Dynegy Announces 2005 Results

Dynegy Inc. (NYSE:DYN):
-- 2005 results benefited from higher prices realized in Midwest,
Northeast and South regions

-- Year marked by the successful completion of key self-restructuring
initiatives:

-- Settled significant legacy litigation, including shareholder
class action and Midwest environmental litigation

-- Sold Midstream business for $2.4 billion in cash

-- Reached agreement to terminate Sterlington power tolling
obligation

-- Year-end liquidity was $1.6 billion

-- Updated estimates for 2006 provided

Dynegy Inc. (NYSE:DYN) today reported net income applicable tocommon stockholders of $88 million or $0.23 per diluted share for2005, which included net income of $300 million for the fourth quarter2005. This compares to a net loss applicable to common stockholders of$37 million or $(0.10) per diluted share for 2004, which included anet loss of $176 million for the fourth quarter 2004.

Financial results for 2005 included a $1.1 billion pre-tax gain onthe sale of the Midstream business and $102 million in tax benefitsassociated with the net reduction of a deferred tax valuationallowance primarily related to capital loss carryforwards realized onthe sale of Midstream. The gain and benefit were partially offset bypreviously announced pre-tax charges of $364 million related to thetermination of the Sterlington power tolling obligation and $169million related to the purchase of the Independence facility, whichresulted in the Independence power tolling obligations becomingintercompany agreements. Other 2005 pre-tax charges included legal andsettlement charges of $287 million, which largely related to thesettlement of shareholder class action litigation, asset impairmentsand other charges totaling $67 million.

"2005 was a pivotal year for Dynegy in terms of completing keyself-restructuring initiatives and shifting our approach from theresolution of legacy issues to the future where running and growingour business is the primary focus," said Bruce A. Williamson, Chairmanand Chief Executive Officer of Dynegy Inc. "It was also a year thatsaw us operate our business in a safe, efficient and reliable manner,capitalize on near-term market opportunities, maintain our emphasis onfinancial discipline, and manage costs and capital expenditures tomaximize liquidity and financial flexibility.

"Going forward, we will continue to market our production througha commercial strategy that emphasizes producing and selling energy ina timely and efficient manner to meet market requirements, whilemaintaining a strong balance sheet," Williamson added. "We believethis is a proven business model that has withstood the test of time inother commodity-cyclical energy sectors, and, when coupled with ourstrong operational performance, will produce long-term value for ourcompany's investors as the economy strengthens and power marketscontinue to recover."

Year-Over-Year Comparison

A comparison of the company's 2005 and 2004 results is set forthin the table below (in millions of dollars, except per share amounts):
2005 2004
--------- ---------
Loss from continuing operations before income
taxes $(1,199) $(352)
Income tax benefit from continuing operations 396 172
Income from discontinued operations, net of tax 918 165
Cumulative effect of change in accounting
principle, net of tax (5) --
--------- ---------
Net income (loss) 110 (15)
Less: Preferred stock dividends 22 22
--------- ---------
Net income (loss) applicable to common
stockholders $88 $(37)
Basic earnings (loss) per share $0.23 $(0.10)
Diluted earnings (loss) per share 0.23 (0.10)

Annual Business Results

Following are year-end 2005 business results compared to year-end2004. Because Illinois Power was sold to Ameren Corporation in thethird quarter 2004, Regulated Energy Delivery results are not includedin the company's 2005 business segment discussions. However, 2004financials include results from the Regulated Energy Deliverybusiness.

Power Generation Business

Earnings before interest, taxes and depreciation and amortization(EBITDA) from the power generation business was $404 million for 2005,compared to $547 million for 2004. Results for 2004 benefited from $90million in pre-tax gains related to the sale of the company'sinterests in the Joppa and Oyster Creek generation facilities, as wellas earnings from West Coast Power of $165 million, which were offsetby an $85 million impairment of the company's West Coast Powerinvestment.

For the 12 months ended Dec. 31, 2005, cash flow from operationswas $472 million, while capital expenditures were $143 million,business acquisition costs related to Sithe Energies were $120 millionand changes in restricted cash and other were $14 million. Free cashflow for the power generation business was an inflow of approximately$196 million.

Power generation results are now being reported on a regionalbasis, with segments including the Midwest, Northeast and South.

Midwest segment

EBITDA attributed to the Midwest segment was $355 million in 2005,compared to EBITDA of $430 million in 2004, which included the gain onthe sale of the Joppa facility. This segment comprises 13 facilitieslocated in Illinois (9 facilities), Michigan (1 facility), Ohio (1facility) and Kentucky (2 facilities), with a total capacity of 7,369megawatts.

Average on-peak market prices in NI Hub/Com Ed and Cinergy were 48percent and 49 percent higher, respectively, than during 2004.

Sales volumes generated by Midwest facilities rose to 21.9 millionmegawatt hours in 2005 compared to 20.8 million megawatt hours in2004, excluding volumes from assets sold in 2004. Volumes supplied toAmerenIP under Dynegy's two-year power purchase agreement were 25percent higher in 2005 than volumes provided to Dynegy's formerRegulated Energy Delivery business in 2004. While profitable, energysold to AmerenIP under the power purchase agreement is pricedsignificantly below current market prices. The power purchaseagreement expires at the end of 2006.

Midwest milestones during 2005 included the conversion of thecompany's Havana facility to lower-emission Powder River Basin (PRB)coal. In addition, the Vermilion facility was substantially convertedto PRB during 2005. Today, all of the company's Illinois coal-firedfacilities use PRB coal as a fuel source. In another milestone, thecompany settled environmental litigation related to its Illinoiscoal-fired fleet. In addition, during the fourth quarter, the companyannounced that it has agreed to acquire NRG Energy's 50 percentownership interest in the Rocky Road natural gas-fired peakingfacility near Chicago. This transaction, which is expected to close inearly 2006, will provide Dynegy with full ownership interest in the364-megawatt Rocky Road facility and a related long-term capacitycontract. The Rocky Road facility, as well as the company's otherfully owned peaking facilities in the Midwest segment, all operated atvarious times in 2005 as a result of the implementation of the MidwestIndependent System Operator dispatch structure and favorable weatherconditions. Midwest peaking facilities provided $16 million more inearnings than in 2004 before a $5 million charge in 2005 for aninventory adjustment.

Northeast segment

EBITDA attributed to Dynegy's Northeast segment was $53 million in2005, compared to EBITDA of $31 million in 2004. This segment includesthe Roseton, Danskammer and Independence facilities in New York, whichhave a combined generating capacity of 2,803 megawatts.

Average on-peak market prices in New York Zone G (Roseton andDanskammer) and New York Zone A (Independence) were 48 percent and 43percent higher, respectively, than in 2004. In addition, natural gasand fuel oil prices averaged 50 percent and 43 percent higher,respectively, than in 2004.

