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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended March 31, 2003
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number: 1-15659
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DYNEGY INC.
(Exact name of registrant as specified in its charter)
Illinois 74-2928353
(State or other (I.R.S. Employer
jurisdiction Identification No.)
of incorporation or
organization)
1000 Louisiana, Suite 5800
Houston, Texas 77002
(Address of principal executive offices)
(Zip Code)
(713) 507-6400
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [_]
Number of shares outstanding of each of the issuer's classes of common
stock, as of the latest practicable date: Class A common stock, no par value
per share, 275,763,865 shares outstanding as of May 2, 2003; Class B common
stock, no par value per share, 96,891,014 shares outstanding as of May 2, 2003.
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DYNEGY INC.
TABLE OF CONTENTS
Page
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PART I. FINANCIAL INFORMATION
Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets:
March 31, 2003 and December 31, 2002............................ 3
Condensed Consolidated Statements of Operations:
For the three months ended March 31, 2003 and 2002.............. 4
Condensed Consolidated Statements of Cash Flows:
For the three months ended March 31, 2003 and 2002.............. 5
Condensed Consolidated Statements of Comprehensive Income (Loss):
For the three months ended March 31, 2003 and 2002.............. 6
Notes to Condensed Consolidated Financial Statements................ 7
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS......................................... 23
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. 42
Item 4. CONTROLS AND PROCEDURES.................................... 44
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS.......................................... 45
Item 6. EXHIBITS AND REPORTS ON FORM 8-K........................... 45
Glossary of Key Terms
ARO Asset retirement obligation.
Bcf/d Billion cubic feet per day.
CDWR California Department of Water Resources.
CRM Our customer risk management business segment.
DGC Dynegy Global Communications.
DGC-Asia Dynegy Global Communications-Asia, our former Asian communications business.
DHI Dynegy Holdings Inc., our primary financing subsidiary.
EBIT A non-GAAP measure of Earnings Before Interest and Taxes. As an indicator of our segment
operating performance, EBIT should not be considered an alternative to, or more meaningful
EITF than, net income or cash flows from operations as determined in accordance with GAAP.
FASB Emerging Issues Task Force.
FIN Financial Accounting Standards Board.
GAAP FASB Interpretation.
GEN Generally Accepted Accounting Principles.
Illinova Our power generation business segment.
Illinova Corporation, a wholly owned subsidiary of Dynegy and the direct parent company of
MW Illinois Power Company.
NGL Megawatts.
REG Our natural gas liquids business segment.
SEC Our regulated energy delivery business segment.
SFAS U.S. Securities and Exchange Commission.
WEN Statement of Financial Accounting Standards.
Our former wholesale energy network business segment.
2
DYNEGY INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited) (in millions, except share data)
March 31, December 31,
2003 2002
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ASSETS
Current Assets
Cash and cash equivalents................................................................................. $ 1,775 $ 757
Restricted cash........................................................................................... 19 17
Accounts receivable, net of allowance for doubtful accounts of $162 million and $151 million, respectively 1,629 2,791
Accounts receivable, affiliates........................................................................... 69 31
Inventory................................................................................................. 191 236
Assets from risk-management activities.................................................................... 1,623 2,618
Prepayments and other assets.............................................................................. 899 1,136
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Total Current Assets................................................................................ 6,205 7,586
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Property, Plant and Equipment............................................................................. 9,626 9,659
Accumulated depreciation.................................................................................. (1,233) (1,270)
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Property, Plant and Equipment, Net.................................................................. 8,393 8,389
Other Assets
Unconsolidated investments................................................................................ 710 668
Assets from risk-management activities.................................................................... 1,189 2,529
Goodwill.................................................................................................. 396 396
Other assets.............................................................................................. 473 462
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Total Assets........................................................................................ $17,366 $20,030
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LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable.......................................................................................... $ 755 $ 1,586
Accounts payable, affiliates.............................................................................. 101 65
Accrued liabilities and other............................................................................. 1,317 1,818
Liabilities from risk-management activities............................................................... 1,583 2,418
Notes payable and current portion of long-term debt....................................................... 737 861
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Total Current Liabilities........................................................................... 4,493 6,748
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Long-Term Debt............................................................................................ 6,268 5,454
Other Liabilities
Liabilities from risk-management activities............................................................... 1,071 2,366
Deferred income taxes..................................................................................... 910 951
Other long-term liabilities............................................................................... 815 855
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Total Liabilities................................................................................... 13,557 16,374
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Minority Interest......................................................................................... 129 146
Commitments and Contingencies (Note 9)
Serial Preferred Securities of a Subsidiary............................................................... 11 11
Company Obligated Preferred Securities of a Subsidiary Trust.............................................. 200 200
Series B Mandatorily Convertible Redeemable Preferred Securities.......................................... 1,295 1,212
Stockholders' Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at March 31, 2003 and December 31,
2002, 276,719,606 and 274,850,589 shares issued and outstanding at March 31, 2003 and December 31,
2002, respectively....................................................................................... 2,828 2,825
Class B Common Stock, no par value, 360,000,000 shares authorized at March 31, 2003 and December 31,
2002, 96,891,014 shares issued and outstanding at March 31, 2003 and December 31, 2002................... 1,006 1,006
Additional paid-in capital................................................................................ 707 705
Subscriptions receivable.................................................................................. (11) (12)
Accumulated other comprehensive loss, net of tax.......................................................... (38) (55)
Accumulated deficit....................................................................................... (2,250) (2,314)
Treasury stock, at cost, 1,679,183 shares at March 31, 2003 and December 31, 2002......................... (68) (68)
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Total Stockholders' Equity.......................................................................... 2,174 2,087
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Total Liabilities and Stockholders' Equity....................................................... $17,366 $20,030
======= =======
See the notes to condensed consolidated financial statements.
3
DYNEGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited) (in millions, except per share data)
Three Months Ended
March 31,
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2003 2002
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Revenues (Note 1)......................................................... $ 1,745 $ 1,439
Cost of sales, exclusive of depreciation shown separately below (Note 1).. (1,374) (1,170)
Depreciation and amortization............................................. (115) (93)
Gain on sale of assets.................................................... 1 --
Impairment and other charges.............................................. 7 --
General and administrative expenses....................................... (77) (91)
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Operating income................................................... 187 85
Earnings from unconsolidated investments.................................. 53 35
Interest expense.......................................................... (110) (66)
Other income and expense, net............................................. 8 20
Minority interest income (expense)........................................ 17 (30)
Accumulated distributions associated with trust preferred securities...... (4) (4)
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Income from continuing operations before income taxes..................... 151 40
Income tax provision (benefit)............................................ 56 (7)
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Income from continuing operations......................................... 95 47
Loss on discontinued operations, net of taxes (Note 2).................... (3) (60)
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Income (loss) before cumulative effect of change in accounting principle.. 92 (13)
Cumulative effect of change in accounting principle, net of taxes (Note 1) 55 (234)
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Net income (loss)......................................................... 147 (247)
Less: preferred stock dividends........................................... 83 83
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Net income (loss) applicable to common stockholders....................... $ 64 $ (330)
======= =======
Basic earnings (loss) per share:
Income (loss) from continuing operations............................... $ 0.03 $ (0.10)
Loss from discontinued operations...................................... (0.01) (0.17)
Cumulative effect of change in accounting principle.................... 0.15 (0.64)
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Basic earnings (loss) per share........................................... $ 0.17 $ (0.91)
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Diluted earnings (loss) per share (Note 8):
Income (loss) from continuing operations............................... $ 0.03 $ (0.10)
Loss from discontinued operations...................................... (0.01) (0.17)
Cumulative effect of change in accounting principle.................... 0.15 (0.64)
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Diluted earnings (loss) per share (Note 8)................................ $ 0.17 $ (0.91)
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Basic shares outstanding.................................................. 371 364
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Diluted shares outstanding................................................ 372 371
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See the notes to condensed consolidated financial statements.
4
DYNEGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited) (in millions)
Three Months Ended
March 31,
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2003 2002
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)............................................................... $ 147 $(247)
Items not affecting cash flows from operating activities:
Depreciation and amortization................................................ 125 127
(Earnings) losses from unconsolidated investments, net of cash distributions. (42) 43
Risk-management activities................................................... 71 212
Gain on sale of assets....................................................... (22) --
Deferred income taxes........................................................ 45 (24)
Cumulative effect of change in accounting principle (Note 1)................. (55) 234
Other........................................................................ (4) 66
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Operating cash flows before changes in working capital.......................... 265 411
Changes in working capital:
Accounts receivable.......................................................... 1,061 192
Inventory.................................................................... 167 31
Prepayments and other assets................................................. 215 30
Accounts payable and accrued liabilities..................................... (1,273) (397)
Other, net................................................................... (28) (14)
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Net cash provided by operating activities....................................... 407 253
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CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................................ (84) (395)
Unconsolidated investments...................................................... -- (3)
Business acquisitions, net of cash acquired..................................... -- (20)
Proceeds from asset sales, net.................................................. 7 6
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Net cash used in investing activities........................................... (77) (412)
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CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings.......................................... 142 566
Repayments of long-term borrowings.............................................. (158) (33)
Net cash flow from commercial paper and revolving lines of credit............... 712 (293)
Proceeds from issuance of capital stock......................................... -- 229
Purchase of serial preferred securities of a subsidiary......................... -- (28)
Purchase of treasury stock...................................................... -- (1)
Dividends and other distributions, net.......................................... -- (28)
(Increase) decrease in restricted cash.......................................... (2) 6
Other financing, net............................................................ -- (9)
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Net cash provided by financing activities....................................... 694 409
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Effect of exchange rate changes on cash......................................... (6) (15)
Net increase in cash and cash equivalents....................................... 1,018 235
Cash and cash equivalents, beginning of period.................................. 757 208
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Cash and cash equivalents, end of period........................................ $ 1,775 $ 443
======= =====
See the notes to condensed consolidated financial statements.
5
DYNEGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(unaudited) (in millions)
Three Months Ended
March 31,
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2003 2002
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Net income (loss)................................................... $147 $(247)
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Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net 12 (1)
Reclassification of mark-to-market (gains) losses to earnings, net. (19) (9)
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Unrealized net (gains) losses...................................... (7) (10)
Foreign currency translation adjustments............................ 24 3
Unrealized holding gains on securities arising during period........ -- 6
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Other comprehensive income (loss), net of tax.................... 17 (1)
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Comprehensive income (loss)......................................... $164 $(248)
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See the notes to condensed consolidated financial statements.
6
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
For the Interim Periods Ended March 31, 2003 and 2002
Note 1--Accounting Policies
The accompanying unaudited condensed consolidated financial statements have
been prepared in accordance with the instructions to interim financial
reporting as prescribed by the SEC. These interim financial statements should
be read together with the consolidated financial statements and notes thereto
included in our Annual Report on Form 10-K for the year ended December 31,
2002, which we refer to in this report as the Form 10-K. Our periodic SEC
reports, including this report, remain subject to an ongoing review by the SEC
Division of Corporation Finance.
The unaudited condensed consolidated financial statements contained in this
report include all material adjustments that, in the opinion of management, are
necessary for a fair presentation of the results for the interim periods.
Interim period results are not necessarily indicative of the results for the
full year. The preparation of the condensed consolidated financial statements
in conformity with accounting principles generally accepted in the United
States of America requires management to develop estimates and make assumptions
that affect reported financial position and results of operations and that
impact the nature and extent of disclosure, if any, of contingent assets and
liabilities. We review significant estimates affecting our consolidated
financial statements on a recurring basis and record the effect of any
necessary adjustments prior to their publication. Judgments and estimates are
based on our beliefs and assumptions derived from information available at the
time such judgments and estimates are made. Adjustments made with respect to
the use of these estimates often relate to information not previously
available. Uncertainties with respect to such estimates and assumptions are
inherent in the preparation of financial statements. Estimates are primarily
used in (1) developing fair value assumptions, including estimates of future
cash flows and discount rates, (2) analyzing tangible and intangible assets for
impairment, (3) estimating the useful lives of our assets, (4) assessing future
tax exposure and the realization of tax assets, (5) determining the amounts to
accrue related to contingencies and (6) the estimate of various factors
impacting the valuation of our pension assets. Actual results could differ
materially from any such estimates. Certain reclassifications have been made to
prior period amounts in order to conform to current year presentation.
Accounting Principles Adopted
EITF Issue 02-03. In 2002, the EITF reached consensus on two issues
presented in EITF Issue 02-03, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities." First, the EITF concluded that all
mark-to-market gains and losses on energy trading contracts (whether realized
or unrealized) should be shown net in the income statement, irrespective of
whether the contract is physically or financially settled. In the third quarter
2002, we began presenting all mark-to-market gains and losses on a net basis to
reflect this change in accounting principle. In accordance with the transition
provisions in the consensus, comparative period financial statements have been
conformed to reflect this change in accounting principle. Prior to the change
in accounting principle, we classified net unrealized gains and losses from
energy trading contracts as revenue in our unaudited condensed consolidated
statements of operations. Physical transactions that were realized and settled
were previously reflected gross in revenues and cost of sales. This change in
accounting classification has no impact on our operating income, net income
(loss), earnings (loss) per share or cash flow from operations.
7
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
The following table reconciles the revenues and costs of sales reported
under prior accounting guidance to the amounts reported herein in connection
with the change in accounting principle (in millions):
Three Months Ended
March 31, 2002
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Revenues as previously reported....... $ 8,426
Adjustment for discontinued operations (340)
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Adjusted revenues..................... 8,086
Change in accounting principle........ (6,647)
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Revenues as reported herein........... $ 1,439
=======
Cost of sales as previously reported.. $ 8,075
Adjustment for discontinued operations (258)
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Adjusted cost of sales................ 7,817
Change in accounting principle........ (6,647)
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Cost of sales as reported herein...... $ 1,170
=======
Second, in October 2002, the EITF reached a consensus to rescind EITF Issue
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," which previously required us to use mark-to-market accounting for
our energy trading contracts. While the rescission of EITF Issue 98-10 will
reduce the number of contracts accounted for on a mark-to-market basis, it does
not eliminate mark-to-market accounting. All derivative contracts that either
do not qualify, or are not designated, as hedges will continue to be
marked-to-market in accordance with SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." Any earnings/losses previously recognized
under EITF Issue 98-10 that would not have been recognized under SFAS No. 133
have been reversed in the first quarter 2003. The cumulative effect of this
change in accounting principle resulted in after-tax earnings of $21 million
and is comprised of the following items, which are no longer required to be
recorded using mark-to-market accounting (in millions):
Removal of net risk-management assets representing the value of natural gas storage
contracts........................................................................ $(176)
Removal of other net risk-management assets........................................ (24)
Removal of net risk-management liabilities representing the value of power tolling
arrangements..................................................................... 103
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Net change in risk-management assets and liabilities............................... (97)
Addition of natural gas and coal inventory previously included in risk-management
assets (1)....................................................................... 130
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Pre-tax gain recorded from change in accounting principle.......................... 33
Income tax provision............................................................... (12)
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After-tax gain recorded in the unaudited condensed consolidated statements
of operations.................................................................... $ 21
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(1) A substantial portion of this natural gas inventory was sold during the
three months ended March 31, 2003.
