell  our  power  generation  facility  in  the  U.K.  See  "Summary  --  Recent
Developments  --  Sale of  Saltend  Energy  Centre."  We may  pursue  additional
international  investments  in the  future  subject  to the  limitations  on our
expansion  plans  due  to  current  capital  market  constraints.  International
investments  are  subject  to unique  risks and  uncertainties  relating  to the
political,  social and economic  structures of the countries in which we invest.
Risks  specifically  related to  investments in non-United  States  projects may
include:

     o    fluctuations in currency valuation;

     o    currency inconvertibility;

     o    expropriation and confiscatory taxation;

     o    increased regulation; and

     o    approval  requirements and governmental  policies  limiting returns to
          foreign investors.

California Power Market

     The  volatility  in the  California  power  market  from  mid-2000  through
mid-2001 has produced significant unanticipated results, and as described in the
following risk factors,  the unresolved issues arising in that market,  where 42
of our 103 power plants are located, could adversely affect our performance.

     We may be  required  to make  refund  payments  to the CalPX and CAISO as a
result of the California  Refund  Proceeding.  On August 2, 2000, the California
Refund  Proceeding  was  initiated  by a complaint  made at the  Federal  Energy
Regulatory Commission,  or FERC, by SDG&E under Section 206 of the FPA alleging,
among other  things,  that the markets  operated by the  California  Independent
System  Operator  Corporation,  or  CAISO,  and the  California  Power  Exchange
("CalPX") were  dysfunctional.  FERC  established a refund  effective  period of
October 2, 2000,  to June 19, 2001 (the  "Refund  Period"),  for sales made into
those markets.

     On December 12, 2002, an Administrative Law Judge issued a Certification of
Proposed Finding on California  Refund Liability  ("December 12  Certification")
making an initial  determination  of refund  liability.  On March 26, 2003, FERC
issued an order (the "March 26 Order")  adopting  many of the findings set forth
in the December 12 Certification.  In addition,  as a result of certain findings
by the FERC  staff  concerning  the  unreliability  or  misreporting  of certain
reported  indices for gas prices in California  during the Refund  Period,  FERC
ordered that the basis for calculating a party's  potential  refund liability be
modified  by  substituting  a gas  proxy  price  based  upon gas  prices  in the
producing areas plus the tariff transportation rate for the California gas price
indices  previously  adopted in the California  Refund  Proceeding.  We believe,
based  on the  information  that we have  analyzed  to  date,  that  any  refund
liability that may be attributable to us could total  approximately $9.9 million
(plus  interest,  if  applicable),  after  taking the  appropriate  set-offs for
outstanding  receivables  owed by the CalPX and CAISO to Calpine.  We believe we
have  appropriately  reserved  for the  refund  liability  that  by our  current
analysis would potentially be owed under the refund calculation clarification in
the March 26 Order.  The final  determination  of the refund  liability  and the
allocation of payment  obligations  among the numerous buyers and sellers in the
California markets is subject to further Commission proceedings.  It is possible
that there will be further  proceedings to require  refunds from certain sellers
for periods prior to the originally  designated Refund Period. In addition,  the
FERC orders  concerning the Refund  Period,  the method for  calculating  refund
liability and numerous  other issues are pending on appeal before the U.S. Court
of Appeals  for the Ninth  Circuit.  At this time,  we are unable to predict the
timing of the  completion of these  proceedings  or the final refund  liability.
Thus, the impact on our business is uncertain.

