Dynegy Announces Second Quarter 2005 Results

-- Company reports net income of $32 million, which included a $125 million tax benefit associated with the anticipated sale of the Midstream natural gas business

-- Power Generation business benefited from increased volumes and improved electricity prices, offset by expiration of West Coast Power customer contract

-- Midstream business continued to benefit from favorable commodity prices

-- Liquidity strong at $765 million

Dynegy Inc. (NYSE:DYN) today reported net income applicable tocommon shareholders of $32 million, or $0.08 per diluted share, forthe second quarter 2005, compared to net income applicable to commonshareholders of $2 million and diluted earnings per share of $0.01 forthe second quarter 2004.

The year-over-year increase in net income primarily resulted fromthe reduction of a deferred tax valuation allowance in the secondquarter 2005 of $125 million related to capital loss carryforwardsexpected to be utilized on the anticipated sale of the company'sMidstream natural gas business.

"Dynegy's Power Generation and Midstream natural gas businessesdelivered strong operational performances due to our continuing focuson asset availability to serve customers and capture marketopportunities," said Bruce A. Williamson, Chairman, President andChief Executive Officer of Dynegy Inc. "All but one of the company'sPower Generation peaking facilities operated during the quarter as aresult of increased demand in the Midwest and the Northeast. Inaddition, Midstream continued to benefit from a favorable commoditypricing environment and strong volumes.

"The recently announced sale of Midstream to Targa Resources for$2.475 billion in cash is yet another significant step in creating asustainable merchant power platform for the future," Williamson added."The proceeds from the transaction will provide Dynegy withopportunities to improve our balance sheet, thereby positioning ourPower Generation business for new growth or strategic directionsinvolving greater scale and scope through an expansion of our assetportfolio or combinations."

Year-Over-Year Comparison

A comparison of the company's second quarter 2005 and secondquarter 2004 results is contained in the table below (in millions ofdollars, except per share amounts):
2Q 2005 2Q 2004
---------- ----------
Loss from continuing operations, before tax $(150) $(44)
Income tax benefit from continuing operations 41 29
Income from discontinued operations, before tax 36 71
Income tax benefit (expense) from discontinued
operations 111 (48)
---------- ----------
Net income 38 8
Preferred stock dividends 6 6
---------- ----------
Net income applicable to common stockholders $32 $2
---------- ----------
Basic earnings per share $0.08 $0.01
Diluted earnings per share $0.08 $0.01

Quarterly Business Segment Results

Following are business segment financial results for the secondquarter 2005 compared to the second quarter 2004. Because IllinoisPower was sold to Ameren Corporation in the third quarter 2004,Regulated Energy Delivery results are not included in the company's2005 business segment discussions. However, 2004 financials includeresults from the Regulated Energy Delivery business.

Power Generation

Earnings before interest, taxes and depreciation and amortization(EBITDA) from the Power Generation business was $75 million for thesecond quarter 2005, compared to $132 million for the second quarter2004. The year-over-year decrease was primarily attributable to lowerequity earnings from West Coast Power as a result of the expiration ofa contract with the California Department of Water Resources inDecember 2004. In the second quarter 2004, the company recognizedearnings of $47 million from West Coast Power, compared to $1 millionin the second quarter 2005.

Power Generation benefited from increased volumes in nearly allregions where the company operates. Volumes in the Midwest increasedapproximately 11 percent during the second quarter 2005 compared tothe second quarter 2004. Energy supplied to AmerenIP under Dynegy'stwo-year power purchase agreement was more than 35 percent higher thanthe second quarter 2004. However, incremental energy sold to AmerenIPunder the power purchase agreement, which expires at the end of 2006,is priced significantly below current on-peak market prices, resultingin reduced margins for the Midwest region quarter-over-quarter.

Reduced margins in the Midwest region were largely offset byimprovements in the Electric Reliability Council of Texas (ERCOT)region, where reserve margins have fallen from 30 percent in 2004 to17 percent in 2005 due to the retirement of older units by othermarket participants. Stronger weather-driven demand in ERCOT resultedin higher power prices and improved spark spreads during the secondquarter 2005. Additionally, the company's ERCOT facility, the610-megawatt CoGen Lyondell combined-cycle plant, benefited from abaseload contract that allows it to capture additional ancillaryservice revenues from the marketplace.

In the Northeast region, volumes in the second quarter 2005 wereslightly higher than the second quarter 2004, largely as a result ofthe 1,021-megawatt Independence combined-cycle facility, which thecompany acquired in the first quarter 2005. Volumes generated by thecompany's 1,210-megawatt Roseton dual fuel-fired intermediate facilityduring the second quarter 2005 were lower due to compressed marginsgiven the higher costs of fuel oil relative to power prices.

Power Generation's operational performance benefited from thecommercial operation of all but one of the company's peaking plantsduring the second quarter 2005. During the first six months of 2005,Dynegy's Midwest peaking plants have generated more electricity thanthey did throughout all of 2004. This result is indicative of thecompany's continuing focus on operational readiness and in-marketavailability to meet weather-driven demand.

For the six months ended June 30, 2005, cash flow from operationswas $194 million, while capital expenditures were $65 million andbusiness acquisition costs related to the Sithe Energies transactionwere $120 million. Free cash flow for the Power Generation segment wasan inflow of $9 million.