8
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
SFAS No. 143. In June 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations." We adopted SFAS No. 143 effective January 1,
2003. SFAS No. 143 provides accounting requirements for costs associated with
legal obligations to retire tangible, long-lived assets. Under SFAS No. 143,
the ARO is recorded at fair value in the period in which it is incurred by
increasing the carrying amount of the related long-lived asset. In each
subsequent period, the liability is accreted to its fair value and the
capitalized costs are depreciated over the useful life of the related asset.
The cumulative effect of applying SFAS No. 143 has been recognized as a change
in accounting principle in the unaudited condensed consolidated statements of
operations.
As part of the transition adjustment, some existing environmental
liabilities are required to be reversed upon adoption of SFAS No. 143. As we
had previously accrued environmental liabilities for which remediation can be
delayed until asset retirement, such liabilities have been reversed as a
component of the cumulative effect adjustment in adopting SFAS No. 143. As the
previously accrued liabilities exceeded the fair value of the future retirement
obligations, the impact of adopting SFAS No. 143 was an increase in earnings,
net of tax, of approximately $34 million, which is reflected as a cumulative
effect of a change in accounting principle in the unaudited condensed
consolidated financial statements. The annual amortization of the asset created
under this standard and the accretion of the liability to its fair value is
estimated to be approximately $6 million in 2003. We also have AROs that are
not quantifiable given our inability to estimate in a reasonable manner the
time of settlement. When we are able to estimate the timing of the ARO, a
liability will be established.
At January 1, 2003, our ARO liabilities were $26 million for our GEN
segment, $9 million for our NGL segment and $6 million for our REG segment.
These retirement obligations related to activities such as ash pond and
landfill capping, closure and post-closure costs, environmental testing,
remediation monitoring and land and equipment lease obligations. During the
quarter ended March 31, 2003, our accretion expense recognized for the fair
value for all of our ARO liabilities totaled approximately $1 million. At March
31, 2003, our ARO liability totaled $42 million.
Had SFAS No. 143 been applied retroactively in the three months ended March
31, 2002, our net loss applicable to common stockholders would have been $331
million and basic and diluted loss per share would be unchanged.
SFAS No. 146. In July 2002, the FASB issued SFAS No. 146, "Accounting for
Exit or Disposal Activities." SFAS No. 146 addresses issues regarding the
recognition, measurement and reporting of costs that are associated with exit
and disposal activities, including restructuring activities that were
previously accounted for pursuant to the guidance in EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other
Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." SFAS No. 146 is effective for exit or disposal activities that
are initiated after December 31, 2002. We have not initiated any such
activities since December 31, 2002 but intend to apply provisions of SFAS No.
146 for any exit or disposal activities initiated in the future.
SFAS No. 148. In December 2002, the FASB issued SFAS No. 148, "Accounting
for Stock-Based Compensation--Transition and Disclosure." SFAS No. 148 amends
SFAS No. 123 and provides alternative methods of transition (prospective,
modified prospective or retroactive) for entities that voluntarily change to
the fair value-based method of accounting for stock-based employee compensation
in a fiscal year beginning before December 16, 2003. SFAS No. 148 requires
prominent disclosure about the effects on reported net income of an entity's
accounting policy decisions with respect to stock-based employee compensation.
We transitioned to a fair value-based method of accounting for stock-based
compensation in the first quarter 2003 and are using the
9
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
prospective method of transition as described under SFAS No. 148. As a result,
an annual charge of approximately $1 million will be reflected in general and
administrative expenses in the unaudited condensed consolidated statements of
operations.
Under the prospective method of transition, all stock options granted since
January 1, 2003 will be accounted for on a fair value basis. Options granted
prior to January 1, 2003 continue to be accounted for using the intrinsic value
method. Had compensation cost for stock options issued prior to 2003 been
determined on a fair value basis consistent with SFAS No. 123, our net income
(loss) and basic and diluted earnings (loss) per share amounts would have
approximated the following pro forma amounts for the three months ended March
31, 2003 and 2002, respectively.
Three Months Ended
March 31,
-------------------------------
2003 2002
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(in millions, except per share data)
Net Income (loss) as reported............................. $ 147 $ (247)
Add: Stock-based employee compensation expense included
in reported net income, net of related tax effects...... 1 1
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects.............................. (17) (20)
----- ------
Pro forma net income (loss)............................... $ 131 $ (266)
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Earnings per share:
Basic--as reported..................................... $0.17 $(0.91)
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Basic--pro forma....................................... $0.13 $(0.96)
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Diluted--as reported................................... $0.17 $(0.91)
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Diluted--pro forma..................................... $0.13 $(0.96)
===== ======
FIN 45. In November 2002, the FASB issued FIN No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others". As required by FIN 45, we adopted the
disclosure requirements on December 31, 2002. On January 1, 2003, we adopted
the initial recognition and measurement provisions for guarantees issued or
modified after December 31, 2002. The adoption of the recognition/measurement
provisions did not have any impact on our financial statements.
Accounting Principles Not Yet Adopted
FIN 46. In January 2003, the FASB issued FIN No. 46, "Consolidation of
Variable Interest Entities--an Interpretation of ARB No. 51." In summary, this
interpretation increases the level of risk that must be assumed by equity
investors in special purpose entities. FIN 46 requires that the equity investor
have significant equity at risk (a minimum of 10 percent with few exceptions,
which is an increase from the 3 percent allowed under previous guidance) and
hold a controlling interest, evidenced by voting rights, risk of loss and the
benefit of residual returns. If the equity investor is unable to evidence these
characteristics, the entity that retains these ownership characteristics will
be required to consolidate the variable interest entity. We are in the process
of evaluating the impact of FIN 46. While we have not entered into any
arrangements in 2003 that would be subject to FIN 46, we are analyzing the
structures of entities previously formed to determine whether we have any
arrangements that are impacted. FIN 46 is applicable immediately to variable
interest entities created or obtained after January 31, 2003. For variable
interest entities created or obtained before February 1, 2003, FIN 46 is
applicable as of July 1, 2003.
10
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
SFAS No. 149. In April 2003, the FASB issued SFAS No. 149, "Amendment of
SFAS No. 133 on Derivative Instruments and Hedging Activities." SFAS No. 149
clarifies and amends various issues related to derivatives and financial
instruments addressed in SFAS No. 133 and interpretations issued by the
Derivatives Implementation Group. In particular, SFAS No. 149 clarifies (1)
under what circumstances a contract with an initial net investment meets the
characteristics of a derivative, (2) when a derivative contains a financing
component that should be reflected as a financing on the balance sheet and the
statement of cash flows, (3) the definition of an "underlying" in SFAS No. 133
to conform to the language used in FIN 45 and (4) other derivative concepts.
SFAS No. 149 is applicable to all contracts entered into or modified after June
30, 2003 and to all hedging relationships designated after June 30, 2003. We
are currently reviewing what impact, if any, SFAS No. 149 will have on the
accounting treatment of our price risk-management and other derivative
contracts.
Note 2--Dispositions and Discontinued Operations
Dispositions
SouthStar Energy Services. During the first quarter 2003, we completed the
sale of our 20 percent equity investment in SouthStar Energy Services LLC. We
received cash proceeds of approximately $20 million and recognized an after-tax
gain on the sale of approximately $0.8 million. The gain is included in gain on
sale of assets in the unaudited condensed consolidated statements of operations.
Hackberry LNG Project. During the first quarter 2003, we entered into an
agreement to sell our interest in Hackberry LNG Terminal LLC, the entity we
formed in connection with our proposed LNG terminal/gasification project in
Hackberry, Louisiana, to Sempra LNG Corp., a subsidiary of San Diego-based
Sempra Energy. The transaction closed on April 23, 2003. At closing, we
received an initial payment of $20 million and have the right to receive
additional contingent payments based upon project development milestones. We
expect to recognize an after-tax gain of approximately $8 million in the second
quarter 2003 in relation to this sale. Additionally, we are entitled to a
portion of the return on the project if specified performance targets are
achieved in the future.
Discontinued Operations
During 2002, we sold our ownership interests in each of Northern Natural Gas
Company, our United Kingdom natural gas storage business, our global liquids
business and DGC-Asia. The historical results from these operations are
included in discontinued operations for the first quarter 2002. In addition, as
part of our restructuring plan, we sold (or agreed to sell) or liquidated
portions of our operations during the first quarter 2003, some of which have
been accounted for as discontinued operations under SFAS No. 144, as further
discussed below.
Global Communications. During January 2003, we disposed of Dynegy Europe
Communications to an affiliate of Klesch & Company, a London-based private
equity firm. We recognized an after-tax gain on the sale of approximately $19
million in the first quarter 2003. During May 2003, we disposed of our U.S.
communications network to an affiliate of 360networks Corporation. We do not
expect any gain or loss associated with this sale, the closing of which
completes our exit from the communications business, to be significant.
Approximately $17 million of undiscounted obligations with respect to this
business remain following these sales.
As previously described in the Form 10-K, Level 3 Communications, LLC sent a
letter in April 2003 purporting to terminate an indefeasible right of use
agreement between one of our subsidiaries and Level 3 for breach of contract.
Prior to the closing of our disposition of our U.S. communications business in
May 2003, Level 3 retracted its termination notice and reaffirmed the subject
agreement.
11
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
U.K. CRM. During the first quarter 2003, the wind-down efforts of the U.K.
CRM business were substantially completed. We recognized an after-tax loss of
$10 million resulting primarily from selling and terminating all gas and power
positions, offset by administrative expenses, depreciation and amortization,
shut-down costs and currency translation losses. During the quarter, collateral
postings totaling $93 million were eliminated. We do not expect any material
losses from the U.K. CRM operations in the future.
The following table summarizes information related to our discontinued
operations (in millions):
Northern UK UK Global
Natural Storage CRM Liquids DGC Total
-------- ------- ---- ------- ----- -----
Quarter ended March 31, 2003
Revenue................................... $-- $-- $ 21 $-- $ 4 $ 25
Loss from operations before taxes......... -- -- (15) -- (19) (34)
Gain on sale before taxes................. -- -- -- -- 21 21
Gain on sale after taxes.................. -- -- -- -- 19 19
Quarter ended March 31, 2002
Revenue................................... $98 $40 $ 20 $196 $ 4 $358
Income (loss) from operations before taxes 45 7 (14) (1) (109) (72)
Note 3--Restructuring and Other Charges
Restructuring Charges. In October 2002, we announced a restructuring plan
designed to improve operational efficiencies and performance across our lines
of business, including the adoption of a decentralized business structure
consisting of a streamlined corporate center and operating units in power
generation, natural gas liquids and regulated energy delivery. Previously,
during the second quarter 2002, we recognized a charge for severance benefits
in connection with a reduction in force affecting approximately 325 employees.
As part of our restructuring, we recognized an aggregate pre-tax charge of $219
million during 2002.
The following is a schedule of 2003 activity for the liabilities recorded in
connection with these charges (in millions):
Cancellation
Fees and
Operating
Severance Leases Total
--------- ------------ -----
Balance at December 31, 2002..... $ 71 $61 $132
2003 adjustments to liability. (6) -- (6)
Cash payments................. (22) (7) (29)
---- --- ----
Balance at March 31, 2003........ $ 43 $54 $ 97
==== === ====
The adjustment to the accrued liability in the first quarter 2003 reflects
reductions in the severance accrual provided for employees that will now be
retained, as well as for individuals in our foreign operations.
Cumulative Effect of Change in Accounting Principles
We adopted SFAS No. 142, "Goodwill and Other Intangible Assets," effective
January 1, 2002, and, accordingly, tested for impairment all amounts recorded
as goodwill. We determined that goodwill associated with our communications
business was impaired and we therefore recognized a charge of $234 million for
this impairment in the first quarter 2002. The fair value of this reporting
segment was estimated using expected
12
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
discounted future cash flows. The value was negatively impacted by continued
weakness in the communications and broadband markets. The first quarter 2002
impairment charge is reflected in the unaudited condensed consolidated
statements of operations as a cumulative effect of change in accounting
principle. There were no changes in the carrying amount of goodwill for any of
our reporting units for the three-month period ended March 31, 2003.
We adopted SFAS No. 143 and provisions of EITF Issue 02-03 in the first
quarter 2003. Please see Note 1 for a discussion of the impact of adopting
these standards.
Note 4--Commercial Operations, Risk Management Activities and Financial
Instruments
The nature of our business necessarily involves market and financial risks.
We routinely enter into financial instrument contracts in an attempt to
mitigate or eliminate these various risks. These risks and our strategy for
mitigating these risks are more fully described in Note 5 to our Form 10-K
beginning on page F-25.
From time to time, we enter into various financial derivative instruments
that qualify as cash flow hedges. Instruments related to our power generation
and natural gas liquids businesses are entered into for purposes of hedging
future fuel requirements and power sales commitments for power generation and
fractionation facilities and locking in future margin in the domestic natural
gas liquids and power generation businesses. In addition, prior to exiting the
global liquids business, we utilized these instruments to hedge price risks
associated with that business. Interest rate swaps are also used to convert the
floating interest-rate component of some obligations to fixed rates.
During the three-month periods ended March 31, 2003 and 2002, there was no
material ineffectiveness from changes in fair value of hedge positions and no
amounts were excluded from the assessment of hedge effectiveness related to the
hedge of future cash flows. Additionally, no amounts were reclassified to
earnings in connection with forecasted transactions that were no longer
considered probable of occurring.
The balance in cash flow hedging activities, net at March 31, 2003 is
expected to be reclassified to future earnings, contemporaneously with the
related purchases of fuel, sales of electricity or natural gas liquids and
payments of interest, as applicable to each type of hedge. Of this amount,
approximately $21 million of after-tax losses is estimated to be reclassified
into earnings over the twelve-month period ending March 31, 2004. The actual
amounts that will be reclassified to earnings over the next year and beyond
could vary materially from this estimated amount as a result of changes in
market conditions.