Sales volumes generated by Northeast facilities rose to 8.3million megawatt hours in 2005 compared to 6 million megawatt hours in2004, largely as a result of the acquisition of the Independencecombined-cycle facility during the first quarter 2005. Sales volumeswere slightly higher year-over-year for the Danskammer facility, butcompressed spark spreads resulted in lower volumes generated by theRoseton facility. Volumes produced by the two plants were essentiallyflat for the year.

Northeast segment milestones during 2005 included the acquisitionof the natural gas-fired Independence facility, which diversifies theNortheast segment's fuel types among natural gas, fuel oil and coal.

South segment

The loss before interest, taxes and depreciation and amortizationattributed to the South segment was $4 million in 2005, compared toEBITDA of $86 million in 2004. Results for 2004 included earnings fromWest Coast Power related to a California Department of Water Resources(CDWR) contract that ended in December 2004. This segment primarilyincludes the 610-megawatt CoGen Lyondell combined-cycle facility inTexas, peaking facilities in three other states and Dynegy's interestin West Coast Power, which the company has agreed to sell to NRGEnergy.

Average on-peak market prices in the Electric Reliability Councilof Texas (ERCOT) were 57 percent higher than during 2004. Resultsbenefited from higher power prices, improved spark spreads andstronger sales of ancillary services from CoGen Lyondell.

Sales volumes generated by South segment facilities decreased from5.8 million megawatt hours in 2004 to 5.3 million megawatt hours in2005, excluding volumes from assets sold in 2004, primarily as aresult of decreased volumes related to the expiration of the CDWRcontract.

South segment milestones during 2005 included a new, 15-yearcommercial arrangement where the company's CoGen Lyondell facilitywill provide electricity and steam to Lyondell Chemical Company undera contract providing for fuel cost recovery and a market-based margin.The new contract begins on Jan. 1, 2007.

Customer Risk Management Business

The loss before interest, taxes and depreciation and amortizationfrom the Customer Risk Management segment totaled $640 million during2005, compared to a $101 million loss before interest, taxes anddepreciation and amortization in 2004. The 2005 loss included thepreviously announced $364 million and $169 million charges,respectively, related to the agreement to terminate the Sterlingtonpower tolling obligation and the purchase of the Independencefacility. This segment's results reflect the impact of fixed paymentson the company's remaining power tolling arrangements in the segmentin excess of realized margins on power generated and sold.

Midstream Business

The sale of the Midstream business to Targa Resources wascompleted on Oct. 31, 2005. EBITDA from the Midstream segment was $1.3billion for the 10 months of 2005 that Dynegy owned the business,compared to EBITDA of $369 million for 2004. 2005 results included again on sale of approximately $1.1 billion.

For the 10 months of 2005, cash flow from operations was $288million and proceeds from asset sales were $2.4 billion, while capitalexpenditures were $45 million. Free cash flow for the Midstreamsegment was an inflow of $2.6 billion.

Other

In the Other segment, which consists primarily of general andadministrative expenses and legal and settlement charges, the companyrecorded a $355 million loss before interest, taxes and depreciationand amortization for 2005, compared to a $240 million loss for 2004.The loss in 2005 related primarily to a $249 million charge for thesettlement of the company's shareholder class action litigation andassociated legal expenses, compared to $92 million in legal andsettlement expenses in 2004. The 2005 loss was partially offset bylower general and administrative costs and lower insurance costs.

Consolidated Interest and Taxes

Interest expense totaled $389 million in 2005, compared to $453million in 2004. The decrease is primarily attributable to loweraverage debt balances in 2005, resulting from the sale of IllinoisPower in September 2004 and other debt repayments in 2004, partiallyoffset by the acquisition of the Independence facility, increasedinterest rates and decreased amortization of debt issuance costs in2005.

The 2005 tax benefit from continuing operations of $396 millionincludes a $32 million charge associated with a deferred tax valuationallowance. The 2004 tax benefit from continuing operations of $172million includes a $36 million benefit primarily related to therelease of a deferred tax valuation allowance. After adjusting forthese items, the effective tax rates for 2005 and 2004 were 36 percentand 39 percent, respectively.

Liquidity

As of Dec. 31, 2005, Dynegy's liquidity was approximately $1.6billion. This consisted of approximately $1.5 billion in cash on handand $71 million in unused availability under the company's cashcollateralized letter of credit facility.

On March 6, 2006 the company announced the completion of athree-year, $400 million revolving credit facility. The new facilityamends and restates the credit facility last amended on Oct. 31, 2005,and eliminates the requirement to cash collateralize the facility. Thenew credit facility, which is undrawn, is available for letters ofcredit and general corporate purposes. As of March 7, 2006, after alsoreflecting the announced completion of the Sterlington power tollingsettlement, liquidity was approximately $1.7 billion.

Cash Flow

Cash flow from operations, including working capital changes,totaled an outflow of $30 million for the 12 months ended Dec. 31,2005. This consisted of cash inflows of $472 million from the powergeneration business and $288 million from the former Midstreambusiness. These cash inflows were more than offset by outflows of $769million in the Other segment resulting from payments to settle theshareholder class action litigation, interest payments and general andadministrative expenses. In addition, the legacy Customer RiskManagement business had cash outflows of $21 million primarily frompayments related to the company's remaining tolling arrangements,partially offset by the return of cash collateral.

Cash flow from investing activities for the 12 months ended Dec.31, 2005, totaled $1.8 billion. This consisted of $2.5 billion inproceeds from asset sales, primarily relating to the sale of theMidstream business, partially offset by $664 million in capitalexpenditures, business acquisition costs and changes in restrictedcash.

For the 12 months ended Dec. 31, 2005, Dynegy's free cash flow(cash from operations plus cash flow from investing activities) was$1.8 billion.

2006 Cash Flow and Earnings Estimates

On Nov. 8, 2005, Dynegy provided cash flow and earnings estimatesfor 2006. Those estimates were based on quoted forward commodity pricecurves as of Oct. 4, 2005. In connection with today's announcement,Dynegy is updating its 2006 estimates to reflect quoted forwardcommodity price curves as of Feb. 7, 2006. These commodity pricecurves were derived from standard market quotes and are notnecessarily indicative of management's expectations for commodityprice movements during the rest of 2006; rather, they representcommodity price estimates as of Feb. 7, 2006 and are intended toprovide a basis on which the effects of future commodity pricemovements can be measured. Dynegy's updated estimates also reflectcurrent estimates and assumptions regarding, among other things, salesvolumes, fuel costs and other operational activities, as well as thefinancial results of the termination of the Sterlington power tollingobligation and the pending sale of the company's interest in WestCoast Power.