Midstream

On August 2, Dynegy entered into an agreement to sell thecompany's Midstream business to Targa Resources, Inc. The Midstreambusiness is classified as "held-for-sale" in accordance with GenerallyAccepted Accounting Principles (GAAP), and its results are presentedas discontinued operations for all periods. As a result of theheld-for-sale status, depreciation of Midstream assets was suspendedbeginning in June 2005.

EBITDA from the Midstream business was $64 million for the secondquarter 2005, compared to $99 million for the second quarter 2004,which included a $36 million pre-tax gain related to the sale of thecompany's interest in the Indian Basin Gas Processing Plant. Secondquarter 2004 results also included a $6 million gain on sales ofnatural gas liquids held at historic below market costs, as well asfinancial contributions made by the Sherman Gas Processing Plant,which was sold in the fourth quarter 2004.

Second quarter 2005 results benefited from higher commodityprices, volumes and margins than were reported for the second quarter2004. The average natural gas price of $6.74 per million Britishthermal units represented a 12 percent increase compared to the secondquarter 2004. The average natural gas liquids price of $0.79 pergallon was 23 percent higher than the second quarter 2004.

Gross natural gas liquids volumes processed by the company's fieldand straddle plants in the second quarter 2005 increased 9 percent to86.6 thousand barrels per day compared to 79.7 thousand barrels perday in the second quarter 2004. Field processing volumes of 58thousand barrels per day, a 5 percent increase over the previous yearwhen adjusted for non-core asset sales, were attributable to strongeractivity in the company's Permian Basin and North Texas regions. Inaddition, the operation of the company's Barracuda, Lowry and Stingraygas processing facilities on the Louisiana Gulf Coast contributed tostraddle plant volumes of 28.6 thousand barrels per day, a 21 percentincrease over the second quarter 2004.

For the six months ended June 30, 2005, cash flow from operationswas $178 million, while capital expenditures were $23 million. Freecash flow for the Midstream segment was an inflow of $155 million.

Customer Risk Management

Loss before interest, taxes and depreciation and amortization fromthe Customer Risk Management business totaled $15 million for thesecond quarter 2005, compared to EBITDA of $90 million for the secondquarter 2004. Second quarter 2005 results included a benefit of $13million related to an adjustment to the first quarter 2005 chargeresulting from the restructuring of the Independence power tollingarrangement. Second quarter 2004 results included an $88 million gainrelated to the exit from four natural gas transportation contracts. Inaddition, results for the second quarter 2004 included $23 million ingains associated with the mark-to-market value of certain legacycontracts and positions.

The company's Customer Risk Management business, includingobligations associated with its remaining power tolling arrangementsand gas transportation arrangements, will continue to have a negativeeffect on its consolidated results of operations and cash flows untilthe related obligations have been satisfied or restructured. Thecompany remains open to opportunities to assign or renegotiate theterms of these arrangements.

Other

In the Other segment, which consists primarily of general andadministrative expenses, the company recorded a $59 million lossbefore interest, taxes and depreciation and amortization for thesecond quarter 2005, compared to an $89 million loss before interest,taxes and depreciation and amortization for the second quarter 2004.The loss in the second quarter 2005 included $31 million in legal andsettlement charges, compared to $42 million in legal and settlementcharges in the second quarter 2004. Compensation, insurance andexternal consultant costs were also lower in the second quarter 2005than the second quarter 2004.

The company's interest expense decreased by $45 million to $96million for the second quarter 2005 primarily as a result of the saleof Illinois Power in the third quarter 2004. Additionally, $14 millionand $4 million of interest expense has been reclassified asdiscontinued operations in the second quarter of 2005 and 2004,respectively, in accordance with GAAP. This reclassification is due tothe company's requirement to repay its priority lien debt withproceeds from the expected sale of the Midstream business.

The second quarter 2005 tax benefit from continuing anddiscontinued operations totaled $152 million, which included a $112million benefit primarily related to the reversal of a deferred taxvaluation allowance due to the anticipated sale of the Midstreambusiness. The second quarter 2004 tax expense from continuing anddiscontinued operations was $19 million, which included a $9 millionexpense primarily related to the conclusion of the prior year taxaudits offset by the reversal of a deferred tax valuation allowancedue to gains on asset sales. After adjusting for these items, theeffective tax rates for 2005 and 2004 were 35 percent and 37 percent,respectively.

Liquidity

As of June 30, 2005, Dynegy's liquidity was $765 million. Thisconsisted of $358 million in cash on hand and $407 million in unusedavailability under the company's $700 million revolving bank creditfacility. The decrease in liquidity as compared to the $968 millionbalance on March 31, 2005 primarily related to the payment during thesecond quarter 2005 of $175 million as part of the company'sshareholder class action litigation settlement.

To date, the company's revolving credit facility has been usedexclusively to support the issuance of letters of credit. Accordingly,as of June 30, there were no borrowings outstanding under thisfacility. Total collateral posted as of June 30, 2005, including cashand letters of credit, was approximately $509 million.