     We have been  mentioned in a show cause order in  connection  with the FERC
investigation into western markets regarding the CalPX and CAISO tariffs and may
be found liable for payments thereunder. 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 and others used their 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.
On August 13, 2002, the FERC staff issued the Initial Report on Company-Specific
Separate  Proceedings  and Generic  Reevaluations;  Published  Natural Gas Price
Data;  and Enron Trading  Strategies  (the "Initial  Report"),  summarizing  its
initial findings in this investigation. There were no findings or allegations of
wrongdoing by Calpine set forth or described in the Initial Report. On March 26,
2003,  the FERC staff  issued a final report in this  investigation  (the "Final
Report"). In the Final Report, the FERC staff recommended that FERC issue a show
cause order to a number of companies, including Calpine, regarding certain power
scheduling  practices  that may have been in violation of the CAISO's or CalPX's
tariff.  The  Final  Report  also  recommended  that FERC  modify  the basis for
determining  potential  liability in the California Refund Proceeding  discussed
above.  Calpine  believes that it did not violate these tariffs and that, to the
extent that such a finding could be made, any potential  liability  would not be
material.

     On June 25, 2003, FERC issued a number of orders based on the Final Report,
including   the  issuance  of  two  show  cause   orders  to  certain   industry
participants.  FERC did not subject  Calpine to either of the show cause orders.
FERC  also   issued  an  order   directing   the  FERC  Office  of  Markets  and
Investigations  to investigate  further  whether market  participants  who bid a
price in excess of $250 per MWh hour into  markets  operated by either the CAISO
or the CalPX  during  the period of May 1,  2000,  to October 2, 2000,  may have
violated CAISO and CalPX tariff  prohibitions.  No individual market participant
was  identified.  We believe  that we did not violate the CAISO and CalPX tariff
prohibitions  referred  to by FERC in this  order;  however,  we are  unable  to
predict at this time the final  outcome of this  proceeding or its impact on our
business.

     The  energy  payments  made to us  during a  certain  period  under  our QF
contracts with PG&E may be retroactively adjusted downward as a result of a CPUC
proceeding. Our qualifying facility, or QF, contracts with PG&E provide that the
CPUC has the authority to determine the appropriate utility "avoided cost" to be
used to set energy  payments by determining  the short run avoided cost ("SRAC")
energy price formula. In mid-2000 our QF facilities elected the option set forth
in Section 390 of the California  Public  Utilities Code, which provided QFs the
right to elect to receive  energy  payments  based on the CalPX market  clearing
price instead of the SRAC price administratively  determined by the CPUC. Having
elected  such  option,  our QF  facilities  were paid based upon the CalPX zonal
day-ahead  clearing price ("CalPX Price") for various periods  commencing in the
summer of 2000  until  January  19,  2001,  when the CalPX  ceased  operating  a
day-ahead market. The CPUC has conducted proceedings  (R.99-11-022) to determine
whether the CalPX Price was the appropriate  price for the energy component upon
which to base payments to QFs which had elected the CalPX-based  pricing option.
No final  decision has been issued to date.  Therefore,  it is possible that the
CPUC  could  order a  payment  adjustment  based  on a  different  energy  price
determination.  On  January  10,  2001,  PG&E  filed an  emergency  motion  (the
"Emergency  Motion")  requesting  that  the  CPUC  issue  an  order  that  would
retroactively  change the energy  payments  received by QFs based on CalPX-based
pricing for electric energy delivered during the period  commencing  during June
2000 and ending on January 18, 2001. On April 29, 2004, PG&E, the Utility Reform
Network,  a consumer advocacy group, and the Office of Ratepayer  Advocates,  an
independent  consumer advocacy department of the CPUC  (collectively,  the "PG&E
Parties"), filed a Motion for Briefing Schedule Regarding True-Up of Payments to
QF Switchers (the "April 2004 Motion").  The April 2004 Motion requests that the
CPUC set a briefing schedule in R.99-11-022 to determine what is the appropriate
price that should be paid to the QFs that had switched to the CalPX  Price.  The
PG&E Parties allege that the  appropriate  price should be determined  using the
methodology that has been developed thus far in the California Refund Proceeding
discussed  above.  Supplemental  pleadings  have been  filed on the  April  2004
Motion,  but  neither  the CPUC nor the  assigned  administrative  law judge has
issued any rulings  with  respect to either the April 2004 Motion or the initial
Emergency  Motion. We believe that the CalPX Price was the appropriate price for
energy  payments for our QFs during this  period,  but there can be no assurance
that this will be the outcome of the CPUC proceedings.