Taking these factors into consideration, the company's estimatedfree cash flow for 2006 is an inflow of $85 million to $195 million,compared to the previous estimate of an inflow of $20 million to $130million. The current 2006 estimated net loss applicable to commonstockholders is $65 million to $130 million, compared to thepreviously estimated net loss of $5 million to $75 million. EstimatedEBITDA for the company's power generation business is $565 million to$660 million, compared to the previous estimate of $725 million to$825 million.

Investor Conference Call/Web Cast

Dynegy will discuss its 2005 results during an investor conferencecall and web cast today at 9 a.m. ET/8 a.m. CT. Participants mayaccess the web cast and the related presentation materials on the"News & Financials" section of www.dynegy.com.

About Dynegy Inc.

Dynegy Inc. produces and sells electric energy, capacity andancillary services in key U.S. markets. The company's power generationportfolio consists of more than 12,600 megawatts of baseload,intermediate and peaking power plants fueled by a mix of coal, fueloil and natural gas.

Certain statements included in this news release are intended as"forward-looking statements." These statements include assumptions,expectations, predictions, intentions or beliefs about future events,particularly the statements concerning the company's strategy ofrunning and growing its power generation business and the anticipatedresults of its business model, indications of a recovering powermarket environment, the agreed upon purchase and sale transactionsinvolving interests in the West Coast Power and Rocky Road facilities,the contract for our CoGen Lyondell facility, and Dynegy's estimatedfinancial results for 2006. Historically, Dynegy's performance hasdeviated, in some cases materially, from its earnings and cash flowestimates, and Dynegy cautions that actual future results may varymaterially from those expressed or implied in any forward-lookingstatements, particularly as a result of changes in commodity prices.While Dynegy would expect to update these estimates on a quarterlybasis, it does not intend to update these estimates during any quarterbecause definitive information regarding its quarterly financialresults is not available until after the books for the quarter havebeen closed. Accordingly, Dynegy expects to provide updates only afterit has closed the books and reported the results for a particularquarter, or otherwise as may be required by applicable law.

Some of the key factors that could cause actual results to varymaterially from those estimated, expected or implied include: changesin commodity prices, particularly for power and natural gas; theeffects of competition and weather on the demand for Dynegy's productsand services; the impacts of hedging and the strategy of reducedhedging; Dynegy's ability to successfully complete its exit from theCustomer Risk Management business and fund the costs associated withthis exit; the availability, ability to consummate, and effects ofcommercial and strategic growth opportunities for Dynegy's powergeneration business; Dynegy's ability to address its substantialleverage on favorable terms; the condition of the capital marketsgenerally and Dynegy's ability to access the capital markets as andwhen needed; operational factors affecting Dynegy's assets, includingblackouts or other unscheduled outages; Dynegy's ability to fund theprojects mandated by the Baldwin consent decree; and uncertaintiesregarding environmental regulations, litigation and other legal orregulatory developments affecting Dynegy's businesses, includinglitigation relating to the western power and natural gas markets andmaster netting agreement matters. More information about the risks anduncertainties relating to these forward-looking statements is found inDynegy's SEC filings, including its Annual Report on Form 10-K for theyear ended Dec. 31, 2004, its Quarterly Report on Form 10-Q for thequarter ended September 30, 2005 and its Current Reports, which areavailable free of charge on the SEC's web site at http://www.sec.gov.Dynegy expressly disclaims any obligation to update anyforward-looking statements contained in this news release to reflectevents or circumstances that may arise after the date of this release,except as otherwise required by applicable law.

Dynegy's 2005 independent audit is not complete, and Dynegyexpects to file its 2005 Form 10-K with the SEC upon completion ofthis audit on or before the applicable SEC filing deadline. The 2005Form 10-K will contain audited financial statements and other requireddisclosures, including any changes that may be identified relative tothe results reported herein. DYNC
DYNEGY INC.
REPORTED UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)

Three Months Ended Twelve Months Ended
December 31, December 31,
------------------- -------------------
2005 2004 2005 2004
--------- --------- --------- ---------

Revenues $622 $327 $2,313 $2,451
Cost of sales, exclusive of
depreciation and amortization
shown separately below (934) (418) (2,416) (1,850)
Depreciation and amortization
expense (55) (52) (220) (235)
Impairment and other charges (40) - (46) (78)
Loss on sale of assets, net - (19) (1) (58)
General and administrative
expenses (47) (99) (468) (330)
--------- --------- --------- ---------
Operating loss (454) (261) (838) (100)

Earnings (losses) from
unconsolidated investments (12) 5 2 192
Interest expense (105) (67) (389) (453)
Other income and expense, net 17 3 26 9
--------- --------- --------- ---------
Loss from continuing
operations before income
taxes (554) (320) (1,199) (352)

Income tax benefit 168 97 396 172
--------- --------- --------- ---------
Loss from continuing
operations (386) (223) (803) (180)

Income from discontinued
operations, net of tax 696 52 918 165
Cumulative effect of change in
accounting principle, net of
tax (5) - (5) -
--------- --------- --------- ---------
Net income (loss) $305 $(171) $110 $(15)
--------- --------- --------- ---------

Less: Preferred stock
dividends 5 5 22 22
--------- --------- --------- ---------
Net income (loss) applicable
to common stockholders $300 $(176) $88 $(37)
========= ========= ========= =========

Earnings (loss) before
interest, taxes, and
depreciation and amortization
(EBITDA) (1) $714 $(107) $750 $727

Basic earnings (loss) per
share:
Loss from continuing
operations (2) $(0.98) $(0.60) $(2.13) $(0.53)
Income from discontinued
operations 1.74 0.14 2.37 0.43
Cumulative effect of change
in accounting principle (0.01) - (0.01) -
--------- --------- --------- ---------
Basic earnings (loss) per
share $0.75 $(0.46) $0.23 $(0.10)
========= ========= ========= =========

Diluted earnings (loss) per
share:
Loss from continuing
operations (2) $(0.98) $(0.60) $(2.13) $(0.53)
Income from discontinued
operations 1.74 0.14 2.37 0.43
Cumulative effect of change
in accounting principle (0.01) - (0.01) -
--------- --------- --------- ---------
Diluted earnings (loss) per
share $0.75 $(0.46) $0.23 $(0.10)
========= ========= ========= =========

Basic shares outstanding 398 379 387 378
Diluted shares outstanding 524 505 513 504

(1) EBITDA is a non-GAAP financial measure. Consolidated EBITDA can be
reconciled to Net income (loss) using the following calculation:
Net income (loss) less Income tax benefit, plus Interest expense
and Depreciation and amortization expense. Management and some
members of the investment community utilize EBITDA to measure
financial performance on an ongoing basis. However, EBITDA should
not be used in lieu of GAAP measures such as net income and cash
flow from operations. A reconciliation of EBITDA to Operating
income (loss) and Net income (loss) for the periods presented is
included below.

