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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(MARK ONE)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
OR
[ ] 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 1-16455
RELIANT RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)
Delaware 76-0655566
(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.)
1111 Louisiana
Houston, Texas 77002
(Address of Principal Executive Offices) (Zip Code)
(713) 497-3000
(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 [ ]
As of November 8, 2002, Reliant Resources, Inc. (Reliant Resources) had
290,441,403 shares of common stock outstanding excluding 9,362,597 shares held
as treasury stock.
RELIANT RESOURCES, INC.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2002
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Statements of Consolidated Income (unaudited)
Three and Nine Months Ended September 30, 2001 (as restated) and 2002.......................1
Consolidated Balance Sheets (unaudited)
December 31, 2001 and September 30, 2002....................................................2
Statements of Consolidated Cash Flows (unaudited)
Nine Months Ended September 30, 2001 and 2002...............................................4
Notes to Unaudited Consolidated Financial Statements........................................5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations......47
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................73
Item 4. Controls and Procedures....................................................................75
PART II. OTHER INFORMATION
Item 1. Legal Proceedings..........................................................................76
Item 5. Other Information..........................................................................76
Item 6. Exhibits and Reports on Form 8-K...........................................................77
i
PART I. FINANCIAL INFORMATION
RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------------- --------------------------------
2001 2002 2001 2002
------------- ----------- ------------- -----------
(AS RESTATED) (AS RESTATED)
Revenues ........................................... $ 2,399,819 $ 5,236,855 $ 5,355,007 $ 9,220,825
Trading margins (See Note 3) ....................... 61,869 118,375 311,478 291,031
----------- ----------- ----------- -----------
Total ............................................ 2,461,688 5,355,230 5,666,485 9,511,856
----------- ----------- ----------- -----------
EXPENSES:
Fuel and cost of gas sold ........................ 476,532 495,711 1,744,606 1,083,043
Purchased power .................................. 1,308,183 3,863,918 2,190,671 6,062,458
Accrual for payment to CenterPoint Energy, Inc. .. -- 89,000 -- 89,000
Operation and maintenance ........................ 138,922 259,139 385,610 673,622
General, administrative and development .......... 114,099 223,869 406,846 503,805
Depreciation ..................................... 36,094 134,962 96,675 303,865
Amortization ..................................... 35,774 6,561 82,669 14,962
----------- ----------- ----------- -----------
Total ........................................ 2,109,604 5,073,160 4,907,077 8,730,755
----------- ----------- ----------- -----------
OPERATING INCOME ................................... 352,084 282,070 759,408 781,101
----------- ----------- ----------- -----------
OTHER INCOME (EXPENSE):
Gain (loss) from investments, net ................ 3,700 (2,338) 15,015 2,493
Income from equity investments in unconsolidated
subsidiaries ................................... 2,132 955 66,482 10,263
Other, net ....................................... 250 10,487 7,152 14,081
Interest expense ................................. (8,355) (103,130) (52,220) (208,974)
Interest income .................................. 3,010 11,183 18,360 19,493
Interest income - affiliated companies, net ...... 11,319 570 7,888 4,754
----------- ----------- ----------- -----------
Total other income (expense) ................... 12,056 (82,273) 62,677 (157,890)
----------- ----------- ----------- -----------
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF
ACCOUNTING CHANGE ................................ 364,140 199,797 822,085 623,211
INCOME TAX EXPENSE ................................. 150,279 142,063 300,976 290,146
----------- ----------- ----------- -----------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 213,861 57,734 521,109 333,065
Cumulative effect of accounting change, net of tax -- -- 3,062 (233,600)
----------- ----------- ----------- -----------
NET INCOME ......................................... $ 213,861 $ 57,734 $ 524,171 $ 99,465
=========== =========== =========== ===========
BASIC EARNINGS PER SHARE:
Income before cumulative effect of accounting
change ......................................... $ 0.71 $ 0.20 $ 1.92 $ 1.15
Cumulative effect of accounting change, net of tax -- -- 0.01 (0.81)
----------- ----------- ----------- -----------
Net Income .................................. $ 0.71 $ 0.20 $ 1.93 $ 0.34
=========== =========== =========== ===========
DILUTED EARNINGS PER SHARE:
Income before cumulative effect of accounting
change ......................................... $ 0.71 $ 0.20 $ 1.91 $ 1.14
Cumulative effect of accounting change, net of tax -- -- 0.01 (0.80)
----------- ----------- ----------- -----------
Net Income .................................. $ 0.71 $ 0.20 $ 1.92 $ 0.34
=========== =========== =========== ===========
See Notes to the Company's Interim Financial Statements
1
RELIANT RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
ASSETS
DECEMBER 31, SEPTEMBER 30,
2001 2002
------------ -------------
CURRENT ASSETS:
Cash and cash equivalents .............................................. $ 118,453 $ 1,443,605
Restricted cash ....................................................... 167,421 447,087
Accounts and notes receivable, principally customer, net ............... 1,167,870 1,270,346
Accrued unbilled revenues ............................................. 14,270 418,585
Note receivable related to receivable facility ......................... -- 253,928
Accounts and notes receivable - affiliated companies, net .............. 415,081 --
Fuel stock and petroleum products ...................................... 109,036 218,782
Materials and supplies ................................................. 64,999 117,787
Stranded costs settlement receivable .................................. 201,503 --
Trading and marketing assets ........................................... 1,611,393 1,376,817
Non-trading derivative assets .......................................... 392,900 370,464
Margin deposits on energy trading and hedging activities ............... 213,727 284,086
Collateral for electric generating equipment ........................... 141,701 --
Prepayments and other current assets ................................... 126,936 179,851
------------ ------------
Total current assets ................................................. 4,745,290 6,381,338
------------ ------------
Property, plant and equipment ............................................ 4,834,122 9,494,171
Less accumulated depreciation ............................................ (275,729) (525,810)
------------ ------------
Property, plant and equipment, net ................................... 4,558,393 8,968,361
------------ ------------
OTHER ASSETS:
Goodwill, net .......................................................... 891,061 2,157,244
Air emissions regulatory allowances and other intangibles, net ......... 315,438 402,704
Notes receivable - affiliated companies, net ........................... 30,278 --
Trading and marketing assets ........................................... 446,610 551,308
Non-trading derivative assets .......................................... 254,168 271,375
Equity investments in unconsolidated subsidiaries ...................... 386,841 288,297
Stranded costs indemnification receivable .............................. 203,693 225,931
Accumulated deferred income taxes ...................................... 46,322 --
Prepaid lease .......................................................... 121,699 214,809
Restricted funds for stranded costs .................................... -- 1,514
Collateral for electric generating equipment ........................... 88,268 --
Other .................................................................. 203,645 216,541
------------ ------------
Total other assets ................................................... 2,988,023 4,329,723
------------ ------------
TOTAL ASSETS ....................................................... $ 12,291,706 $ 19,679,422
============ ============
See Notes to the Company's Interim Financial Statements
2
RELIANT RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (CONTINUED)
(THOUSANDS OF DOLLARS)
(UNAUDITED)
LIABILITIES AND STOCKHOLDERS' EQUITY
DECEMBER 31, SEPTEMBER 30,
2001 2002
------------ -------------
CURRENT LIABILITIES:
Current portion of long-term debt ........................................... $ 23,769 $ 31,768
Short-term borrowings ....................................................... 296,769 5,284,717
Accounts payable, principally trade ......................................... 1,002,326 1,315,417
Trading and marketing liabilities ........................................... 1,478,336 1,265,655
Non-trading derivative liabilities .......................................... 399,277 376,801
Accumulated deferred income taxes ........................................... 37,034 115,891
Margin deposits from customers on energy trading and hedging activities ..... 144,700 66,602
Other ....................................................................... 253,800 468,577
------------ ------------
Total current liabilities ............................................. 3,636,011 8,925,428
------------ ------------
OTHER LIABILITIES:
Accumulated deferred income taxes ........................................... -- 344,553
Trading and marketing liabilities ........................................... 361,786 437,966
Non-trading derivative liabilities .......................................... 639,211 433,274
Major maintenance reserve ................................................... 16,784 20,882
Accrual for payment to CenterPoint Energy, Inc. ............................. -- 89,000
Non-derivative stranded costs liability ..................................... 203,693 225,931
Benefit obligations ......................................................... 127,012 148,748
Other ....................................................................... 455,865 386,904
------------ ------------
Total other liabilities ............................................... 1,804,351 2,087,258
------------ ------------
LONG-TERM DEBT ................................................................ 867,712 2,425,140
------------ ------------
COMMITMENTS AND CONTINGENCIES (NOTE 12)
STOCKHOLDERS' EQUITY:
Preferred stock (125,000,000 shares authorized; none outstanding) ........... -- --
Common stock (2,000,000,000 shares authorized; 299,804,000 issued and
outstanding, respectively) ................................................ 61 61
Additional paid-in capital .................................................. 5,777,169 5,797,057
Treasury stock at cost, 11,000,000 shares and 9,364,221 shares .............. (189,460) (161,333)
Retained earnings ........................................................... 557,451 656,916
Accumulated other comprehensive loss ........................................ (161,589) (51,105)
------------ ------------
Stockholders' equity .................................................. 5,983,632 6,241,596
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ........................... $ 12,291,706 $ 19,679,422
============ ============
See Notes to the Company's Interim Financial Statements
3
RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2001 2002
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ......................................................................... $ 524,171 $ 99,465
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation and amortization .................................................... 179,344 318,826
Deferred income taxes ............................................................ (8,071) 299,982
Net trading and marketing assets and liabilities ................................. (43,122) (13,994)
Net non-trading derivative assets and liabilities ................................ (1,759) (52,886)
Amortization of contractual rights and obligations ............................... -- (50,128)
Curtailment and related benefit enhancement ...................................... 99,523 --
Accounting settlement for certain benefit plans .................................. -- 47,356
Accrual for payment to CenterPoint Energy, Inc. .................................. -- 89,000
Undistributed earnings of unconsolidated subsidiaries ............................ (31,884) (7,612)
Gain on settlement of stranded costs contracts ................................... -- (109,000)
Cumulative effect of accounting change ........................................... (3,062) 233,600
Changes in other assets and liabilities, net of effects of acquisitions:
Restricted cash ................................................................ 50,000 56,650
Accounts and notes receivable and unbilled revenue, net ........................ 332,181 (354,577)
Accounts receivable/payable - affiliated companies, net ........................ 111,472 26,603
Inventory ...................................................................... (52,779) (103,552)
Collateral for electric generating equipment, net .............................. (62,366) 136,013
Margin deposits on energy trading activities, net .............................. 123,995 (147,267)
Net non-trading derivative assets and liabilities .............................. (74,879) (147,204)
Prepaid lease obligation ....................................................... (195,239) (93,309)
Other current assets ........................................................... 56,954 (5,019)
Other assets ................................................................... (31,563) (32,059)
Accounts payable ............................................................... (979,614) 162,385
Taxes accrued .................................................................. 185,073 41,667
Other current liabilities ...................................................... 63,424 21,268
Other liabilities .............................................................. 27,435 (74,999)
Other, net ...................................................................... (7,489) (21,865)
----------- -----------
Net cash provided by operating activities .................................... 261,745 319,344
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ............................................................... (719,577) (474,974)
Business acquisitions, net of cash acquired ........................................ -- (2,963,801)
Distribution from equity investment in unconsolidated subsidiary ................... -- 137,475
Other, net ......................................................................... 10,675 27
----------- -----------
Net cash used in investing activities ........................................ (708,902) (3,301,273)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt ....................................................... -- 22,324
Proceeds from issuance of stock, net ............................................... 1,697,848 --
Purchase of treasury stock ......................................................... (20,420) --
Payments of long-term debt ......................................................... (2,286) (229,785)
Increase in short-term borrowings, net ............................................. 184,779 4,109,925
Change in notes with affiliated companies, net ..................................... (1,234,444) 385,652
Contributions from owner ........................................................... 9,441 --
Other, net ......................................................................... (3) 13,120
----------- -----------
Net cash provided by financing activities .................................... 634,915 4,301,236
----------- -----------
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS ......................... (5,865) 5,845
----------- -----------
NET INCREASE IN CASH AND CASH EQUIVALENTS ............................................ 181,893 1,325,152
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ..................................... 89,755 118,453
----------- -----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ........................................... $ 271,648 $ 1,443,605
=========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest (net of amounts capitalized) .............................................. $ 63,692 $ 198,279
Income taxes ....................................................................... 116,716 6,743
See Notes to the Company's Interim Financial Statements
4
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(1) BACKGROUND AND BASIS OF PRESENTATION
Included in this Quarterly Report on Form 10-Q (Form 10-Q) for Reliant
Resources, Inc. (Reliant Resources), together with its subsidiaries
(collectively, the Company), are the Company's consolidated interim financial
statements and notes (Interim Financial Statements). The Interim Financial
Statements are unaudited, omit certain financial statement disclosures and
should be read with the amended annual report on Form 10-K/A (Amendment No. 2)
of Reliant Resources (Reliant Resources Form 10-K/A) for the year ended December
31, 2001 filed on November 12, 2002, the Quarterly Report on Form 10-Q of
Reliant Resources for the quarter ended March 31, 2002 (First Quarter 10-Q) and
the Quarterly Report on Form 10-Q of Reliant Resources for the quarter ended
June 30, 2002 (Second Quarter 10-Q).
RESTATEMENT
Also as more fully described in Note 1 to the Consolidated Financial
Statements included in the Reliant Resources Form 10-K/A (Reliant Resources
10-K/A Notes), Reliant Resources determined on May 9, 2002 that it had engaged
in same-day commodity trading transactions involving purchases and sales with
the same counterparty for the same volume at substantially the same price. The
personnel who effected these transactions apparently did so with the sole
objective of increasing volumes. Reliant Resources commenced a review to
quantify the amount and assess the impact of these trades (round trip trades).
The Audit Committees (Audit Committees) of each of the Board of Directors of
Reliant Resources and Reliant Energy, Incorporated (Reliant Energy) also
directed an internal investigation by outside legal counsel, with assistance by
outside accountants, of the facts and circumstances relating to the round trip
trades and related matters.
Prior to the third quarter of 2002, the Company reported all trading,
marketing and risk management services transactions on a gross basis with such
transactions being reported in revenues and expenses except primarily for
financial gas transactions such as swaps. Therefore, the round trip trades were
reflected in both the Company's revenues and expenses. The round trip trades
should not have been recognized in revenues or expenses (i.e., they should have
been reflected on a net basis). However, since the round trip trades were done
at the same volume and substantially the same price, they had no impact on the
Company's reported cash flows, operating income or net income.
Based on the Company's review, the Company determined that it engaged
in such round trip trades in 1999, 2000 and 2001. The results of the Audit
Committees' investigation were consistent with the results of the Company's
review. The round trip trades were for 20 million megawatt hours (MWh) of power
and 61 MWh of power for the three and nine months ended September 30, 2001,
respectively, and 46 Billion cubic feet (Bcf) of natural gas for the nine months
ended September 30, 2001.
These round trip trades collectively had the effect of increasing each
of revenues and purchased power expense by $847 million for the three months
ended September 30, 2001 and increasing revenues, fuel and cost of gas sold
expense and purchased power expense by $3.5 billion, $180 million and $3.3
billion, respectively, for the nine months ended September 30, 2001.
In the course of the Company's review, the Company also identified and
determined that it should record on a net basis several transactions for energy
related services (not involving round trip trades) that totaled $13 million and
$30 million for the three and nine months ended September 30, 2001,
respectively. These transactions were originally recorded on a gross basis.
In addition, during the May 2001 through September 2001 time frame, the
Company entered into four structured transactions involving a series of forward
or swap contracts to buy and sell an energy commodity in 2001 and to buy and
sell an energy commodity in 2002 or 2003 (four structured transactions). The
four structured transactions were intended to increase future cash flow and
earnings and to increase certainty associated with future cash flow and
earnings, albeit at the expense of 2001 cash flow and earnings. Each series of
contracts in a structure were executed with the same counterparty. The contracts
in each structure were offsetting in the aggregate in terms of physical
attributes. The transactions that settled during the three and nine months ended
September 30, 2001 were previously recorded on a gross basis with such
transactions being reported in revenues and expenses which resulted
5
in $700 million of revenues, $206 million in fuel and cost of gas sold and $494
million of purchased power expense, and $1.0 billion of revenues, $367 million
in fuel and cost of gas sold and $656 million of purchased power expense being
recognized in each period, respectively. These transactions should have been
accounted for on a net basis.