From time to time, we also enter into derivative instruments that qualify as
fair-value hedges. We use interest rate swaps to convert a portion of our
nonprepayable fixed-rate debt into variable-rate debt. During the three-month
periods ended March 31, 2003 and 2002, there was no ineffectiveness from
changes in the fair value of hedge positions and no amounts were excluded from
the assessment of hedge effectiveness. Additionally, no amounts were recognized
in relation to firm commitments that no longer qualified as fair-value hedge
items.
We have investments in foreign subsidiaries, the net assets of which are
exposed to currency exchange-rate volatility. We have used derivative financial
instruments, including foreign exchange forward contracts and cross-currency
interest rate swaps, to hedge this exposure. As of March 31, 2003, we had no
net investment hedges in place. For the three months ended March 31, 2002,
approximately $15 million of after-tax net gains related to these contracts
were included in the foreign currency translation adjustment. This amount
offsets the cumulative translation gains of the underlying net investments in
foreign subsidiaries for the period the derivative financial instruments were
outstanding.
13
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
During the three months ended March 31, 2003, our efforts to exit the U.K.
CRM business and the European communications business were substantially
completed. As required by SFAS No. 52, "Foreign Currency Translation,"
unrealized gains and losses resulting from translation and financial
instruments utilized to hedge currency exposures previously recorded in
stockholders' equity were recognized in income, resulting in an after-tax loss
of $10 million.
Accumulated other comprehensive loss, net of tax, is included in
stockholders' equity on the unaudited condensed consolidated balance sheets as
follows (in millions):
March 31, December 31,
2003 2002
--------- ------------
Cash Flow Hedging Activities, Net................... $ 1 $ 8
Foreign Currency Translation Adjustment............. 27 3
Minimum Pension Liability........................... (66) (66)
---- ----
Accumulated Other Comprehensive Loss, Net of Tax. $(38) $(55)
==== ====
Note 5--Unconsolidated Investments
A summary of our unconsolidated investments is as follows (in millions):
March 31, December 31,
2003 2002
--------- ------------
Equity Affiliates:
GEN investments.............. $566 $542
CRM investments.............. 14 4
NGL investments.............. 98 102
---- ----
Total equity affiliates......... 678 648
Other affiliates, at cost....... 32 20
---- ----
Total Unconsolidated Investments $710 $668
==== ====
Summarized aggregate financial information for unconsolidated investments
and our equity share thereof was (in millions):
Three Months Ended March 31,
-------------------------------------
2003 2002
------------------ ------------------
Total Equity Share Total Equity Share
----- ------------ ----- ------------
Revenues........ $998 $390 $826 $289
Operating income 143 61 130 44
Net income...... 120 53 114 35
As previously described in the Form 10-K, a petition was filed in the United
States Bankruptcy Court for the District of Minnesota by several former
officers of NRG Energy, Inc., the parent company of the partner in two of our
joint ventures (including West Coast Power), to put NRG Energy into bankruptcy.
This proceeding was settled and the involuntary bankruptcy was dismissed in
early May 2003. NRG Energy and certain of its affiliates subsequently made
voluntary Chapter 11 bankruptcy filings in the United States Bankruptcy Court
for the Southern District of New York, together with a filing of a plan of
reorganization. We are analyzing these filings, which have only recently been
made. Although we cannot predict with any degree of certainty the effects of
these actions on the operations of the joint ventures, NRG Energy has stated
that it will continue to operate in the ordinary course of business and we do
not expect these filings to significantly impact the joint ventures.
14
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
Note 6--Debt
Revolvers and Commercial Paper. During the three-month period ended March
31, 2003, we borrowed an aggregate of approximately $712 million under the
Dynegy and DHI revolving credit facilities. Additionally, during the
three-month period ended March 31, 2003, Dynegy and DHI eliminated an aggregate
of $433 million of letters of credit under their revolving credit facilities.
During the period from March 31, 2003 through the date of this report, Dynegy
and DHI issued $44 million of letters of credit under the revolving credit
facilities.
On April 2, 2003, DHI entered into a $1.66 billion credit facility
consisting of:
. a $1.1 billion DHI secured revolving credit facility, which matures on
February 15, 2005;
. a $200 million DHI secured term loan, which matures on February 15, 2005;
and
. a $360 million DHI secured term loan, which matures on December 15, 2005.
The credit facility replaces, and preserves the commitment of each lender
under DHI's $900 million and $400 million former revolving credit facilities,
which had maturity dates of April 28, 2003 and May 27, 2003, respectively, and
Dynegy's $360 million DGC secured debt, which had a maturity date of December
15, 2005. The restructured credit facility will provide funding for general
corporate purposes. The revolving facility is also available for the issuance
of letters of credit. Borrowings under the credit facility will bear interest,
at our option, at (i) a base rate plus 3.75% per annum or (ii) LIBOR plus 4.75%
per annum. A letter of credit fee will be payable on the undrawn amount of each
letter of credit outstanding at a percentage per annum equal to 4.75% of such
undrawn amount. An unused commitment fee of 0.50% will be payable on the unused
portion of the revolving facility. Please read Note 10 to the Form 10-K
beginning on page F-35 for further discussion of our restructured credit
facility.
Renaissance and Rolling Hills Credit Facility. In July 2002, we completed a
$200 million interim financing, bearing interest at LIBOR plus 1.38%. This loan
was scheduled to mature in January 2003 and was secured by interests in our
Renaissance and Rolling Hills merchant power generation facilities. In January
2003, we repaid $94 million of this facility and refinanced the remaining $106
million. The maturity date on the remaining $106 million was extended to
October 15, 2003 and the interest rate on the remaining balance was changed to
LIBOR plus 5%. On April 16, 2003, we prepaid the remaining $106 million.
Illinova Senior Notes. In March 2003, we purchased on the open market $5
million in aggregate principal amount of Illinova's 7.125% Senior Notes due
2004. The repurchased notes have been cancelled and are no longer outstanding.
As a result, $95 million in aggregate principle amount of the notes remained
outstanding at March 31, 2003 and are included within current portion of
long-term debt on the unaudited condensed consolidated balance sheets.
Illinois Power Term Loan. In May 2003, Illinois Power used a portion of the
proceeds from its December 2002 sale of $550 million in 11.5% Mortgage Bonds
due 2010, $150 million of which were issued in January 2003 following receipt
of a required approval from the Illinois Commerce Commission, to pay down the
$100 million then outstanding under its one-year term loan.
Note 7--Related Party Transactions
In connection with our announced exit from third-party risk-management
aspects of the marketing and trading business, we agreed with ChevronTexaco in
January 2003 to terminate the natural gas purchase
15
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
agreement between the parties and to provide for an orderly transition of
responsibility for marketing ChevronTexaco's domestic natural gas production.
This agreement will not affect our contractual agreements with ChevronTexaco
related to ChevronTexaco's U.S. natural gas processing and the marketing of
ChevronTexaco's domestic natural gas liquids. The cancellation of the agreement
was effective January 31, 2003. In conjunction with the termination of the
natural gas purchase agreement, we paid ChevronTexaco $13 million. As part of
the transition, we also agreed to provide scheduling, accounting and reporting
services as an agent for ChevronTexaco through April 2003.
Note 8--Earnings Per Share
Basic earnings (loss) per share represents the amount of earnings (loss) for
the period available to each share of common stock outstanding during the
period. Diluted earnings (loss) per share represents the amount of earnings
(loss) for the period available to each share of common stock outstanding
during the period plus each share that would have been outstanding assuming the
issuance of common shares for all dilutive potential common shares outstanding
during the period. In-the-money outstanding options contribute to the
differences between basic and diluted shares outstanding in all periods. The
diluted shares do not include the effect of the preferential conversion to
Class B common stock of the Series B Mandatorily Convertible Redeemable
Preferred Securities held by ChevronTexaco, as such inclusion would be
anti-dilutive.
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 months ended March 31, 2002.
Note 9--Commitments and Contingencies
Please see Note 14--Commitments and Contingencies beginning on page F-49 of
the Form 10-K for a description of our material legal proceedings. Set forth
below is a description of any material developments that have occurred with
respect to such proceedings since the filing of the Form 10-K and a description
of any new matters that have arisen since such filing.
We record reserves for estimated losses from contingencies when information
available indicates that a loss is probable and the amount of the loss is
reasonably estimable in accordance with SFAS No. 5, "Accounting for
Contingencies." For environmental matters, we record liabilities when
environmental assessment indicates that remedial efforts are probable and the
costs can be reasonably estimated. Please see Note 2--Accounting Policies
beginning on page F-8 of the Form 10-K for further discussion.
With respect to some of the items listed below, we have determined that a
loss is not probable or that any such loss, to the extent probable, is not
reasonably estimable. Notwithstanding the foregoing, management has assessed
these matters based on currently available information and made an informed
judgment concerning the potential outcome of such matters, giving due
consideration to the nature of the claim, the amount and nature of damages
sought and the probability of success. Management's judgment may, as a result
of facts arising prior to resolution of these matters or other factors, prove
inaccurate and investors should be aware that such judgment is made subject to
the known uncertainty of litigation.
California Market Litigation. As previously described in the Form 10-K, we
are the subject of various lawsuits alleging rate and market manipulation in
the California wholesale power market. These lawsuits relate
16
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
to, among other things, alleged exploitation of structural flaws in that market
and/or the unlawful use of market power. Symonds v. Dynegy and Lodewick v.
Dynegy, which include allegations similar to those in the California lawsuits,
were filed in the states of Washington and Oregon, respectively. On May 5,
2003, the United States District Court for the District of Oregon, at
plaintiffs' request, ordered the Lodewick suit dismissed without prejudice. An
unopposed motion to dismiss without prejudice was also filed in the Symonds
case.
On May 1, 2003, the case of Egger v. Dynegy Inc., et al. was filed in the
Superior Court of California in the County of San Diego as a class action
complaint. We understand that the suit, the complaint for which has not yet
been served on us, alleges violations of the Cartwright Act and unfair business
practices. The action is brought on behalf of consumers and businesses in
Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that
purchased energy from the California market. We are analyzing these claims,
which have only recently been made, and intend to defend against them
vigorously. It is not possible to predict with certainty whether we will incur
any liability or to estimate the range of possible loss, if any, that we might
incur in connection with this lawsuit.
FERC and California Investigations. As previously described in the Form
10-K, we are the subject of various investigations by the FERC and other
regulatory agencies relating to our past activities in the western power and
natural gas markets. These investigations relate to, among other things,
possible manipulation of natural gas and power prices in the western United
States and "wash," "round-trip" or "sale/buyback" transactions. On April 30,
2003, the FERC issued an order adopting the recommendations in its staff's
March 26, 2003 report that Dynegy and ten other companies be required to submit
information with respect to internal processes for reporting trading data to
publications that publish energy indices--specifically, that the employees
involved in manipulations, or attempted manipulations, of the published indices
have been disciplined; that the company has a clear code of conduct in place
for reporting price information; that all trade data reporting is done by an
entity within the company that does not have a financial interest in the
published index (preferably the chief risk officer); and that the company is
cooperating fully with any government agency investigating its past reporting
practices. We have complied and intend to continue complying with these
requirements. We are required to file a written response to the April 30, 2003
order by June 16, 2003 outlining the steps we have taken to comply with the
necessary requirements.
Apache Litigation. As previously described in the Form 10-K, Apache
Corporation filed suit in Harris County, Texas district court in May 2002
against Versado Gas Processors, LLC as purchaser and processor of Apache's gas,
and against Dynegy Midstream Services, Limited Partnership as operator of the
Versado assets in New Mexico. Apache, which has alleged that Versado owes it a
total of more than $9 million, claims, among other things, that the formula for
calculating the amount Versado receives from the buyers of gas and the liquids
is flawed since it is based on gas price indexes that these same affiliates are
alleged to have manipulated by providing false price information to the index
publisher. Versado intends to defend against these claims vigorously and
believes it has meritorious defenses. In May 2003, we filed a motion for
partial summary judgment relating to lost gas and related matters, which may be
heard at the end of May 2003. Trial in the matter is currently scheduled for
late third quarter 2003. We do not believe that any liability we might incur as
a result of this litigation would have a material adverse effect on our
financial condition, results of operations or cash flows.
Sierra Pacific Litigation. In April 2003, Sierra Pacific Resources and
Nevada Power Company filed suit against various sellers of natural gas,
including some of our subsidiaries, in the United States District Court for the
District of Nevada. In the suit, plaintiffs claim that they purchased natural
gas from us to produce electricity for their customers at artificially high
prices based on published index prices at the California-Arizona border
17
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
market. Plaintiffs claim that we were part of a conspiracy to restrict natural
gas transmission capacity on the El Paso pipeline system, which in turn raised
the California border price. Plaintiffs allege, although without specificity,
that Dynegy withheld capacity from the market in concert with El Paso and that
there was an "illicit" agreement between the other defendants, El Paso and us
to decrease output and raise prices in violation of the Nevada Unfair Trade
Practices Act. Plaintiffs seek an award of unspecified treble damages with
respect to these claims based on the alleged excess natural gas costs they
incurred.
Plaintiffs further allege that we intentionally misrepresented natural gas
prices and volumes to trade publications that compile and report index prices
in an effort to induce plaintiffs to enter into contracts for the purchase of
natural gas at artificially high prices, as well as associated hedging
transactions, and that Nevada Power did in fact rely on the misinformation
suffering damage as a result of such reliance. Plaintiffs further claim that we
conspired with El Paso to provide this false information, and that our
misconduct constitutes fraud and violates Nevada's Racketeering Influenced
Corrupt Organizations Act. Plaintiffs seek an award of unspecified treble
damages with respect to these claims.
We are analyzing these claims, which only recently were made, and intend to
defend against them vigorously. It is not possible to predict with certainty
whether we will incur any liability or to estimate the range of possible loss,
if any, that we might incur in connection with this lawsuit. However, we do not
believe that any liability we might incur as a result of this litigation would
have a material adverse effect on our financial condition, results of
operations or cash flows.
Other Index Pricing Litigation. In addition to the Sierra Pacific suit
described above, we and Dynegy Marketing and Trade were named as defendants in
April 2003 in a third-party complaint in a lawsuit originally initiated by
Nelson Brothers, LLC against Cherokee Nitrogen in Alabama state court. The
underlying suit relates to an agreement between Cherokee and Nelson Brothers
pursuant to which Cherokee allegedly agreed to supply ammonium nitrate to
Nelson Brothers and to use its commercially reasonable efforts to reduce its
supply costs. When Nelson Brothers sued Cherokee under their agreement,
Cherokee filed a third-party complaint alleging that it purchased natural gas
from Dynegy Marketing and Trade based on index pricing and, citing our December
2002 settlement with the CFTC, that the index prices used were artificially
inflated by Dynegy Marketing and Trade due to "fraudulent and inaccurate
reporting" to index services, which resulted in higher costs that it passed on
to Nelson Brothers. Cherokee claims that Dynegy Marketing and Trade is liable
to it for alleged overcharges and seeks actual and punitive damages in
unspecified amounts. We intend to defend against these claims vigorously. It is
not possible to predict with certainty whether we will incur any liability or
to estimate the range of possible loss, if any, that we might incur in
connection with this lawsuit. However, we do not believe that any liability we
might incur as a result of this litigation would have a material adverse effect
on our financial condition, results of operations or cash flows.