Three Months Ended Twelve Months Ended
December 31, December 31,
------------------- -------------------
2005 2004 2005 2004
--------- --------- --------- ---------

Operating loss $(454) $(261) $(838) $(100)

Add: Depreciation and
amortization expense, a
component of operating loss 55 52 220 235
Earnings (losses) from
unconsolidated investments (12) 5 2 192
Other income and expense,
net 17 3 26 9
EBITDA from discontinued
operations (3) 1,115 94 1,347 391
Cumulative effect of change
in accounting principle,
pre-tax (7) - (7) -
--------- --------- --------- ---------
Earnings before interest,
taxes, and depreciation and
amortization (EBITDA) 714 (107) 750 727

Depreciation and
amortization expense, a
component of operating loss (55) (52) (220) (235)
Depreciation and
amortization expense from
discontinued operations (1) (22) (38) (88)
Interest expense from
continuing operations (105) (67) (389) (453)
Interest expense from
discontinued operations (13) (11) (53) (27)
Income tax benefit from
continuing operations 168 97 396 172
Income tax expense from
discontinued operations (405) (9) (338) (111)
Income tax benefit on
cumulative effect of change
in accounting principle 2 - 2 -
--------- --------- --------- ---------
Net income (loss) $305 $(171) $110 $(15)
========= ========= ========= =========

(2) See "Reported Unaudited Basic and Diluted loss Per Share From
Continuing Operations" for a reconciliation of basic loss per
share from continuing operations to diluted loss per share from
continuing operations.

(3) A reconciliation of EBITDA from discontinued operations to Income
from discontinued operations, net of tax for the periods presented
is included below.

Three Months Ended Twelve Months Ended
December 31, December 31,
------------------- -------------------
2005 2004 2005 2004
--------- --------- --------- ---------

EBITDA from discontinued
operations $1,115 $94 $1,347 $391

Depreciation and
amortization expense from
discontinued operations (1) (22) (38) (88)
Interest expense from
discontinued operations (13) (11) (53) (27)
Income tax expense from
discontinued operations (405) (9) (338) (111)
--------- --------- --------- ---------
Income from discontinued
operations, net of tax $696 $52 $918 $165
========= ========= ========= =========


DYNEGY INC.
REPORTED UNAUDITED BASIC AND DILUTED LOSS PER SHARE
FROM CONTINUING OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)

Three Months Ended Twelve Months Ended
December 31, December 31,
------------------- -------------------
2005 2004 2005 2004
--------- --------- --------- ---------

Loss from continuing
operations $(386) $(223) $(803) $(180)
Less: convertible preferred
stock dividends 5 5 22 22
--------- --------- --------- ---------
Loss from continuing
operations for basic loss per
share (391) (228) (825) (202)
Effect of dilutive securities:
Interest on convertible
subordinated debentures 2 2 7 7
Dividends on Series C
convertible preferred stock 5 5 22 22
--------- --------- --------- ---------
Loss from continuing
operations for diluted loss
per share $(384) $(221) $(796) $(173)
========= ========= ========= =========

Basic weighted-average shares 398 379 387 378

Effect of dilutive securities:
Stock options and restricted
stock 2 2 2 2
Convertible subordinated
debentures 55 55 55 55
Series C convertible
preferred stock 69 69 69 69
--------- --------- --------- ---------
Diluted weighted-average
shares 524 505 513 504
========= ========= ========= =========


Loss per share from continuing
operations:
Basic $(0.98) $(0.60) $(2.13) $(0.53)
========= ========= ========= =========

Diluted (1) $(0.98) $(0.60) $(2.13) $(0.53)
========= ========= ========= =========

(1) When an entity has a net loss from continuing operations, SFAS No.
128, "Earnings per Share," prohibits the inclusion of potential
common shares in the computation of diluted per-share amounts.
Accordingly, we have utilized the basic shares outstanding amount
to calculate both basic and diluted loss per share for the three
and twelve months ended December 31, 2005 and December 31, 2004.


DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)

Three Months Ended December 31, 2005
---------------------------------------------------------
Power Generation
--------------------
GEN-MW GEN-NE GEN-SO CRM NGL REG OTHER Total
------ ------ ------ ------ ------- ------ ------ ------

Generation $40 $(16) $(16) $8
Customer Risk
Management $(422) (422)
Other $(40) (40)
------ ------ ------ ------ ------- ------ ------ ------
Operating
income
(loss) 40 (16) (16) (422) $- $- (40) $(454)
Losses
from
uncon-
solidated
investments - - (12) - - - - (12)
Other items,
net - 2 - 5 - - 10 17
Cumulative
effect of
change in
accounting
principle,
pre-tax (5) (2) - - - - - (7)
Add:
Depreciation
and
amortization
expense,
a component
of operating
income
(loss) 40 5 6 - - - 4 55
------ ------ ------ ------ ------- ------ ------ ------
EBITDA from
continuing
operations
(1) 75 (11) (22) (417) - - (26) (401)
EBITDA from
discontinued
operations,
pre-tax (2) - - - 3 1,112 - - 1,115
------ ------ ------ ------ ------- ------ ------ ------
EBITDA (1) $75 $(11) $(22) $(414) $1,112 $- $(26) $714
Depreciation
and
amortization
expense (56)
Interest
expense (118)
------
Pre-tax
income 540
Income tax
expense (235)
------
Net income $305
======

Three Months Ended December 31, 2004
---------------------------------------------------------
Power Generation
--------------------
GEN-MW GEN-NE GEN-SO CRM NGL REG OTHER Total
------ ------ ------ ------ ------- ------ ------ ------

Generation $36 $(13) $(19) $4
Regulated
Energy
Delivery $(19) (19)
Customer Risk
Management $(163) (163)
Other $(83) (83)
------ ------ ------ ------ ------- ------ ------ ------
Operating
income
(loss) 36 (13) (19) (163) $- (19) (83) $(261)
Earnings
from uncon-
solidated
investments - - 5 - - - - 5
Other items,
net - - 1 (2) - - 4 3
Add:
Depreciation
and
amortization
expense,
a component
of operating
income
(loss) 39 3 4 - - - 6 52
------ ------ ------ ------ ------- ------ ------ ------
EBITDA from
continuing
operations
(1) 75 (10) (9) (165) - (19) (73) (201)
EBITDA from
discontinued
operations,
pre-tax (2) - - 2 92 - - 94
------ ------ ------ ------ ------- ------ ------ ------
EBITDA (1) $75 $(10) $(9) $(163) $92 $(19) $(73) $(107)
Depreciation
and
amortization
expense (74)
Interest
expense (78)
------
Pre-tax
loss (259)
Income tax
benefit 88
------
Net loss $(171)
======

(1) See Note (1) to "Reported Unaudited Condensed Consolidated
Statements of Operations." EBITDA is a non-GAAP financial measure.
Consolidated EBITDA can be reconciled to Net income (loss) using
the following calculation: Net income (loss) less Income tax
benefit, plus Interest expense and Depreciation and amortization
expense. Management and some members of the investment community
utilize EBITDA to measure financial performance on an ongoing
basis. However, EBITDA should not be used in lieu of GAAP measures
such as net income and cash flow from operations.