     The  availability  payments made to us under our Geysers'  Reliability Must
Run contracts have been challenged by certain buyers as having been not just and
reasonable.  CAISO,  California  Electricity  Oversight Board,  Public Utilities
Commission of the State of  California,  PG&E,  SDG&E,  and Southern  California
Edison  Company  (collectively  referred to as the "Buyers  Coalition")  filed a
complaint  on  November 2, 2001 at FERC  requesting  the  commencement  of a FPA
Section  206  proceeding  to  challenge  one  component  of a number of separate
settlements  previously reached on the terms and conditions of "reliability must
run" contracts  ("RMR  Contracts")  with certain  generation  owners,  including
Geysers Power Company,  LLC, which settlements were also previously  approved by
FERC. RMR Contracts require the owner of the specific generation unit to provide
energy and ancillary services when called upon to do so by the ISO to meet local
transmission reliability needs or to manage transmission constraints. The Buyers
Coalition has asked FERC to find that the availability  payments under these RMR
Contracts  are not just and  reasonable.  Geysers  Power  Company,  LLC filed an
answer to the complaint in November  2001. On June 3, 2005,  FERC  dismissed the
complaint  brought by the Buyers  Coalition.  The  Buyers  Coalition  may appeal
FERC's order, but it has not yet done so.

Government Regulation

     We are  subject to complex  government  regulation  which  could  adversely
affect our  operations.  Our  activities  are subject to complex  and  stringent
energy,   environmental  and  other  governmental  laws  and  regulations.   The
construction  and  operation  of  power  generation  facilities  and oil and gas
exploration and production require numerous permits,  approvals and certificates
from appropriate foreign,  federal,  state and local governmental  agencies,  as
well  as  compliance  with  environmental   protection   legislation  and  other
regulations.  While we believe that we have obtained the requisite approvals and
permits  for our  existing  operations  and that our  business  is  operated  in
accordance with applicable  laws, we remain subject to a varied and complex body
of laws and regulations that both public  officials and private  individuals may
seek to enforce.  Existing laws and regulations may be revised or reinterpreted,
or new laws and regulations may become applicable to us that may have a negative
effect on our business and results of operations. We may be unable to obtain all
necessary licenses,  permits,  approvals and certificates for proposed projects,
and completed  facilities may not comply with all applicable permit  conditions,
statutes or regulations. In addition, regulatory compliance for the construction
of new facilities is a costly and time-consuming process. Intricate and changing
environmental  and other  regulatory  requirements  may necessitate  substantial
expenditures to obtain and maintain permits.  If a project is unable to function
as planned  due to  changing  requirements  or local  opposition,  it may create
expensive delays, extended periods of non-operation or significant loss of value
in a project.

     Environmental  regulations  have had and will continue to have an impact on
our cost of doing  business  and our  investment  decisions.  For  example,  the
existing market-based cap-and-trade emissions allowance system in Texas requires
operators to either reduce NOx emissions or purchase  additional  NOx allowances
in the marketplace.  Rather than purchase additional allowances,  we have chosen
to install  additional  NOx  emission  controls as part of a $31  million  steam
capacity  upgrade at our Texas City  facility  and to  retrofit  our Clear Lake,
Texas facility with similar  technology at a cost of approximately  $17 million.
These new emission control systems will allow us to meet our thermal  customers'
needs while  reducing  the need to purchase  allowances  for our  facilities  in
Texas.

     Our operations are potentially  subject to the provisions of various energy
laws and  regulations,  including  PURPA,  PUHCA,  the FPA,  and state and local
regulations.  PUHCA  provides for the  extensive  regulation  of public  utility
holding companies and their  subsidiaries.  PURPA provides QFs (as defined under
PURPA) and owners of QFs exemptions from certain federal and state  regulations,
including rate and financial  regulations.  The FPA regulates wholesale sales of
power, as well as electric transmission in interstate commerce.