During the second quarter 2005, the company began to transitionfrom cash collateral to letters of credit in order to replenish cashbalances following the Sithe Energies acquisition and the settlementof the shareholder class action litigation.

Cash Flow

Cash flow from operations, including working capital changes,totaled an outflow of $9 million for the six months ended June 30,2005. This consisted of $372 million from the Power Generation andMidstream businesses and includes the return of cash as letters ofcredit were substituted for collateral. Cash inflows of $41 millionfrom the Customer Risk Management business resulted primarily from thereturn of cash as letters of credit were substituted for collateral,offset by capacity payments that exceeded realized margins on thecompany's power tolling arrangements, as well as a final payment toexit four natural gas transportation contracts. An additional $422million in cash outflows primarily related to interest payments andgeneral and administrative expenses in the company's Other businesssegment, including the $175 million payment in May 2005 in connectionwith the settlement of the shareholder class action litigation.

Cash flow from investing activities for the six months ended June30, 2005 totaled an outflow of $218 million. This consisted of $93million in capital expenditures and $120 million in businessacquisition costs related to the Sithe Energies transaction, as wellas a $5 million payment to Ameren related to working capitaladjustments in connection with the Illinois Power sale.

For the six months ended June 30, 2005, Dynegy's free cash flowwas an outflow of $227 million, which consisted of cash used inoperations and investing activities.

2005 Earnings Guidance Estimates

With today's announcement of second quarter 2005 earnings and theearlier announcement relating to the sale of Dynegy's Midstreambusiness, management is revising its 2005 earnings and cash flowguidance estimates last updated on May 9, 2005. The company's newestimate of net income applicable to common shareholders ofapproximately $400 million to $410 million compared to the previousestimate of a net loss of approximately $410 million to $395 milliontakes into consideration the anticipated significant net gain ofapproximately $815 million on the sale of the Midstream business. Thecompany's new estimate of net loss from its core businesses is a rangeof approximately $235 million to $225 million, compared to thepreviously announced estimated net loss of approximately $145 millionto $130 million. This new estimate takes into consideration thereclassification of Midstream financial results to discontinuedoperations pending the anticipated sale of the business, as well as anincrease in anticipated EBITDA of approximately $30 million from thePower Generation business.

Investor Conference Call/Web Cast

Dynegy will discuss its second quarter results during an investorconference call and web cast today at 9 a.m. ET/8 a.m. CT.Participants may access the web cast and the related presentationmaterials on the "News & Financials" section of www.dynegy.com.

About Dynegy Inc.

Dynegy Inc. provides electricity, natural gas and natural gasliquids to markets and customers throughout the United States. Throughits energy businesses, the company owns and operates a diverseportfolio of assets, including power plants totaling approximately13,000 megawatts of net generating capacity and gas processing plantsthat process approximately 1.6 billion cubic feet of natural gas perday.

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 agreed upon sale of ourMidstream business and its impact on our financial position andresults of operations, the possibility of strategic growthopportunities for our Power Generation business, the ongoing effectsof Dynegy's Customer Risk Management business, the ability toterminate or satisfy remaining power tolling agreements, and Dynegy'sestimated financial results for 2005. Historically, Dynegy'sperformance has deviated, in some cases materially, from its earningsand cash flow targets, and Dynegy cautions that actual future resultsmay vary materially from those expressed or implied in anyforward-looking statements. While Dynegy would expect to update thesetargets on a quarterly basis, it does not intend to update thesetargets during any quarter because definitive information regardingits quarterly financial results is not available until after the booksfor the quarter have been closed. Accordingly, Dynegy expects toprovide updates only after it has closed the books and reported theresults for a particular quarter, or otherwise as may be required byapplicable law.

Some of the key factors that could cause actual results to varymaterially from those targeted, expected or implied include: changesin commodity prices, particularly for power, natural gas and naturalgas liquids; the effects of competition and weather on the demand forDynegy's products and services; Dynegy's ability to successfullycomplete its exit from the Customer Risk Management business and fundthe costs associated with this exit; Dynegy's ability to achieve itsfinancial and operational goals associated with the Sithe Energiesacquisition; Dynegy's ability to close, and achieve tax and capitalstructure objectives associated with, the agreed upon sale of itsMidstream business; the availability, ability to consummate, andeffects of strategic growth opportunities for Dynegy's PowerGeneration business; Dynegy's ability to operate its businessesefficiently; Dynegy's ability to address its substantial leverage; thecondition of the capital markets generally and Dynegy's ability toaccess the capital markets as and when needed; Dynegy's liquidity andits effect on the ability to fund significant debt maturities and debtservice obligations; the impacts of hedging; operational factorsaffecting Dynegy's assets, including blackouts or other unscheduledoutages; Dynegy's ability to fund the environmental projects mandatedby the Baldwin consent decree; the financial impact of cash paymentsand stock issuances required by the shareholder class actionlitigation settlement agreement; and uncertainties regardingenvironmental regulations and litigation and other legal or regulatorydevelopments affecting Dynegy's businesses, including litigationrelating to the western power and natural gas markets and masternetting 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 March 31, 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. DYNF

DYNEGY INC.
REPORTED UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)

Three Months Ended Six Months Ended
June 30, June 30,
------------------- -------------------
2005 2004 2005 2004
--------- --------- --------- ---------