(2) See Note (3) to "Reported Unaudited Condensed Consolidated
Statements of Operations."


DYNEGY INC.
REPORTED SEGMENTED RESULTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS)

Twelve Months Ended December 31, 2005
---------------------------------------------------------
Power Generation
--------------------
GEN-MW GEN-NE GEN-SO CRM NGL REG OTHER Total
------ ------ ------ ------ ------- ------ ------ ------

Generation $194 $29 $(21) $202
Customer Risk
Management $(647) (647)
Other $(393) (393)
------ ------ ------ ------ ------- ------ ------ ------
Operating
income
(loss) 194 29 (21) (647) $- $- (393) $(838)
Earnings
(losses)
from
uncon-
solidated
investments 7 - (5) - - - - 2
Other items,
net 2 5 (1) - - - 20 26
Cumulative
effect of
change in
accounting
principle,
pre-tax (5) (2) - - - - - (7)
Add:
Depreciation
and
amortization
expense,
a component
of operating
income
(loss) 157 21 23 1 - - 18 220
------ ------ ------ ------ ------- ------ ------ ------
EBITDA from
continuing
operations
(1) 355 53 (4) (646) - - (355) (597)
EBITDA from
discontinued
operations,
pre-tax (2) - - - 6 1,341 - - 1,347
------ ------ ------ ------ ------- ------ ------ ------
EBITDA (1) $355 $53 $(4) $(640) $1,341 $- $(355) $750
Depreciation
and
amortization
expense (258)
Interest
expense (442)
------
Pre-tax
income 50
Income tax
benefit 60
------
Net income $110
======

Twelve Months Ended December 31, 2004
---------------------------------------------------------
Power Generation
--------------------
GEN-MW GEN-NE GEN-SO CRM NGL REG OTHER Total
------ ------ ------ ------ ------- ------ ------ ------

Generation $194 $21 $(52) $163
Regulated
Energy
Delivery $139 139
Customer Risk
Management $(118) (118)
Other $(284) (284)
------ ------ ------ ------ ------- ------ ------ ------
Operating
income
(loss) 194 21 (52) (118) $- 139 (284) $(100)
Earnings
from
uncon-
solidated
investments 80 - 112 - - - - 192
Other items,
net - - 1 (3) - 3 8 9
Add:
Depreciation
and
amortization
expense,
a component
of operating
income
(loss) 156 10 25 1 - 10 33 235
------ ------ ------ ------ ------- ------ ------ ------
EBITDA from
continuing
operations
(1) 430 31 86 (120) - 152 (243) 336
EBITDA from
discontinued
operations,
pre-tax (2) - - - 19 369 - 3 391
------ ------ ------ ------ ------- ------ ------ ------
EBITDA (1) $430 $31 $86 $(101) $369 $152 $(240) $727
Depreciation
and
amortization
expense (323)
Interest
expense (480)
------
Pre-tax
loss (76)
Income tax
benefit 61
------
Net loss $(15)
======

(1) See Note (1) to "Reported Unaudited Condensed Consolidated
Statements of Operations." EBITDA is a non-GAAP financial measure.
Consolidated EBITDA can be reconciled to Net income (loss) using
the following calculation: Net income (loss) less Income tax
benefit, plus Interest expense and Depreciation and amortization
expense. Management and some members of the investment community
utilize EBITDA to measure financial performance on an ongoing
basis. However, EBITDA should not be used in lieu of GAAP measures
such as net income and cash flow from operations.

(2) See Note (3) to "Reported Unaudited Condensed Consolidated
Statements of Operations."


DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)

Three Months Ended December 31, 2005
---------------------------------------------------------
Power Generation
--------------------
GEN-MW GEN-NE GEN-SO CRM NGL REG OTHER Total
------ ------ ------ ------ ------- ------ ------ ------

Sterlington
toll
settlement
charge (1) $- $- $- $(364) $- $- $- $(364)
Asset
impairment
(2) (29) - - - - - - (29)
Impairment of
generation
investments (3) - - (19) - - - - (19)
Restructuring
charges (4) - - - - - - (11) (11)
Legal and
settlement
charges (5) - - - (9) - - - (9)
Taxes (6) - - - - - - (23) (23)
Discontinued
operations
(7) - - - 3 1,098 - - 1,101
------ ------ ------ ------ ------- ------ ------ ------
Total $(29) $- $(19) $(370) $1,098 $- $(34) $646
====== ====== ====== ====== ======= ====== ====== ======

Three Months Ended December 31, 2004
---------------------------------------------------------
Power Generation
--------------------
GEN-MW GEN-NE GEN-SO CRM NGL REG OTHER Total
------ ------ ------ ------ ------- ------ ------ ------

Kendall toll
restruc-
turing (8) $- $- $- $(115) $- $- $- $(115)
Legal and
settlement
charges (9) (9) - - (13) - - (35) (57)
Impairment of
West Coast
Power (10) - - (40) - - - - (40)
Loss on sale
of Illinois
Power (11) - - - - - (19) - (19)
Taxes (12) - - - - - - (19) (19)
Discontinued
operations
(13) - - - 2 59 - - 61
------ ------ ------ ------ ------- ------ ------ ------
Total $(9) $- $(40) $(126) $59 $(19) $(54) $(189)
====== ====== ====== ====== ======= ====== ====== ======

(1) We recognized a pre-tax charge of approximately $364 million ($229
million after-tax) related to the Sterlington toll settlement.
This charge is included in Cost of sales.

(2) We recognized a pre-tax charge of approximately $29 million ($18
million after-tax) related to the impairment of a gas turbine not
currently in use. This charge is included in Impairment and other
charges.

(3) We recognized a pre-tax charge of approximately $19 million ($12
million after-tax) related to the impairment of our investments in
Black Mountain, West Coast Power, a joint venture with NRG, and
Chorrera, a joint venture located in Panama. This charge is
included in Earnings (losses) from unconsolidated investments.