     Under  current  federal law, we are not subject to  regulation as a holding
company under PUHCA,  and will not be subject to such  regulation as long as the
plants in which we have an  interest  (1)  qualify  as QFs,  (2) are  subject to
another  exemption  or waiver or (3) are owned or  operated  by an EWG under the
Energy Policy Act of 1992. In order to be a QF, a facility must be not more than
50% owned by one or more electric  utility  companies,  electric utility holding
companies, or any combination thereof.  Generally, any geothermal power facility
which  produces  not more than 80 MW of  electricity  and meets PURPA  ownership
requirements  qualifies for QF status. In addition,  a QF that is a cogeneration
facility, such as the plants in which we currently have interests,  must produce
electricity  as well as thermal  energy for use in an  industrial  or commercial
process in specified minimum proportions.  The QF also must meet certain minimum
energy efficiency standards.

     If any of the plants in which we have an  interest  lose their QF status or
if  amendments  to PURPA are  enacted  that  substantially  reduce the  benefits
currently afforded QFs, we could become a public utility holding company,  which
could subject us to significant federal,  state and local regulation,  including
rate regulation.  If we become a holding company, which could be deemed to occur
prospectively  or  retroactively to the date that any of our plants loses its QF
status,  all of our other QF power  plants could lose QF status  because,  under
FERC regulations,  no more than 50% of a QF's equity can be owned by an electric
utility,  electric  utility  holding  company,  or any combination  thereof.  In
addition, a loss of QF status could,  depending on the particular power purchase
agreement,  allow the power purchaser to cease taking and paying for electricity
or to seek refunds of past amounts paid and thus could cause the loss of some or
all  contract  revenues or otherwise  impair the value of a project.  If a power
purchaser  were to cease  taking  and paying  for  electricity,  there can be no
assurance  that the costs  incurred  in  connection  with the  project  could be
recovered through sales to other purchasers.  Such events could adversely affect
our ability to service our  indebtedness.  See "Item 1 -- Business -- Government
Regulation -- Federal Energy  Regulation -- Federal Power Act Regulation" in our
Annual Report on Form 10-K for the year ended  December 31, 2004. A cogeneration
QF could lose its QF status if it does not continue to meet FERC's operating and
efficiency  requirements.  Such  possible  loss of QF status  could  occur,  for
example,  if the QF's steam host,  typically an industrial  facility,  fails for
operating,  permit or economic reasons to use sufficient  quantities of the QF's
steam output.  We cannot assure you that all of our steam hosts will continue to
take and use sufficient quantities of their respective QF's steam output.

     In light of the  experiences in the California  electricity and natural gas
markets  in 2000 and 2001,  and the PG&E and Enron  bankruptcy  filings in 2001,
among other events in recent  years,  there are a number of federal  legislative
and  regulatory  initiatives  that  could  result in  changes  in how the energy
markets are regulated. For example, Congress has considered proposed legislation
that would repeal PUHCA, and would amend PURPA, among other ways, by, in certain
circumstances, limiting its mandatory purchase obligation to existing contracts.
We do not know whether  these  legislative  or  regulatory  initiatives  will be
adopted or, if adopted,  what form they may take.  We cannot  provide  assurance
that any legislation or regulation ultimately adopted would not adversely affect
our existing projects.

     In  addition,  many  states  are  implementing  or  considering  regulatory
initiatives  designed to increase  competition in the domestic power  generation
industry  and  increase   access  to  electric   utilities'   transmission   and
distribution  systems for IPPs and electricity  consumers.  However, in light of
the circumstances in the California  electricity and natural gas markets and the
bankruptcies  of both  PG&E  and  Enron,  the  pace  and  direction  of  further
deregulation  at the state level in many  jurisdictions  is  uncertain.  See "--
California Power Market."