The consolidated financial statements for the three and nine months
ended September 30, 2001 have been restated from amounts previously reported to
reflect the transactions discussed above on a net basis. The restatement had no
impact on previously reported consolidated cash flows, operating income or net
income. A summary of the principal effects of the restatement are as follows for
the three and nine months ended September 30, 2001: (Note - Those line items for
which no change in amounts are shown were not affected by the restatement.)
THREE MONTHS ENDED SEPTEMBER 30, 2001
-------------------------------------
AS PREVIOUSLY
AS RESTATED REPORTED (1)(2)
-------------- ---------------
(IN MILLIONS)
Total Revenues ......................... $ 2,462 $ 4,070
Expenses:
Fuel and cost of gas sold ............ 476 737
Purchased power ...................... 1,308 2,655
Other expenses ....................... 326 326
------- -------
Total .............................. 2,110 3,718
------- -------
Operating Income ....................... 352 352
Other Income, net ...................... 12 12
Income Tax Expense ..................... (150) (150)
------- -------
Net Income ............................. $ 214 $ 214
======= =======
NINE MONTHS ENDED SEPTEMBER 30, 2001
------------------------------------
AS PREVIOUSLY
AS RESTATED REPORTED (1)(2)
------------ -----------------
(IN MILLIONS)
Total Revenues .................................................. $ 5,666 $ 10,230
Expenses:
Fuel and cost of gas sold ..................................... 1,744 2,313
Purchased power ............................................... 2,190 6,185
Other expenses ................................................ 973 973
------- --------
Total ....................................................... 4,907 9,471
------- --------
Operating Income ................................................ 759 759
Other Income, net ............................................... 63 63
Income Tax Expense .............................................. (301) (301)
------- --------
Income Before Cumulative Effect of Accounting Change ............ 521 521
Cumulative Effect of Accounting Change, net of tax .............. 3 3
------- --------
Net Income ...................................................... $ 524 $ 524
======= ========
- ------------
(1) Beginning with the quarter ended September 30, 2002, the Company now
reports all energy trading and marketing activities on a net basis as
allowed by Emerging Issues Task Force (EITF) Issue No. 98-10,
"Accounting for Contracts involved in Energy Trading and Risk
Management Activities" (EITF No. 98-10). Comparative financial
statements for prior periods have been reclassified to conform to this
presentation. For information regarding the presentation of trading and
marketing activities on a net basis, see Note 3. Revenues, fuel and
cost of gas sold expense and purchased power expense have been
reclassified to conform to this presentation.
(2) In the fourth quarter 2001, the Company changed the classification of
receipts of business interruption insurance claims from other
non-operating income to operating revenues. Receipts of $1 million and
$5 million for the three and nine months ended September 30, 2001,
respectively, have been reclassified to conform to this presentation.
6
The restatement did not impact earnings per share for 2001 or the
Statement of Consolidated Cash Flows for 2001.
In addition to the round trip trades described above, Reliant
Resources' review and the Audit Committees' investigation also considered other
transactions executed on the same day at the same volume, price and delivery
terms and with the same counterparty. These transactions were executed in the
normal course of the Company's trading and marketing activities, and were
historically reported on a gross basis, and were not material.
Also as more fully described in Note 1 to the Reliant Resources 10-K/A
Notes, during the fourth quarter of 2000, two power generation swap contracts
with a fair value of $261 million were terminated and replaced with a
substantially similar contract providing for physical delivery and designated to
hedge electric generation. The termination of the original contracts and
execution of the replacement contract represented a substantive modification to
the original contract. As a result, upon termination of the original contracts,
a contractual liability representing the fair value of the original contracts
and a deferred asset of equal amount should have been recorded. As of January 1,
2001, in connection with the adoption of SFAS No. 133, the deferred asset should
have been recorded as a transition adjustment to other comprehensive loss
totaling $170 million. The liability and transition adjustment should have been
amortized on a straight-line basis over the term of the power generation
contract replacing the terminated power generation contracts (through May 2004).
The Company previously did not give accounting recognition to these
transactions. As a result, the Company restated its Consolidated Balance Sheets
as of December 31, 2000 and 2001 and the Statement of Consolidated Stockholder's
Equity and Comprehensive Income for the year ended December 31, 2001 in the
Reliant Resources Form 10-K/A. The Company has restated its comprehensive income
disclosure for the three and nine months ended September 30, 2001 from amounts
previously reported, to effect this transaction as described above. The
restatement increased comprehensive income by $14 million from a total
comprehensive income of $40 million, as previously reported, to $54 million, as
restated, for the three months ended September 30, 2001 and decreased
comprehensive income by $132 million (including the $170 million transition
adjustment discussed above) from a total comprehensive income of $608 million,
as previously reported, to $476 million, as restated, for the nine months ended
September 30, 2001. The restatement had no impact on the Company's reported
consolidated cash flows, operating income or net income.
Furthermore, in September 2002, during the Company's review of certain
trading transactions in connection with various pending investigations, the
Company identified four natural gas financial swap transactions that should not
have been recorded in the Company's records. The Company has concluded, based on
the offsetting nature of the transactions and manner in which the transactions
were documented, that none of the transactions should have been given accounting
recognition. The Company accounted for the transactions in its financial
statements as a reduction in revenues in December 2000 and an increase in
revenues in January 2001, with the effect of decreasing net income in the fourth
quarter of 2000 and increasing net income in the first quarter of 2001, in each
case by $20.0 million pre-tax ($12.7 million after-tax), and the effect of
increasing basic and diluted earnings per share by $0.05 in the first quarter of
2001. There were no cash flows associated with the transactions. The Company has
further concluded, after considering both qualitative and quantitative factors,
that a restatement of its financial statements for this item is not required.
However, on November 12, 2002, the Company amended its annual report on Form
10-K/A for the year ended December 31, 2001 to disclose this transaction in its
unaudited quarterly information footnote to the consolidated financial
statements (see Note 15 to the Reliant Resources 10-K/A Notes).
BASIS OF PRESENTATION
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
This basis of accounting in the Interim Financial Statements
contemplates the recovery of the Company's assets and the satisfaction of its
liabilities in the normal course of conducting business, which in turn is
dependent upon the Company's ability to successfully execute its refinancing
plans, as described in Note 2. The Company expects to successfully execute its
refinancing plans; accordingly, management believes it will be able to meet its
obligations in a manner consistent with this accounting treatment. However,
there can be no assurance that the Company will be successful in executing its
refinancing plans. If the Company is unable to complete the necessary future
refinancings on acceptable terms and conditions, given the magnitude of the
refinancings the Company may be
7
forced to consider a reorganization under the protection of bankruptcy laws. For
discussion of the Company's refinancing plans, see Note 2.
The Company records gross revenue for energy sales and services related
to its electric power generation facilities under the accrual method and these
revenues generally are recognized upon delivery. Electric power and other energy
services are sold at market-based prices through existing power exchanges or
through third-party contracts. The Company records gross revenue for energy
sales and services to retail customers under the accrual method and these
revenues generally are recognized upon delivery, except for sales to large
commercial, industrial and institutional customers under contract. Energy sales
and services related to its electric power generation facilities and to retail
customers not billed by month-end are accrued based upon estimated energy and
services delivered.
The Company's energy trading, marketing, power origination and risk
management services activities and sales of electricity to large commercial,
industrial and institutional customers under contract are accounted for under
the mark-to-market method of accounting. Under the mark-to-market method of
accounting, derivative instruments and contractual commitments are recorded at
fair value in revenues upon contract execution. The net changes in their fair
values are recognized in the Statements of Consolidated Income as revenues in
the period of change. Trading and marketing revenues related to the sale of
natural gas, electric power and other energy related commodities are recorded on
a net basis. For information regarding the Company's adoption of EITF No. 02-03
and the presentation of trading and marketing activities on a net basis
beginning in the quarter ending September 30, 2002, see Note 3. For additional
discussion regarding trading and marketing revenue recognition and the related
estimates and assumptions that can affect reported amounts of such revenues, see
Note 6 to the Reliant Resources 10-K/A Notes.
The gains and losses related to financial instruments and contractual
commitments qualifying and designated as hedges related to the purchase and sale
of electric power and purchase of fuel are deferred in accumulated other
comprehensive income to the extent the contracts are effective, and then are
recognized in the same period as the settlement of the underlying physical
transaction. Realized gains and losses on financial contracts designated as
hedges are included in operating revenues in the Statements of Consolidated
Income. Revenues, fuel and cost of gas sold, and purchased power related to
physical sale and purchase contracts designated as hedges are generally recorded
on a gross basis in the delivery period. For additional discussion, see Note 6
to the Reliant Resources 10-K/A Notes.
The Company's effective tax rate for the three and nine months ended
September 30, 2002 varied from the historical customary statutory rate as a
result of an additional United States federal tax provision for future cash
distributions from an European equity investment, adjustments to state income
taxes primarily due to Texas franchise tax associated with the Company's retail
energy operations, and valuation allowances that increased due to losses
incurred by the Company's European Energy segment trading and origination
operations.
The Interim Financial Statements reflect all normal recurring
adjustments that are, in the opinion of management, necessary to present fairly
the financial position and results of operations of the Company for the
respective periods. Amounts reported in the Statements of Consolidated Income
are not necessarily indicative of amounts expected for a full year period due to
the effects of, among other things, (a) seasonal fluctuation in demand for
energy and energy services, (b) changes in energy commodity prices, (c) timing
of maintenance and other expenditures, (d) acquisitions and dispositions of
businesses, assets and other interests and (e) changes in interest expense. In
addition, certain amounts from the prior period have been reclassified to
conform to the Company's presentation of financial statements in the current
period. These reclassifications do not affect the earnings of the Company.
The following Reliant Resources 10-K/A Notes relate to certain
contingencies. See applicable note in the Reliant Resources 10-K/A Notes.
Notes to Consolidated Financial Statements included in the Reliant
Resources Form 10-K/A: Note 4 (Related Party Agreements - Agreements
Between Reliant Energy and the Company), Note 5 (Business
Acquisitions), Note 6 (Derivative Instruments), Note 13 (Commitments
and Contingencies), Note 17 (Bankruptcy of Enron Corp. and its
Affiliates) and Note 19 (Subsequent Events).
For information regarding certain legal, regulatory proceedings and
environmental matters, see Note 12.
Reliant Energy adopted a business separation plan in response to the
Texas Electric Choice Plan (Texas electric restructuring law) adopted by the
Texas legislature in June 1999. The Texas electric restructuring law
substantially amended the regulatory structure governing electric utilities in
Texas in order to allow retail electric competition with respect to all customer
classes beginning in January 2002. Under its business separation plan filed with
the Public Utility Commission of Texas (Texas Utility Commission), Reliant
Energy transferred substantially all of its unregulated businesses to the
Company in order to separate its regulated and unregulated operations. In
accordance with the plan, the Company completed its initial public offering
(IPO) of nearly 20% of its common stock in May
8
2001 and received net proceeds from the IPO of $1.7 billion. For additional
information regarding the IPO, see Note 1 and Note 9(a) to the Reliant Resources
10-K/A Notes.
CenterPoint Energy, Inc. (CenterPoint Energy) was formed on August 31,
2002 as the new holding company of Reliant Energy. CenterPoint Energy is a
diversified international energy services and energy delivery company that owned
the majority of Reliant Resources outstanding common stock prior to September
30, 2002. On September 30, 2002, CenterPoint Energy distributed all of the 240
million shares of Reliant Resources common stock it owned to its common
shareholders of record as of the close of business on September 20, 2002
(Distribution). The Distribution completed the separation of Reliant Resources
and CenterPoint Energy into two separate publicly held companies.
(2) REFINANCING AND LIQUIDITY ISSUES
During the first nine months of 2002, many factors negatively impacted
the Company. These factors include weaker pricing for capacity, ancillary
services and power, coupled with a narrowing of the spread between power prices
and natural gas fuel costs (spark spread) in the United States; market
contraction, reduced volatility and reduced liquidity in the power trading
markets in the United States and Northwest Europe; downgrades in the Company's
credit ratings to below investment grade by each of the major rating agencies;
various legal and regulatory investigations and proceedings (see Notes 1 and
12); reduced market confidence in the Company's financial reporting in light of
previous restatements and amendments; reduced access to capital and increased
demands for collateral in connection with the Company's trading, hedging and
commercial obligations; the decline in market prices of the Company's common
stock; and continued weakness in the United States economy generally. Many of
these factors are discussed in more detail below.
Refinancing Issues. As of September 30, 2002, the Company had
approximately $6.6 billion of credit facilities that will mature prior to
September 30, 2003, including $5.2 billion prior to March 31, 2003. In October
2002, $1.6 billion of these credit facilities was refinanced as further
discussed below and Note 16(b). The Company expects to extend or replace the
remaining facilities. However, in light of the negative factors summarized above
and the current credit environment, the Company believes that any extended or
replacement facilities are likely to, as compared to the current facilities:
include higher interest rates; more significantly restrict the use of the
Company's cash; require collateral or additional collateral, as the case may be,
as security; and otherwise contain more restrictive terms associated with loans
to non-investment grade borrowers. If the Company is unable to extend or replace
these facilities on acceptable terms and conditions, given the magnitude of the
refinancings, the Company may be forced to consider other alternatives,
including a reorganization under the protection of bankruptcy laws.
9
The following table provides a summary of the amounts owed and amounts
available as of September 30, 2002 under the Company's various credit
facilities.
EXPIRING
TOTAL BY
COMMITTED DRAWN LETTERS OF UNUSED SEPTEMBER
CREDIT AMOUNT CREDIT AMOUNT 30, 2003 EXPIRATION DATE
--------- ------ ---------- ------ --------- ----------------
(IN MILLIONS)
RELIANT RESOURCES:
Orion acquisition
term loan ......................................$2,908 $2,908 $ -- $ -- $2,908 February 2003
364-day revolver/
term loan ...................................... 800 800 -- -- 800 August 2003
Three-year revolver .............................. 800 569 218 13 -- August 2004
WHOLESALE ENERGY:
Orion Power and
Subsidiaries:
Orion Power .................................... 62 51 11 -- 62(1) December 2002
Orion MidWest .................................. 1,063 1,048 15 -- 1,063(1) October 2002
Orion NY ....................................... 442 412 10 20 442(1) December 2002
October 2002 -
Liberty Project ................................ 292 270 17 5 8 April 2026
Reliant Energy
Channelview LP:
Equity bridge .................................. 92 92 -- -- 92 November 2002
Construction term
loan and working capital October 2002 -
facility ..................................... 383 348 -- 35 3(2) July 2024
REMA letter of credit
facility ....................................... 51 -- 38 13 51 August 2003
EUROPEAN ENERGY:
Reliant Energy Capital
Europe, Inc .................................... 592 592 -- -- 592(3) March 2003
REPGB 364-day revolver ........................... 182 35 17 130 182(3) July 2003
REPGB letter of
credit facility ................................ 420 -- 271 149 420(3) July 2003
------ ------ ---- ---- ------
Total ..............................................$8,087 $7,125 $597 $365 $6,623
====== ====== ==== ==== ======
- ------------
(1) As discussed in Note 16(b), these Orion Power and subsidiaries credit
facilities were restructured in October 2002.
(2) Excludes $369 million of facilities expiring in November 2002 as
borrowings under such facilities are convertible into a long-term loan.
(3) The results of the Company's European Energy segment are consolidated
on a one-month lag basis.
During October 2002, the Company restructured (a) the Orion Power
Holdings, Inc. (Orion Power) revolving senior credit facility that matured in
December 2002, (b) the Orion Power MidWest, LP (Orion MidWest) credit facility
that matured in October 2002 and (c) the Orion Power New York, LP (Orion NY)
credit facility that matured in December 2002. As part of this restructuring,
the Orion Power revolving credit facility was terminated, and the Orion MidWest
and Orion NY credit facilities were extended until October 2005. For further
information regarding this restructuring, please read Note 16(b).
It is Reliant Resources' current expectation to invest equity or
subordinated debt in Reliant Energy Channelview LP totaling $92 million using
cash on hand during November 2002. Reliant Energy Channelview LP must use the
funds from this debt or equity investment to repay its equity bridge loan
totaling $92 million during November 2002.
The Company's $2.9 billion term loan to finance the purchase of Orion
Power was funded on February 19, 2002. This term loan must be repaid within one
year from the date on which it was funded, or February 19, 2003. The Company is
currently negotiating with the lead banks regarding the appropriate terms and
conditions for an extension of the maturity of this loan. The Company expects to
complete this extension on or before the maturity. The Company anticipates that
the banks will require that the loan be collateralized, contain additional and
more restrictive covenants, have higher interest rates or fees or contain other
provisions that may be dilutive to stockholders.