Note 10--Regulatory Issues
We are subject to regulation by various federal, state, local and foreign
agencies, including extensive rules and regulations governing transportation,
transmission and sale of energy commodities as well as the discharge of
materials into the environment or otherwise relating to environmental
protection. Compliance with these regulations requires general and
administrative, capital and operating expenditures including those related to
monitoring, pollution control equipment, emission fees and permitting at
various operating facilities and remediation obligations. In addition, the
United States Congress has before it a number of bills that could impact
regulations or impose new regulations applicable to us and our subsidiaries. We
cannot predict the outcome of these bills or other regulatory developments or
the effects that they might have on our business. For a more
18
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
detailed description of regulatory issues affecting our business, please refer
to "Item 1. Business--Regulation" in the Form 10-K beginning on page 22.
Note 11--Segment Information
As reflected in this report, we have changed our reporting segments. In
2002, we reported results for the following four business segments:
. Wholesale Energy Network, or WEN;
. Dynegy Midstream Services, or DMS;
. Transmission and Distribution, or T&D; and
. Dynegy Global Communications, or DGC.
Beginning January 1, 2003, we are reporting our operations in the following
segments:
. Power generation, or GEN;
. Natural gas liquids, or NGL;
. Regulated energy delivery, or REG; and
. Customer risk management, or CRM.
For the three-month period ended March 31, 2002, our segment information has
been presented based on our revised reportable segments. GEN includes the
operations of owned or leased electric power generation facilities located in
six regions of the United States. This segment is focused on optimizing our
portfolio of energy assets and related contracts, as well as direct commercial
and industrial sales. NGL consists of our North American natural gas gathering
and processing, natural gas liquids fractionation and marketing businesses and
transportation operations. REG is engaged in the transmission, distribution and
sale of electricity and natural gas to customers across a 15,000-square-mile
area of Illinois. CRM consists of third-party marketing, trading and
risk-management activities unrelated to our generating assets. Other reported
results include corporate governance roles and functions, which are managed on
a consolidated basis, and specialized support functions. All costs associated
with other reported results were allocated to the four operating segments prior
to January 1, 2003.
Prior to January 1, 2003, the WEN segment was comprised of the current GEN
segment and the current CRM segment. In connection with our exit from the
third-party marketing and trading business, individual contracts within the
former WEN segment were identified on January 1, 2003 as either GEN contracts,
as they were determined to be a part of our continuing operations, or CRM
contracts. During the three-month period ended March 31, 2003, unaffiliated
revenues presented below for the CRM and GEN segments reflect actual
third-party revenues recorded for settlement of physical and financial
contracts in the respective segments.
Prior to January 1, 2003, the GEN and CRM segments were operated together as
an asset-based third-party marketing, trading and risk-management business.
Under this business model, the fair value of GEN's generation capacity, forward
sales and related trading positions were sold to the CRM segment each month at
an internally determined transfer price based on then-current market prices.
The CRM segment would record revenue from the third-party contracts associated
with the GEN segment, together with all of its other third-party marketing and
trading positions unrelated to the GEN segment, during the month of settlement.
The intersegment revenues presented below for the GEN segment during the
three-month period ended March 31, 2002 reflect this internal transfer price
and do not represent amounts actually received by GEN for power sold to third
parties. As such, the GEN intersegment revenues for the three-month period
ended March 31, 2002 do not include the effects of
19
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
intra-month market price volatility. Please take into account these differences
when attempting to compare the first quarter results for 2002 and 2003.
Prior to January 1, 2003, our natural gas liquids operations comprised our
Dynegy Midstream Services segment. Beginning January 1, 2003, these operations
comprise the NGL segment. Additionally, prior to January 1, 2003, we reported
our Illinois Power utility operations and, for the first three quarters of 2002
prior to its sale, the operations of Northern Natural in our Transmission and
Distribution segment. Beginning January 1, 2003, our Illinois Power utility
operations comprise the REG segment. Results associated with the former DGC
segment are included in discontinued operations due to the sale of our
communications businesses. Reportable segment information for the three-month
periods ended March 31, 2003 and 2002 is presented below.
20
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
Dynegy's Segment Data for the Quarter Ended March 31, 2003
(in millions)
Other and
GEN NGL REG CRM Eliminations Total
------ ------ ------ ------ ------------ -------
Unaffiliated revenues:
Domestic.................................. $ 106 $ 978 $ 455 $ 198 $ -- $ 1,737
Canadian.................................. -- -- -- 8 -- 8
------ ------ ------ ------ ------- -------
106 978 455 206 -- 1,745
Intersegment revenues (1).................... 788 73 8 (158) (711) --
------ ------ ------ ------ ------- -------
Total revenues........................ $ 894 $1,051 $ 463 $ 48 $ (711) $ 1,745
====== ====== ====== ====== ======= =======
Depreciation and amortization................ $ (42) $ (20) $ (30) $ (1) $ (22) $ (115)
Operating income (loss)...................... $ 83 $ 51 $ 59 $ 38 $ (44) $ 187
Other items, net............................. 3 (5) -- 26 (3) 21
Earnings from unconsolidated investments..... 39 3 -- 11 -- 53
Interest expense............................. (110)
Income tax provision......................... (56)
-------
Income from continuing operations............ 95
Loss on discontinued operations, net of taxes (3)
Cumulative effect of a change in accounting
principle, net of taxes.................... 55
-------
Net income................................... $ 147
=======
Identifiable assets:
Domestic.................................. $6,568 $1,804 $5,652 $4,808 $(2,111) $16,721
Other..................................... -- -- -- 725 (80) 645
Unconsolidated investments................... 598 98 -- 14 -- 710
Capital expenditures and unconsolidated
investments................................ (37) (12) (32) -- (3) (84)
- --------
(1) EITF Issue 02-03 requires all gains and losses on energy trading contracts,
whether realized or unrealized, to be presented net in the income
statement. Unaffiliated revenues of the CRM segment include, pursuant to
EITF Issue 02-03, net purchases and sales of power and natural gas
transacted with third parties on behalf of the GEN segment. This
relationship results in a net intersegment purchase from the GEN segment,
which is presented as a reduction in CRM intersegment revenues.
21
DYNEGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Interim Periods Ended March 31, 2003 and 2002
Dynegy's Segment Data for the Quarter Ended March 31, 2002
(in millions)
Other and
GEN NGL REG CRM Eliminations Total
------ ------ ------ ------ ------------ -------
Unaffiliated revenues:
Domestic.................................. $ 38 $ 649 $ 385 $ 136 $ -- $ 1,208
Canadian.................................. -- 231 -- -- -- 231
------ ------ ------ ------ ----- -------
38 880 385 136 -- 1,439
Intersegment revenues:....................... 286 33 8 227 (554) --
------ ------ ------ ------ ----- -------
Total revenues........................ $ 324 $ 913 $ 393 $ 363 $(554) $ 1,439
====== ====== ====== ====== ===== =======
Depreciation and amortization................ $ (35) $ (19) $ (36) $ (3) $ -- $ (93)
Operating income (loss)...................... $ 65 $ 40 $ 40 $ (60) $ -- $ 85
Other items, net............................. 1 1 2 (18) -- (14)
Earnings from unconsolidated investments..... 28 4 -- 3 -- 35
Interest expense............................. (66)
Income tax benefit........................... 7
-------
Income from continuing operations............ $ 47
Loss on discontinued operations, net of taxes (60)
Cumulative effect of a change in accounting
principle, net of taxes.................... (234)
-------
Net loss..................................... $ (247)
=======
Identifiable assets:
Domestic.................................. $7,284 $2,061 $6,428 $8,053 $ 487 $24,313
Canadian.................................. -- 120 -- 640 -- 760
European and other........................ 206 -- -- 2,689 278 3,173
Unconsolidated investments................... 728 149 8 35 -- 920
Capital expenditures and unconsolidated
investments................................ (262) (31) (29) (9) (67) (398)
Note 12--Subsequent Event
In April 2003, we reached an agreement in principle with Southern Power
Company to terminate three power tolling arrangements among Dynegy, Southern
and our respective affiliates covering an aggregate of 1,100 MW. Under the
terms of the agreement, which is subject to definitive documentation, we will
pay Southern $155 million to terminate two of these arrangements effective May
30, 2003 and the third such arrangement effective October 31, 2003. The
terminations will result in $96 million of collateral being returned to us and
will eliminate our obligation to make $1.7 billion in payments due to Southern
over the next 30 years. We anticipate we will close the transaction in May 2003.
22
DYNEGY INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
For the Interim Periods Ended March 31, 2003 and 2002
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion should be read together with the unaudited
condensed consolidated financial statements included in this report and with
the audited consolidated financial statements and the notes thereto included in
the Form 10-K.
We are a holding company and conduct substantially all of our business
operations through our subsidiaries. Our three main operating divisions are
engaged in power generation, natural gas liquids and regulated energy delivery.
Our power generation business owns or leases 13,167 MW of net generating
capacity, including 838 MW scheduled to begin commercial operation in the
second quarter 2003. Our power generation fleet is diversified by facility type
(base load, intermediate and peaking), fuel source and geographic location. Our
natural gas liquids business owns natural gas gathering and processing assets
with processing capacity of 2.6 Bcf/d located in key producing areas of
Louisiana, New Mexico and Texas. This business also owns integrated assets used
to fractionate, store, terminal, transport, distribute and market natural gas
liquids. These assets are generally connected to and supplied by our natural
gas gathering and processing assets and are located in Mont Belvieu, Texas, the
hub of the U.S. natural gas liquids business, and West Louisiana. Our regulated
energy delivery business is comprised of our Illinois Power Company subsidiary.
Illinois Power serves more than 590,000 electricity customers and nearly
415,000 natural gas customers in Illinois.
We are restructuring our company around these three asset-based energy
businesses. In carrying out our restructuring, we have disposed of our
communications business. We also have made significant progress in our planned
exit from third-party risk-management aspects of the marketing and trading
business. Our U.S. communications business will be reported as discontinued
operations through the closing of the sale. The remaining portion of our North
American third-party marketing and trading business, which includes the power
tolling arrangements to which we remain a party, now comprises our CRM segment.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Since the end of 2002, we have executed a number of important initiatives,
including the restructuring of our primary bank credit facilities and the exit
of the communications business. We also have made substantial progress in
executing our planned exit from third-party marketing and trading, including
the cessation of our European marketing and trading operations, the sale of our
natural gas inventories and the transition back to ChevronTexaco of the natural
gas purchase and sale contracts related to its domestic natural gas production.
Most recently, we announced our agreement with Southern Power Company to
terminate three of our eight remaining power tolling arrangements.
As a result of these efforts, through May 12, 2003 we have improved our
liquidity position while reducing usage under our revolving credit facility,
including letters of credit and borrowings, by approximately $317 million. We
also have reduced our other debt obligations by approximately $241 million.
Going forward, we intend to replace some of our cash collateral postings with
letters of credit, increasing our revolver usage. We expect to rely on cash on
hand, cash from operations and availability under our restructured revolving
credit facility to satisfy our collateral obligations and our other liquidity
requirements. Please read "--Conclusion" for further discussion.
23
Available Credit Capacity and Liquidity Sources
Bank Restructuring. On April 2, 2003, DHI entered into a $1.66 billion
credit facility consisting of:
. a $1.1 billion DHI secured revolving credit facility, which matures on
February 15, 2005;
. a $200 million DHI secured term loan, which matures on February 15, 2005;
and
. a $360 million DHI secured term loan, which matures on December 15, 2005.
The credit facility replaces, and preserves the commitment of each lender
under, DHI's $900 million and $400 million former revolving credit facilities,
which had maturity dates of April 28, 2003 and May 27, 2003, respectively, and
Dynegy's $360 million Polaris communications lease, which had a maturity date
of December 15, 2005. The restructured credit facility will provide funding for
general corporate purposes. The revolving facility is also available for the
issuance of letters of credit. Borrowings under the credit facility will bear
interest, at our option, at (i) a base rate plus 3.75% per annum or (ii) LIBOR
plus 4.75% per annum. A letter of credit fee will be payable on the undrawn
amount of each letter of credit outstanding at a percentage per annum equal to
4.75% of such undrawn amount. An unused commitment fee of 0.50% will be payable
on the unused portion of the revolving facility. Please read "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Bank
Restructuring" beginning on page 42 of the Form 10-K for further discussion.
The following table summarizes our consolidated credit capacity and
liquidity position at December 31, 2002, March 31, 2003 and May 12, 2003 (in
millions):
December 31, March 31, May 12,
2002 2003 2003
------------ --------- -------
Total Credit Capacity........................ $1,400 $1,400 $1,100(2)
Outstanding Loans............................ (228) (940) --
Outstanding Letters of Credit Under Revolving
Credit Facility............................ (872) (439) (483)
------ ------ ------
Unused Borrowing Capacity.................... 300 21 617
Cash......................................... 757 1,775 1,153
Liquid Inventory(1).......................... 258 -- --
------ ------ ------
Total Available Liquidity.................... $1,315 $1,796 $1,770
====== ====== ======
- --------
(1) Amounts reflected for 2003 periods do not include liquid inventory, as we
have sold the natural gas inventories that comprised that item and
converted them to cash.
(2) Reflects the conversion of $200 million of credit capacity under the former
DHI revolving credit facilities into a term loan in connection with the
April 2003 restructuring of such facilities, as well as the May 2003
payment of the final $100 million then outstanding under Illinois Power's
termed out revolving credit facility.
Liquidity Uses
During the first quarter 2003, significant uses of liquidity included the
following:
. Funding of a $94 million payment under the Renaissance and Rolling Hills
interim financing;
. Funding of a $19 million quarterly payment under the Black Thunder
financing;
. Funding of a $22 million quarterly payment on Illinois Power's
transitional funding trust notes;
. Funding of an $18 million payment under the ABG Gas Supply financing; and
. Purchase of $5 million of Illinova senior notes on the open market.
Since March 31, 2003, we have paid the remaining $106 million due under the
Renaissance and Rolling Hills interim financing and the remaining $100 million
due on Illinois Power's termed out revolving credit facility.