Revenues $459 $689 $921 $1,456
Cost of sales, exclusive of
depreciation and amortization
shown separately below (380) (423) (910) (989)
Depreciation and amortization
expense (54) (57) (109) (125)
Impairment and other charges (7) (59) (6) (75)
Loss on sale of assets, net - - - (15)
General and administrative
expenses (82) (94) (345) (156)
--------- --------- --------- ---------
Operating income (loss) (64) 56 (449) 96

Earnings from unconsolidated
investments 4 50 7 88
Interest expense (96) (141) (185) (271)
Other income and expense, net 6 (9) 9 6
--------- --------- --------- ---------
Loss from continuing
operations before income
taxes (150) (44) (618) (81)

Income tax benefit 41 29 215 82
--------- --------- --------- ---------
Income (loss) from
continuing operations (109) (15) (403) 1

Income from discontinued
operations, net of tax 147 23 179 77
--------- --------- --------- ---------
Net income (loss) $38 $8 $(224) $78
--------- --------- --------- ---------

Less: Preferred stock
dividends 6 6 11 11
--------- --------- --------- ---------
Net income (loss)
applicable to common
stockholders $32 $2 $(235) $67
========= ========= ========= =========

Earnings (loss) before
interest, taxes, and
depreciation and amortization
(EBITDA) (1) $65 $254 $(178) $521

Basic earnings (loss) per
share:
Loss from continuing
operations (2) $(0.30) $(0.06) $(1.09) $(0.03)
Income from discontinued
operations 0.38 0.07 0.47 0.20
--------- --------- --------- ---------
Basic earnings (loss) per
share $0.08 $0.01 $(0.62) $0.17
========= ========= ========= =========

Diluted earnings (loss) per
share:
Loss from continuing
operations (2) $(0.30) $(0.06) $(1.09) $(0.03)
Income from discontinued
operations 0.38 0.07 0.47 0.20
--------- --------- --------- ---------
Diluted earnings (loss) per
share $0.08 $0.01 $(0.62) $0.17
========= ========= ========= =========

Basic shares outstanding 380 378 379 377
Diluted shares outstanding 506 435 505 503

(1) EBITDA is a non-GAAP financial measure. EBITDA consists of
Operating income (loss) plus Depreciation and amortization
expense; Earnings from unconsolidated investments; Other income
and expense, net; and Income from discontinued operations
(before interest expense, depreciation and amortization expense
and income tax benefit (expense)). 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 Six Months Ended
June 30, June 30,
------------------- -------------------
2005 2004 2005 2004
--------- --------- --------- ---------

Operating income (loss) $(64) $56 $(449) $96

Add: Depreciation and
amortization expense, a
component of operating
income (loss) 54 57 109 125
Earnings from
unconsolidated
investments 4 50 7 88
Other income and expense,
net 6 (9) 9 6
EBITDA from discontinued
operations (3) 65 100 146 206
--------- --------- --------- ---------
Earnings (losses) before
interest, taxes, and
depreciation and amortization
(EBITDA) 65 254 (178) 521

Depreciation and
amortization expense, a
component of operating
income (loss) (54) (57) (109) (125)
Depreciation and
amortization expense from
discontinued operations (15) (25) (35) (45)
Interest expense from
continuing operations (96) (141) (185) (271)
Interest expense from
discontinued operations (14) (4) (25) (6)
Income tax benefit from
continuing operations 41 29 215 82
Income tax benefit
(expense) from
discontinued operations 111 (48) 93 (78)
--------- --------- --------- ---------
Net income (loss) $38 $8 $(224) $78
========= ========= ========= =========

(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 for the periods presented is
included below.

Three Months Ended Six Months Ended
June 30, June 30,
------------------- -------------------
2005 2004 2005 2004
--------- --------- --------- ---------

EBITDA from discontinued
operations $65 $100 $146 $206

Depreciation and
amortization expense from
discontinued operations (15) (25) (35) (45)
Interest expense from
discontinued operations (14) (4) (25) (6)
Income tax benefit
(expense) from
discontinued operations 111 (48) 93 (78)
--------- --------- --------- ---------
Income from discontinued
operations, net of tax $147 $23 $179 $77
========= ========= ========= =========


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

Three Months Ended Six Months Ended
June 30, June 30,
------------------- -------------------
2005 2004 2005 2004
--------- --------- --------- ---------

Income (loss) from continuing
operations $(109) $(15) $(403) $1
Less: convertible preferred
stock dividends 6 6 11 11
--------- --------- --------- ---------
Loss from continuing
operations for basic loss per
share (115) (21) (414) (10)
Effect of dilutive securities:
Interest on convertible
subordinated debentures 2 2 3 3
Dividends on Series C
convertible preferred
stock (1) 6 - 11 11
--------- --------- --------- ---------
Income (loss) from continuing
operations for diluted loss
per share $(107) $(19) $(400) $4
========= ========= ========= =========

Basic weighted-average shares 380 378 379 377

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 (1) 69 - 69 69
--------- --------- --------- ---------
Diluted weighted-average
shares 506 435 505 503
========= ========= ========= =========


Loss per share from continuing
operations:
Basic $(0.30) $(0.06) $(1.09) $(0.03)
========= ========= ========= =========

Diluted (2) $(0.30) $(0.06) $(1.09) $(0.03)
========= ========= ========= =========

(1) The diluted shares for the three months ended June 30, 2004 do not
include the effect of the preferential conversion to Class B
common stock of the Series C convertible preferred stock held by a
ChevronTexaco subsidiary, as such inclusion would be anti-
dilutive.