10
In August 2002, the Company exercised its option to convert its $800
million 364-day revolving facility to a one-year term loan with a maturity of
August 22, 2003. The Company expects to extend and/or refinance this facility,
as well as the $800 million three-year revolver that expires in August 2004, in
conjunction with any extension of the $2.9 billion Orion acquisition term loan
on terms and conditions substantially similar to any extended $2.9 billion Orion
acquisition loan.
The Company is considering the possibility of requesting equity and
debt participants under the credit agreement related to its construction agency
agreements to restructure and extend the maturity of the existing commitments in
connection with the proposed extensions/refinancings described above. For
further discussion of the construction agency agreements, see Note 12(f). To the
extent that the Company is successful in such effort, it expects that such
equity and debt participants under the credit agreements to the construction
agency agreement may require additional collateral, additional and more
restrictive covenants, and higher interest rates and fees.
The Euro 600 million (approximately $592 million) term loan facility at
Reliant Energy Capital Europe, Inc. (RECE) matures on March 1, 2003. Preliminary
work has commenced on the refinancing of this term loan facility. The Company
anticipates the completion of such refinancing during the first quarter of 2003.
In addition, the Company has various other facilities that mature over
the next twelve months. The Company anticipates refinancing or replacing the
Reliant Energy Mid-Atlantic (REMA) letter of credit facility totaling $51
million maturing in August 2003, the Reliant Energy Power Generation Benelux
(REPGB) 364-day revolver totaling Euro 184 million maturing in July 2003 and the
REPGB letter of credit facility totaling $420 million maturing in July 2003
prior to their maturity, to the extent it continues to need access to this
amount of committed credit. The Company anticipates that the lenders may require
that these facilities be secured, contain additional and more restrictive
covenants and have higher interest rates and fees.
Credit Ratings. During the third quarter of 2002, each of the major
rating agencies downgraded the Company's credit ratings to sub-investment grade.
Credit ratings impact the Company's ability to obtain short- and long-term
financing, the execution of its commercial strategies and the cost of financing
because many of the Company's credit facilities have fees and interest rate
margins based on the Company's credit rating. As of November 8, 2002, the
Company's credit ratings for its senior unsecured debt were as follows:
DATE ASSIGNED RATING AGENCY RATING RATING DESCRIPTION
- ------------------ ----------------- ------ ---------------------------------------
July 31, 2002 Moody's Ba3 Review for potential downgrade
September 13, 2002 Standard & Poor's BB+ Credit watch with negative implications
September 18, 2002 Fitch BB Rating watch negative
The credit ratings of the Company's subsidiaries have been affected as
well. As of November 8, 2002, the REMA lease certificates were rated BB+ by
Standard & Poor's and Baa3 by Moody's. The ratings remain on credit watch with
negative implications and review for possible downgrade, respectively. As of
November 8, 2002, the RECE senior unsecured bank credit facility was rated Ba3
by Moody's. The rating remains on review for possible downgrade. The Standard &
Poor's issuer rating was BB+ and remains on credit watch with negative
implications. As of November 8, 2002, the long-term issuer rating assigned by
Moody's to REPGB was Baa2 and remains on review for possible downgrade. The
senior unsecured bank loan rating assigned by Standard & Poor's was BBB- and
remains on credit watch with negative implications. As of November 8, 2002, the
Moody's senior unsecured debt rating for Orion Power was Ba3. The rating remains
on review for possible downgrade. Standard & Poor's senior unsecured debt and
issuer ratings for Orion Power were BB- and BB+, respectively. These ratings
remain on credit watch with negative implications.
The Company cannot assure that these ratings will remain in effect for
any given period of time or that one or more of these ratings will not be
lowered again. As discussed above, the Company expects to provide additional
collateral as security to obtain future financings and refinancings which may
adversely affect the Company's current credit ratings thereby increasing the
cost of future financings or refinancings. The Company notes that these credit
ratings are not recommendations to buy, sell or hold its securities and may be
revised or withdrawn at any time by such rating agency. Each rating should be
evaluated independently of any other rating. Any future incremental reduction or
withdrawal of one or more of the Company's credit ratings could have a material
adverse impact on its ability to access capital on acceptable terms, including
its ability to refinance debt obligations as they mature. The Company's
financial and operational flexibility is likely to be reduced as a result of
more restrictive covenants, the
11
requirement for security and other terms that are typically imposed on
sub-investment grade borrowers as further discussed above.
The Company could be adversely impacted by its downgrade to
sub-investment grade in connection with certain commercial agreements. These
commercial arrangements primarily include: (a) commercial contracts and/or
guarantees related to the Company's wholesale and retail trading, marketing,
risk management and hedging activities and (b) surety bonds and contractual
obligations related to the development and construction or refurbishment of
power plants and related facilities.
In most cases, the consequences of ratings downgrades are limited to
the requirement by the Company's counterparties that the Company provide credit
support to the counterparties in the form of a pledge of cash collateral, a
letter of credit or other similar credit support. In addition, certain of the
Company's retail electricity contracts with large commercial, industrial and
institutional customers of the Retail Energy segment permit the customers to
terminate their contracts if the Company's unsecured debt ratings fall below
investment grade or if its ratings are withdrawn entirely by a rating agency. As
of November 8, 2002, no retail contracts have been terminated pursuant to these
terms. In light of the credit rating downgrades, the Company is working with its
various commercial counterparties to minimize the disruption to its normal
commercial activities and to reduce the magnitude of the collateral the Company
must post in support of its obligations to such counterparties.
In addition, the Company has been involved in certain commercial
activities (including term sales of electric energy or capacity from its
generating facilities) that prospectively may not be feasible due to the
Company's current credit and liquidity situation, among other factors. The
credit downgrades have resulted also in more limited access to credit worthy
counterparties to transact with and the need to make commercial concessions with
counterparties as an inducement to do business with the Company. Given these
factors, the Company has reduced the level of its trading, marketing and hedging
activities, which could result in greater volatility in future earnings.
On October 1, 2002, the Company's Retail Energy segment, through its
subsidiary, entered into a master power contract with Texas Genco, LP (Texas
Genco), a subsidiary of CenterPoint Energy, covering, among other things, the
Company's purchases of capacity and/or energy from Texas Genco's generating
units, under an unsecured line of credit. This contract contains covenants that
restrict the activities of several of the Retail Energy segment's subsidiaries
transacting business in Texas. These restrictions include limitations on the
ability of these subsidiaries to (a) sell assets (including customers),
consolidate or merge with other companies, including affiliated companies
outside the Retail Energy segment; (b) grant liens on their properties; (c)
borrow money in excess of agreed upon levels; (d) enter into or guaranty certain
trading arrangements; and (e) incur liabilities outside the ordinary course of
the Retail Energy segment's business. In addition, there are restrictions
involving transactions with affiliates. Under some circumstances, the Company
would be required to post collateral in favor of Texas Genco. The primary term
of this contract ends on December 31, 2003.
Other Liquidity Issues and Concerns. Currently, the Company is
satisfying its capital requirements and other commitments primarily with cash
from operations, cash on hand and borrowings available under its credit
facilities. The following table summarizes the Company's credit capacity and
liquidity position at September 30, 2002.
12
RELIANT ORION EUROPEAN
TOTAL RESOURCES POWER (2) ENERGY (3) OTHER
------ --------- --------- ---------- -----
(IN MILLIONS)
Total Committed Credit ............. $8,087 $4,508 $1,859 $1,194 $526
Outstanding Borrowings ............. 7,125 4,277 1,781 627 440
Outstanding Letters of Credit ...... 597 218 53 288 38
------ ------ ------ ------ ----
Unused Borrowing Capacity .......... 365 13 25 279 48
Cash and Cash Equivalents .......... 1,444 1,169 -- 79 196
Restricted Cash(1) ................. 447 7 380 60 --
------ ------ ------ ------ ----
Total Available Liquidity .......... $2,256 $1,189 $ 405 $ 418 $244
====== ====== ====== ====== ====
- ----------
(1) Restricted cash includes cash at certain subsidiaries that is
restricted by financing agreements, but is available to the applicable
subsidiary to use to satisfy certain of its obligations.
(2) On October 30, 2002, Orion Power and its subsidiaries repaid
approximately $144 million in borrowings with cash and restricted cash.
(3) The results of the Company's European Energy segment are consolidated
on a one-month lag basis.
Based on current commodity prices, the Company estimates that as of
November 8, 2002, it could be required to post collateral of up to $478 million.
This estimate could increase based on commodity prices and a reduction in the
current credit rating of REPGB. As of November 8, 2002, the Company had posted
cash collateral and letters of credit in the amount of $363 million and $629
million, respectively. Factors which could lead to an increase in the Company's
actual posting of collateral include additional downgrades, adverse changes in
the Company's industry or in reaction to the possible secured nature of any
extension or refinancing of the Company's debt facilities. As of November 8,
2002, the Company had $1.2 billion in unrestricted available cash and cash
equivalents and $5 million available under committed corporate credit facilities
of the Company to support domestic requirements and $82 million in unrestricted
available cash and cash equivalents and $165 million available under committed
European facilities to support European operations. These amounts are currently
available to meet working capital needs and possible future requirements for
credit support related to the Company's credit ratings.
Assuming successful extension or replacement of its credit facilities
as they mature, the Company believes that its current level of cash and
borrowing capability, along with its future anticipated cash flows from
operations, will be sufficient to meet the liquidity needs of its business for
the next twelve months. Under certain unfavorable commodity price scenarios,
however, it is possible that the Company could experience inadequate liquidity.
In order to enhance the Company's liquidity position, the Company may
sell some of its assets. The Company has identified certain non-strategic
generating assets for potential sale to enhance the Company's liquidity
position. To date, the Company has not reached an agreement to dispose of assets
nor has it contemplated any proceeds from asset sales in its current liquidity
plan. Due to unfavorable market conditions in the wholesale power markets, there
can be no assurance that the Company will be successful in disposing of
generating assets at reasonable prices or on a timely basis.
All of the Company's operations are conducted by its subsidiaries. The
Company's cash flow and its ability to service certain of its indebtedness when
due is dependent upon its receipt of cash dividends, distributions or other cash
transfers. The terms of some of the Company's subsidiaries' indebtedness
restrict their ability to pay dividends or make other restricted payments to the
Company, and future financings at the Company's subsidiaries may contain, to
avoid an event of default under these notes similar or even more stringent
restrictions. Further, Reliant Resources may elect to make the interest payments
on Orion Power's 12% senior notes to avoid an event of default under these
notes, if, at the time of such payments are due, dividends are restricted under
the Orion NY and Orion MidWest credit facilities, and funds generated by Orion
Power's other subsidiaries or from other sources are insufficient to make such
payments.
As further discussed in Note 13(d) to the Reliant Resources Form
10-K/A, during the period from 1994 through 1997, under cross border lease
transactions, REPGB leased several of its power plants and related equipment and
turbines to non-Netherlands based investors. Pursuant to these transactions,
REPGB is required, in specified situations, to post letters of credit. In the
case of early termination of these contracts, REPGB would be contingently liable
for some payments to the sublessors. Letters of credit have been posted as of
September 30, 2002 in the total amount of $307 million. In the event that REPGB
credit ratings fall one notch below their current levels, REPGB will be required
to post an
13
additional $45 million under the cross border leases. As of November 8, 2002,
under its $420 million letter of credit facility, REPGB has unused letter of
credit capacity of $113 million available for this purpose.
As of September 30, 2002, the Company had forward-starting interest
rate swaps having an aggregate notional amount of $500 million to hedge the
interest rate on a portion of future offerings of long-term fixed-rate notes.
The Company liquidated the swaps in November 2002 for $52 million. For
additional information regarding the accounting related to these swaps, see
Notes 4 and 16(d).
In early 2004, the Company expects to pay to CenterPoint Energy
approximately $155 million to $185 million, with a most probable estimate of
$170 million, pursuant to the Texas electric restructuring law. For additional
information, see Note 12(e).
For additional information regarding Reliant Energy Desert Basin
generating facility and the potential requirement of additional letters of
credit, see Note 12(h).
For additional information regarding Liberty Electric Power, LLC and
Liberty Electric PA, LLC credit facility and related issues and concerns, see
Notes 9 and 12(i).
For discussion of a covenant violation under the Receivables Facility,
see Note 16(a).
The Company estimates its consolidated forecasted capital commitments
for the fourth quarter of 2002 and the year ended December 31, 2003 to be
approximately $130 million and $533 million, respectively. We expect these
capital commitments to be met with cash flows from operations, project
financings, securitization of assets and other borrowings. Additional capital
expenditures, some of which may be substantial, depend to a large extent upon
the nature and extent of future project commitments which are discretionary. In
addition to the above, the Company currently estimates the capital expenditures
by off-balance sheet special purpose entities to be $207 million and $304
million in the fourth quarter of 2002 and the year ended December 31, 2003,
respectively. For additional information regarding these off-balance sheet
transactions, see Note 12(f).
Also, in connection with the Company's separation from CenterPoint
Energy, CenterPoint Energy granted the Company an option to purchase all of the
shares of capital stock owned by CenterPoint Energy in January 2004 of Texas
Genco that owns the Texas generating assets of Reliant Energy's former electric
utility division. This option may be exercised between January 10, 2004 and
January 24, 2004. If the Company exercises its purchase option, the Company
expects to fund the purchase obligation with proceeds from asset sales, cash
flows from operations, proceeds from debt and equity offerings, and/or other
borrowings. The Company's liquidity position and restrictive covenants of future
financings, may limit its ability to exercise the option. If the Company does
not exercise the option, the Company will need to contract with Texas Genco or
others to meet its retail supply obligations. For additional information
regarding this option to purchase CenterPoint Energy's interest in Texas Genco,
please read Note 4(b) to the Reliant Resources Form 10-K/A.
(3) NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board (FASB) issued
SFAS No. 141 "Business Combinations" (SFAS No. 141). SFAS No. 141 requires
business combinations initiated after June 30, 2001 to be accounted for using
the purchase method of accounting and broadens the criteria for recording
intangible assets separate from goodwill. Recorded goodwill and intangibles will
be evaluated against these new criteria and may result in certain intangibles
being transferred to goodwill, or alternatively, amounts initially recorded as
goodwill may be separately identified and recognized apart from goodwill. The
Company adopted the provisions of the statement which apply to goodwill and
intangible assets acquired prior to June 30, 2001 on January 1, 2002. The
adoption of SFAS No. 141 did not have a material impact on the Company's
historical results of operations or financial position.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of
a liability for an asset retirement legal obligation to be recognized in the
period in which it is incurred. When the liability is initially recorded,
associated costs are capitalized by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted to its present
value
14
each period, and the capitalized cost is depreciated over the useful life of the
related asset. SFAS No. 143 is effective for fiscal years beginning after June
15, 2002, with earlier application encouraged. SFAS No. 143 requires entities to
record a cumulative effect of change in accounting principle in the income
statement in the period of adoption. The Company plans to adopt SFAS No. 143 on
January 1, 2003, and is in the process of determining the effect of adoption on
its consolidated financial statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144
provides new guidance on the recognition of impairment losses on long-lived
assets to be held and used or to be disposed of and also broadens the definition
of what constitutes a discontinued operation and how the results of a
discontinued operation are to be measured and presented. SFAS No. 144 supercedes
SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" and Accounting Principles Board Opinion No.
30, "Reporting the Results of Operations - Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," while retaining many of the requirements of these two
statements. Under SFAS No. 144, assets held for sale that are a component of an
entity will be included in discontinued operations if the operations and cash
flows will be or have been eliminated from the ongoing operations of the entity
and the entity will not have any significant continuing involvement in the
operations prospectively. SFAS No. 144 did not materially change the methods
used by the Company to measure impairment losses on long-lived assets, but may
result in additional future dispositions being reported as discontinued
operations. The Company adopted SFAS No. 144 on January 1, 2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current requirement
that gains and losses on debt extinguishment must be classified as extraordinary
items in the income statement. Instead, such gains and losses will be classified
as extraordinary items only if they are deemed to be unusual and infrequent.
SFAS No. 145 also requires sale-leaseback accounting for certain lease
modifications that have economic effects that are similar to sale-leaseback
transactions. The changes related to debt extinguishment will be effective for
fiscal years beginning after May 15, 2002, and the changes related to lease
accounting will be effective for transactions occurring after May 15, 2002. The
Company will apply this guidance prospectively.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
nullifies EITF No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred
in a Restructuring)" (EITF No. 94-3). The principal difference between SFAS No.