24
Collateral Obligations
During the first quarter 2003, we reduced the collateral obligations
associated with our third-party marketing and trading business by approximately
$350 million. This reduction, together with the reductions achieved in the
fourth quarter 2002 and from April 1, 2003 through May 12, 2003, eliminated an
aggregate of approximately $706 million in collateral obligations associated
with this business. Upon completion of the termination of the three Southern
power tolling arrangements, we will eliminate $96 million in further collateral
obligations associated with this business. Please read Note 12 to the unaudited
condensed consolidated financial statements for further discussion of the
Southern transaction.
The following table summarizes our consolidated collateral postings by
operating division at December 31, 2002, March 31, 2003 and May 12, 2003 (in
millions):
December 31, March 31, May 12,
2002 2003 2003
------------ --------- -------
GEN.. $ 202 334 $274
CRM.. 769 419 311
NGL.. 166 226 213
REG.. 31 31 23
Other 48 52 44
------ ------ ----
Total $1,216 $1,062 $865
====== ====== ====
The collateral obligations associated with our CRM business have been
dramatically reduced from the approximately $1 billion in amounts outstanding
at September 30, 2002. However, the collateral requirements for our GEN and NGL
businesses and the remaining power tolling arrangements have increased since
the end of 2002. This increase primarily was caused by a significant increase
in power and natural gas prices during this period, and collateral requirements
for these businesses will continue to reflect this sensitivity to commodity
prices.
Dividends on Preferred and Common Stock
Beginning with the third quarter 2002, our Board of Directors elected to
cease payment of a dividend on our common stock. Payments of dividends for
subsequent periods will be at the discretion of the Board of Directors, but we
do not foresee reinstating the dividend in the near term. We have, however,
continued to make the required dividend payments on our outstanding trust
preferred securities. Please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Bank Restructuring" beginning on
page 42 of the Form 10-K for a discussion of the dividend limitations contained
in our restructured credit facility.
There is no cash dividend required to be paid on the Series B preferred
stock issued to ChevronTexaco in November 2001. Because of ChevronTexaco's
discounted conversion option, we are required to accrete an implied preferred
stock dividend over the redemption period, as required by GAAP. Please read
"Item 8, Financial Statements and Supplementary Data, Note 13--Redeemable
Preferred Securities" beginning on page F-47 of the Form 10-K for further
discussion of this non-cash implied dividend.
Illinois Power Liquidity
Illinois Power has a significant amount of leverage, with near-term
maturities including $190 million in aggregate mortgage bond maturities due in
August and September 2003 and quarterly payments of approximately $22 million
due on its transitional funding trust notes. Illinois Power is required to make
these quarterly payments on its transitional funding trust notes through 2008
and has a payment of up to $81 million due on its Tilton lease financing in the
third quarter 2004. Because Illinois Power has no revolving credit facility and
no access to the commercial paper markets, it relies on cash on hand, cash from
asset sales or other liquidity initiatives and cash flows from operations,
including interest payments under its $2.3 billion intercompany note
25
receivable from Illinova, to satisfy its debt obligations and to otherwise
operate its business. In December 2002, Illinois Power sold $550 million of
mortgage bonds, $150 million of which were issued in January 2003 following
approval from the Illinois Commerce Commission. A portion of the proceeds were
used to repay Illinois Power's $300 million term loan (including the final
payment of $100 million on May 2, 2003) and to replenish liquidity used to pay
a $96 million mortgage bond maturity earlier in 2002. The remaining proceeds
from this offering are to be used to fund a significant portion of Illinois
Power's remaining 2003 maturities.
Illinois Power remains reliant on its ability to execute one or more other
liquidity initiatives in order to satisfy its future debt and commercial
obligations, including the remaining portion of its third quarter 2003 mortgage
bond maturities. We expect these initiatives will include new bank borrowings
or mortgage bond issuances or another type of initiative, including a support
commitment by Dynegy. Although Dynegy's recently restructured credit agreement
prohibits prepayments of principal on the intercompany note receivable in
excess of $200 million, it does not limit Dynegy's ability to prepay interest
under the intercompany note receivable. Depending on the structure of the
transaction, one or more of these initiatives could require regulatory approval.
Conclusion
In April 2003, we restructured our primary revolving credit facilities that
were set to expire in April and May of this year. By extending the maturity
dates of these obligations, which totaled approximately $1.3 billion upon
completion of the restructuring, together with the successful execution of our
other liquidity initiatives, we believe that we have provided our company with
sufficient capital resources to meet our debt obligations and provide
collateral support for our ongoing asset businesses and our continued exit from
third-party marketing and trading through 2004. However, our success and future
financial condition, including our ability to refinance our substantial debt
maturities in 2005 and thereafter, will depend on our ability to execute the
remainder of our exit from third-party marketing and trading successfully and
to produce adequate operating cash flows from our continuing asset-based
businesses to meet our debt and commercial obligations, including a substantial
increase in interest expense. Please read "Factors Affecting Future Results of
Operations" and "Uncertainty of Forward-Looking Statements and Information" for
additional factors that could impact our future operating results and financial
condition.
FACTORS AFFECTING FUTURE RESULTS OF OPERATIONS
Our results of operations during the remainder of 2003 and beyond may be
significantly affected by the following factors, among others:
. the level of earnings and cash flows from our asset-based businesses,
which are subject to the effect of changes in commodity prices,
particularly for power, natural gas and other fuels and, to a lesser
extent, the spark spread between power and natural gas prices;
. the effects of competition on the results of operations from our
asset-based businesses;
. our ability to complete our exit from third-party risk-management aspects
of the marketing and trading business and the costs associated with this
exit;
. our ability to operate our asset-based businesses with a reduced work
force and within the confines of the increased borrowing rates and more
restrictive covenants contained in our restructured credit agreement;
. our ability to address our substantial leverage and the $1.5 billion in
Series B preferred stock held by ChevronTexaco;
. increased interest costs resulting from increased collateral requirements
and higher borrowing costs associated with our restructured credit
agreement; and
. the effects of ongoing litigation relating to, among other things, the
western power and natural gas markets and shareholder claims, as well as
the ongoing regulatory investigations primarily relating to Project Alpha
and our past trading practices.
26
Additionally, as further discussed in Note 1 to the unaudited condensed
consolidated financial statements, new accounting pronouncements have impacted
our results of operations and will continue to do so in the future. Please read
"Uncertainty of Forward-Looking Statements and Information" for additional
factors that could impact our future operating results.
RESULTS OF OPERATIONS
In this section, we discuss our results of operations, both on a
consolidated basis and by segment, for the three-month periods ended March 31,
2003 and 2002.
As reflected in this report, we have changed our reporting segments. In
2002, we reported results for the following four business segments:
. Wholesale Energy Network, or WEN;
. Dynegy Midstream Services, or DMS;
. Transmission and Distribution, or T&D; and
. Dynegy Global Communications, or DGC.
Beginning January 1, 2003, we are reporting our operations in the following
segments:
. Power generation, or GEN;
. Natural gas liquids, or NGL;
. Regulated energy delivery, or REG; and
. Customer risk management, or CRM.
Other reported results include corporate overhead and our discontinued
communications operations. All corporate overhead included in other reported
results was allocated to the four operating segments prior to January 1, 2003.
This change in reportable segments will affect the comparability of our segment
results for 2003 and beyond.
As described in Note 11 to the unaudited condensed consolidated financial
statements included in this report, prior to January 1, 2003, the CRM and GEN
segments were reported together in the WEN segment. In connection with our exit
from the CRM business, we separated the contracts within the former WEN segment
as of January 1, 2003 as being GEN contracts or CRM contracts, based on their
terms and their importance to our GEN segment. The unaffiliated revenues
presented below for the GEN and CRM segments for the first quarter 2003 reflect
actual third-party revenues recorded for settlement of physical and financial
contracts based on this separation. With respect to the comparative results for
the first quarter 2002, the GEN and CRM businesses were operated together
within the WEN segment as an asset-based third-party marketing, trading and
risk-management business during that period. Under this business model, the
fair value of the GEN segment's generation capacity, forward sales and related
trading positions were sold to the CRM segment each month at an internally
determined transfer price. The CRM segment would record revenue from the
third-party contracts associated with the GEN segment, together with all of its
other third-party marketing and trading positions unrelated to the GEN segment,
during the month of settlement. The intersegment revenues for the GEN segment
during the three-month period ended March 31, 2002 reflect this internal
transfer price and do not represent amounts actually received for power sold to
third parties. As such, the intersegment revenues for the three-month period
ended March 31, 2002 do not include the effects of intra-month market price
volatility. Please take into account these differences when attempting to
compare the first quarter results for 2002 and 2003.
Recent accounting pronouncements have affected our financial results,
particularly those of our third-party marketing and trading business, so as to
further reduce the comparability of some of our historical financial data. For
example, the rescission of EITF Issue 98-10, effective January 1, 2003, has
reduced the number of contracts accounted for on a mark-to-market basis in the
2003 period as compared to the 2002 period. Please read "--Cumulative Effect of
Change in Accounting Principle" below for further discussion.
27
For segment reporting purposes, all general and administrative expenses
incurred by Dynegy on behalf of its subsidiaries are charged to the applicable
subsidiary as incurred. Other income (expense) items incurred by us on behalf
of our subsidiaries are allocated directly to the four segments.
Three-Months Ended March 31, 2003 and 2002
The following table provides summary financial data regarding our unaudited
condensed consolidated results of operations for the three-month periods ended
March 31, 2003 and 2002, respectively (in millions):
Results of Operations
Three Months Ended
March 31,
-----------------
2003 2002
------ ------
Operating Income................................................. $ 187 $ 85
Earnings from Unconsolidated Investments......................... 53 35
Interest Expense................................................. (110) (66)
Other Items, Net................................................. 21 (14)
Income Tax (Provision) Benefit................................... (56) 7
----- -----
Income from Continuing Operations................................ 95 47
Loss on Discontinued Operations, Net of Taxes.................... (3) (60)
Cumulative Effect of Change in Accounting Principle, Net of Taxes 55 (234)
----- -----
Net Income (Loss)................................................ $ 147 $(247)
===== =====
Net Income (Loss). For the quarter ended March 31, 2003, we recorded net
income of $147 million, compared with a first quarter 2002 net loss of $247
million. After taking into consideration the $83 million preferred stock
dividend, diluted earnings per share for the quarter ended March 31, 2003 was
$0.17 compared to a net loss per share of $0.91 for the quarter ended March 31,
2002.
Operating income increased approximately $102 million quarter-to-quarter
primarily due to higher commodity prices, which positively impacted all of our
segments, as well as weather-driven demand resulting in greater volumes
produced and sold. Operating income also reflects increased depreciation and
amortization expense primarily associated with the expansion of our depreciable
asset base, including the completion of three generation facilities that were
under construction during the first quarter 2002. General and administrative
expenses were lower period-to-period principally as a result of significantly
lower compensation costs in the 2003 period, which were partially offset by
higher professional fees.
Subsequent to the issuance of our first quarter 2003 earnings release on
April 29, 2003, we reclassified $29 million of operating income to minority
interest expense. This amount represents the correction of an error in the
consolidation of ABG Supply and has no impact on income from continuing
operations, net income or cash flows.
Earnings from Unconsolidated Investments. Our earnings from unconsolidated
investments were approximately $53 million in the 2003 period compared to $35
million in 2002. The increase period-to-period primarily reflects higher
volumes sold by West Coast Power, a 50-50 joint venture through which we own
our California power generation facilities. Please read "--Segment
Disclosures--Power Generation" below for further discussion.
Interest Expense. Interest expense totaled $110 million for the three-month
period ended March 31, 2003, compared to $66 million for the 2002 period. The
significant increase period-to-period primarily is attributable to higher
average principal balances in the 2003 period compared to the 2002 period,
partially offset by lower
28
average interest rates on borrowings based primarily on a reduction in the
LIBOR rate. The increase in principal balances primarily resulted from
substantially higher collateral postings in the second and third quarters of
2002 which, despite subsequent reductions, remained at levels above those
outstanding during the first quarter 2002. Please read "--Liquidity and Capital
Resources--Collateral Obligations" above for a discussion of the significant
reductions in collateral postings, particularly with respect to our third-party
marketing and trading business, since the end of the third quarter 2002.
While these collateral reductions are expected to reduce our 2003 principal
balances, higher commodity prices compared to 2002 and a related increase in
collateral postings associated with our CRM, GEN and NGL businesses may
mitigate such impact. In addition, our interest expense during the remainder of
2003 and thereafter will reflect the increased costs of borrowing under our
restructured credit facility. Generally, borrowings under the restructured
credit facility will bear interest, at our option, at (i) a base rate plus
3.75% per annum or (ii) LIBOR plus 4.75% per annum. Pricing on letters of
credit has increased from 50 basis points under DHI's former $400 million
credit facility and from 200 basis points under DHI's former $900 million
credit facility to approximately 475 basis points under the restructured credit
facility. Interest expense in 2003 will also reflect higher costs from Illinois
Power's December 2002 and January 2003 issuances of mortgage bonds totaling
$550 million, which bonds were issued at a 12% effective interest rate compared
to Illinois Power's average 2002 mortgage bond interest rate of 5.81%.
Other Items, Net. Other items, net consists of other income and expense
items, net, minority interest income (expense) and accumulated distributions
associated with trust preferred securities in the unaudited condensed
consolidated statements of operations. Other items, net totaled $21 million in
income and $14 million in expense for the three-month periods ended March 31,
2003 and 2002, respectively. The change in these amounts primarily represents
increases in minority interest income in the 2003 period.
Income Tax (Provision) Benefit. We reported an income tax provision of $56
million for the quarter ended March 31, 2003, compared to an income tax benefit
of $7 million for the 2002 period. The 2003 effective rate of 37 percent was
increased from statutory rates primarily as a result of state income taxes. The
tax benefit in the 2002 period resulted from the combination of book income and
losses in jurisdictions with varying tax rates and the realization of permanent
differences.
Discontinued Operations. Discontinued operations primarily include Northern
Natural Gas, our global liquids business, our U.K. natural gas storage assets,
our U.K. marketing business and our communications business. The first quarter
2003 loss of $3 million is comprised of a $19 million after-tax gain on the
disposition of the European communications business, offset by $12 million in
after-tax losses on operations of the communications business and $10 million
in after-tax losses on operations of U.K. CRM. The first quarter 2002 loss of
$60 million is comprised of $82 million in after-tax losses on the operations
of the communications business and $10 million in after-tax losses associated
with U.K. CRM , offset by $27 million in after-tax income from Northern Natural
Gas and $5 million in after-tax income from the U.K. natural gas storage assets.