Other Risk Factors

     We depend on our management and employees. Our success is largely dependent
on the skills,  experience  and efforts of our people.  While we believe that we
have  excellent  depth  throughout all levels of management and in all key skill
levels of our employees,  the loss of the services of one or more members of our
senior  management or of numerous  employees  with critical  skills could have a
negative effect on our business,  financial conditions and results of operations
and future  growth.  We have an employment  agreement  with our Chief  Executive
Officer.

     Seismic disturbances could damage our projects.  Areas where we operate and
are  developing  many of our  geothermal  and gas-fired  projects are subject to
frequent low-level seismic  disturbances.  More significant seismic disturbances
are possible.  Our existing power  generation  facilities are built to withstand
relatively  significant  levels  of  seismic  disturbances,  and we  believe  we
maintain adequate insurance protection.  However, earthquake, property damage or
business interruption  insurance may be inadequate to cover all potential losses
sustained in the event of serious seismic disturbances.  Additionally, insurance
for  these  risks  may  not  continue  to be  available  to  us on  commercially
reasonable terms.

     Our  results  are  subject to  quarterly  and  seasonal  fluctuations.  Our
quarterly  operating  results have fluctuated in the past and may continue to do
so in the future as a result of a number of factors, including:

     o    seasonal variations in energy prices;

     o    variations in levels of production;

     o    the timing and size of acquisitions; and

     o    the completion of development and construction projects.

     Additionally,  because we receive the majority of capacity  payments  under
some of our PSAs  during the months of May through  October,  our  revenues  and
results of operations are, to some extent, seasonal.

     The ultimate  outcome of the legal  proceedings  relating to our activities
cannot be predicted.  Any adverse  determination  could have a material  adverse
effect on our  financial  condition and results of  operations.  We are party to
various  litigation  matters  arising out of the normal course of business,  the
more significant of which are summarized in Note 25 of the Notes to Consolidated
Financial  Statements  contained in our Annual  Report on Form 10-K for the year
ended December 31, 2004, and in Note 11 of the Notes to  Consolidated  Financial
Statements  contained in our Quarterly Report on Form 10-Q for the quarter ended
March 31, 2005,  which are  incorporated  by  reference  herein.  These  matters
include securities class action lawsuits,  such as Hawaii Structural Ironworkers
Pension Fund v. Calpine et al.,  which relate to our April 2002 equity  offering
and also named the underwriters of that offering as defendants.

     Harbert Distressed  Investment Master Fund, Ltd. has brought a suit against
us  and  certain  of our  subsidiaries  that  alleges  violations  or  potential
violations of certain Nova Scotia and Canadian  laws in connection  with certain
financing  transactions  and in connection with the proposed sale of the Saltend
Energy Centre.  The Harbert Fund,  which holds two series of notes issued by one
of our subsidiaries and guaranteed by us, seeks interim and permanent injunctive
relief freezing,  or tracing and returning to Calpine Canada Resources  Company,
the indirect  parent company of the owner of the Saltend Energy Centre,  assets,
including the proceeds of financing transactions and the proceeds of any sale of
the  Saltend  Energy  Centre.  We have been  advised  by the  trustee  under the
indenture  governing  the notes held by the Harbert Fund that it intends to file
an  application  to  intervene in the suit. A hearing on the merits of this suit
has been scheduled for July 7 and 8, 2005.

     In April 2005, the Division of Enforcement of the SEC commenced an informal
inquiry into the facts and circumstances  relating to: (a) our downward revision
of our proved oil and gas reserve estimates at year-end 2004 as compared to such
estimates  at year-end  2003,  and a  corresponding  impairment  of the value of
certain assets,  all previously  disclosed by us, (b) certain statements made to
various  regulatory  agencies by a  terminated  former  employee  regarding  our
determination  of state sales and use taxes,  and (c) our upward  restatement in
April 2005 of our previously disclosed net income for the third quarter, and the
first three  quarters,  of 2004.  We are fully  cooperating  with this  informal
inquiry.  The ultimate  outcome of this inquiry cannot  presently be determined,
however,  it is  possible  that the SEC  could  conclude  that our  estimate  of
continuing proved reserves,  as revised,  requires further downward revision, or
could require that we take other actions.