146 and EITF No. 94-3 relates to the requirements for recognition of a liability
for cost associated with an exit or disposal activity. SFAS No. 146 requires
that a liability be recognized for a cost associated with an exit or disposal
activity when it is incurred. A liability is incurred when a transaction or
event occurs that leaves an entity little or no discretion to avoid the future
transfer or use of assets to settle the liability. Under EITF No. 94-3, a
liability for an exit cost was recognized at the date of an entity's commitment
to an exit plan. In addition, SFAS No. 146 also requires that a liability for a
cost associated with an exit or disposal activity be recognized at its fair
value when it is incurred. SFAS No. 146 is effective for exit or disposal
activities that are initiated after December 31, 2002 with early application
encouraged. The Company will apply the provisions of SFAS No. 146 to all exit or
disposal activities initiated after December 31, 2002.
See Note 4 for a discussion regarding the Company's adoption of SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities," as
amended (SFAS No. 133) on January 1, 2001 and adoption of subsequent cleared
guidance. See Note 7 for a discussion regarding the Company's adoption of SFAS
No. 142 "Goodwill and Other Intangible Assets" (SFAS No. 142) on January 1,
2002.
In June 2002, the EITF reached a consensus that all mark-to-market
gains and losses on energy trading contracts should be shown net in the income
statement whether or not settled physically. In October 2002, the EITF issued a
consensus that superceded the June 2002 consensus. The October 2002 consensus
required, among other things, that energy derivatives held for trading purposes
be shown net in the income statement. This new consensus is effective for fiscal
periods beginning after December 15, 2002. However, consistent with the new
consensus and as allowed under EITF No. 98-10, beginning with the quarter ended
September 30, 2002, the Company now reports all energy trading and marketing
activities on a net basis in the Statements of Consolidated Income. Comparative
financial statements for prior periods have been reclassified to conform to this
presentation.
15
The adoption of net reporting resulted in a reduction of revenues, fuel
and cost of gas sold, purchase power expense during the three and nine months
ended September 30, 2001, and six months ended June 30, 2002 as follows (in
millions):
FOR THE THREE FOR THE NINE FOR THE SIX
MONTHS ENDED MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, 2001 SEPTEMBER 30, 2001 JUNE 30, 2002
------------------ ------------------ -------------
Revenues .......................... $ 6,278 $ 19,687 $ 11,434
Fuel and cost of gas sold ......... 2,471 11,011 6,142
Purchased power ................... 3,807 8,676 5,292
-------- --------- ---------
Net impact on margins ........ $ -- $ -- $ --
======== ========= =========
Furthermore, in October 2002, under EITF No. 02-03, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities" (EITF No.
02-03) the EITF reached a consensus to rescind EITF No. 98-10. All new contracts
that would have been accounted for under EITF No. 98-10, and that do not fall
within the scope of SFAS No. 133, should no longer be marked-to-market through
earnings beginning October 25, 2002. In addition, inventories used in the
trading and marketing operations should no longer be marked-to-market through
earnings. This transition is effective for the Company for the first quarter
of 2003. A cumulative effect of a change in accounting principle should be
recorded effective January 1, 2003 related to all contracts and inventories that
will no longer be recorded at fair value that were entered into or held, as
applicable, prior to October 25, 2002. The Company is in process of determining
the effect of adoption on its consolidated financial statements.
Finally, the EITF has not reached a consensus on whether recognition of
dealer profit, or unrealized gains and losses at inception of an energy trading
contract is appropriate in the absence of quoted market prices or current market
transactions for contracts with similar terms. In the June 2002 EITF meeting and
again in the October 2002 EITF meeting, the FASB staff indicated that until such
time as a consensus is reached, the FASB staff will continue to hold the view
that previous EITF consensus do not allow for recognition of dealer profit,
unless evidenced by quoted market prices or other current market transactions
for energy trading contracts with similar terms and counterparties. During the
three and nine months ended September 30, 2002, the Company recorded $8 million
and $54 million, respectively, of fair value at the contract inception related
to trading and marketing activities. The Company believes that any material
inception gains recorded subsequent to the FASB staff comment regarding this
issue were evidenced by quoted market prices and other current market
transactions for energy trading contracts with similar terms and
counterparties.
(4) DERIVATIVE FINANCIAL INSTRUMENTS
Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax
increase in net income of $3 million and a cumulative after-tax increase in
accumulated other comprehensive loss of $460 million. The adoption also
increased current assets, long-term assets, current liabilities and long-term
liabilities by $566 million, $127 million, $811 million and $339 million,
respectively, in the Company's Consolidated Balance Sheet. For additional
information regarding the adoption of SFAS No. 133 and the Company's accounting
policies for derivative financial instruments, see Note 6 to the Reliant
Resources 10-K/A Notes.
The application of SFAS No. 133 is still evolving as the FASB clears
issues submitted to the Derivatives Implementation Group for consideration.
During the second quarter of 2001, an issue that applies exclusively to the
electric industry and allows the normal purchases and normal sales exception for
option-type contracts if certain criteria are met was approved by the FASB with
an effective date of July 1, 2001. The adoption of this cleared guidance had no
impact on the Company's results of operations. Certain criteria of this
previously approved guidance were revised in October and December 2001 and
became effective on April 1, 2002. The effect of adoption of the revised
guidance did not impact the Company's consolidated financial statements.
During the third quarter of 2001, the FASB cleared an issue related to
application of the normal purchases and normal sales exception to contracts that
combine forward and purchased option contracts. The effective date of this
guidance was April 1, 2002, and the effect of adoption of this guidance did not
materially impact the Company's consolidated financial statements.
16
Cash Flow Hedges. During the three and nine months ended September 30,
2002, the amount of hedge ineffectiveness recognized in earnings from
derivatives that are designated and qualify as cash flow hedges, including
interest rate swaps, was a $15 million and a $5 million loss, respectively.
During the nine months ended September 30, 2001, the amount of hedge
ineffectiveness recognized in earnings from derivatives that are designated and
qualify as cash flow hedges was immaterial. No component of the derivative
instruments' gain or loss was excluded from this assessment of effectiveness.
During the nine months ended September 30, 2002, there was a loss of
approximately $0.2 million recognized in earnings as a result of the
discontinuance of cash flow hedges because it was no longer probable that the
forecasted transaction would occur. As of September 30, 2002, the Company
expects $22 million in accumulated other comprehensive income to be reclassified
into net income during the next twelve months.
Interest Rate Swaps. As of September 30, 2002, the Company holds
interest rate swaps with an aggregate notional amount of $1.2 billion to fix the
interest rate applicable to floating rate short-term debt and floating rate
long-term debt. The Company pays floating interest at LIBOR for a fixed interest
rate of 6.92%. The swaps relating to both short-term and long-term debt qualify
for hedge accounting under SFAS No. 133 and the periodic settlements are
recognized as an adjustment to interest expense in the Statements of
Consolidated Income over the term of the swap agreements. During January 2002,
the Company entered into forward-starting interest rate swaps having an
aggregate notional amount of $1.0 billion, of which $500 million has been
liquidated as discussed below, to hedge the interest rate on a portion of future
offerings of long-term fixed-rate notes. With respect to the $500 million of
forward-starting interest rate swaps that are outstanding, the Company pays
fixed interest at a rate of 5.2% for floating interest at LIBOR. These swaps
qualify as cash flow hedges under SFAS No. 133. On May 9, 2002, the Company
liquidated $500 million of the forward starting interest rate swaps that were
entered into in January 2002. The liquidation of these swaps resulted in a loss
of $3 million, which was recorded in other comprehensive income and will be
amortized into interest expense in the same period during which the forecasted
interest payment affects earnings. Should the forecasted interest payments no
longer be probable, any remaining deferred amount will be recognized immediately
as an expense. The maximum length of time the Company is hedging its exposure to
the payment of variable interest rates is 7 years. In November 2002, the Company
liquidated $500 million of the forward-starting interest rate swaps at a cost of
$52 million. For further discussion of the liquidation of these swaps, see Note
16(d).
Hedge of Net Investment in Foreign Subsidiaries. The Company has hedged
its entire net investment in its European subsidiaries against a material
decline of the Euro through a combination of Euro-denominated borrowings and
foreign currency option contracts. During the nine months ended September 30,
2002, the derivative and non-derivative instruments designated as hedging the
net investment in the Company's European subsidiaries resulted in a loss of $163
million, which is included in the balance of the cumulative translation
adjustment in accumulated other comprehensive income.
Other Derivatives. In December 2000, the Dutch parliament adopted
legislation allocating to the Dutch generation sector, including REPGB,
financial responsibility for various out-of-market contracts and other
liabilities. The legislation became effective in all material respects on
January 1, 2001. In particular, the legislation allocated to the Dutch
generation sector, including REPGB, financial responsibility to purchase
imported electricity and gas under certain long-term power contracts and a gas
contract entered into by NEA B.V. (NEA), the regulated entity which formerly
purchased and sold energy in the Netherlands.
The Company accounts for the gas supply contract at fair value as a
non-trading derivative pursuant to SFAS No. 133. Prior to amending the
electricity import contracts in May 2002, the Company also accounted for the
electricity import contracts at fair value as non-trading derivatives pursuant
to SFAS No. 133. However, subsequent to amending the electricity import
contracts, the Company began to account for the electricity contracts as a part
of the Company's energy trading activities.
As of December 31, 2001, the Company has a recorded liability of $369
million for the REPGB stranded cost gas and electric commitments in non-trading
derivative liabilities. As of September 30, 2002, the Company has a recorded
liability of $141 million for the REPGB stranded cost gas supply contract in
non-trading derivative liabilities. Pursuant to SFAS No. 133, during nine months
ended September 30, 2002, the Company recognized a net $16 million gain, net of
derivative transactions entered into to economically hedge the stranded cost gas
contracts, recorded in fuel expense related to changes in the valuation of these
non-trading derivative liabilities, excluding the effects of the gain related to
amending the two power contracts as discussed in Note 12(d).
For additional information regarding REPGB's obligations under these
out-of-market contracts and the related indemnification by former shareholders
of these stranded costs during 2001, see Note 13(f) to the Reliant Resources
10-K/A Notes and Note 12(d).
17
During the May 2001 through September 2001 time frame, the Company
entered into two structured transactions which were recorded on the balance
sheet in non-trading derivative assets and liabilities involving a series of
forward contracts to buy and sell an energy commodity in 2001 and to buy and
sell an energy commodity in 2002 or 2003. The change in fair value of these
derivative assets and liabilities must be recorded in the statement of income
for each reporting period. As of December 31, 2001, the Company has recognized
$221 million of non-trading derivative assets and $103 million of non-trading
derivative liabilities related to these transactions. During the three and nine
months ended September 30, 2002, $46 million and $96 million, respectively, of
net non-trading derivative assets were settled related to these transactions,
and a $1 million and $3 million pre-tax unrealized gain, respectively, was
recognized. As of September 30, 2002, the Company has recognized $33 million of
non-trading derivative assets and $8 million of non-trading derivative
liabilities related to these transactions.
(5) HISTORICAL RELATED PARTY TRANSACTIONS
The Interim Financial Statements include significant transactions
between the Company and CenterPoint Energy and its subsidiaries involving
services, including various corporate support services (including accounting,
finance, investor relations, planning, legal, communications, governmental and
regulatory affairs and human resources), information technology services and
other shared services such as corporate security, facilities management,
accounts receivable, accounts payable and payroll, office support services and
purchasing and logistics. The costs of these services have been directly charged
or allocated to the Company using methods that management believes are
reasonable. These methods include negotiated usage rates, dedicated asset
assignment, and proportionate corporate formulas based on assets, operating
expenses and employees. These charges and allocations are not necessarily
indicative of what would have been incurred had the Company been an unaffiliated
entity. Amounts charged and allocated to the Company for these services were $1
million and $5 million for the three months ended September 30, 2001 and 2002,
respectively. Amounts charged and allocated to the Company for these services
were $6 million and $15 million for the nine months ended September 30, 2001 and
2002, respectively, and are included primarily in operation and maintenance
expenses and general and administrative expenses. In addition, during the three
and nine months ended September 30, 2001, the Company incurred costs primarily
related to corporate support services which were billed to CenterPoint Energy
and its affiliates of $8 million and $29 million, respectively. Some
subsidiaries of the Company have entered into office rental agreements with
CenterPoint Energy. During the three months ended September 30, 2001 and 2002,
the Company incurred $5 million and $8 million, respectively, of rent expense to
CenterPoint Energy. The Company incurred $13 million and $24 million of rent
expense to CenterPoint Energy during the nine months ended September 30, 2001
and 2002, respectively.
The Company purchases natural gas, electric generation energy and
capacity, electric transmission services and natural gas transportation services
from, supplies natural gas to, and provides marketing and risk management
services to affiliates of CenterPoint Energy. Purchases of electric generation
energy and capacity, electric transmission services, natural gas transportation
services and natural gas from CenterPoint Energy and its subsidiaries were $634
million for the three months ended September 30, 2002 and $1.5 billion for the
nine months ended September 30, 2002. During the three months ended September
30, 2001 and 2002, the sales and services to CenterPoint Energy and its
subsidiaries totaled $87 million and $18 million, respectively, and $416 million
and $176 million for the nine months ended September 30, 2001 and 2002,
respectively.
During the fourth quarter of 2001 and the first and third quarters of
2002, the Company purchased entitlements to some of the generation capacity of
electric generation assets of Texas Genco. The Company purchased these
entitlements under the terms of a master separation agreement between Reliant
Resources and Reliant Energy (Master Separation Agreement) and in capacity
auctions conducted by Texas Genco. Under the Texas electric restructuring law,
Texas Genco is required to sell at auction entitlements to at least 15% of its
installed generating capacity (State Mandated Auctions). Under the law, the
Company is not permitted to participate in the State Mandated Auctions. However,
the Company is entitled to purchase capacity and energy in the auction
entitlements required by the Texas electric restructuring law of the power
generation companies affiliated with the other Texas electric utilities. Under
the Master Separation Agreement, Texas Genco is obligated to auction
entitlements to all of its capacity and related ancillary services available
after the State Mandated Auctions subject to certain permitted reductions, for a
specified period of time, subject to certain agreements (Contractually Mandated
Auctions). Under the Master Separation Agreement, the Company is entitled to
elect to purchase 50% of the capacity to be auctioned by Texas Genco in the
Contractually Mandated Auctions at the prices established in such auctions. In
addition to this right, the Company may participate in the Contractually
Mandated Auctions. As of September 30, 2002, the Company has purchased
entitlements to capacity of Texas Genco averaging 5,967 MW per month for the
remainder of 2002 and 775 MW per
18
month in 2003. The Company has no minimum obligations for energy or ancillary
services under the Master Separation Agreement. The Company's anticipated
capacity payments related to these capacity entitlements are $46 million in 2002
and $58 million in 2003. During the fourth quarter of 2002, through November 8,
2002, the Company purchased additional entitlements to some of the generation
capacity of electric generation assets of Texas Genco averaging 4,173 MW per
month in 2003. The Company's anticipated capacity payments related to these
additional capacity entitlements are $246 million in 2003. For additional
information regarding agreements relating to Texas Genco, see Note 4(b) to the
Reliant Resources 10-K/A Notes.
During the nine months ended September 30, 2001, CenterPoint Energy or
its subsidiaries made equity contributions to the Company of $1.8 billion. The
contributions in the nine months ended September 30, 2001, primarily related to
the conversion into equity of debt and related interest expense as discussed
above and the contribution of net benefit assets and liabilities, net of
deferred income taxes. During the nine months ended September 30, 2002,
CenterPoint Energy made contributions to the Company of $21 million, which
primarily related to benefit obligations pursuant to the Master Separation
Agreement.
(6) ACQUISITIONS
Orion Power Holdings, Inc. In February 2002, the Company acquired all
of the outstanding shares of common stock of Orion Power for $26.80 per share in
cash for an aggregate purchase price of $2.9 billion. The Company funded the
Orion Power acquisition with a $2.9 billion credit facility (see Note 9) and $41
million of cash on hand. As a result of the acquisition, the Company's
consolidated net debt obligations also increased by the amount of Orion Power's
net debt obligations. As of February 19, 2002, Orion Power's debt obligations
were $2.4 billion ($2.1 billion net of restricted cash pursuant to debt
covenants). Orion Power is an electric power generating company formed in March
1998 to acquire, develop, own and operate power-generating facilities in certain
deregulated wholesale markets throughout North America. As of February 19, 2002,
Orion Power had 81 power plants with a total generating capacity of 5,644 MW and
two development projects with an additional 804 MW of capacity under
construction. As of September 30, 2002, both projects under construction had
reached commercial operation.
The Company accounted for the acquisition as a purchase with assets and
liabilities of Orion Power reflected at their estimated fair values. The
Company's fair value adjustments primarily included adjustments in property,
plant and equipment, contracts, severance liabilities, debt, unrecognized
pension and postretirement benefits liabilities and related deferred taxes. The
Company expects to finalize these fair value adjustments no later than February
2003, based on valuations of property, plant and equipment, intangible assets
and other assets and obligations.