Cumulative Effect of Change in Accounting Principle. As described in Note 1
to the unaudited condensed consolidated financial statements, we reflected the
rescission of EITF Issue No. 98-10 effective January 1, 2003 as a cumulative
effect of change in accounting principle. The net impact was an after-tax
benefit of $21 million. We also adopted SFAS No. 143 effective January 1, 2003
and recognized an after-tax benefit of $34 million associated with its
implementation. As described in Note 3 to the unaudited condensed consolidated
financial statements, we adopted SFAS No. 142 effective January 1, 2002. In
connection with its adoption, we realized a cumulative effect loss of
approximately $234 million associated with a write-down of goodwill in our
discontinued communications business.
29
Segment Disclosures
Non-GAAP Financial Measures. Management uses Earnings Before Interest and
Taxes, or "EBIT," as one measure of financial performance of our business
segments. EBIT is a non-GAAP financial measure and consists of operating
income, earnings from unconsolidated investments, other income and expenses,
net, minority interest income (expense) and accumulated distributions
associated with trust preferred securities. EBIT does not include, among other
things, interest expense, income taxes and the cumulative effect of a change in
accounting principle, each of which is evaluated on a consolidated level. We
use EBIT to combine operating income with earnings from unconsolidated
investments because such earnings can be significant, particularly in our GEN
segment. In addition, because we do not allocate interest expense and income
taxes by segment, we believe that EBIT is a useful measurement of our segment
performance for investors. It also provides additional information with respect
to the performance of our underlying assets, including those owned by joint
ventures. Management also believes that debt-holders frequently use EBIT to
analyze operating performance and debt service capacity. EBIT should not be
considered an alternative to, or more meaningful than, net income or cash flows
from operations as determined in accordance with GAAP. Our segment EBIT may not
be comparable to similarly titled measures used by other companies.
Power Generation
Three Months
Ended March 31,
-------------------
2003 2002
------ ------
(in millions, except
operating statistics)
Total Operating Income......................... $ 83 $ 65
Earnings from Unconsolidated Investments....... 39 28
Other Items, Net............................... 3 1
------ ------
Earnings Before Interest and Taxes............. $ 125 $ 94
====== ======
Operating Statistics:
Million Megawatt Hours Generated--Gross........ 11.4 9.5
Million Megawatt Hours Generated--Net.......... 10.9 8.5
Average Natural Gas Price--Henry Hub ($/MMbtu). $ 6.30 $ 2.52
Average On-Peak Market Power Prices ($/MW hour)
Cinergy..................................... $50.64 $21.95
Commonwealth Edison......................... 47.98 21.76
Southern.................................... 48.80 22.25
New York--Zone G............................ 75.88 32.23
ERCOT....................................... 56.29 21.76
Three-Month Periods Ended March 31, 2003 and 2002
GEN reported EBIT of $125 million for the three-month period ended March 31,
2003 compared to $94 million for the same period in 2002. EBIT consists of the
following amounts reported by GEN for the periods presented: operating income
of $83 million and $65 million, respectively; earnings from unconsolidated
investments of $39 million and $28 million, respectively; and other items, net
of $3 million and $1 million, respectively. This segment's results for the
first quarter 2003 reflected higher power prices and limited excess generation
capacity in selected markets we serve. Demand for power was higher in the
Midwest and Northeast regions given colder than expected weather conditions and
less capacity due to periodic outages at other generation facilities. Net MW
hours generated were 5.5 million and 1.4 million in the first quarter 2003
versus 4.3 million and 0.8 million in the first quarter 2002 in the Midwest and
Northeast, respectively. Due to the increase in demand period-to-period,
average on-peak prices increased 120% and 135% in the Midwest and Northeast,
respectively. As a result of the increased demand and higher prices, we delayed
routine operating
30
maintenance at four of our facilities. These delays did not negatively impact
the safety of our operations. Our first quarter 2003 results were positively
impacted by the operation of these facilities, which we expect to temporarily
shut down in the second quarter 2003 in order to perform the necessary
maintenance.
GEN's reported operating income also includes $14 million of income related
to transactions which are recorded on a mark-to-market basis, as these forward
sales did not meet the criteria for hedge accounting under SFAS No. 133.
Additionally, we recognized earnings of $29 million in the first quarter 2003
related to our equity investment in West Coast Power. West Coast Power's
earnings increased 97% from the first quarter 2002 due to higher sales under
its contract with the CDWR. Weather-driven demand in the west region of the
United States caused the CDWR to purchase more capacity from West Coast Power
under the terms of the parties' contract, which permits the CDWR to reserve
specified levels of on-peak and off-peak capacity in excess of those levels
that are the subject of a firm commitment. Please read "Item 1.
Business--Segment Discussion--Power Generation" beginning on page 4 of the Form
10-K for further discussion of the West Coast Power contract and the ongoing
legal challenges relating thereto.
Operating income for the three-month period ended March 31, 2002 reflects
the sale to our CRM segment of the fair value of GEN's generation capacity,
forward sales and related trading positions at an internally determined
transfer price. For the three-month period ended March 31, 2003, operating
income for the GEN segment reflects the sale of power to third parties at
market prices. Please take into account these differences when attempting to
compare the first quarter results for 2002 and 2003. Please see Note 11 to the
accompanying unaudited condensed consolidated financial statements for further
discussion regarding the comparability of these results.
Net electric power produced and sold was 10.9 million MW hours for the first
quarter 2003, which represented a 28 percent increase over 2002, primarily as a
result of favorable weather conditions.
Power Generation Outlook
We expect that this segment's future financial results will continue to
reflect a sensitivity to power prices, weather and other factors affecting
generation demand, natural gas and other fuel prices (including, to a lesser
extent, the "spark spread," or price differential between natural gas and
power), and terms of contracts for contracted generation. We believe that our
generation fleet's fuel diversity will help mitigate the extent to which this
segment's future results are affected by changes in the spark spread. We also
expect that this business will continue its efforts to manage its price risk
through the optimization of fuel procurement and the marketing of power
generated from its assets. As part of our strategy of commercially optimizing
our assets, including agency and energy management agreements to which we are a
party, we enter into financial and other transactions, including forward hedge
activities, relating to our generating capacity. This segment's sensitivity to
prices and our ability to manage this sensitivity is subject to a number of
factors, including general market liquidity, our ability to provide necessary
collateral support and the willingness of counterparties to transact business
with us given our non-investment grade credit ratings. Other factors that could
affect the prices at which transactions can be consummated and this segment's
results of operations include transmission constraints, or the lack thereof,
and governmental actions, excess generation capacity or supply shortages in the
markets we serve. Please see "Item 1. Business--Segment Discussion--Power
Generation" beginning on page 4 of the Form 10-K for a discussion of the
effects of competition on this segment's future results of operations.
Any events that negatively impact this segment's significant long-term power
sales agreements could likewise affect its future results of operations. For
example, equity earnings from West Coast Power are primarily derived from West
Coast Power's long-term power sales contract with the CDWR. That contract,
which runs through December 31, 2004, is the subject of various legal
challenges. The success of any such challenges could negatively impact this
segment's equity earnings from West Coast Power and, accordingly, results of
operations for the periods affected.
31
Natural Gas Liquids
Three Months Ended
March 31,
------------------
2003 2002
------ ------
(in millions, except
operating statistics)
Operating Income:
Upstream.............................. $ 29 $ 12
Downstream............................ 22 28
------ ------
Total Operating Income............ 51 40
Earnings from Unconsolidated Investments. 3 4
Other Items, Net......................... (5) 1
------ ------
Earnings Before Interest and Taxes....... $ 49 $ 45
====== ======
Operating Statistics:
Natural Gas Processing Volumes (MBbls/d):
Field Plants.......................... 56.0 55.9
Straddle Plants....................... 26.8 36.2
------ ------
Total Natural Gas Processing Volumes..... 82.8 92.1
------ ------
Fractionation Volumes (MBbls/d).......... 175.5 204.6
Natural Gas Liquids Sold (MBbls/d)....... 364.3 609.5
Average Commodity Prices:
Crude Oil--WTI ($/Bbl)................ $34.43 $20.55
Natural Gas Liquids ($/Gal)........... $ 0.62 $ 0.32
Fractionation Spread ($/MMBtu)........ $ 0.38 $ 1.30
Three-Month Periods Ended March 31, 2003 and 2002
NGL reported EBIT of $49 million for the three-month period ended March 31,
2003 compared to $45 million for the same period in 2002. EBIT consists of the
following amounts reported by NGL for the periods presented: operating income
of $51 million and $40 million, respectively; earnings from unconsolidated
investments of $3 million and $4 million, respectively; and other items, net of
$(5) million and $1 million, respectively. Upstream operating income increased
period-over-period primarily as a result of higher natural gas and natural gas
liquids prices, which caused significantly increased processing plant margins.
Total volumes of liquids produced at our field plants were at prior year levels
even though the extremely low fractionation spread led us to reject ethane at
field plants with keep-whole and wellhead purchase contracts. Increased
production in our North Texas area offset the reduced ethane recovery and
allowed our natural gas liquids production to remain at prior year levels. Our
straddle plant volumes were much lower period-to-period because of the low
fractionation spread, which resulted in our decision to by-pass unprofitable
gas or to shut-down plants that are subject to fractionation spread risk.
In our downstream business, volumes available for fractionation declined 14
percent period-to-period as a direct result of the reduced liquids recovery
from both our own and from third-party gas processing plants. Additional
factors adversely affecting the volumes fractionated include the willingness of
our competitors to reduce fractionation fees below levels acceptable to us,
expiration of some long-term fractionation agreements and customer concerns
relating to our liquidity and non-investment grade credit. In our wholesale
marketing operations, profits were higher due to margin increases resulting
from weather-driven propane sales and increases in the volumes sold in our
northeast and southeast regions. Higher liquids prices on our percentage of
netback contracts with our refinery services customers increased margins from
our refinery services business. Natural gas liquids marketing results declined
from prior period levels as a result of reduced overall market liquidity and
customer concerns relating to our liquidity and non-investment grade credit.
Our marketed volumes
32
declined from approximately 610,000 barrels per day to approximately 365,000
barrels per day due to reduced domestic marketing opportunities and the
divestiture of our global liquids business, effective January 1, 2003. The
global liquids business sold an average of 110,000 barrels per day in the first
quarter of 2002.
NGL Outlook
There has been a sharp decline in crude oil prices since March 31, 2003,
while domestic natural gas prices remain strong. This relationship of lower
crude oil and strong natural gas prices will continue to depress fractionation
spreads and lead to reduced liquids production at both our own and third-party
natural gas processing plants that are exposed to wellhead purchase and
keep-whole processing contracts. The result will be a continued reduction in
the natural gas liquids that supply our fractionation, storage and distribution
infrastructure. Industry-wide propane inventories remain at historically low
levels. These factors, reduced natural gas liquids production and low
industry-wide propane inventories should cause propane prices to increase
enough to attract sufficient imports and/or increased domestic liquids
production to meet petrochemical feedstock demand and the required accumulation
of propane inventory for the 2003-2004 winter season. We are beginning to see
increased interest in propane imports at our Galena Park marine facility.
Drilling rig rates for natural gas throughout our core processing areas in
New Mexico, West Texas, North Texas and offshore Louisiana continue to
increase, consistent with natural gas prices in the $4.00-5.00 per MMBtu range.
Despite operational challenges caused by our non-investment grade credit
ratings and a lack of market liquidity, NGL was able to meet its contractual
obligations in its wholesale marketing business during the first quarter 2003.
Despite significant competition, customers generally are choosing to renew
their contracts with us as they reach their current term. While we have not
experienced significant turnover in customer contracts as a result of our
non-investment grade credit ratings, we have been required to provide
collateral or other adequate assurance of our obligations under the renewed
contracts.
33
Regulated Energy Delivery
Three Months Ended
March 31,
------------------
2003 2002
------ ------
(in millions)
Operating Income................................ $ 59 $ 40
Other Items, Net................................ -- 2
------ ------
Earnings Before Interest and Taxes........... $ 59 $ 42
====== ======
Operating Statistics:
Electric Sales in kWh
Residential.................................. 1,433 1,304
Commercial................................... 1,058 1,022
Industrial................................... 1,405 1,376
Transportation of Customer-Owned Electricity. 549 708
Other........................................ 99 93
------ ------
Total Electric Sales..................... 4,544 4,503
====== ======
Gas Sales in Therms
Residential.................................. 185 153
Commercial................................... 72 62
Industrial................................... 23 18
Transportation of Customer-Owned Gas......... 65 72
------ ------
Total Gas Delivered...................... 345 305
====== ======
Heating Degree Days--Actual(1)............... 2,933 2,498
Heating Degree Days--10 Year Rolling Average. 2,587 2,623
- --------
(1) A Heating Degree Day ("HDD") represents the number of degrees that the mean
temperature for a particular day is below 65 degrees Fahrenheit. The HDDs
for a period of time are computed by adding the HDDs for each day during
the period.
Three-Month Periods Ended March 31, 2003 and 2002
EBIT for the REG segment was $59 million for the three-month period ended
March 31, 2003 compared to $42 million for the same period in 2002. EBIT
consists of the following amounts reported by REG for the periods presented:
operating income of $59 million and $40 million, respectively; and other items,
net of zero and $2 million, respectively. Results were positively impacted in
2003 by colder than normal weather throughout REG's service territory, which
caused increases in electric and gas residential and commercial sales volumes,
partially offset by a 5% electric residential rate reduction effective May 1,
2002. Operating expenses were lower in 2003 due to the recovery of an
industrial customer's bankruptcy settlement and continued operating efficiency
gains, partially offset by higher taxes related to higher gas revenues. In
addition, lower regulatory asset amortization in 2003 resulted from the
additional regulatory asset amortization that was recorded in late 2002.
REG Outlook
Future results of operations for the REG segment may be affected, either
positively or negatively, by regulatory actions, general economic conditions,
weather, overall economic growth, the demand for power and natural gas in its
service area, utilization of competitive alternate service providers by its
customers and financing costs. The REG segment's future results also will be
affected by its decision whether to proceed with a sale of its electric
transmission system. Under the pending sale agreement with Trans-Elect, Inc.,
if the transaction does not close on or before July 7, 2003, either party can
terminate the agreement. Because of the lead time required to receive the
necessary regulatory approvals, it is unlikely that the transaction could be
closed by July 7th. We continue to evaluate our options in the event the sale
to Trans-Elect is not concluded. Please read "Liquidity and
34
Capital Resources--Illinois Power Liquidity" for discussion of Illinois Power's
significant leverage and its liquidity plans.