(2) 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 six months ended June 30, 2005 and 2004.


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

Three Months Ended June 30, 2005
-----------------------------------------
GEN NGL REG CRM OTHER Total
------ ------ ------ ------ ------ ------

Generation $19 $19
Natural Gas Liquids
Upstream $- -
Downstream - -
Regulated Energy Delivery $- -
Customer Risk Management $(15) (15)
Other $(68) (68)
------ ------ ------ ------ ------ ------
Operating income (loss) 19 - - (15) (68) $(64)
Earnings from
unconsolidated investments 4 - - - - 4
Other items, net 2 - - (1) 5 6
Add: Depreciation and
amortization expense, a
component of operating
income (loss) 50 - - - 4 54
------ ------ ------ ------ ------ ------
EBITDA from continuing
operations (1) 75 - - (16) (59) -
EBITDA from discontinued
operations, pre-tax (2) - 64 - 1 - 65
------ ------ ------ ------ ------ ------
EBITDA (1) $75 $64 $- $(15) $(59) $65
Depreciation and
amortization expense (69)
Interest expense (110)
------
Pre-tax loss (114)
Income tax benefit 152
------
Net income $38
======

Three Months Ended June 30, 2004
-----------------------------------------
GEN NGL REG CRM OTHER Total
------ ------ ------ ------ ------ ------

Generation $35 $35
Natural Gas Liquids
Upstream $- -
Downstream - -
Regulated Energy Delivery $22 22
Customer Risk Management $90 90
Other $(91) (91)
------ ------ ------ ------ ------ ------
Operating income (loss) 35 - 22 90 (91) $56
Earnings from
unconsolidated investments 50 - - - - 50
Other items, net - - - (1) (8) (9)
Add: Depreciation and
amortization expense, a
component of operating
income (loss) 47 - - - 10 57
------ ------ ------ ------ ------ ------
EBITDA from continuing
operations (1) 132 - 22 89 (89) 154
EBITDA from discontinued
operations, pre-tax (2) - 99 - 1 - 100
------ ------ ------ ------ ------ ------
EBITDA (1) $132 $99 $22 $90 $(89) $254
Depreciation and amortization
expense, a component of
operating income (loss) (82)
Interest expense (145)
------
Pre-tax income 27
Income tax expense (19)
------
Net income $8
======

(1) See Note (1) to "Reported Unaudited Condensed Consolidated
Statements of Operations." EBITDA is a non-GAAP financial measure.
EBITDA consists of Operating income (loss) plus Depreciation and
amortization expense; Earnings from unconsolidated investments;
Other income and expense, net; and Income from discontinued
operations (before interest expense, depreciation and amortization
expense and income tax benefit (expense)). 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)

Six Months Ended June 30, 2005
-----------------------------------------
GEN NGL REG CRM OTHER Total
------ ------ ------ ------ ------ ------

Generation $79 $79
Natural Gas Liquids
Upstream $- -
Downstream - -
Regulated Energy Delivery $- -
Customer Risk Management $(207) (207)
Other $(321) (321)
------ ------ ------ ------ ------ ------
Operating income (loss) 79 - - (207) (321) $(449)
Earnings from
unconsolidated investments 7 - - - - 7
Other items, net 2 - - - 7 9
Add: Depreciation and
amortization expense, a
component of operating
income (loss) 97 - - 1 11 109
------ ------ ------ ------ ------ ------
EBITDA from continuing
operations (1) 185 - - (206) (303) (324)
EBITDA from discontinued
operations, pre-tax (2) - 141 - 5 - 146
------ ------ ------ ------ ------ ------
EBITDA (1) $185 $141 $- $(201) $(303) $(178)
Depreciation and
amortization expense (144)
Interest expense (210)
------
Pre-tax loss (532)
Income tax benefit 308
------
Net loss $(224)
======

Six Months Ended June 30, 2004
-----------------------------------------
GEN NGL REG CRM OTHER Total
------ ------ ------ ------ ------ ------

Generation $88 $88
Natural Gas Liquids
Upstream $- -
Downstream - -
Regulated Energy Delivery $76 76
Customer Risk Management $77 77
Other $(145) (145)
------ ------ ------ ------ ------ ------
Operating income (loss) 88 - 76 77 (145) $96
Earnings (losses) from
unconsolidated investments 88 - - - - 88
Other items, net - - 1 2 3 6
Add: Depreciation and
amortization expense, a
component of operating
income (loss) 95 - 10 - 20 125
------ ------ ------ ------ ------ ------
EBITDA from continuing
operations (1) 271 - 87 79 (122) 315
EBITDA from discontinued
operations, pre-tax (2) - 185 - 18 3 206
------ ------ ------ ------ ------ ------
EBITDA (1) $271 $185 $87 $97 $(119) $521
Depreciation and
amortization expense, a
component of operating
income (loss) (170)
Interest expense (277)
------
Pre-tax income 74
Income tax benefit 4
------
Net income $78
======