The Company's results of operations include the results of Orion Power
only for the period beginning February 19, 2002. The following table presents
selected financial information and unaudited pro forma information for the three
months ended September 30, 2001 and nine months ended September 30, 2001 and
2002, as if the acquisition had occurred on January 1, 2001 and 2002, as
applicable.
THREE MONTHS ENDED
SEPTEMBER 30, 2001
-----------------------------
ACTUAL PRO FORMA
-------- ---------
(IN MILLIONS)
Revenues ............................................. $ 2,462 $ 2,844
Net income ........................................... 214 267
Basic and diluted earnings per share ................. $ 0.71 $ 0.89
19
NINE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2001 SEPTEMBER 30, 2002
----------------------------- -----------------------------
ACTUAL PRO FORMA ACTUAL PRO FORMA
--------- ---------- --------- ----------
(IN MILLIONS)
Revenues .............................................. $ 5,666 $ 6,630 $ 9,512 $ 9,634
Income before cumulative effect of accounting
change .............................................. 521 586 333 274
Net income ............................................ 524 589 99 41
Basic earnings per share before cumulative effect
of accounting change ................................ $ 1.92 $ 2.15 $ 1.15 $ 0.95
Basic earnings per share .............................. 1.93 2.16 0.34 0.14
Diluted earnings per share before cumulative
effect of accounting change ......................... 1.91 2.15 1.14 0.94
Diluted earnings per share ............................ 1.92 2.16 0.34 0.14
These unaudited pro forma results, based on assumptions deemed
appropriate by the Company's management, have been prepared for informational
purposes only and are not necessarily indicative of the amounts that would have
resulted if the acquisition of Orion Power had occurred on January 1, 2001 and
2002, as applicable. Purchase-related adjustments to the results of operations
include the effects on depreciation and amortization, interest expense, interest
income and income taxes. The unaudited pro forma condensed consolidated
financial statements reflect the acquisition of Orion Power in accordance with
SFAS No. 141 and SFAS No. 142. For additional information regarding the
Company's adoption of SFAS No. 141 and SFAS No. 142, see Notes 3 and 7.
Each of Orion Power New York, LP, Orion Power New York GP, Inc.,
Astoria Generating Company, L.P., Carr Street Generating Station, LP, Erie
Boulevard Hydropower, LP, Orion Power MidWest, LP, Orion Power Midwest GP, Inc.,
Twelvepole Creek, LLC and Orion Power Capital, LLC is a separate legal entity
and has its own assets.
(7) GOODWILL AND INTANGIBLES
In July 2001, the FASB issued SFAS No. 142, which provides that
goodwill and certain intangibles with indefinite lives will not be amortized
into results of operations, but instead will be reviewed periodically for
impairment and written down and charged to results of operations only in the
periods in which the recorded value of goodwill and certain intangibles with
indefinite lives is more than its fair value. The Company adopted the provisions
of the statement which apply to goodwill and intangible assets acquired prior to
June 30, 2001 on January 1, 2002.
On January 1, 2002, the Company discontinued amortizing goodwill into
its results of operations pursuant to SFAS No. 142. A reconciliation of
previously reported net income and earnings per share to the amounts adjusted
for the exclusion of goodwill amortization:
THREE MONTHS ENDED SEPTEMBER 30,
--------------------------------
2001 2002
-------- --------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Reported net income ......................... $ 214 $ 58
Add: Goodwill amortization, net of tax ...... 27 --
-------- --------
Adjusted net income ......................... $ 241 $ 58
======== ========
Basic and Diluted Earnings Per Share:
Reported net income ......................... $ 0.71 $ 0.20
Add: Goodwill amortization, net of tax ...... 0.09 --
-------- --------
Adjusted basic and diluted earnings ......... $ 0.80 $ 0.20
======== ========
20
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2001 2002
-------- --------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Reported net income ......................... $ 524 $ 99
Add: Goodwill amortization, net of tax ...... 44 --
-------- --------
Adjusted net income ......................... $ 568 $ 99
======== ========
Basic Earnings Per Share:
Reported net income ......................... $ 1.93 $ 0.34
Add: Goodwill amortization, net of tax ...... 0.16 --
-------- --------
Adjusted basic earnings ..................... $ 2.09 $ 0.34
======== ========
Diluted Earnings Per Share:
Reported net income ......................... $ 1.92 $ 0.34
Add: Goodwill amortization, net of tax ...... 0.16 --
-------- --------
Adjusted diluted earnings ................... $ 2.08 $ 0.34
======== ========
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2001 SEPTEMBER 30, 2002
-------------------------- ---------------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Air Emission Regulatory Allowances .................... $ 255 $ (78) $ 271 $ (88)
Water Rights .......................................... 68 (4) 68 (6)
Other Power Generation Site Permits ................... 77 (3) 77 (5)
Contractual rights .................................... -- -- 92 (9)
Other ................................................. -- -- 3 --
------ ------ ------ -------
Total ................................................. $ 400 $ (85) $ 511 $ (108)
====== ====== ====== =======
The Company recognizes specifically identifiable intangibles, including
air emissions regulatory allowances, water rights and permits, when specific
rights and contracts are acquired. The Company has no intangible assets with
indefinite lives recorded as of September 30, 2002. The Company amortizes air
emissions regulatory allowances primarily on a units-of-production basis as
utilized. The Company amortizes other acquired intangibles, excluding
contractual rights, on a straight-line basis over the lesser of their
contractual or estimated useful lives with a weighted average amortization
period of 35 years.
In connection with the acquisition of Orion Power, the Company recorded
the fair value of certain fuel and power contracts acquired. The Company
estimated the fair value of the contracts using forward pricing curves over the
life of each contract. Those contracts with positive fair value at the date of
acquisition (Contractual Rights) were recorded to intangible assets and those
contracts with negative fair value at the date of acquisition (Contractual
Obligations) were recorded to other current and long-term liabilities in the
Consolidated Balance Sheet.
Contractual Rights and Contractual Obligations are amortized to fuel
expense and revenues, as applicable, based on the estimated realization of the
fair value established on the acquisition date over the contractual lives.
Additionally, the time value portion of the contract's value is amortized to
interest expense over the contractual lives. There may be times during the life
of the contract when accumulated amortization exceeds the carrying value of the
recorded assets or liabilities due to the timing of realizing the fair value
established on the acquisition date.
Amortization expense for other intangibles, excluding Contractual
Rights, for the three months ended September 30, 2001 and 2002 was $9 million
and $7 million, respectively. Amortization expense for other intangibles,
excluding Contractual Rights, for the nine months ended September 30, 2001 and
2002 was $39 million and $15 million, respectively. Estimated amortization
expense for the remainder of 2002 and the five succeeding fiscal years is as
follows (in millions):
21
2002 ......................... $ 7
2003 ......................... 23
2004 ......................... 13
2005 ......................... 13
2006 ......................... 12
2007 ......................... 12
-----
Total ...................... $ 80
=====
The Company amortized $2 million and $9 million of Contractual Rights
during the three and nine months ended September 30, 2002, respectively. The
Company amortized $49 million and $59 million of Contractual Obligations during
the three and nine months ended September 30, 2002, respectively. Estimated
amortization of Contractual Rights and Contractual Obligations for the remainder
of 2002 and the five succeeding fiscal years is as follows (in millions):
NET (INCREASE)
CONTRACTUAL CONTRACTUAL DECREASE IN
RIGHTS OBLIGATIONS INCOME
----------- ----------- --------------
2002 .............................. $ 8 $ -- $ 8
2003 .............................. 25 (52) (27)
2004 .............................. 30 (44) (14)
2005 .............................. 18 (7) 11
2006 .............................. 14 (1) 13
2007 .............................. 21 -- 21
--------- ------- ---------
Total ........................... $ 116 $ (104) $ 12
========= ======= =========
Changes in the carrying amount of goodwill for the nine months ended
September 30, 2002, by reportable segment, are as follows:
GOODWILL FOREIGN
ACQUIRED CURRENCY
AS OF DURING THE EXCHANGE AS OF
JANUARY 1, 2002 PERIOD IMPAIRMENT IMPACT OTHER SEPTEMBER 30, 2002
--------------- ---------- ---------- ---------- ---------- ------------------
(IN MILLIONS)
Wholesale Energy......... $ 184 $ 1,448 $ - $ - $ 1 $ 1,633
European Energy.......... 675 - (234) 51 - 492
Retail Energy............ 32 - - - - 32
------------ ---------- ----------- ---------- ---------- ----------
Total.................. $ 891 $ 1,448 $ (234) $ 51 $ 1 $ 2,157
============ ========== =========== ========== ========== ==========
During the third quarter of 2002, the Company completed the
transitional impairment test for the adoption of SFAS No. 142 on its
Consolidated Financial Statements, including the review of goodwill for
impairment as of January 1, 2002. This impairment test was performed in two
steps. The initial step was designed to identify potential goodwill impairment
by comparing an estimate of the fair value of the applicable reporting unit to
its carrying value, including goodwill. If the carrying value exceeded fair
value, a second step was performed, which compared the implied fair value of the
applicable reporting unit's goodwill with the carrying amount of that goodwill,
to measure the amount of the goodwill impairment, if any. Based on this
impairment test, the Company recorded an impairment of its European Energy
segment's goodwill of $234 million. This impairment loss was recorded
retroactively as a cumulative effect of a change in accounting principle for the
quarter ended March 31, 2002. Based on the first step of the goodwill impairment
test, no other reporting units' goodwill was impaired.
The circumstances leading to the goodwill impairment of the Company's
European Energy segment included a significant decline in electric margins
attributable to the deregulation of the European electricity market in 2001,
lack of growth in the wholesale energy trading markets in Northwest Europe and
continued regulation of the European fuel markets. The Company's measurement of
the fair value of European Energy was based on both an income approach, using
future discounted cash flows, and a market approach, using acquisition
multiples, including price per Megawatt, based on publicly available data for
recently completed European transactions.
An impairment analysis requires estimates of future market prices,
valuation of plant and equipment, growth, competition and many other factors as
of the determination date. The resulting impairment loss is highly dependent on
these underlying assumptions. Such assumptions are generally consistent with
those utilized in the Company's annual planning process and industry valuation
and appraisal reports. If the assumptions and estimates underlying
22
this goodwill impairment evaluation differ greatly from the actual results or to
the extent that such assumptions change through time, there could be additional
goodwill impairments in the future.
SFAS No. 142 also requires goodwill to be tested annually and between
annual tests if events occur or circumstances change that would more likely than
not reduce the fair value of a reporting unit below its carrying amount. The
Company has elected to perform its annual test for indications of goodwill
impairment as of November 1, in conjunction with the Company's annual planning
process. Subsequent impairments, if any, will be classified as an operating
expense. The Company anticipates finalizing its annual impairment test during
the fourth quarter of 2002 and currently cannot estimate the outcome.
As of March 31, 2002, the Company completed its assessment of
intangible assets and no indefinite lived intangible assets were identified. No
related impairment losses were recorded in the first quarter of 2002 and no
changes were made to the expected useful lives of its intangible assets as a
result of this assessment.
(8) COMPREHENSIVE INCOME
The following table summarized the component of total comprehensive
income:
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------- -------------------------
2001 2002 2001 2002
------ ------ ------ -------
(IN MILLIONS)
Net income ............................................ $ 214 $ 58 $ 524 $ 99
Other comprehensive income (loss):
Foreign currency translation adjustments ............ (79) (15) (74) 61
Changes in minimum benefit liability ................ -- -- (6) --
Cumulative effect of adoption of SFAS No. 133 ....... -- -- (460) --
Deferred gain (loss) from cash flow hedges .......... 14 (113) 451 73
Reclassification of deferred loss (gain) from
cash flow hedges realized in net income ........... (92) 8 31 (19)
Unrealized (loss) gain on available-for-sale
securities ........................................ (3) (3) 11 (2)
Reclassification adjustments for loss (gain) on
sales of available-for-sale securities realized in
net income ............................................ -- (1) (1) (3)
------ ------ ------ -------
Comprehensive income .................................. $ 54 $ (66) $ 476 $ 209
====== ====== ====== =======
(9) BORROWINGS FROM THIRD PARTIES
Credit Facilities. As of September 30, 2002, the Company had $8.1
billion in committed credit facilities of which $365 million remained unused.
Credit facilities aggregating $5.3 billion were unsecured. As of September 30,
2002, letters of credit outstanding under these facilities aggregated $597
million and borrowings of $7.1 billion of which $1.9 billion were classified as
long-term debt, based upon the restructuring of Orion Power subsidiaries'
credit facilities as described in Note 16(b) and the availability of committed
credit facilities and management's intention to maintain these borrowings in
excess of one year. In addition to credit facilities, the Company had long-term
debt totaling $457 million of which $411 million related to bonds issued by
Orion Power.
As of September 30, 2002, the Company had $6.6 billion of committed
credit facilities which will expire by September 30, 2003, $1.7 billion of which
will expire by December 31, 2002. For a discussion of the repayment, refinancing
and/or amendment of certain of these committed credit facilities and our
liquidity concerns, please read Note 2.
The Company entered into a term loan facility during the fourth quarter
of 2001 and amended in January 2002 that provided for $2.9 billion in funding to
finance the purchase of Orion Power. Interest rates on the borrowings under this
facility are based on LIBOR plus 1.75% or a base rate. This facility was funded
on February 19, 2002 for $2.9 billion. As of September 30, 2002, the weighted
average interest rate on outstanding borrowings was 3.0%. This term loan must be
repaid within one year from the date on which it was funded. For discussion of
the acquisition of Orion Power, see Note 6.
23
The Company termed out its $800 million unsecured 364-day revolving
credit facility before it matured on August 22, 2002. The facility agreement
allowed the Company the option to borrow the entire amount and convert it,
provided that there was no default on the conversion date, to a one-year term
loan with a maturity of August 22, 2003. Interest rates on the borrowings are
based on the London inter-bank offered rate (LIBOR) plus a margin, based on the
Company's credit rating, a base rate or a rate determined through a bidding
process. The LIBOR margin as of September 30, 2002 was 1.375%.
Sale of Receivables. In July 2002, the Company entered into an
arrangement (Receivables Facility) with a financial institution to sell an
undivided interest in accounts receivable from residential and small commercial
retail electric customers under which, on an ongoing basis, the financial
institution will invest a maximum of $250 million for its interest in such
receivables. The Receivables Facility expires July 2003 and may be renewed at
the Company's option and the option of the financial institution participating
in the Receivables Facility. If the Receivables Facility is not renewed on its
termination date, the collections from the receivables purchased will repay the
financial institution's investment and no new receivables will be purchased
under the Receivables Facility. There can be no assurance that the financial
institution participating in the Receivables Facility will agree to a renewal.
The Receivables Facility may be increased to an amount greater than $250 million
on a seasonal basis, subject to the availability of receivables and approval by
the participating financial institution.
The Company received net proceeds in an initial amount of $230 million
at the inception of the Receivables Facility. That amount was increased to $250
million on August 23, 2002. The amount of funding available to the Company under
the Receivables Facility will fluctuate based on the amount of receivables
available which, in turn, is effected by seasonal changes in demand for
electricity. As of November 8, 2002, the amount of funding outstanding under the
Company's Receivables facility was $235 million as the Company's receivables had
decreased with the lower demand for electricity due to cooler autumn weather.
Pursuant to the Receivables Facility, the Company formed a qualified
special purpose entity (QSPE), as a bankruptcy remote subsidiary. The QSPE was
formed for the sole purpose of buying and selling receivables generated by the
Company. The QSPE is a separate entity and its assets will be available first
and foremost to satisfy the claims of its creditors. The Company, irrevocably
and without recourse, transfers receivables to the QSPE. The QSPE, in turn,
sells an undivided interest in these receivables to the participating financial
institution. The Company is not ultimately liable for any failure of payment of
the obligors on the receivables. The Company has, however, guaranteed the
performance obligations of the sellers and the servicer of the receivables under
the related documents.
The two-step transaction described in the above paragraph is accounted
for as a sale of receivables under the provisions of SFAS No. 140 "Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities" (SFAS No. 140), and as a result the related receivables are
excluded from the Consolidated Balance Sheet. Costs associated with the sale of
receivables, $4 million for both the three and nine months ended September 30,
2002, primarily the discount and loss on sale, is included in other expense in
the Company's Statement of Consolidated Income. During the three and nine months
ended September 30, 2002, an accumulated $521 million of receivables had been
sold and the sale has been reflected as a reduction of accounts receivable in
the Company's Consolidated Balance Sheet. The Company has a note receivable from
the QSPE for approximately $254 million at September 30, 2002, which is included
on the Consolidated Balance Sheet. This note is the difference between the
amount of receivables sold to the QSPE and the receivables sold by the QSPE to
the financial institution.