(4) We recognized a pre-tax loss of approximately $11 million ($7
million after-tax) related to restructuring charges in connection
with a reduction in workforce. This loss is included in Impairment
and other charges.

(5) We recognized a pre-tax loss of approximately $9 million ($6
million after-tax) related to legal and settlement charges. This
loss is included in General and administrative expenses and
Impairment and other charges.

(6) We recognized a net income tax expense of approximately $23
related to an increase in the deferred tax valuation allowance. An
expense of $32 million is included in Income tax benefit,
partially offset by a $9 million benefit included in the $696
million after-tax Income from discontinued operations.

(7) We recognized pre-tax income of approximately $1,101 million ($696
million after-tax) related to discontinued operations. The income
consists primarily of $1,098 million associated with our NGL
segment, which was reclassified to discontinued operations due to
the sale of DMSLP. Included in the $1,098 is a pre-tax gain of
approximately $1,087 ($681 million after-tax) on the sale of
DMSLP.

(8) We recognized a pre-tax charge of approximately $115 million ($72
million after-tax) related to the restructuring of the Kendall
toll with Constellation Energy. This charge is included in Cost of
sales.

(9) We recognized a pre-tax loss of approximately $57 million ($36
million after-tax) related to legal and settlement charges. The
loss is included in Cost of sales and General and administrative
expenses.

(10) We recognized a pre-tax charge of approximately $40 million ($25
million after-tax) related to our share of an impairment of assets
at West Coast Power and an impairment of our investment in West
Coast Power. This charge is included in Earnings (losses) from
unconsolidated investments.

(11) We recognized a pre-tax loss of approximately $19 million ($12
million after-tax) related to the sale of Illinois Power. This
loss is included in Loss on sale of assets, net.

(12) We recognized a net income tax expense of approximately $19
million primarily related to deferred tax capital loss valuation
allowances. An expense of $28 million is included in Income tax
benefit and a benefit of $9 million is included in Income from
discontinued operations.

(13) We recognized pre-tax income of approximately $61 million ($52
million after-tax) related to discontinued operations. The income
consists primarily of $59 million associated with our NGL segment,
which was reclassified to discontinued operations due to the
anticipated sale of DMSLP. Included in the $59 million of income
from our NGL segment is a pre-tax gain of approximately $16
million ($10 million after-tax) on the sale of our Sherman natural
gas processing facility.


DYNEGY INC.
SIGNIFICANT ITEMS
(UNAUDITED) (IN MILLIONS)

Twelve Months Ended December 31, 2005
--------------------------------------------------------
Power Generation
--------------------
GEN-MW GEN-NE GEN-SO CRM NGL REG OTHER Total
------ ------ ------ ------ ------- ------ ------ ------

Sterlington
toll
settlement
charge (1) $- $- $- $(364) $- $- $- $(364)
Legal and
settlement
charges (2) - - - (38) - - (249) (287)
Independence
toll
settlement
charge (3) - - - (169) - - - (169)
Asset
impairment
(4) (29) - - - - - - (29)
Impairment of
generation
investments
(5) - - (27) - - - - (27)
Restructuring
charges (6) - - - - - - (11) (11)
Taxes (7) - - - - - - 102 102
Discontinued
operations
(8) - - - 6 1,250 - - 1,256
------ ------ ------ ------ ------- ------ ------ ------
Total $(29) $- $(27) $(565) $1,250 $- $(158) $471
====== ====== ====== ====== ======= ====== ====== ======

Twelve Months Ended December 31, 2004
--------------------------------------------------------
Power Generation
--------------------
GEN-MW GEN-NE GEN-SO CRM NGL REG OTHER Total
------ ------ ------ ------ ------- ------ ------ ------

Kendall
toll
restruc-
turing (9) $- $- $- $(115) $- $- $- $(115)
Legal and
settlement
charges (10) (9) - 2 (13) - (1) (92) (113)
Impairment of
West Coast
Power (11) - - (85) - - - - (85)
Loss on sale
of Illinois
Power (12) - - - - - (58) - (58)
Impairment of
Illinois
Power (13) - - - - - (54) - (54)
Acceleration
of financing
costs (14) - - - - - - (14) (14)
Gain on sale
of Oyster
Creek (15) - - 15 - - - - 15
Taxes (16) - - - - - - 24 24
Gain on sale
of Joppa
(17) 75 - - - - - 75
Gas transpor-
tation
contracts (18) - - - 88 - - - 88
Discontinued
operations
(19) - - - 19 254 - 3 276
------ ------ ------ ------ ------- ------ ------ ------
Total $66 $- $(68) $(21) $254 $(113) $(79) $39
====== ====== ====== ====== ======= ====== ====== ======

(1) We recognized a pre-tax charge of approximately $364 million ($229
million after-tax) related to the Sterlington toll settlement.
This charge is included in Cost of sales.

(2) We recognized a pre-tax loss of approximately $287 million ($197
million after-tax) primarily related to the settlement of our
class action shareholder lawsuit and other legal and settlement
charges. This loss is included in General and administrative
expenses.

(3) We recognized a pre-tax loss of approximately $169 million ($109
million after-tax) related to the Independence toll restructuring
charge following our acquisition of ExRes SHC, Inc., the parent
company of Sithe Energies, Inc. and Sithe/Independence Power
Partners, L.P. This loss is included in Cost of sales.

(4) We recognized a pre-tax charge of approximately $29 million ($18
million after-tax) related to the impairment of a gas turbine not
currently in use. This charge is included in Impairment and other
charges.

(5) We recognized a pre-tax charge of approximately $27 million ($17
million after-tax) related to the impairment of our investments in
Black Mountain, West Coast Power, a joint venture with NRG, and
Chorrera, a joint venture located in Panama. This charge is
included in Earnings (losses) from unconsolidated investments.

(6) We recognized a pre-tax loss of approximately $11 million ($7
million after-tax) related to restructuring charges in connection
with a reduction in workforce. This loss is included in Impairment
and other charges.

(7) We recognized a net income tax benefit of approximately $102
primarily for the reversal of a deferred tax capital loss
valuation allowance related to gains on the anticipated sale of
DMSLP. A benefit of $134 million is included in the $918 million
after-tax Income from discontinued operations, partially offset by
a $32 million charge in Income tax benefit.

(8) We recognized pre-tax income of approximately $1,256 million ($918
million after-tax) related to discontinued operations. The income
consists primarily of $1,250 million associated with our NGL
segment, which was reclassified to discontinued operations due to
the sale of DMSLP, and $6 million pre-tax income on our UK CRM
business. Included in the $1,250 million of income from our NGL
segment are a pre-tax gains of approximately $1,087 ($681 million
after-tax) on the sale of DMSLP and $10 million ($7 million
after-tax) on the sale of the Port Everglades property.