Customer Risk Management
Three Months Ended
March 31,
-----------------
2003 2002
---- ----
(in millions)
Operating Income (Loss).................. $38 $(60)
Earnings from Unconsolidated Investments. 11 3
Other Items, Net......................... 26 (18)
--- ----
Earnings (Loss) Before Interest and Taxes $75 $(75)
=== ====
Three-Month Periods ended March 31, 2003 and 2002
CRM reported EBIT of $75 million for the three-month period ended March 31,
2003 compared to $(75) million for the same period in 2002. EBIT consists of
the following amounts reported by CRM for the periods presented: operating
income (loss) of $38 million and $(60) million respectively; earnings from
unconsolidated investments of $11 million and $3 million, respectively; and
other items, net, representing earnings of $26 million and losses of $18
million. Results associated with this business benefited primarily from sales
of natural gas in storage which had previously been recorded at fair value (see
Note 1 to the unaudited condensed consolidated financial statements for
additional details), gains in value of our remaining marketing and trading
portfolio and equity earnings from our Nicor Energy joint venture. The increase
in other items, net was primarily associated with an increase in minority
interest income.
The results of operations for the three-month period ended March 31, 2003
reflect the wind-down of the third-party marketing and trade business. During
the three-month period ended March 31, 2002, the CRM segment was actively
managed as part of our ongoing strategy and its results included, in part,
settlement with third parties of physical power and other trading positions
purchased from our GEN segment at an internally determined transfer price.
Please see Note 11 to the accompanying unaudited condensed consolidated
financial statements for further discussion.
CRM Outlook
Our CRM business' future results of operations will be significantly
impacted by our ability to execute our exit strategy. We are actively pursuing
opportunities to assign or renegotiate the terms of many of our contractual
obligations related to this business, particularly some of our power tolling
arrangements. In April 2003, we reached an agreement in principle with Southern
to terminate three power tolling arrangements among Dynegy, Southern and our
respective affiliates covering an aggregate of 1,100 MW. Under the terms of the
agreement, which is subject to definitive documentation, we will pay Southern
$155 million to terminate two of these arrangements effective May 30, 2003 and
the third such arrangement effective October 31, 2003. The termination will
result in $96 million of collateral being returned to us and will eliminate our
obligation to make $1.7 billion in payments to Southern over the next 30 years.
We anticipate we will close the transaction in May 2003.
The Southern contracts represent three of our eight remaining tolling
arrangements with power plant owners, or approximately one-third of the total
in terms of MW contracted. If we are unsuccessful in our efforts to renegotiate
or terminate the remaining five power tolling arrangements to which we remain a
party, we would be required to pay an aggregate amount of approximately $2
billion in capacity payments under the related agreements through 2014. After
applying a LIBOR-based discount rate, the total of these capacity payments
approximate $1.7 billion. Our net capacity payments for the remainder of 2003
are $157 million. Even if we are
35
successful in our efforts to renegotiate or terminate some of these
arrangements, we could incur significant expenses relating to any such
renegotiation or termination.
In addition, we have posted collateral to support a substantial portion of
our obligations in this business, including $121 million at May 12, 2003 posted
in connection with our power tolling arrangements. Of the $121 million, $96
million relates to postings with Southern that we expect will be released as
discussed above. While we have been working with various counterparties to
provide mutually acceptable collateral or other adequate assurance under these
contracts, we have not reached agreement with Sithe Independence and
Sterlington/Quachita Power LLC regarding a mutually acceptable amount of
collateral. Although we are current on all contract payments to these
counterparties, we have received a notice of default from each such
counterparty with regard to collateral. We are continuing to negotiate with
both parties. Our annual net payments under these two arrangements approximate
$67 million and $57 million, respectively, and the contracts extend through
2014 and 2012, respectively. If these counterparties were successful in pursuit
of claims that we defaulted on these contracts, they could declare a
termination of these contracts, which would provide for termination payments
based on the mark-to-market value of the contracts.
We generally have been successful in satisfying customer collateral
requirements and have had few terminations or disputes relating to contracts in
this segment. However, we are involved in litigation with some of our former
counterparties relating to contract terminations with respect to which we were
unable to agree on mutually acceptable collateral or other adequate assurance.
There is a risk that we may be unable to agree with other counterparties on
mutually acceptable forms and amounts of adequate assurance or other
collateral, resulting in additional litigation and related expenses. Our
ability to address these and other issues relating to collateral posted for
ongoing CRM contracts could affect this business' future results of operations.
We intend to manage actively our exit from the CRM business with the
objective of maximizing the ultimate cash proceeds received and completing our
exit plan in a timely and cost-effective manner. However, our failure to manage
this exit successfully would negatively impact the CRM segment's results of
operations.
Cash Flow Disclosures
The following table includes data from the operating section of the
unaudited condensed consolidated statements of cash flows and includes cash
flows from our discontinued operations, which are disclosed on a net basis in
loss on discontinued operations, net of tax, in the unaudited condensed
consolidated statements of operations (in millions):
For the Three Months Ended March 31, 2003
------------------------------------------------
Other &
GEN NGL REG CRM Eliminations Consolidated
---- ---- ---- ---- ------------ ------------
Operating Cash Flows Before Changes in
Working Capital....................... $ 97 $ 81 $ 71 $140 $(124) $265
Changes in Working Capital.............. (31) (39) (33) 139 106 142
---- ---- ---- ---- ----- ----
Net Cash Provided by (Used in) Operating
Activities............................ $ 66 $ 42 $ 38 $279 $ (18) $407
---- ---- ---- ---- ----- ----
Operating Cash Flow. Cash flow from operating activities totaled $407
million for the three-month period ended March 31, 2003 compared to $253
million reported in the same 2002 period. Non-cash add-backs to net income were
greater in the 2002 period, primarily due to a $234 million impairment of
goodwill for the communications business related to the adoption of SFAS No.
142 as previously disclosed in the first quarter 2002. Additional changes in
non-cash items from the 2002 to 2003 period included the following:
. Earnings from unconsolidated investments, net of cash distributions,
decreased by approximately $85 million. The decrease results from higher
earnings in 2003 versus 2002, as described above, which results in a
deduction from operating cash flows.
36
. Deferred income taxes are a $45 million provision position for the three
months ended March 31, 2003, compared to a benefit of $24 million in the
same 2002 period, producing a $69 million increased add-back; and
. Risk management activities produced a $71 million add-back, compared to
an add-back of $212 million in the 2002 period. Add-backs in both periods
primarily represent net cash realized for settled contracts in excess of
mark-to-market gains and losses recognized currently in income.
Changes in working capital had a positive impact on cash flow from
operations for the three-month period ended March 31, 2003. Increased
receivable accruals, largely driven by price and volume increases in the GEN
segment from period to period, and an increase in prepayments in the NGL
segment contributed to working capital uses for the quarter ended March 31,
2003. These uses were offset by the receipt of a $110 million tax refund in
March 2003 and receivable settlements in our CRM segment due to the continued
winding down of this business.
Capital Expenditures and Investing Activities. Cash used in investing
activities during the three-month period ended March 31, 2003 totaled $77
million. Capital spending of $84 million was primarily comprised of
$32 million, $37 million and $12 million in the REG, GEN and NGL segments,
respectively, primarily representing improvements to the existing asset base.
The capital spending amount above for the GEN segment includes approximately
$17 million spent on the construction of the Rolling Hills generating facility,
with respect to which commercial operation is expected to begin in June 2003.
Proceeds from assets sales include $20 million in proceeds from the sale of
SouthStar, offset by $13 million in cash outflows associated with the sale of
our European communications business.
Funds used in investing activities in the first quarter of 2002 totaled $412
million. Capital expenditures of $395 million primarily relate to the
construction and improvement of power generation assets and investments
associated with technology infrastructure. The business acquisitions cash
outflows of $20 million relate to the acquisition of Northern Natural, net of
cash acquired.
Financing Activities. Cash provided by financing activities during the
three-month period ended March 31, 2003 totaled $694 million. During the three
months ended March 31, 2003, we borrowed $712 million, net, under our revolving
credit facilities primarily for the purpose of posting cash collateral to
replace expiring letters of credit in advance of the restructuring of our
credit facility. Long-term debt proceeds, net of issuance costs, for the three
months ended March 31, 2003 consisted of $142 million from the delayed issuance
of $150 million in Illinois Power 11.5% Mortgage Bonds due 2010. Repayments of
long-term debt totaled $158 million for the three months ended March 31, 2003.
Please read "--Liquidity and Capital Resources--Liquidity Uses" for further
discussion.
Net cash provided by financing activities was $409 million during the first
quarter 2002. We received $205 million in cash proceeds related to
ChevronTexaco's January 2002 purchase of approximately 10.4 million shares of
Class B common stock. Capital stock proceeds also include $21 million of cash
inflows associated with cash received from senior management associated with a
December 2001 private placement of equity. In March 2002, dividends of $21
million were paid to the holders of Class A common stock and $7 million was
paid to the holder of Class B common stock. Also in March 2002, Illinova
consummated a tender offer pursuant to which it paid $28 million in cash for
approximately 73% of the then-outstanding shares of Illinois Power's preferred
stock. Net long-term debt proceeds consisted primarily of the February 2002
issuance by DHI of 8.75 percent senior notes due February 2012 and proceeds
from borrowings entered into by ABG Gas Supply. Repayments of long-term
borrowings consisted of $22 million in transitional funding notes relating to
IP and $11 million relating to the gas supply agreement with ABG Gas Supply.
Finally, we repaid commercial paper and borrowings under revolving credit lines
for DHI and Illinois Power of $293 million.
37
RISK MANAGEMENT DISCLOSURES
The following table provides a reconciliation of the risk-management data on
the unaudited condensed consolidated balance sheets, statements of operations
and statements of cash flows (in millions):
As of and for the
Three Months Ended
March 31, 2003
------------------
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2003.......................................... $ 363
Risk-management losses recognized through the income statement in the period, net... 1
Cash received related to contracts settled in the period, net (1)................... (84)
Changes in fair value as a result of a change in valuation technique (2)............ --
Non-cash adjustments and other (3).................................................. (122)
-----
Fair value of portfolio at March 31, 2003........................................... $ 158
-----
Income Statement Reconciliation
Risk-management gains recognized through the income statement in the period, net (1) $ 1
Physical business recognized through the income statement in the period, net........ 244
Non-cash adjustments and other (4).................................................. 4
-----
Net recognized operating income (5)................................................. $ 249
-----
Cash Flow Statement
Cash received related to risk-management contracts settled in the period, net (1)... $ 84
Estimated cash received related to physical business settled in the period, net..... 244
Timing and other, net (6)........................................................... (8)
-----
Cash received during the period..................................................... $ 320
-----
Risk Management cash flow adjustment for the three-month period ended
March 31, 2003 (7)................................................................ $ 71
-----
- --------
(1) This amount includes cash settlements of hedging instruments, emission
allowances and other non-trading amounts in addition to the cash settlement
of trading contracts.
(2) Our modeling methodology has been consistently applied period over period.
(3) This amount primarily consists of approximately $97 million of
risk-management assets that were removed from the risk-management accounts
at January 1, 2003 in conjunction with the adoption of certain provisions
of EITF Issue 02-03. This amount also includes changes in value and cash
settlements associated with foreign currency and interest rate hedges.
(4) This amount consists primarily of changes in value of interest rate hedges.
(5) This amount consists primarily of GEN and CRM operating income before the
deduction of Depreciation and Amortization and General and Administrative
Expenses.
(6) This amount represents cash received for the settlement of fuel hedges and
cash payments associated with interest rate hedges.
(7) This amount is calculated as "Cash received during the period" less "Net
recognized operating income."
38
Risk-Management Asset and Liability Disclosures. The following tables
depict the mark-to-market value and cash flow components of our net
risk-management assets and liabilities at March 31, 2003 and December 31, 2002:
Mark-to-Market Value of Net Risk-Management Asset (1)
Total 2003(2) 2004 2005 2006 2007 Thereafter
----- ------- ---- ---- ---- ---- ----------
(in millions)
March 31, 2003..... $ 192 $ 32 $46 $ 42 $39 $(15) $48
December 31, 2002.. 363 250 24 52 27 (24) 34
----- ----- --- ---- --- ---- ---
Increase (Decrease) $(171) $(218) $22 $(10) $12 $ 9 $14
===== ===== === ==== === ==== ===
- --------
(1) The table reflects the fair value of our risk-management asset position
after deduction of time value, credit, price and other reserves necessary
to determine fair value. These amounts exclude the fair value associated
with certain derivative instruments designated as hedges. The net
risk-management assets at March 31, 2003 of $158 million on the unaudited
condensed consolidated balance sheets include the $192 million herein as
well as hedging instruments.
(2) Amounts represent April 1 to December 31, 2003 values in the March 31, 2003
row and January 1 to December 31, 2003 values in the December 31, 2002 row.
The decreases in the Net Risk-Management Asset and Liabilities were impacted
most significantly by the adoption of EITF Issue 02-03 (which resulted in a
decrease of approximately $97 million) and the settlement of the U.K. marketing
and trading portfolio (which resulted in a decrease of approximately $94
million).
Cash Flow Components of Net Risk-Management Asset
Three Months Nine Months
Ended Ended
March 31, December 31, Total
2003 2003 2003 2004 2005 2006 2007 Thereafter
------------ ------------ ----- ---- ---- ---- ---- ----------
(in millions)
March 31, 2003 (1). $84 $39 $ 123 $66 $ 41 $42 $(21) $ 66 (2)
December 31, 2002.. 259 43 57 36 (15) 599
----- --- ---- --- ---- -----
Increase (Decrease) $(136)(3) $23 $(16) $ 6 $ (6) $(533)(2)
===== === ==== === ==== =====
- --------
(1) The cash flow values for 2003 reflect realized cash flows for the three
months ended March 31, 2003 and anticipated undiscounted cash inflows and
outflows by contract based on tenor of individual contract position for the
remaining periods. These anticipated undiscounted cash flows have not been
adjusted for counterparty credit or other reserves. These amounts exclude
the cash flows associated with certain derivative instruments designated as
hedges.
(2) Significant decrease is primarily the result of the implementation of EITF
Issue 02-03 on January 1, 2003. This required all of our power tolling
arrangements, some of which were previously accounted for on a
mark-to-market basis, to be recorded on an accrual basis. Therefore, the
cash flows associated with the power tolling arrangements have been
excluded from the amounts reported as of March 31, 2003.
(3) This amount includes approximately $97 million of risk-management assets
that were removed from the risk-management accounts at January 1, 2003 in
conjunction with the adoption of certain provisions of EITF Issue 02-03.
39
The following table provides an assessment of net contract values by year
based on our valuation methodology.