Refinancing of Certain REPGB Debt. During July 2002, REPGB renewed its
364-day revolving credit facility for another year. The term of this facility is
now scheduled to expire in July 2003. The amount of the credit facility was
reduced from Euro 250 million (approximately $247 million) to Euro 184 million
(approximately $182 million). An option was added that permits REPGB to utilize
up to Euro 100 million (approximately $99 million) of the facility for letters
of credit. As of September 30, 2002, there were $35 million and $17 million of
borrowings and letters of credit outstanding, respectively, under this facility.
The revolving credit facility bears interest at the rate of inter-bank offered
rate for Euros (EURIBOR) plus a margin depending on REPGB's credit rating. The
EURIBOR margin as of September 30, 2002 was 1.40%. The weighted average interest
rate on outstanding borrowings as of September 30, 2002, was 4.73%. The credit
facility contains certain covenants and negative pledges that must be met by
REPGB to borrow funds or obtain letters of credit, that require REPGB to, among
other things, maintain a ratio of net balance sheet debt to the sum of net
balance sheet debt and total equity of 0.60 to 1.00. These covenants are not
anticipated to materially restrict REPGB from borrowing funds or obtaining
letters of credit, as applicable, under this facility.
24
Orion Power's Debt Obligations. As a result of the Company's
acquisition of Orion Power, the Company's consolidated net debt obligations also
increased by the amount of Orion Power's net debt obligations, which are
discussed below.
Revolving Senior Credit Facility. As of September 30, 2002, Orion Power
had an unsecured revolving senior credit facility. As part of the ongoing
refinancing negotiations the amount of this facility was reduced on September 6,
2002, from $75 million to $62 million in conjunction with a reduction of the
total letters of credit outstanding. Amounts outstanding under the facility bore
interest at a floating rate. As of September 30, 2002, there were $51 million of
borrowings outstanding under this facility, and a total of $11 million in
letters of credit were also outstanding. This credit facility contained various
covenants that included, among others, restrictions on the payment of dividends
by Orion Power. As of September 30, 2002, restricted cash under this revolving
senior credit facility totaled $10 million.
The senior credit facility of Orion Power contained various business
and financial covenants that required Orion Power to, among other things,
maintain a debt service coverage ratio of at least 1.4 to 1.0. Orion Power did
not meet the debt service coverage ratio for the three months ended June 30,
2002 and September 30, 2002, as required. While the failure to meet such ratio
for two consecutive fiscal quarters is a default under the senior credit
facility, the senior credit facility was amended to provide that such failure
was not considered to be an event of default until the maturity date of the
Orion MidWest credit facility.
This facility was terminated in October 2002 in connection with the
execution of the amended and restated Orion Midwest and Orion NY credit
facilities. See Note 16(b) for further discussion of the debt restructuring.
New York Credit Agreement. As of September 30, 2002, Orion NY, a wholly
owned subsidiary of Orion Power, had a secured credit agreement (New York Credit
Agreement), which includes a $412 million acquisition facility and a $30 million
revolving working capital facility, including letters of credit. As of September
30, 2002, Orion NY had $412 million of acquisition loans outstanding. As of
September 30, 2002, there were no revolving loans outstanding. A total of $10
million in letters of credit were also outstanding under the New York Credit
Agreement. The loans bore interest at the borrower's option at a base rate plus
0.75% or LIBOR plus 1.75%. As of September 30, 2002, the weighted average
interest rate on outstanding borrowings was 3.90%. The credit agreement was
secured by substantially all of the assets of Orion NY and its subsidiaries
excluding certain plant assets. As of September 30, 2002, restricted cash under
the New York Credit Agreement was $261 million.
A subsidiary of Orion NY provided a mortgage with respect to one of the
hydropower plants to the City of Cohoes Industrial Development Agency (CCIDA),
in violation of the negative covenant in the New York Credit Agreement that
limits liens, other than those permitted, on the assets. The transaction was
approved by the lenders and the default was cured in October 2002, in connection
with the restructuring of the Orion New York Credit Agreement. See Note 16(b)
for further discussion of the debt restructuring.
MidWest Credit Agreement. As of September 30, 2002, Orion MidWest, a
wholly owned subsidiary of Orion Power, had a secured credit agreement (Midwest
Credit Agreement), which includes a $988 million acquisition facility and a $75
million revolving working capital facility, including letters of credit. As of
September 30, 2002, Orion MidWest had $988 million and $60 million of
acquisition loans and revolving loans outstanding, respectively. A total of $15
million in letters of credit were also outstanding under the MidWest Credit
Agreement. The loans bore interest at the borrower's option at a base rate plus
1.00% or LIBOR plus 2.00%. As of September 30, 2002, the weighted average
interest rate on outstanding borrowings was 3.83 %. Borrowings under the MidWest
Credit Agreement were secured by substantially all the assets of Orion MidWest
and its subsidiary. As of September 30, 2002, restricted cash under the MidWest
Credit Agreement was $85 million. See Note 16(b) for further discussion of the
debt restructuring.
In connection with the Orion Power acquisition, the existing interest
rate swaps for the New York Credit Agreement and MidWest Credit Agreement
(collectively, the Orion Credit Agreements) were bifurcated into a debt
component and a derivative component. The fair value of the debt component,
approximately $31 million for the New York Credit Agreement and $59 million for
the MidWest Credit Agreement, was based on the Company's incremental borrowing
rates at the acquisition date for similar types of borrowing arrangements. The
value of the debt component will be amortized to interest expense over the life
of the interest rate swaps to which they relate. For the period from February
20, 2002 through September 30, 2002, $5 million and $12 million was amortized to
interest expense for Orion NY and Orion MidWest, respectively. See Note 4 for
information regarding the Company's derivative financial instruments.
25
The Orion Credit Agreements contained various business and financial
covenants requiring Orion NY or Orion MidWest to, among other things, maintain a
debt service coverage ratio of at least 1.5 to 1.0. Because it was anticipated
that Orion MidWest would not meet this ratio for the quarter ended September 30,
2002, the MidWest Credit Agreement was amended to provide that Orion MidWest was
not required to meet this ratio for that quarter, and was subsequently amended
to remove this requirement entirely.
The Midwest and New York Credit Agreements were amended and restated in
October 2002 to extend the maturity of the agreements by 3 years, to October 28,
2005. See Note 16(b) for additional discussion of the amended and restated
agreements.
Liberty Credit Agreement. Liberty Electric Power, LLC (LEP) and Liberty
Electric PA, LLC (Liberty), wholly owned subsidiaries of Orion Power, entered
into a facility that provides for (a) a construction/term loan in an amount of
up to $105 million; (b) an institutional term loan in an amount of up to $165
million; (c) a revolving working capital facility for an amount of up to $5
million; and (d) a debt service reserve letter of credit facility of $17.5
million (Liberty Credit Agreement).
In May 2002, the construction loan was converted to a term loan. As of
the conversion date, the term loan had an outstanding principal balance of $270
million, with $105 million having a final maturity in 2012 and the balance
having maturities through 2026. On the conversion date, Orion Power made the
required cash equity contribution of $30 million into Liberty, which was used to
repay a like amount of equity bridge loans advanced by the lenders. A related
$41 million letter of credit furnished by Orion Power as credit support was
returned for cancellation. In addition, on the conversion date, a $17.5 million
letter of credit was issued in satisfaction of Liberty's obligation to provide a
debt service reserve. The project financing facility also provides for a $5
million working capital line of credit. The debt service reserve letter of
credit facility and the working capital facility expire in May 2007.
Amounts outstanding under the Liberty Credit Agreement bear interest at
a floating rate for a portion of the facility, which may be either LIBOR plus
1.25% or a base rate, except for the institutional term loan which bears
interest at a fixed rate. At September 30, 2002, the weighted average interest
rate on the outstanding borrowings was 3.11% on the floating rate component and
9.02% on the fixed rate portion. As of September 30, 2002, Liberty had $105
million and $165 million of the floating rate and fixed rate portions of the
facility outstanding, respectively. A total of $17.5 million in letters of
credit were also outstanding under the Liberty Credit Agreement.
The lenders under the Liberty Credit Agreement have a security interest
in substantially all of the assets of Liberty. The Liberty Credit Agreement
contains restrictive covenants that restrict Liberty's ability to, among other
things, make dividend distributions unless Liberty satisfies various conditions.
As of September 30, 2002, restricted cash under the Liberty Credit Agreement
totaled $24 million.
For additional information regarding the LEP and Liberty credit
facility related issues and concerns, see Note 12(i).
Senior Notes. Orion Power has outstanding $400 million aggregate
principal amount of 12% senior notes due 2010 (Senior Notes). The Senior Notes
are senior unsecured obligations of Orion Power. Orion Power is not required to
make any mandatory redemption or sinking fund payments with respect to the
Senior Notes. The Senior Notes are not guaranteed by any of Orion Power's
subsidiaries. In connection with the Orion Power acquisition, the Company
recorded the Senior Notes at estimated fair value of $479 million. The $79
million premium will be amortized against interest expense over the life of the
Senior Notes. For the period February 20, 2002 to September 30, 2002, $4 million
was amortized to interest expense for the Senior Notes. The fair value of the
Senior Notes was based on the Company's incremental borrowing rates for similar
types of borrowing arrangements as of the acquisition date. The Senior Notes
indenture contains covenants that include among others, restrictions on the
payment of dividends by Orion Power.
Pursuant to certain change of control provisions, Orion Power commenced
an offer to repurchase the Senior Notes on March 21, 2002. The offer to
repurchase expired on April 18, 2002. There were no acceptances of the offer to
repurchase and the entire $400 million aggregate principal amount remains
outstanding. Before May 1, 2003, Orion Power may redeem up to 35% of the Senior
Notes issued under the indenture at a redemption price of 112% of the principal
amount of the notes redeemed, plus accrued and unpaid interest and special
interest, with the net cash proceeds of an equity offering provided that certain
provisions under the indenture are met.
26
Convertible Senior Notes. Orion Power had outstanding $200 million of
aggregate principal amount of 4.5% convertible senior notes, due on June 1, 2008
(Convertible Senior Notes). Pursuant to certain change of control provisions,
Orion Power commenced an offer to repurchase the Convertible Senior Notes on
March 1, 2002, which expired on April 10, 2002. During the second quarter of
2002, the Company repurchased $189 million in principal amount under the offer
to repurchase and $11 million aggregate principal amount of the Convertible
Senior Notes remained outstanding as of September 30, 2002. During the fourth
quarter of 2002, the remaining $11 million aggregate principal amount of the
Convertible Senior Notes were repurchased for $8.4 million.
(10) TREASURY STOCK
On December 6, 2001, Reliant Resources' Board of Directors authorized
the Company to purchase up to 10 million shares of its common stock through June
2003. Any purchases will be made on a discretionary basis in the open market or
otherwise at times and in amounts as determined by management subject to market
conditions, legal requirements and other factors. Since the date of
authorization through November 8, 2002, the Company has not purchased any shares
of its common stock under this program.
In January and July 2002, the Company sold 550,781 and 776,062,
respectively, treasury shares to employees under an employee stock purchase plan
at a price of $14.07 per share and $7.44 per share, respectively. In April 2002,
the Company made a discretionary annual contribution of 308,936 shares to the
employee savings plan. The Company funded its contribution using treasury
shares.
(11) EARNINGS PER SHARE
The following tables present Reliant Resources' basic and diluted
earnings per share (EPS) calculation. There were no dilutive reconciling items
to net income.
FOR THE THREE MONTHS ENDED SEPTEMBER 30,
----------------------------------------
2001 2002
-------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Weighted average shares outstanding ........................ 299,164 290,425
======== ========
Diluted EPS Calculation:
Weighted average shares outstanding ........................ 299,164 290,425
Plus: Incremental shares from assumed conversions:
Stock options .......................................... -- 13
Restricted stock ....................................... 186 977
Employee stock purchase plan ........................... 60 169
-------- --------
Weighted average shares assuming dilution ................ 299,410 291,584
======== ========
Basic and Diluted EPS ...................................... $ 0.71 $ 0.20
======== ========
For the three months ended September 30, 2002, the computation of
diluted EPS excludes purchase options for 20,008,790 shares of common stock that
have an exercise price (ranging from $6.20 - $34.03 per share) greater than the
per share average market price ($5.21) for the period and would thus be
anti-dilutive if exercised. For the three months ended September 30, 2001, the
computation of diluted EPS excludes purchase options for 8,671,268 shares of
common stock that have an exercise price (ranging from $23.20 - $34.03) greater
than the per share average market price ($21.08) for the period and would thus
be anti-dilutive if exercised.
27
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
---------------------------------------
2001 2002
------------ ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Weighted average shares outstanding ........................ 272,253 289,788
============ ============
Diluted EPS Calculation:
Weighted average shares outstanding ........................ 272,253 289,788
Plus: Incremental shares from assumed conversions:
Stock options .......................................... 2 769
Restricted stock ....................................... 186 977
Employee stock purchase plan ........................... 60 169
------------ ------------
Weighted average shares assuming dilution ................ 272,501 291,703
============ ============
Basic EPS:
Income before cumulative effect of accounting change ..... $ 1.92 $ 1.15
Cumulative effect of accounting change, net of tax ....... 0.01 (0.81)
------------ ------------
Net income ............................................... $ 1.93 $ 0.34
============ ============
Diluted EPS:
Income before cumulative effect of accounting change ..... $ 1.91 $ 1.14
Cumulative effect of accounting change, net of tax ....... 0.01 (0.80)
------------ ------------
Net income ............................................... $ 1.92 $ 0.34
============ ============
For the nine months ended September 30, 2002, the computation of
diluted EPS excludes purchase options for 14,581,582 shares of common stock that
have an exercise price (ranging from $10.29 - $34.03 per share) greater than the
per share average market price ($10.23) for the period and would thus be
anti-dilutive if exercised. For the nine months ended September 30, 2001, the
computation of diluted EPS excludes purchase options for 8,505,100 shares of
common stock that have an exercise price (ranging from $30.00 - $34.03) greater
than the per share average market price ($25.48) for the period and would thus
be anti-dilutive if exercised.
(12) COMMITMENTS AND CONTINGENCIES
(a) Legal Matters.
Southern California Class Actions. Reliant Energy, Reliant Energy
Services, Inc. (Reliant Energy Services), Reliant Energy Power Generation, Inc.
(REPG) and several other subsidiaries of Reliant Resources, as well as two
former officers and one present officer have been named as defendants in class
action lawsuits and other lawsuits filed against a number of companies that own
generation plants in California and other sellers of electricity in California
markets. Three of these lawsuits were filed in the Superior Court of the State
of California, San Diego County; two were filed in the Superior Court in San
Francisco County; and one was filed in the Superior Court of Los Angeles County.
While the plaintiffs allege various violations by the defendants of state
antitrust laws and state laws against unfair and unlawful business practices,
each of the lawsuits is grounded on the central allegation that the defendants
conspired to drive up the wholesale price of electricity. In addition to
injunctive relief, the plaintiffs in these lawsuits seek treble the amount of
damages alleged, restitution of alleged overpayments, disgorgement of alleged
unlawful profits for sales of electricity, costs of suit and attorneys' fees.
Plaintiffs have voluntarily dismissed Reliant Energy from two of the three class
actions in which it was named as a defendant.
The cases were initially removed to federal court and were then
assigned to Judge Robert H. Whaley, United States District Judge, pursuant to
the federal procedures for multi-district litigation. On July 30, 2001, Judge
Whaley remanded the cases to state court. Upon remand to state court, the cases
were assigned to Superior Court Judge Janis L. Sammartino pursuant to the
California state coordination procedures. On March 4, 2002, Judge Sammartino
adopted a schedule proposed by the parties that would result in a trial
beginning on March 1, 2004. On March 8, 2002, the plaintiffs filed a single,
consolidated complaint naming numerous defendants, including Reliant Energy
Services and other Reliant Resources' subsidiaries, that restated the
allegations described above and alleged that damages against all defendants
could be as much as $1 billion. On April 22 and 23, 2002, the Company and Duke
Energy filed cross complaints in the coordinated proceedings seeking, in an
alternative pleading, relief against other market participants in California,
the surrounding states, Canada and Mexico including Powerex Corp., the
28
Los Angeles Department of Water and Power and the Bonneville Power
Administration. Powerex Corp., Bonneville Power Administration and British
Columbia Hydro and Power Authority removed the case once again to federal court
where it was re-assigned to Judge Whaley. On July 10, 2002, a motion to dismiss
was filed in coordinated proceedings seeking dismissal of the complaints on the
basis of the filed rate doctrine and federal preemption. On September 19, 2002,
Judge Whaley heard arguments on plaintiffs' motion to remand the cases back to
state court. The matter is under consideration by the court.