(9) We recognized a pre-tax charge of approximately $115 million ($72
million after-tax) related to the restructuring of the Kendall
toll with Constellation Energy. This charge is included in Cost of
sales.

(10) We recognized a pre-tax loss of approximately $113 million ($71
million after-tax) related to legal and settlement charges. The
loss is primarily included in General and administrative expenses,
Impairment and other charges and Cost of sales.

(11) We recognized a pre-tax charge of approximately $85 million ($54
million after-tax) related to our share of an impairment of assets
at West Coast Power and an impairment of our investment in West
Coast Power. This charge is included in Earnings (losses) from
unconsolidated investments.

(12) We recognized a pre-tax loss of approximately $58 million ($37
million after-tax) related to the sale of Illinois Power. The
loss is primarily included in Loss on sale of assets, net.

(13) We recognized a pre-tax charge of approximately $54 million ($34
million after-tax) relating to the impairment of Illinois Power.
This loss is included in Impairment and other charges.

(14) We recognized a pre-tax charge of approximately $14 million ($9
million after-tax) related to the acceleration of debt issuance
costs associated with our former $1.1 billion revolving credit
facility that was replaced in May 2004 with a $700 million
revolving credit facility and $600 million term loan. This charge
is included in Interest expense.

(15) We recognized a pre-tax gain of approximately $15 million ($9
million after-tax) on the sale of our interest in the Oyster Creek
cogeneration facility. This gain is included in Earnings (losses)
from unconsolidated investments.

(16) We recognized a net income tax benefit of approximately $24
million primarily related to a net release of deferred tax capital
loss valuation allowances related to gains on asset sales offset
by charges resulting from the conclusion of prior year tax audits.
A benefit of $36 million is included in Income tax benefit,
partially offset by a $12 million charge in Income from
discontinued operations.

(17) We recognized a pre-tax gain of approximately $75 million ($47
million after-tax) on the sale of our interest in the Joppa power
generation facility. This gain is included in Earnings (losses)
from unconsolidated investments.

(18) We recognized a pre-tax gain of approximately $88 million ($55
million after-tax) related to our exit from four long-term natural
gas transportation contracts. This gain is included in Revenues.

(19) We recognized pre-tax income of approximately $276 million ($165
million after-tax) related to discontinued operations. The income
consists primarily of $254 million associated with our NGL
segment, which was reclassified to discontinued operations due to
sale of DMSLP, $19 million pre-tax income on our UK CRM business
and $3 million pre-tax income associated with our global
communications business. Included in the $254 million of income
from our NGL segment is a pre-tax gain of approximately $36
million ($24 million after-tax) on the sale of our interest in the
Indian Basin gas processing plant, a pre-tax gain of approximately
$17 million ($11 million after-tax) on the sale of our remaining
financial interest in the Hackberry LNG project and a pre-tax gain
of approximately $16 million ($10 million after-tax) on the sale
of our Sherman natural gas processing facility.


DYNEGY INC.
SUMMARY CASH FLOW INFORMATION
(UNAUDITED) (IN MILLIONS)

Twelve Months Ended December 31, 2005
------------------------------------------------
GEN (1) CRM NGL REG OTHER Total
------- ------- ------- ------- -------- -------

Cash Flow from
Operations $472 $(21) $288 $- $(769) $(30)

Capital Expenditures (143) - (45) - (7) (195)

Business Acquisition
Costs (120) - - - - (120)

Proceeds from Asset
Sales (2) 1 - 2,392 (5) 100 2,488

Restricted Cash and
Other (3) (14) - - - (335) (349)
------- ------- ------- ------- -------- -------

Free Cash Flow (4) $196 $(21) $2,635 $(5) $(1,011) $1,794
======= ======= ======= ======= ======== =======

Twelve Months Ended December 31, 2004
------------------------------------------------
GEN (1) CRM NGL REG OTHER Total
------- ------- ------- ------- -------- -------

Cash Flow from
Operations $421 $(371) $278 $213 $(536) $5

Capital Expenditures (148) - (61) (92) (13) (314)

Proceeds from Asset
Sales 260 - 99 217 - 576
------- ------- ------- ------- -------- -------

Free Cash Flow (4) $533 $(371) $316 $338 $(549) $267
======= ======= ======= ======= ======== =======

(1) Beginning in the fourth quarter 2005, we report the results of our
power generation business as three separate segments in our
consolidated financial statements: (1) the Midwest segment (GEN-
MW); (2) the Northeast segment (GEN-NE); and (3) the South segment
(GEN-SO). For the purpose of this schedule, GEN includes the three
combined segments.

(2) During the fourth quarter 2005, we received proceeds of
approximately $2,382 million from the sale of DMSLP and
approximately $10 million in the third quarter for sale of the
Port Everglades property. Also, during the first quarter 2005, we
paid approximately $5 million to Ameren related to the working
capital adjustment for our sale of Illinois Power.

(3) Restricted cash and other primarily relates to an increase in
restricted cash associated with the $335 million cash collateral
posted for the Amended and Restated Credit Facility.

(4) Free cash flow is a non-GAAP financial measure. Free cash flow can
be reconciled to operating cash flow using the following
calculation: Operating cash flow plus investing cash flow
(consisting of asset sale proceeds less business acquisition
costs, capital expenditures and changes in restricted cash) equals
free cash flow. We use free cash flow to measure the cash
generating ability of our operating asset-based energy businesses
relative to their capital expenditure obligations. Free cash flow
should not be used in lieu of GAAP measures with respect to cash
flows and should not be interpreted as available for discretionary
expenditures, as mandatory expenditures such as debt obligations
are not deducted from the measure. A reconciliation of free cash
flow to cash flow from operations by segment for the periods
presented is included above.