     The  ultimate  outcome  of  each  of  these  matters  cannot  presently  be
determined,  nor can the liability that may  potentially  result from a negative
outcome be reasonably  estimated  presently for every case. The liability we may
ultimately  incur  with  respect  to any one of these  matters in the event of a
negative outcome may be in excess of amounts  currently  accrued with respect to
such matters and, as a result,  these matters may potentially be material to our
business or to our financial condition and results of operations.



<PAGE>


ITEM 9.01  FINANCIAL STATEMENTS AND EXHIBITS

(a) Financial Statements of Businesses Acquired.

      Not Applicable

(b) Pro Forma Financial Information.

      Not Applicable

(c) Exhibits.

      99.1 Press  Release  dated June 23, 2005, regarding  the  Company's 7 3/4%
          Contingent Convertible Notes due 2015

      99.2 Press  Release dated June 24, 2005, regarding  the  redemption of the
          HIGH TIDES III preferred securities

<PAGE>


                                   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 hereunto duly authorized.


                                       CALPINE CORPORATION

                                       By: /s/ Charles B. Clark, Jr.
                                           ------------------------------------
                                           Charles B. Clark, Jr.
                                           Senior Vice President and Controller
                                           Chief Accounting Officer


Date: June 30, 2005


<PAGE>


                                    EXHIBITS

     99.1 Press  Release  dated June 23, 2005,  regarding  the  Company's 7 3/4%
          Contingent Convertible Notes due 2015

     99.2 Press  Release dated June 24, 2005,  regarding  the  redemption of the
          HIGH TIDES III preferred securities



EXHIBIT 99.1.


NEWS RELEASE
                                                       CONTACTS:  (408) 995-5115
                                    Media Relations: Katherine Potter, Ext. 1168
                                     Investor Relations: Rick Barraza, Ext. 1125


                         Calpine Closes $650 Million of
                      Contingent Convertible Notes Due 2015

        Proceeds to be Used to Redeem HIGH TIDES III and Repurchase Debt

     (SAN JOSE,  Calif.) / PR  Newswire  - First Call / June 23,  2005 - Calpine
Corporation  [NYSE:CPN] has received funds for its registered public offering of
$650  million  of  contingent  convertible  notes due 2015.  The notes  will pay
interest at a rate of 7 3/4% and will be  convertible  into cash and into shares
of Calpine  common stock at a price of $4.00 per share,  which  represents a 29%
premium  over the New York Stock  Exchange  closing  price of $3.10 per  Calpine
common  share on June 17,  2005.  Upon  conversion  of the notes,  Calpine  will
deliver the applicable  current principal value in cash and any additional value
in Calpine common shares.

     Calpine  expects to use  approximately  $402.5  million of the net proceeds
from the convertible  notes offering  towards the redemption in full of its HIGH
TIDES III preferred securities.  The company will use the remaining net proceeds
to repurchase a portion of the outstanding principal amount of its 8 1/2% senior
unsecured notes due 2011.

     Goldman,  Sachs & Co. is the sole  manager of the  offering.  A copy of the
final  prospectus  supplement  relating to the  offering  may be  obtained  from
Goldman,  Sachs & Co., Attention:  Prospectus Department at 85 Broad Street, New
York, NY 10004.

     A registration  statement  relating to these securities has been filed with
the Securities and Exchange  Commission  and has been declared  effective.  This
press release shall not  constitute an offer to sell or the  solicitation  of an
offer to buy,  nor shall there be any sale of these  securities  in any state in
which such offer,  solicitation  or sale would be unlawful prior to registration
or qualification under the securities laws of any such state.