California Attorney General Actions. On March 11, 2002, the California
Attorney General filed a civil lawsuit in San Francisco Superior Court naming
Reliant Energy, Reliant Resources, Reliant Energy Services, REPG, and several
other subsidiaries of Reliant Resources as defendants. The Attorney General
alleges various violations by the defendants of state laws against unfair and
unlawful business practices arising out of transactions in the markets for
ancillary services run by the California Independent System Operator (Cal ISO).
In addition to injunctive relief, the Attorney General seeks restitution and
disgorgement of alleged unlawful profits for sales of electricity and civil
penalties. The Company removed this lawsuit to federal court, where it has been
assigned to Judge Vaughn Walker in the Northern District of California. Judge
Walker denied the California Attorney General's motion to remand this case to
state court. The Company filed a motion to dismiss this action, which is under
consideration by the court.
On March 19, 2002, the California Attorney General filed a complaint
with the Federal Energy Regulatory Commission (FERC) naming Reliant Energy
Services and "all other public utility sellers" in California as defendants. The
complaint alleges that sellers with market-based rates have violated their
tariffs by not filing with the FERC transaction-specific information about all
of their sales and purchases at market-based rates. The California Attorney
General argued that, as a result, all past sales should be subject to refund if
found to be above just and reasonable levels. On May 31, 2002, the FERC issued
an order that largely denied the complaint and required only that Reliant Energy
Services and other sellers file revised transaction reports regarding prior
sales in California spot markets. On September 23, 2002, the FERC issued an
order denying rehearing of the May 31, 2002 order. On September 24, 2002, the
California Attorney General petitioned the Court of Appeals for the Ninth
Circuit for review of these orders.
On April 15, 2002, the California Attorney General filed a lawsuit in
San Francisco County Superior Court against Reliant Energy, Reliant Resources,
Reliant Energy Services and several other subsidiaries of Reliant Resources. The
complaint is substantially similar to the compliant described above filed by the
California Attorney General with the FERC on March 19, 2002. The complaint also
alleges that the Company consistently charged unjust and unreasonable prices for
electricity, and that each instance of overcharge violated California law. The
lawsuit seeks fines of up to $2,500 for each alleged violation, and "other
equitable relief as appropriate." The Company has removed this case to federal
court, where it has been assigned to Judge Vaughn Walker in the Northern
District of California. Judge Walker has denied the California Attorney
General's motion to remand this case to state court. The Company filed a motion
to dismiss this action, which is under consideration by the court.
On April 15, 2002, the California Attorney General and the California
Department of Water Resources filed a complaint in the United States District
Court for the Northern District of California against Reliant Energy, Reliant
Resources and a number of Reliant Resources' subsidiaries. In this lawsuit, the
Attorney General alleges that the Company's acquisition of electric generating
facilities from Southern California Edison in 1998 violated Section 7 of the
Clayton Act, which prohibits mergers or acquisitions that substantially lessen
competition. The lawsuit claims that the acquisitions gave the Company market
power which it then exercised to overcharge California consumers for
electricity. The lawsuit seeks injunctive relief against alleged unfair
competition, divestiture of the Company's California facilities, disgorgement of
alleged illegal profits, damages, and civil penalties for each alleged exercise
of market power. This lawsuit also has been assigned to Judge Vaughn Walker. The
Company filed a motion to dismiss this action, which is under consideration by
the court.
Northern California Class Actions. In the wake of the filing of the
Attorney General cases, there have been seven new class action cases filed in
state courts in Northern California. Each of these purports to represent the
same class of California ratepayers, assert the same claims as asserted in the
Southern California class action cases, and in some instances repeat as well the
allegations in the Attorney General cases. All of these cases have been removed
to federal court and plaintiffs filed motions to remand. In October 2002, the
Panel on Multidistrict Litigation transferred these cases to Judge Whaley for
coordination with the Southern California class actions.
On October 21, 2002, the Company received notice that a new class
action has been filed in Los Angeles County Superior Court. The complaint is
virtually identical to those filed in Northern California and names as
defendants Reliant Energy and five subsidiaries of Reliant Resources. The
Company has not yet been served.
29
Washington Class Action. After the filing of the Northern California
class actions, a separate class action suit was filed in federal court in Los
Angeles on behalf of the Snohomish County Public Utility District and its
customers in the State of Washington. In September 2002, the Panel on
Multidistrict Litigation transferred this case to Judge Whaley for coordination
with the Southern California class actions. Defendants have filed a motion to
dismiss the case and a hearing on such motion has been set for December 19,
2002.
The Company has not answered any of the above-referenced class action
cases; however, it has moved to dismiss each of the cases on the grounds that
the claims are barred by federal preemption and the filed rate doctrine.
Pursuant to the terms of the Master Separation Agreement (see Note 4(c)
to the Reliant Resources 10-K/A Notes), Reliant Resources has agreed to
indemnify CenterPoint Energy for any damages arising under these lawsuits and
may elect to defend these lawsuits at the Company's own expense.
FERC Complaints. On April 11, 2002, the FERC set for hearing a series
of complaints filed by Nevada Power Company, which seek reformation of certain
forward power contracts, including two contracts with Reliant Energy Services
that have since been terminated. Proceedings are ongoing before an
administrative law judge who anticipates issuing a decision in December 2002 for
consideration by the FERC. PacifiCorp Company filed a similar complaint
challenging two ninety-day contracts with Reliant Energy Services, which the
FERC also has set for hearing. The FERC has stated that it intends to issue a
decision in both cases by May 31, 2003.
Trading and Marketing Activities. The Company is party to numerous
lawsuits and regulatory proceedings relating to its trading and marketing
activities, including (a) round trip trades, as more fully described in Note 1,
and (b) structured transactions. In addition, various state and federal
governmental agencies have commenced investigations relating to such activities.
Their ultimate outcome cannot be predicted at this time. Additional information
regarding certain of these matters is set forth below.
In June 2002, the SEC advised the Company that it had issued a formal
order in connection with its investigation of the Company's financial reporting,
internal controls and related matters. Reliant Resources understands that the
investigation is focused on its round trip trades and structured transactions.
These matters were previously the subject of an informal inquiry by the SEC. The
SEC's formal order is also addressed to Reliant Energy. Reliant Resources is
cooperating with the SEC staff.
As part of the Commodity Futures Trading Commission's (CFTC)
industry-wide investigation of so-called round trip trading, the CFTC has
subpoenaed documents, requested information and conducted discovery relating to
Reliant Resources' natural gas and power trading activities, including round
trip trades and alleged price manipulation, occurring since January 1, 1999.
Reliant Resources is cooperating with the CFTC staff.
On August 13, 2002, the FERC staff issued its Initial Report on Fact
Finding Investigation of Potential Manipulation of Electric and Gas Prices
(Initial Report). Certain findings, conclusions and observations in the staff
report, if adopted or otherwise acted on by the FERC, could have a material
adverse effect on the Company. For example, in the Initial Report the FERC staff
recommends that the mitigated market clearing prices for purposes of determining
refunds in the pending refund proceeding described in Note 12(c) should be based
on gas costs determined using producing basin spot prices plus regulated
transportation costs instead of the published gas price indices for deliveries
in California, as the FERC originally ordered. Such a change in the refund
methodology, if adopted, would likely have an adverse impact on the Company's
potential refund obligations. Other findings, conclusions and observations in
the report may likewise have a material adverse effect on the Company if adopted
or otherwise acted upon.
In the Initial Report, the FERC Staff indicated that it is continuing
to receive and review data, including information relevant to the subjects
covered in the report. In this regard, the Company has provided information to
FERC about its trading activities in the Western United States during 2000 and
2001. Included among the data requests the Company has received from the FERC
are requests asking for information regarding power trading activity, natural
gas trading for specific periods or locations, certain trading practices, round
trip trades and
30
compliance with supplemental dispatch requests. The Company has received
additional data requests regarding gas trading in the West. The Company is
cooperating and will continue to cooperate with the FERC. The ultimate outcome
of the investigation cannot be predicted at this time.
The Company has received subpoenas and informal request from the United
States Attorney for the Southern District of New York and Northern District of
California requesting documents, interviews and other information pertaining to
the round trip trades, and the Company's energy trading activities. These
inquiries appear to parallel that of the SEC, the CFTC and the FERC. The Company
is cooperating with the office of the United States Attorney.
In connection with the Texas Utility Commission's industry-wide
investigation into potential manipulation of the ERCOT market, the Company has
provided information to the Texas Utility Commission concerning its scheduling
and trading practices on and after July 31, 2001. Also, the Company, and four
other qualified scheduling entities in ERCOT, reached a settlement relating to
scheduling issues that arose during August 2001. The Texas Utility Commission
approved the settlement on November 7, 2002.
In May, June and July 2002, eleven class action lawsuits were filed on
behalf of purchasers of securities of Reliant Resources and/or Reliant Energy.
Reliant Resources and several of its executive officers are named as defendants.
Reliant Energy is also named as a defendant in three of the lawsuits. Two of the
lawsuits also name as defendants the underwriters of the IPO. One of those two
lawsuits also names Reliant Resources' and Reliant Energy's independent auditors
as a defendant. The dates of filing of these lawsuits are as follows: two
lawsuits on May 15, 2002; two lawsuits on May 16, 2002; one lawsuit on May 17,
2002; one lawsuit on May 20, 2002; one lawsuit on May 21, 2002; one lawsuit on
May 23, 2002; one lawsuit on June 19, 2002; one lawsuit on June 20, 2002; and
one lawsuit on July 1, 2002. Ten of the lawsuits were filed in the United States
District Court, Southern District of Texas, Houston Division. One lawsuit was
filed in the United States District Court, Eastern District of Texas, Texarkana
Division.
The complaints allege that the defendants overstated the revenues of
the Company by including transactions involving the purchase and sale of
commodities with the same counterparty at the same price and that the Company
improperly accounted for certain other transactions. The complaints seek
monetary damages and, in one of the lawsuits rescission, on behalf of a supposed
class. In eight of the lawsuits, the supposed class is composed of persons who
purchased or otherwise acquired Reliant Resources and/or Reliant Energy
securities during specified class periods. The three lawsuits that include
Reliant Energy as a named defendant were also filed on behalf of purchasers of
securities of Reliant Resources and/or Reliant Energy during specified class
periods.
Additionally, in May and June 2002, four class action lawsuits were
filed on behalf of purchasers of securities of Reliant Energy. Reliant Energy
and several of its executive officers are named as defendants. The dates of
filing of the four lawsuits are as follows: one on May 16, 2002; one on May 21,
2002; one on June 13, 2002; and one on June 17, 2002. The lawsuits were filed in
the United States District Court, Southern District of Texas, Houston Division.
The complaints allege that the defendants violated federal securities laws by
issuing false and misleading statements to the public. The plaintiffs allege
that the defendants made false and misleading statements as part of an alleged
scheme to artificially inflate trading volumes and revenues by including
transactions involving the purchase and sale of commodities with the same
counterparty at the same price, to spin-off Reliant Resources to avoid exposure
to Reliant Resources' liabilities and to cause the price of Reliant Resources'
stock to rise artificially, among other things. The complaints seek monetary
damages on behalf of persons who purchased Reliant Energy securities during
specified class periods.
By order dated August 1, 2002, the court consolidated ten of the cases
pending in the United States District Court, Southern District of Texas, Houston
Division. By order dated August 27, 2002, the court consolidated the remaining
four cases in the Houston Division. In the same order, the court appointed the
Boca Raton Police & Firefighters Retirement System and the Louisiana Retirement
Funds to be lead plaintiffs. By order dated August 22, 2002, the remaining
securities case was transferred from United States District Court for the
Eastern District of Texas, Texarkana Division, to the Southern District of
Texas, Houston Division. By order dated September 20, 2002, the court
consolidated the case originally filed in the Texarkana Division with the
fourteen cases previously consolidated in the Houston Division.
In May 2002, three class action lawsuits were filed on behalf of
participants in various employee benefits plans sponsored by Reliant Energy.
Reliant Energy and its directors are named as defendants in all of the lawsuits.
Reliant Resources is named as a defendant in two of the lawsuits. The lawsuits
were filed on May 29, 2002, May 30, 2002, and May 31, 2002. All of the lawsuits
were filed in the United States District Court, Southern District of
31
Texas, Houston Division. By order dated June 20, 2002, the Court granted the
motion for voluntary dismissal filed by the plaintiffs in one of the cases and
dismissed that case without prejudice. By Order dated August 21, 2002, the Court
granted the motion for voluntary dismissal filed by the plaintiff in one of the
two remaining cases and dismissed that case without prejudice.
The remaining complaint alleges that the defendants breached their
fiduciary duties to various employee benefits plans sponsored by Reliant Energy,
in violation of the Employee Retirement Income Security Act. The plaintiffs
allege that the defendants permitted the plans to purchase or hold securities
issued by Reliant Energy when it was imprudent to do so, including after the
prices for such securities became artificially inflated because of alleged
securities fraud engaged in by the defendants. The complaints seek monetary
damages for losses suffered by a putative class of plan participants whose
accounts held Reliant Energy or Reliant Resources securities, as well as
equitable relief in the form of restitution.
In May 2002, a derivative action was filed against the directors and
independent auditors of Reliant Resources. The lawsuit was filed on May 17,
2002, in the 269th Judicial District, Harris County, Texas. The petition alleges
that the defendants breached their fiduciary duties to the Company. The
shareholder plaintiff alleges that the defendants caused the Company to conduct
its business in an imprudent and unlawful manner, including allegedly failing to
implement and maintain an adequate internal accounting control system, engaging
in transactions involving the purchase and sale of commodities with the same
counterparty at the same price, and disseminating materially misleading and
inaccurate information regarding the Company's revenue and trading volume. The
petition seeks monetary damages on behalf of the Company.
The above-described lawsuits and proceedings are currently the subject
of intense, highly-charged media and political attention. As these matters
progress, additional issues may be identified that could expose the Company to
further lawsuits and proceedings. Their ultimate outcome cannot be predicted at
this time.
Other Legal and Environmental Matters. The Company is involved in other
environmental and legal proceedings before various courts and governmental
agencies regarding matters arising in the ordinary course of business, some of
which involve substantial amounts. The Company's management regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters.
(b) Environmental Matters.
REMA Ash Disposal Site Closures and Site Contaminations. Under the
agreement to acquire REMA (see Note 5(a) to the Reliant Resources 10-K/A Notes),
the Company became responsible for liabilities associated with ash disposal site
closures and site contamination at the acquired facilities in Pennsylvania and
New Jersey prior to a plant closing, except for the first $6 million of
remediation costs at the Seward Generating Station. A prior owner retained
liabilities associated with the disposal of hazardous substances to off-site
locations prior to November 24, 1999. As of September 30, 2002, REMA had
liabilities associated with six future ash disposal site closures and six
current site investigations and environmental remediations. The Company has
recorded its estimate of these environmental liabilities in the amount of $32
million as of September 30, 2002. The Company expects approximately $13 million
will be paid over the next five years.
REPGB Asbestos Abatement and Environmental Remediation. Prior to the
Company's acquisition of REPGB (see Note 5(b) to the Reliant Resources 10-K/A
Notes), REPGB had a $23 million obligation primarily related to asbestos
abatement, as required by Dutch law, and soil remediation at six sites. During
2000, the Company initiated a review of potential environmental matters
associated with REPGB's properties. REPGB began remediation in 2000 of the
properties identified to have exposed asbestos and soil contamination, as
required by Dutch law and the terms of some leasehold agreements with
municipalities in which the contaminated properties are located. All remediation
efforts are to be fully completed by 2005. As of September 30, 2002, the
recorded undiscounted liability for asbestos abatement, soil remediation and
plant water system compliance was $20 million.
Orion Power Environmental Contingencies. In connection with Orion
Power's acquisition of 70 hydro plants in northern and central New York and four
gas- or oil- fired plants in New York City, Orion Power assumed the liability
for the estimated cost of environmental remediation at several properties. Orion
Power developed remediation plans for each of these properties and entered into
Consent Orders with the New York State Department of Environmental Conservation
at two New York City sites and one hydro site for releases of petroleum and
other substances by the prior owners. The liability assumed and recorded by the
Company for all New York assets was approximately $10 million, which the Company
expects to pay out through 2006.
In connection with the acquisition of Midwest assets by Orion Power,
Orion Power became responsible for the liability associated with the closure of
three ash disposal sites in Pennsylvania. The liability assumed and recorded
32
by the Company for these disposal sites was approximately $12 million, with $1
million to be paid over the next five years.
(c) California Wholesale Market Uncertainty.