(1) See Note (1) to "Reported Unaudited Condensed Consolidated
Statements of Operations." EBITDA is a non-GAAP financial measure.
EBITDA consists of Operating income (loss) plus Depreciation and
amortization expense; Earnings (losses) from unconsolidated
investments; Other income and expense, net; and Income (loss) from
discontinued operations (before interest expense, depreciation and
amortization expense and income tax benefit(expense)).
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 June 30, 2005
-----------------------------------------
GEN NGL REG CRM OTHER Total
------ ------ ------ ------ ------ ------

Legal and settlement
charges (1) $- $- $- $- $(31) $(31)
Independence toll
settlement adjustment (2) - - - 13 - 13
Discontinued operations (3) - 35 - 1 - 36
Taxes (4) - - - - 112 112
------ ------ ------ ------ ------ ------
Total $- $35 $- $14 $81 $130
====== ====== ====== ====== ====== ======

Three Months Ended June 30, 2004
-----------------------------------------
GEN NGL REG CRM Other Total
------ ------ ------ ------ ------ ------

Illinois Power asset
impairment (5) $- $- $(48) $- $- $(48)
Legal and settlement
charges (6) - - 1 - (42) (41)
Acceleration of financing
costs (7) - - - - (14) (14)
Taxes (8) - - - - (9) (9)
Gas transportation
contracts (9) - - - 88 - 88
Discontinued operation (10) - 70 - 1 - 71
------ ------ ------ ------ ------ ------
Total $- $70 $(47) $89 $(65) $47
====== ====== ====== ====== ====== ======

(1) We recognized a pre-tax loss of approximately $31 million ($20
million after-tax) 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.

(2) We recognized a pre-tax gain of approximately $13 million ($9
million after-tax) related to an adjustment to the Independence
toll settlement charge following our acquisition of ExRes SHC,
Inc., the parent company of Sithe Energies, Inc. and Sithe /
Independence Power Partners, L.P. This gain is included in Cost of
sales.

(3) We recognized a pre-tax gain of approximately $36 million ($147
million after-tax) related to discontinued operations. The gain
consists primarily of income associated with our NGL segment of
$35 million, which has been reclassified to discontinued
operations due to the anticipated sale of DMSLP.

(4) We recognized an income tax benefit of approximately $112 million
for the reversal of a deferred tax capital loss valuation
allowance primarily related to gains on the anticipated sale of
DMSLP. A benefit of $125 million is included in the $147 million
after-tax Income from discontinued operations, offset by a $13
million expense in Income tax benefit.

(5) We recognized a pre-tax loss of approximately $48 million ($30
million after-tax) related to an asset impairment recorded in
connection with the sale of Illinois Power. The loss is included
in Impairment and other charges.

(6) We recognized a pre-tax charge of approximately $41 million ($26
million after-tax) related to legal and settlement charges. This
loss is included in General and administrative expenses and
Impairment and other charges.

(7) 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 a $600 million term loan. This
charge is included in Interest expense.

(8) We recognized a net income tax expense of approximately $9 million
for charges resulting from the conclusion of prior year tax audits
offset by the reversal of a deferred tax capital loss valuation
allowance related to anticipated gains on asset sales. A charge of
$20 million is included in the $23 million after-tax Income from
discontinued operations, partially offset by a $11 million benefit
in Income tax benefit.

(9) 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.

(10) We recognized a pre-tax gain of approximately $71 million ($23
million after-tax) related to discontinued operations. The gain
consists primarily of income associated with our NGL segment of
$70 million, which has been reclassified to discontinued
operations due to the anticipated sale of DMSLP and a $1 million
pre-tax gain on our UK CRM business. Included in the $70 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.


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

Six Months Ended June 30, 2005
-----------------------------------------
GEN NGL REG CRM OTHER Total
------ ------ ------ ------ ------ ------

Legal and settlement
charges (1) $- $- $- $- $(253) $(253)
Independence toll
settlement charge (2) - - - (170) - (170)
Discontinued operations (3) - 81 - 5 - 86
Taxes (4) - - - - 125 125
------ ------ ------ ------ ------ ------
Total $- $81 $- $(165) $(128) $(212)
====== ====== ====== ====== ====== ======

Six Months Ended June 30, 2004
-----------------------------------------
GEN NGL REG CRM OTHER Total
------ ------ ------ ------ ------ ------

Illinois Power asset
impairment and loss on
sale (5) $- $- $(69) $- $- $(69)
Legal and settlement
charges (6) 2 - (1) - (57) (56)
Acceleration of financing
costs (7) - - - - (14) (14)
Gas transportation
contracts (8) - - - 88 - 88
Taxes (9) - - - - 30 30
Discontinued
operations (10) $- $134 $- $18 $3 $155
------ ------ ------ ------ ------ ------
Total $2 $134 $(70) $106 $(38) $134
====== ====== ====== ====== ====== ======

(1) We recognized a pre-tax loss of approximately $253 million ($176
million after-tax) 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.