DYNEGY INC.
OPERATING DATA

Three Months Ended Twelve Months Ended
December 31, December 31,
------------------- -------------------
2005 2004 2005 2004
--------- --------- --------- ---------
GEN - MW
Million Megawatt Hours
Generated - Gross and Net 5.1 5.1 21.9 22.6
Average On-Peak Market Power
Prices ($/MWh):
Cinergy $71 $43 $64 $43
Commonwealth Edison
(NI Hub) $71 $42 $62 $42


GEN - NE
Million Megawatt Hours
Generated - Gross and Net 1.5 1.0 8.3 6.0
Average On-Peak Market Power
Prices ($/MWh):
New York - Zone G $111 $62 $92 $62
New York - Zone A $93 $53 $76 $53


GEN - SO
Million Megawatt Hours
Generated - Gross 1.5 1.8 6.6 8.5
Million Megawatt Hours
Generated - Net 1.2 1.4 5.3 6.7
Average On-Peak Market Power
Prices ($/MWh):
Southern $87 $49 $71 $49
ERCOT $93 $53 $80 $51
SP-15 $98 $61 $73 $55


Average Natural Gas Price -
Henry Hub ($/MMBtu) (1) $12.21 $6.26 $8.80 $5.85


NGL (2)
Field Plant Gross NGL
Production (MBbls/d) 60.4 57.0 56.6 57.3
Straddle Plant Gross NGL
Production (MBbls/d) 4.3 29.3 23.7 26.6
--------- --------- --------- ---------
Total Gross NGL
Production 64.7 86.3 80.3 83.9
========= ========= ========= =========

Natural Gas (Residue) Sales
(BBtu/d) 190.2 179.7 185.0 182.8

Natural Gas Field Plant Inlet
Volumes (MMCFD) 544.5 506.9 518.5 535.6
Natural Gas Straddle Plant
Inlet Volumes (MMCFD) 296.8 1,063.3 1,030.2 990.0
--------- --------- --------- ---------
Total Natural Gas Inlet
Volumes 841.3 1,570.2 1,548.7 1,525.6
========= ========= ========= =========

Fractionation Volumes
(MBbls/d) 169.5 154.7 173.8 202.5
Natural Gas Liquids Sold
(MBbls/d) 181.4 286.3 257.7 282.5

Average Commodity Prices:
Crude Oil - WTI ($/Bbl) $66.23 $50.10 $54.75 $41.43
Natural Gas - Henry Hub
($/MMBtu) (3) $13.93 $7.06 $7.87 $6.13
Natural Gas Liquids
($/Gal) $1.10 $0.83 $0.87 $0.71
Fractionation Spread
($/MMBtu) - daily $0.91 $3.11 $1.91 $2.18


REG (4)
Electric Sales in KWH
(Millions):
Residential - - - 4,182
Commercial - - - 3,389
Industrial - - - 3,859
Transportation of
Customer-Owned
Electricity - - - 2,407
Other - - - 287
--------- --------- --------- ---------
Total Electricity
Delivered - - - 14,124
========= ========= ========= =========

Gas Sales in Therms
(Millions):
Residential - - - 214
Commercial - - - 85
Industrial - - - 40
Transportation of
Customer-Owned Gas - - - 171
--------- --------- --------- ---------
Total Gas Delivered - - - 510
========= ========= ========= =========

Cooling Degree Days - Actual - - - 932
Cooling Degree Days - 10 year
rolling average - - - 1,236
Heating Degree Days - Actual - - - 3,145
Heating Degree Days - 10 year
rolling average - - - 3,190

(1) Calculated as the average of the daily gas prices for the period.

(2) Effective October 31, 2005, we sold DMSLP to Targa Resources.

(3) Calculated as the average of the first of the month prices for the
period.

(4) Effective September 30, 2004, we sold Illinois Power, our
regulated utility, to Ameren.


DYNEGY INC.
2006 EARNINGS ESTIMATES (1)
(IN MILLIONS)

Total
GEN-MW GEN-NE GEN-SO GEN CRM OTHER Total
-------- -------- ------- -------- ---- -------- ---------

EBITDA
(2) $490-540 $80-115 $(5)-5 $565-660 $15 $(100-90) $480-585

Deprec-
iation
and
Amorti-
zation (155) (50) (30) (235) - (10) (245)

Interest
Expense (410)

Income
Tax
Benefit 67-27

Preferred
Stock
Divi-
dends (22)
---------

Net Loss $(130-65)
=========


2006 CASH FLOW ESTIMATES (1)
(IN MILLIONS)

Total Non-
Core Core
GEN (4) CRM OTHER Business (5) Total
-------- -------- ---------- --------- ------ ---------

Cash Flow
from
Operations $530-630 $(10) $(360-350) $160-270 (370) $(210-100)

Capital
Expenditures
and Business
Acquisitions (190) - (5) (195) (5) (200)

Proceeds from
Asset Sales - - - - 160 160

Changes in
Restricted
Cash - - - - 335 335

-------- -------- ---------- --------- ------ ---------
Free Cash
Flow (3) $340-440 $(10) $(365-355) $(35)-75 $120 $85-195
======== ======== ========== ========= ====== ==========

(1) 2006 estimates are presented on a GAAP basis and are based on
forward commodity price curves as of Feb. 7, 2006. Actual results
may vary materially from these estimates based on changes in
commodity prices, among other things, including operational
activities, legal settlements, financing or investing activities
and other uncertain or unplanned items. Core business represents
continuing results, excluding significant items.

(2) EBITDA is a non-GAAP financial measure. Consolidated EBITDA can be
reconciled to Net income (loss) using the following calculation:
Net income (loss) less Income tax benefit, plus Interest expense
and Depreciation and amortization expense. Management and some
members of the investment community utilize EBITDA to measure
financial performance on an ongoing basis. However, EBITDA should
not be used in lieu of GAAP measures such as net income (loss) and
cash flow from operations.

(3) Free cash flow is a non-GAAP financial measure. Free cash flow can
be reconciled to operating cash flow using the following
calculation: Operating cash flow plus investing cash flow
(consisting of asset sale proceeds less business acquisition
costs, capital expenditures and changes in restricted cash) equals
free cash flow. We use free cash flow to measure the cash
generating ability of our operating asset-based energy businesses
relative to their capital expenditure obligations. Free cash flow
should not be used in lieu of GAAP measures with respect to cash
flows and should not be interpreted as available for discretionary
expenditures as mandatory expenditures such as debt obligations
are not deducted from the measure. A reconciliation of free cash
flow to cash flow from operations by segment for the periods
presented is included above.

(4) Beginning in the fourth quarter 2005, we report the results of our
power generation business as three separate segments in our
consolidated financial statements: (1) the Midwest segment (GEN-
MW); (2) the Northeast segment (GEN-NE); and (3) the South segment
(GEN-SO). For the purpose of this schedule, GEN includes the three
combined segments.

(5) The following summarizes the items included in Non-core business
in our cash flow estimate.


Capital Proceeds Changes
Cash Flow Exp. and from in Free
from Business Asset Restricted Cash
Operations Acq. Sales Cash Flows
---------- ---------- ---------- --------- ----------
Sterlington toll
settlement
payment (CRM) $(370) $- $- $- $(370)
Development
Capital
Expenditures
(GEN) - (5) - - (5)
Net proceeds
from sale of
West Coast
Power and
acquisition of
Rocky Road
(GEN) - - 160 - 160
Return of Cash
Collateral
(OTHER) - - - 335 335
---------- ---------- ---------- --------- --------
Total $(370) $(5) $160 $335 $120
========== ========== ========== ========= ========