     A  major  power  company,   Calpine  Corporation   supplies  customers  and
communities  with  electricity  from clean,  efficient,  natural  gas-fired  and
geothermal power plants. Calpine owns, leases and operates integrated systems of
plants in 21 U.S.  states,  three Canadian  provinces and in the United Kingdom.
Calpine was founded in 1984. It is included in the S&P 500 Index and is publicly
traded  on  the  New  York  Stock  Exchange  under  the  symbol  CPN.  For  more
information, visit www.calpine.com.

     This  news  release  discusses  certain  matters  that  may  be  considered
"forward-looking" statements within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
as  amended,  including  statements  regarding  the  intent,  belief or  current
expectations  of  Calpine   Corporation  ("the  Company")  and  its  management.
Prospective investors are cautioned that any such forward-looking statements are
not  guarantees  of  future  performance  and  involve  a number  of  risks  and
uncertainties  that could  materially  affect  actual  results  such as, but not
limited to, (i) the timing and extent of  deregulation of energy markets and the
rules and regulations adopted on a transitional basis with respect thereto; (ii)
the timing and extent of changes in  commodity  prices for energy,  particularly
natural gas and electricity; (iii) unscheduled outages of operating plants; (iv)
a competitor's  development of lower cost generating gas-fired power plants; (v)
risks  associated  with  marketing  and selling  power from power  plants in the
newly-competitive  energy market;  (vi) other risks identified from time-to-time
in the  Company's  reports  and  registration  statements  filed  with  the SEC,
including the risk factors  identified in its Annual Report on Form 10-K for the
year ended  December 31, 2004 and in its  Quarterly  Report on Form 10-Q for the
quarter ended March 31, 2005,  which can also be found on the Company's  website
at  www.calpine.com.  All  information  set forth in this news  release is as of
today's date, and the Company undertakes no duty to update this information.


<PAGE>


EXHIBIT 99.2.


NEWS RELEASE
                                                       CONTACTS:  (408) 995-5115
                                    Media Relations: Katherine Potter, Ext. 1168
                                     Investor Relations: Karen Bunton, Ext. 1121


                        Calpine to Redeem HIGH TIDES III

     (SAN JOSE,  Calif.),  /PR  Newswire - First  Call/ June 24,  2005 - Calpine
Corporation [NYSE: CPN] today announced that it has called for redemption all of
the  outstanding  5% HIGH TIDES III  preferred  securities.  There is  currently
outstanding $402.5 million of HIGH TIDES III not held by Calpine. The redemption
date  for the  HIGH  TIDES  III  preferred  securities  is July  13,  2005.  The
redemption  price per each $50  principal  amount of HIGH  TIDES III is $50 plus
accrued and unpaid  distributions to the redemption date in the amount of $0.50.
Upon  completion  of this  redemption,  no further  series of HIGH TIDES will be
outstanding.

     Upon deposit of the redemption price with The Depository Trust Company, all
rights of  Holders of the HIGH  TIDES III will  cease,  except the right of such
Holders to receive the redemption  price,  and such HIGH TIDES III will cease to
be outstanding.

     In  connection  with the  redemption  of the HIGH  TIDES  III,  the  entire
outstanding  principal amount of Calpine's convertible  subordinated  debentures
held by Calpine  Capital  Trust III will also be  redeemed  and will cease to be
outstanding.

     A  major  power  company,   Calpine  Corporation   supplies  customers  and
communities  with  electricity  from clean,  efficient,  natural  gas-fired  and
geothermal power plants. Calpine owns, leases and operates integrated systems of
plants in 21 U.S.  states,  three Canadian  provinces and in the United Kingdom.
Calpine was founded in 1984. It is included in the S&P 500 Index and is publicly
traded  on  the  New  York  Stock  Exchange  under  the  symbol  CPN.  For  more
information, visit www.calpine.com.
</TEXT>
</DOCUMENT>
</SUBMISSION>