(2) We recognized a pre-tax loss of approximately $170 million ($109
million after-tax) related to the Independence toll settlement
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.

(3) We recognized a pre-tax gain of approximately $86 million ($179
million after-tax) related to discontinued operations. The gain
consists primarily of income associated with our NGL segment of
$81 million, which has been reclassified to discontinued
operations due to the anticipated sale of DMSLP, and a $5 million
pre-tax gain on our UK CRM business.

(4) We recognized an income tax benefit of approximately $125 million
for the reversal of a deferred tax capital loss valuation
allowance primarily related to gains on the anticipated sale of
DMSLP. The benefit is included in the $179 million after-tax
Income from discontinued operations.

(5) We recognized a pre-tax loss of approximately $69 million ($43
million after-tax) related to expenses expected to be incurred in
connection with the sale of Illinois Power and impairment of
assets. The loss is included in Loss on sale of assets, net, and
Impairment and other charges.

(6) We recognized a pre-tax loss of approximately $56 million ($35
million after-tax) related to legal and settlement charges. The
loss is primarily included in General and administrative expenses
and Impairment and other charges.

(7) 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 a $600 million term loan. This
charge is included in Interest expense.

(8) 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.

(9) We recognized a net income tax benefit of approximately $30
million for the reversal of a deferred tax capital loss valuation
allowance related to anticipated gains on asset sales offset by
charges resulting from the conclusion of prior year tax audits. A
benefit of $50 million is included in Income tax benefit,
partially offset by a $20 million charge in the $77 million
after-tax Income from discontinued operations.

(10)We recognized a pre-tax gain of approximately $155 million ($77
million after-tax) related to discontinued operations. The gain
consists primarily of income associated with our NGL segment of
$134 million, which has been reclassified to discontinued
operations due to the anticipated sale of DMSLP, an $18 million
pre-tax gain on our UK CRM business and a $3 million pre-tax gain
associated with our global communications business. Included in
the $134 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 and 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.


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

Six Months Ended June 30, 2005
-----------------------------------------
GEN NGL REG CRM OTHER Total
------ ------ ------ ------ ------ ------

Cash Flow from Operations $194 $178 $- $41 $(422) $(9)

Capital Expenditures (65) (23) - - (5) (93)

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

Proceeds from Asset
Sales (1) - - (5) - - (5)
------ ------ ------ ------ ------ ------

Free Cash Flow (2) $9 $155 $(5) $41 $(427) $(227)
====== ====== ====== ====== ====== ======

Six Months Ended June 30, 2004
-----------------------------------------
GEN NGL REG CRM OTHER Total
------ ------ ------ ------ ------ ------

Cash Flow from Operations $200 $170 $181 $(182) $(308) $61

Capital Expenditures (58) (27) (61) - (5) (151)

Proceeds from Asset Sales 15 65 1 - - 81
------ ------ ------ ------ ------ ------

Free Cash Flow (2) $157 $208 $121 $(182) $(313) $(9)
====== ====== ====== ====== ====== ======

(1) During the first quarter 2005, we paid approximately $5 million to
Ameren related to the working capital adjustment for our sale of
Illinois Power.

(2) Free cash flow is a non-GAAP financial measure. Free cash flow
consists of cash flows from operations less capital expenditures
and business acquisition costs, net, adjusted for proceeds from
asset sales. 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 Six Months Ended
June 30, June 30,
------------------ ------------------
2005 2004 2005 2004
--------- -------- --------- --------
GEN
Million Megawatt Hours Generated
- Gross 8.6 9.0 17.5 19.6
Million Megawatt Hours Generated
- Net 8.3 8.6 16.7 18.7

Average Natural Gas Price - Henry
Hub ($/MMBtu) (1) $6.94 $6.09 $6.67 $5.86
Average On-Peak Market Power
Prices ($/MWh):
Cinergy $54 $45 $52 $43
Commonwealth Edison (NI Hub) $52 $44 $50 $42
Southern $57 $52 $53 $47
New York - Zone G $78 $63 $74 $63
New York - Zone A $62 $53 $60 $55
ERCOT $68 $54 $60 $49
SP-15 $55 $55 $55 $52


NGL
Field Plant Gross NGL Production
(MBbls/d) 58.0 56.1 56.7 57.0
Straddle Plant Gross NGL
Production (MBbls/d) 28.6 23.6 29.7 23.8
--------- -------- --------- --------
Total Gross NGL Production 86.6 79.7 86.4 80.8
========= ======== ========= ========

Natural Gas (Residue) Sales
(BBtu/d) 181.1 181.9 182.6 182.4

Natural Gas Field Plant Inlet
Volumes (MMCFD) 516.3 529.9 517.2 551.3
Natural Gas Straddle Plant Inlet
Volumes (MMCFD) 1,212.5 785.1 1,275.9 826.7
--------- -------- --------- --------
Total Natural Gas Inlet
Volumes 1,728.8 1,315.0 1,793.1 1,378.0
========= ======== ========= ========

Fractionation Volumes (MBbls/d) 176.6 213.1 168.6 199.0
Natural Gas Liquids Sold
(MBbls/d) 242.2 252.3 268.2 276.9