Net Fair Value of Risk-Management Portfolio
Total 2003 2004 2005 2006 2007 Thereafter
----- ---- ---- ---- ---- ---- ----------
(in millions)
Market Quotations (1)....................... $ 41 $32 $46 $(13) $(19) $(19) $14
Other External Sources (2).................. 109 -- -- 52 57 -- --
---- --- --- ---- ---- ---- ---
Market Quotations and Other External Sources 150 32 46 39 38 (19) 14
Prices Based on Models (3).................. 42 -- -- 3 1 4 34
---- --- --- ---- ---- ---- ---
Total....................................... $192 $32 $46 $ 42 $ 39 $(15) $48
==== === === ==== ==== ==== ===
- --------
(1) Prices obtained from actively traded, liquid markets for commodities other
than natural gas positions. All natural gas positions for all periods are
contained in this line based on available market quotations.
(2) Mid-term prices validated against industry posted prices.
(3) See discussion of our use of long-term models in "Critical Accounting
Policies" beginning on page 73 in the Form 10-K.
UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION
This Form 10-Q includes statements reflecting assumptions, expectations,
projections, intentions or beliefs about future events that are intended as
"forward-looking statements" under applicable SEC rules and regulations. You
can identify these statements by the fact that they do not relate strictly to
historical or current facts. They use words such as "anticipate," "estimate,"
"project," "forecast," "may," "will," "should," "expect" and other words of
similar meaning. In particular, these include, but are not limited to,
statements relating to the following:
. Projected operating or financial results;
. Expectations regarding capital expenditures and other payments;
. Our beliefs and assumptions relating to our liquidity position, including
our ability to satisfy or refinance our obligations as they come due;
. Our ability to compete effectively for market share with industry
participants;
. Illinois Power's ability to consummate one or more liquidity initiatives,
including any sale of its electric transmission system;
. Beliefs about the outcome of legal and administrative proceedings,
including matters involving the western power and natural gas markets,
shareholder claims and environmental matters as well as the
investigations primarily relating to Project Alpha and our past trading
practices; and
. Our ability to complete our exit from third-party risk-management aspects
of the marketing and trading business and costs associated with this exit.
Any or all of our forward-looking statements may turn out to be wrong. They
can be affected by inaccurate assumptions or by known or unknown risks and
uncertainties, including the following:
. The timing and extent of changes in commodity prices for energy,
particularly power, natural gas and the spark spread between power and
natural gas prices;
. The effects of competition in our asset-based business lines;
40
. The condition of the capital markets generally, which will be affected by
interest rates, foreign currency fluctuations and general economic
conditions, and our financial condition, including our ability to satisfy
our significant debt maturities;
. Developments in the western power and natural gas markets, including, but
not limited to, governmental intervention, deterioration in the financial
condition of our counterparties, default on receivables due and adverse
results in current or future investigations or litigation;
. The effectiveness of our risk-management policies and procedures and the
ability of our counterparties to satisfy their financial commitments;
. The liquidity and competitiveness of wholesale markets for energy
commodities, particularly natural gas, electricity and NGLs;
. Operational factors affecting the start up or ongoing commercial
operations of our power generation, natural gas, natural gas liquids or
regulated energy delivery facilities, including catastrophic weather-
related damage, regulatory approvals, permit issues, unscheduled outages
or repairs, unanticipated changes in fuel costs or availability of fuel
emission credits, the unavailability of gas transportation, the
unavailability of electric transmission service or workforce issues;
. Increased interest expense and the other effects of our restructured
credit facilities, including the security arrangements and restrictive
covenants contained therein;
. Counterparties' collateral demands and other factors affecting our
liquidity position and financial condition;
. Our ability to generate sustainable earnings and cash flow from our
assets and businesses;
. Our ability to address the $1.5 billion in Series B preferred stock held
by ChevronTexaco;
. The direct or indirect effects on our business of any changes in our
credit ratings (or actions we may take in response to changing credit
ratings criteria), including refusal by counterparties to enter into
transactions with us and our inability to obtain credit or capital in
amounts or on terms that are considered favorable;
. Cost and other effects of legal and administrative proceedings,
settlements, investigations and claims, including legal proceedings
related to the western power and natural gas markets, shareholder claims,
claims arising out of the CRM business and environmental liabilities that
may not be covered by indemnity or insurance, as well as the FERC, U.S.
Attorney and other similar investigations primarily surrounding Project
Alpha and our past trading practices;
. Other North American regulatory or legislative developments that affect
the regulation of the electric utility industry, the demand and pricing
for energy generally, increase the environmental compliance cost for our
facilities or impose liabilities on the owners of such facilities; and
. General political conditions and developments in the United States and in
foreign countries whose affairs affect our lines of business,
particularly commodity prices, including any extended period of war or
conflict.
Many of these factors will be important in determining our actual future
results. Consequently, no forward-looking statement can be guaranteed. Our
actual future results may vary materially from those expressed or implied in
any forward-looking statements.
All of our forward-looking statements, whether written or oral, are
expressly qualified by these cautionary statements and any other cautionary
statements that may accompany such forward-looking statements. In addition, we
disclaim any obligation to update any forward-looking statements to reflect
events or circumstances after the date of this quarterly report.
41
RECENT ACCOUNTING PRONOUNCEMENTS
See Note 1 to the unaudited condensed consolidated financial statements for
a discussion of recently issued accounting pronouncements affecting us.
Specifically, we adopted the net presentation provisions of EITF Issue 02-03 in
the third quarter 2002, and we adopted the provision within EITF Issue 02-03
that rescinds EITF Issue No. 98-10 effective January 1, 2003. We also adopted
SFAS No. 143 effective January 1, 2003.
CRITICAL ACCOUNTING POLICIES
Please read "Critical Accounting Policies" beginning on page 73 of the Form
10-K for a complete description of our critical accounting policies, with
respect to which there have been no material changes since the filing of the
Form 10-K.
Item 3--QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Value at Risk ("VaR"). The following table sets forth the aggregate daily
VaR of the mark-to-market portion of Dynegy's risk-management portfolio
primarily associated with the WEN and CRM segments.
Daily and Average VaR for Risk-Management Portfolio
March 31, December 31,
2003 2002
--------- ------------
(in millions)
One Day VaR--95% Confidence Level................................ $ 8 $ 8
--- ----
One Day VaR--99% Confidence Level................................ $11 $ 11
--- ----
Average VaR for the Year-to-Date Period--95% Confidence Level (1) $ 8 N/A
--- ----
- --------
(1) Average VaR is not available for 2002 due to the restatement of historical
results.
Credit Risk. The following table represents our credit exposure at March
31, 2003 associated with the mark-to-market portion of our risk-management
portfolio, as well as power tolling arrangements, netted by counterparty (in
millions):
Credit Exposure Summary
Investment Non-Investment
Grade Quality Grade Quality Total
------------- -------------- ------
Type of Business:
Financial Institutions......... $154 $ -- $ 154
Commercial/Industrial/End Users 143 120 263
Utility and Power Generators... 388 250 638
Oil and Gas Producers.......... 61 12 73
Other.......................... 9 -- 9
---- ---- ------
Total....................... $755 $382 $1,137
==== ==== ======
42
Interest Rate Risk. The following table sets forth the daily and average
VaR associated with the interest rate component of the risk-management
portfolio. We seek to manage our interest rate exposure through application of
various hedging strategies. Hedging instruments executed to mitigate such
interest rate exposure in the risk-management portfolio are included in the VaR
as of March 31, 2003 and December 31, 2002 and are reflected in the table below.
Daily and Average VaR on Interest Component of Risk-Management Portfolio
March 31, December 31,
2003 2002
--------- ------------
(in millions)
One Day VaR--95% Confidence Level................................ $1.2 $2.5
---- ----
Average VaR for the Year-to-Date Period--95% Confidence Level (1) $2.3 N/A
---- ----
- --------
(1) Average VaR is not available for 2002 due to the restatement of historical
results.
The decrease in One Day VaR is due to the wind down of the CRM business.
In addition to the risk-management portfolio, the Company is exposed to
fluctuating interest rates as it relates to other variable rate financial
obligations. Based on sensitivity analysis as of March 31, 2003, it is
estimated that a one percentage point interest rate movement in the average
market interest rates (either higher or (lower)) over the twelve months ended
March 31, 2004 would (decrease) increase income before taxes by approximately
$23 million. Hedging instruments executed to mitigate such interest rate
exposure are included in the sensitivity analysis.
Foreign Currency Exchange Rate Risk. The following table sets forth the
daily and average foreign currency exchange VaR. Hedging instruments executed
to mitigate such foreign currency exchange exposure are included in the VaR as
of March 31, 2003 and December 31, 2002 and are reflected in the table below.
Daily and Average Foreign Currency Exchange VaR
March 31, December 31,
2003 2002
--------- ------------
(in millions)
One Day VaR--95% Confidence Level............................ $0.2 $0.4
---- ----
Average VaR for the Year-to-Date Period--95% Confidence Level $0.3 $2.9
---- ----
The decrease in One Day and Average VaR is due to the significant reduction
in foreign activities in first quarter 2003.
Derivative Contracts. The absolute notional financial contract amounts
associated with our commodity risk-management, interest rate and foreign
currency exchange contracts were as follows at March 31, 2003 and December 31,
2002, respectively:
43
Absolute Notional Contract Amounts
March 31, December 31,
2003 2002
--------- ------------
Natural Gas (Trillion Cubic Feet)................................... 4.944 7.910
Electricity (Million Megawatt Hours)................................ 21.867 64.563
Natural Gas Liquids (Million Barrels)............................... 0.180 0.265
Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars).. $ 306 $ 601
Fixed Interest Rate Received on Swaps (Percent).................. 5.265 5.616
Cash Flow Hedge Interest Rate Swaps (in Millions of U.S. Dollars)... $ 905 $ 1,566
Fixed Interest Rate Paid on Swaps (Percent)...................... 3.081 2.824
Interest Rate Risk-Management Contract (In Millions of U.S. Dollars) $ 558 $ 1,001
Fixed Interest Rate Paid (Percent)............................... 5.951 5.530
U.K. Pound Sterling (In Millions of U.S. Dollars)................... $ 104 $ 198
Average U.K. Pound Sterling Contract Rate (In U.S. Dollars)......... $1.6029 $ 1.574
Euro Dollars (In Millions of U.S. Dollars).......................... $ 6 $ 5
Average Euro Contract Rate (In U.S. Dollars)........................ $1.2989 $ 1.212
Canadian Dollar (In Millions of U.S. Dollars)....................... $ 54 $ 523
Average Canadian Dollar Contract Rate (In U.S. Dollars)............. $0.6757 $0.7140
Item 4--CONTROLS AND PROCEDURES
Within the 90-day period immediately preceding the filing of this report, an
evaluation was carried out under the supervision and with the participation of
our management, including our Chief Executive Officer and our Chief Financial
Officer, of the effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the
Exchange Act). This evaluation included consideration of our establishment of a
disclosure committee and the various processes that were carried out under the
direction of this committee in an effort to ensure that information required to
be disclosed in our SEC reports is recorded, processed, summarized and reported
within the time periods specified by the SEC. This evaluation also included
consideration of our internal controls and procedures for the preparation of
our consolidated financial statements. While we have identified internal
control weaknesses, which are discussed below, our evaluation indicated that
these weaknesses did not impair the effectiveness of our overall disclosure
controls and procedures.
Reference is made to "Item 14. Controls and Procedures" beginning on page 87
of the Form 10-K. In that section, we indicated that in evaluating our internal
controls in connection with the preparation of the Form 10-K we identified two
reportable conditions that were considered to be "material weaknesses" under
applicable accounting standards. The first such condition related to the fact
that inappropriate persons within our organization had access to record or
revise entries in our accounting software system. The second such condition
related to the process whereby accrued estimates of volumes bought, sold,
transported and stored in our natural gas marketing business were reconciled to
the actual volumes. We also identified the measures we had taken toward
remedying these conditions, as well as other initiatives being implemented with
respect to our system of internal controls generally.
During our most recent evaluation undertaken in connection with the
preparation of this quarterly report, we did not discover any additional
reportable conditions with respect to our internal controls. Regarding the
previous identified access condition, we are continuing to develop a technical
solution to ensure that such access is limited to appropriate personnel, and we
expect to begin the implementation of this solution in the second quarter 2003.
In the interim, in addition to the strengthening of our monitoring policy as
described in the Form 10-K, we have modified the security settings where
appropriate in an effort to ensure that unauthorized individuals are prohibited
from recording or revising entries.
44
DYNEGY INC.
PART II. OTHER INFORMATION
Item 1--LEGAL PROCEEDINGS
See Note 9 to the accompanying unaudited condensed consolidated financial
statements for discussion of material developments in our material legal
proceedings since the filing of our Form 10-K.
Item 6--EXHIBITS AND REPORTS ON FORM 8-K
(a) The following documents are included as exhibits to this Form 10-Q:
*99.1 Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
*99.2 Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
- --------
* Pursuant to Securities and Exchange Commission Release No. 33-8212, this
certification will be treated as "accompanying" this report and not "filed"
as part of such report for purposes of Section 18 of the Securities Exchange
Act of 1934, as amended, or the Exchange Act, or otherwise subject to the
liability of Section 18 of the Exchange Act and this certification will not
be deemed to be incorporated by reference into any filing under the
Securities Act of 1933, as amended, or the Exchange Act.
(b) Reports on Form 8-K of Dynegy Inc. filed during the first quarter 2003:
1. We filed a Current Report on Form 8-K on January 8, 2003. Items 7 and
9 were reported and no financial statements were filed.
2. We filed a Current Report on Form 8-K on January 22, 2003. Items 5
and 7 were reported and no financial statements were filed.
3. We filed a Current Report on Form 8-K on January 31, 2003. Items 7
and 9 were reported and no financial statements were filed.
45
DYNEGY INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
DYNEGY INC.
Date: May 15, 2003 /s/ NICK J. CARUSO
By: ----------------------------------
Nick J. Caruso
Executive Vice President and Chief
Financial Officer
(Duly Authorized Officer and
Principal Financial Officer)
46
SECTION 302 CERTIFICATION
I, Bruce A. Williamson, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Dynegy Inc.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent functions):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions
with regard to significant deficiencies and material weaknesses.
Date: May 15, 2003 By: /s/ BRUCE A. WILLIAMSON
----------------------------------
Bruce A. Williamson
Chief Executive Officer
47
SECTION 302 CERTIFICATION
I, Nick J. Caruso, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Dynegy Inc.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
(c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent functions):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions
with regard to significant deficiencies and material weaknesses.
Date: May 15, 2003 By: /s/ NICK J. CARUSO
----------------------------------
Nick J. Caruso
Executive Vice President and
Chief Financial Officer
48