Average Commodity Prices:
Crude Oil - WTI ($/Bbl) $51.96 $38.51 $49.96 $36.64
Natural Gas - Henry Hub
($/MMBtu) (2) $6.74 $6.00 $6.51 $5.84
Natural Gas Liquids ($/Gal) $0.79 $0.64 $0.78 $0.63
Fractionation Spread ($/MMBtu)
- daily $1.97 $1.15 $2.15 $1.27


REG (3)
Electric Sales in KWH (Millions):
Residential - 1,135 - 2,590
Commercial - 1,118 - 2,172
Industrial - 1,371 - 2,691
Transportation of Customer-
Owned Electricity - 803 - 1,432
Other - 90 - 188
--------- -------- --------- --------
Total Electricity Delivered - 4,517 - 9,073
========= ======== ========= ========

Gas Sales in Therms (Millions):
Residential - 34 - 194
Commercial - 16 - 74
Industrial - 10 - 29
Transportation of Customer-
Owned Gas - 56 - 125
--------- -------- --------- --------
Total Gas Delivered - 116 - 422
========= ======== ========= ========

Cooling Degree Days - Actual - 373 - 373
Cooling Degree Days - 10 year
rolling average - 373 - 374
Heating Degree Days - Actual - 388 - 3,094
Heating Degree Days - 10 year
rolling average - 453 - 3,131

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

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

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


DYNEGY INC.
2005 EARNINGS GUIDANCE ESTIMATES (1)
(IN MILLIONS)

GEN CRM OTHER
----------- ----------- ------------

EBITDA (2) $425 - 435 $(70) $(100 - 95)

Depreciation and Amortization (210) - (15)

Interest Expense

Income Tax Benefit (Expense)

Preferred stock dividends

Net Income (Loss)

Total Core Non-Core
Business (3) Total
------------- ---------- ---------------

EBITDA (2) $255 - 270 $927 $1,182 - 1,197

Depreciation and Amortization (225) (35) (260)

Interest Expense (385) (50) (435)

Income Tax Benefit (Expense) 142 - 137 (207) (65 - 70)

Preferred stock dividends (22) - (22)
------------- ---------- ---------------

Net Income (Loss) $(235 - 225) $635 $400 - 410
============= ========== ===============


2005 CASH FLOW GUIDANCE ESTIMATES (1)
(IN MILLIONS)

GEN CRM OTHER
----------- ----------- ------------

Cash Flow from Operations $465 - 470 $(5) $(460 - 455)

Capital Expenditures and Business
Acquisitions (160) - (6)

Proceeds from Asset Sales - - -
----------- ----------- ------------
Free Cash Flow (4) $305 - 310 $(5) $(466 - 461)
=========== =========== ============

Total Core Non-Core
Business (5) Total
------------- ---------- ---------------

Cash Flow from Operations $0 - 10 $(43) $(43 - 33)

Capital Expenditures and
Business Acquisitions (166) (215) (381)

Proceeds from Asset Sales - 2,515 2,515
------------- ---------- ---------------
Free Cash Flow (4) $(166 - 156) $2,257 $2,091 - 2,101
============= ========== ===============

(1) Estimates are provided as a guide for forecasted 2005 consolidated
results on an as-reported GAAP basis. Forecasted segment results
are intended to reflect management's estimate of the breakdown of
its consolidated results and are subject to change. Estimates do
not incorporate assumptions for potential items such as legal
settlements, tolling settlements, capital-raising activities or
other restructuring events.

(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) The following summarizes the items included in Non-core business
in our earnings guidance estimate.


Depreciation Income Tax Net
and Interest Benefit Income
EBITDA Amortization Expense (Expense) (Loss)
-------- ------------- -------- ---------- -------
Independence toll
settlement charge
(CRM segment) $(170) $- $- $61 $(109)
Legal and settlement
charges (Other
segment) (253) - - 77 (176)
NGL operating
results (NGL
segment) 250 (35) (50) (60) 105
Gain on sale of NGL
(NGL segment) 1,100 - - (285) 815
-------- ------------- -------- ---------- -------
Total $927 $(35) $(50) $(207) $635
======== ============= ======== ========== =======

(4) Free cash flow is a non-GAAP financial measure. Free cash flow
consists of cash flows from operations less capital expenditures
and business acquisition costs, adjusted for proceeds from asset
sales. 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.

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

Capital Proceeds
Cash Flow Exp. and from Free
from Business Asset Cash
Operations Acq. Sales Flows
----------- --------- -------- -------
ANR/Middleton Gas Payment (CRM
segment) $(26) $- $- $(26)
Sithe Energies Acquisition (GEN
segment) - (120) - (120)
Baldwin Escrow Release (Other
segment) - - 100 100
Legal and settlement charges
(Other segment) (268) - - (268)
Illinois Power Working Capital/
Other (Other segment) (9) - (5) (14)
NGL operating cash flow (NGL
segment) 260 - - 260
NGL capital expenditures (NGL
segment) - (60) - (60)
Net proceeds from sale of NGL
(NGL segment) - - 2,420 2,420
Development Capital Expenditures
(All segments) - (35) - (35)
----------- --------- -------- -------
Total $(43) $(215) $2,515 $2,257
=========== ========= ======== =======