Receivables. During portions of 2000 and 2001, prices for wholesale
electricity in California increased dramatically as a result of a combination of
factors, including higher natural gas prices and emission allowance costs,
reduction in available hydroelectric generation resources, increased demand,
decreased net electric imports and limitations on supply as a result of
maintenance and other outages. The resulting supply and demand imbalance
disproportionately impacted California utilities that relied heavily on
short-term power markets to meet their load requirements. Although wholesale
prices increased, California's deregulation legislation kept retail rates frozen
at 10% below 1996 levels for two of California's public utilities, Pacific Gas
and Electric (PG&E) and Southern California Edison Company (SCE), until rates
were raised by the California Public Utilities Commission (CPUC) early in 2001.
Due to the disparity between wholesale and retail rates, the credit
ratings of PG&E and SCE fell below investment grade. Additionally, PG&E filed
for protection under the bankruptcy laws on April 6, 2001. As a result, PG&E and
SCE are no longer considered creditworthy, and since January 17, 2001, have not
directly purchased power from third-party suppliers through the Cal ISO to serve
that portion of load that cannot be met from their own supply sources (net short
load). Pursuant to emergency legislation enacted by the California Legislature,
the California Department of Water Resources (DWR) has negotiated and purchased
power through short- and long-term contracts and through real-time markets
operated by the Cal ISO to serve the net short load requirements of PG&E and
SCE. In December 2001, the DWR began making payments to the Cal ISO for
real-time transactions. On May 15, 2002, the FERC issued an order stating that
sellers, including the Company, should receive interest payments on past due
amounts owed by the Cal ISO and DWR. The DWR has now made payment through the
Cal ISO for its real-time energy deliveries subsequent to January 17, 2001,
although the Cal ISO's distribution of DWR's payment for the month of January
2001, and the allocation of interest to past due amounts, are the subjects of
motions that the Company has filed with the FERC objecting to the Cal ISO's
failure to allocate the January payment and interest solely to post-January 17,
2001 transactions. In addition, the Company is prosecuting a lawsuit in
California to recover the market value of forward contracts seized by California
Governor Gray Davis in violation of the Federal Power Act. Governor Davis'
actions prevented the liquidation of the contracts by the California Power
Exchange (Cal PX) to satisfy the outstanding obligations of SCE and PG&E to
wholesale suppliers, including the Company. The timing and ultimate resolution
of this claim is uncertain at this time.
On September 20, 2001, PG&E filed a Plan of Reorganization and an
accompanying disclosure statement with the bankruptcy court. Under this plan,
PG&E would pay all allowed creditor claims in full, through a combination of
cash and long-term notes. Components of the plan will require the approval of
the FERC, the SEC and the Nuclear Energy Regulatory Commission, in addition to
the bankruptcy court. PG&E has stated it seeks to have this plan confirmed by
December 31, 2002. On April 24, 2002, the bankruptcy judge approved PG&E's
disclosure statement. A number of parties are contesting PG&E's reorganization
plan, including a number of California parties and agencies. The bankruptcy
judge in the PG&E case has ordered that the CPUC may file a competing plan. The
ability of PG&E to have its reorganization plan confirmed, including the
provision providing for the payment in full of unsecured creditors, is uncertain
at this time. The CPUC has filed a competing plan and disclosure statement which
provides for payment of allowed creditor claims in full in cash. The CPUC
disclosure statement was approved on May 15, 2002. The timing and probability of
confirmation of either plan, including the provision for payment in full of all
unsecured creditors, is uncertain at this time. The Company has signed a
stipulation with PG&E whereby it has agreed to vote for PG&E's reorganization
plan and PG&E has agreed to pay amounts it indirectly owed to the Company
subject to any refunds ordered by the FERC. The stipulation does not preclude
the Company from approving other reorganization plans, including the CPUC plan.
On October 5, 2001, a federal district court in California entered a
stipulated judgment approving a settlement between SCE and the CPUC in an action
brought by SCE regarding the recovery of its wholesale power costs under the
filed rate doctrine. Under the stipulated judgment, a rate increase approved
earlier in 2001 will remain in place until the earlier of SCE recovering $3.3
billion or December 31, 2002. After that date, the CPUC will review the
sufficiency of retail rates through December 31, 2005. A consumer organization
has appealed the judgment to the Ninth Circuit Court of Appeals, and no hearing
has been held to date. Under the stipulated judgment, any settlement with SCE's
creditors that is entered into after March 1, 2002 must be approved by the CPUC.
The Company has appealed this provision of the judgment. On March 1, 2002, SCE
made a payment to the Cal PX that included amounts it owed the Company. The
Company has made a filing with FERC seeking an order providing for the
33
disbursement of the funds owed to the suppliers. The FERC and the bankruptcy
court governing the Cal PX bankruptcy proceedings are considering how to
dispense this money and it remains uncertain when those funds will be paid over
to the Company.
As of December 31, 2001 and September 30, 2002, the Company was owed a
total of $302 million and $233 million (net of estimated refund provision),
respectively, by the Cal ISO, the Cal PX, the DWR, and California Energy
Resources Scheduling for energy sales in the California wholesale market during
the fourth quarter of 2000 through September 30, 2002. From September 30, 2002
through November 8, 2002, the Company has collected $9 million of these
receivable balances. As of December 31, 2001, the Company had a pre-tax credit
provision of $68 million against receivable balances related to energy sales in
the California market. For the nine months ended September 30, 2002, $44 million
of a previously accrued credit provision for energy sales in California was
reversed. The reversal resulted from collections of outstanding receivables
during the period, a determination that credit risk had been reduced on the
remaining outstanding receivables as a result of payments in 2002 to the Cal PX
and the reversal of $11 million of credit provision due to the write-off of
receivables as a result of a May 15, 2002 FERC order discussed below. As of
September 30, 2002, the Company had a remaining pre-tax credit provision of $24
million against these receivable balances. Management will continue to assess
the collectability of these receivables based on further developments affecting
the California electricity market and the market participants described herein.
FERC Market Mitigation. In response to the filing of a number of
complaints challenging the level of wholesale prices in California, the FERC
initiated a staff investigation and issued a number of orders implementing a
series of wholesale market reforms. In these orders, the FERC also instituted a
refund proceeding, described below, as a result of which the Company may face an
as yet undetermined amount of refund liability. See "- FERC Refunds" below.
Prior to adopting a methodology for calculating refunds in the refund
proceeding, the FERC identified, for the period January 1, 2001 through June 19,
2001, approximately $20 million of the $149 million charged by the Company for
sales in California to the Cal ISO and the Cal PX as being subject to possible
refunds. During the nine months ended September 30, 2001, the Company accrued
refunds of $15 million.
The FERC initially established an interim market monitoring and
mitigation plan for the California markets that extended until September 30,
2002, and included imposition of price controls to California and other Western
states in all hours as well as a requirement that generators in California offer
all their available capacity for sale in the real-time market. The FERC set July
2, 2001 as the refund effective date for sales subject to the price mitigation
plan throughout the West region. This meant that transactions after that date
may be subject to refund if they exceed the calculated price cap. Sellers other
than marketers that bid higher than the capped price, had a limited opportunity
to justify their bids if they could demonstrate higher gas costs than those
assumed in the price cap calculation.
On July 17, 2002, the FERC issued an order directing short-term and
longer-term redesign of the California wholesale electricity market to take
effect following the interim mitigation plan. On October 11, 2002, the FERC
issued an order clarifying and modifying certain aspects of the new California
market design. On September 26, 2002, FERC granted the Cal ISO's motion to
extend the interim market mitigation measures discussed above until October 30,
2002. Effective October 31, 2002, a $250/MWh soft cap was adopted in place of
the existing price cap of $91.87/MWh and so called automatic mitigation
procedures were implemented. Under this approach, mitigation will be applied if
a bid exceeds $91.87/MWh, results in a 200% or $100/MWh increase above an as yet
undetermined unit-specific reference level, and results in a 200% or $50/MWh
increase in the market clearing price for the zone where the relevant unit is
located. A variation of this formula will be used to cap bids in congested
areas. Bids from outside California are exempt from the automatic mitigation
procedures. Instead, bidders outside California will continue to be "price
takers" by submitting zero bids into Cal ISO markets. The FERC approved new
penalties for generators that fail to generate at levels instructed by the Cal
ISO. The Cal ISO may not impose penalties, however, until it develops software
to recognize various operating constraints on units. The market redesign ordered
by the FERC on July 17, 2002 continues the requirement that generators offer all
available supply into the California market until the FERC determines that
"long-term market-based solutions can be fully implemented."
The October 11, 2002 order of the FERC instructed the Cal ISO to
develop a modified day-ahead market for implementation January 1, 2003, with
full implementation of integrated forward markets by late 2003. The Cal ISO has
petitioned FERC to delay these implementation deadlines. The July 17, 2002 order
also requires adoption by the Cal ISO of a resource adequacy requirement but
does not set a deadline for its development. Other long-term aspects of the
redesign of the Cal ISO market remain open for consideration by the FERC.
34
In a separate order issued July 17, 2002, the FERC ordered that the
current Cal ISO Board of Governors be disbanded and replaced with an independent
Board by January 1, 2003. The Cal ISO Board responded with a filing stating that
it would not disband. The FERC has sued in federal district court for
enforcement of its order and the Cal ISO Board has filed a motion to dismiss
that suit.
FERC Refunds. The FERC issued an order on July 25, 2001 adopting a
refund methodology and initiating a hearing schedule to determine (a) revised
mitigated prices for each hour from October 2, 2000 through June 20, 2001; (b)
the amount owed in refunds by each supplier according to the methodology; and
(c) the amount currently owed to each supplier. The amounts of any refunds will
be determined by the FERC after the Administrative Law Judge makes his
recommendations to the FERC in late 2002. However, the Company does not know
when the FERC will issue its final decision. This decision may be delayed
pending a final report from FERC staff regarding the gas price component of the
refund methodology. Based on the FERC's May 15, 2002 order and the FERC staff's
interpretation of such order, the Company estimates its refund obligation to be
between $70 million and $190 million for energy sales in the West region. Until
the FERC issues additional guidance for refunds, the Company is unable to narrow
the range of estimates for its refund obligations. During the second quarter of
2002, the Company recorded a reserve for refunds of $34 million related to
energy sales in the West region based on the May 15, 2002 order. In the third
quarter of 2002, the Company recorded an additional reserve for refunds of $21
million based in further FERC staff interpretations of the May 15, 2002 FERC
order. As discussed above, $15 million was recognized in the second quarter of
2001. As of September 30, 2002, the Company's total reserve for refunds related
to energy sales in the West region is $70 million. Refunds will likely be offset
against unpaid amounts owed to the Company for its prior sales. The ultimate
outcome of the total refunds within the above range related to energy sales in
the West regions cannot be estimated.
On November 20, 2001, the FERC instituted an investigation under
Section 206 of the Federal Power Act regarding the tariffs of all sellers with
market-based rates authority, including the Company. In this proceeding, the
FERC proposes to condition the market-based rate authority of all sellers on
their not engaging in anti-competitive behavior. Such condition would depend
upon a further order from the FERC establishing a refund effective date. This
condition would allow the FERC, if it determines that a seller has engaged in
anti-competitive behavior subsequent to the start of the refund effective
period, to order refunds back to the date of such behavior. The FERC invited
comments regarding this proposal, and the Company has filed comments in
opposition to the proposal. The timing of further action by the FERC is
uncertain, although the FERC has publicly indicated that it is considering
modifications that would limit the scope and application of its original
proposal. If the FERC implements its proposed approach for dealing with
anti-competitive behavior without modification, the resulting refund obligation
could affect the Company's future earnings.
On February 13, 2002, the FERC issued an order initiating a staff
investigation into potential manipulation of electric and natural gas prices in
the West region for the period January 1, 2000 forward. On August 13, 2002, the
FERC staff issued its Initial Report on Fact Finding Investigation of Potential
Manipulation of Electric and Gas Prices (Initial Report), which is described
above. See Note 12(a) - "Trading and Marketing Activities."
Other Investigations. In addition to the FERC investigation discussed
above, several state and other federal regulatory investigations and complaints
have commenced in connection with the wholesale electricity prices in California
and other neighboring Western states to determine the causes of the high prices
and potentially to recommend remedial action. In California, the California
State Senate and the California Office of the Attorney General have separate
ongoing investigations into the high prices and their causes. Although these
investigations have not been completed and no findings have been made in
connection with either of them, the California Attorney General has filed a
civil lawsuit in San Francisco Superior Court alleging that the Company has
violated state laws against unfair and unlawful business practices and a
complaint with the FERC alleging the Company violated the terms of its tariff
with the FERC (see Note 12(a)). Adverse findings or rulings could result in
punitive legislation, sanctions, fines or even criminal charges against the
Company or its employees. The Company is cooperating with both investigations
and has produced a substantial amount of information requested in subpoenas
issued by each body. The Washington and Oregon attorneys general have also begun
similar investigations. As the above-described investigation and complaints
progress, additional issues may be identified that could expose the Company to
further investigations and complaints. Their ultimate outcome cannot be
predicted at this time.
Legislative Efforts. Since the inception of the California energy
crisis, various pieces of legislation, including tax proposals, have been
introduced in the United States Congress and the California Legislature
addressing several issues related to the increase in wholesale power prices in
2000 and 2001. For example, a bill was introduced in the California legislature
that would have created a "windfall profits" tax on wholesale electricity sales
and would subject exempt wholesale generators, such as the Company's
subsidiaries that own generation facilities in California, to regulation by the
CPUC as "public utilities." To date, only a few energy-related bills have
passed,
35
such as the recently enacted plant inspection law, which would empower the CPUC
to monitor activities of the Company's generating plants. The Company believes
this bill is vulnerable to challenge based on the preemptive effect of the
Federal Power Act. The Company does not believe that this or other legislation
that has been enacted to date will have a material adverse effect on the
Company. However, it is possible that legislation could be enacted at either the
state or federal level that could have a material adverse effect on the
Company's financial condition, results of operations and cash flows.
(d) Dutch Stranded Costs.
Background. In January 2001, the Dutch Electricity Production Sector
Transitional Arrangements Act (Transition Act) became effective. Among other
things, the Transition Act allocated to REPGB and the three other large-scale
Dutch generation companies, a share of the assets, liabilities and stranded cost
commitments of NEA. Prior to the enactment of the Transition Act, NEA acted as
the national electricity pooling and coordinating body for the generation output
of REPGB and the three other large-scale national Dutch generation companies.
REPGB and the three other large-scale Dutch generation companies are
shareholders of NEA.
The Transition Act and related agreements specify that REPGB has a
22.5% share of NEA's assets, liabilities and stranded cost commitments. NEA's
stranded cost commitments consisted primarily of various uneconomical or
stranded cost investments and commitments, including a gas supply contract,
three power contracts entered into prior to the liberalization of the Dutch
wholesale electricity market and a contract relating to the construction of an
interconnection cable between Norway and the Netherlands subject to a long-term
power exchange agreement (PEA) (the NorNed Project). REPGB's stranded cost
obligations also include uneconomical district heating contracts which were
previously administrated by NEA prior to deregulation of the Dutch power market.
In January 2001, NEA assigned to REPGB a 22.5% interest in the stranded
cost contracts, including the gas supply contract, which expires in 2016, and
provides for gas imports aggregating 2.283 billion cubic meters per year. During
December 2001, one of the stranded power contracts was settled. In May 2002, NEA
amended the two remaining long-term power contracts in order to bring them to
market-conforming terms and, in connection with these amendments, assigned the
contracts to NEA's shareholders. The district heating obligations relate to
three water heating supply contacts entered into with various municipalities
expiring from 2008 through 2015. Under the district heating contracts, the
municipal districts are required to take annually a combined minimum of 5,549
terajoules (TJ) increasing annually to 7,955 TJ over the life of the contracts.
The Transition Act provided that, subject to the approval of the
European Commission, the Dutch government will provide financial compensation to
the Dutch generation companies, including REPGB, for liabilities associated with
long-term district heating contracts. In July 2001, the European Commission
ruled that under certain conditions the Dutch government can provide financial
compensation to the generation companies for the district heating contracts. To
the extent that this compensation is not ultimately provided to the generation
companies by the Dutch government, REPGB is entitled to claim compensation
directly from the former shareholders of REPGB as further discussed below.
Settlement of Stranded Cost Indemnification Agreement. Until December
2001, the former shareholders of REPGB were obligated to indemnify REPGB for up
to Dutch Guilders (NLG) 1.9 billion of its share of NEA's stranded cost
liabilities. In December 2001, REPGB and its former shareholders agreed to
settle the indemnity obligations of the former shareholders in so far as they
related to NEA's stranded cost gas supply and power contracts and other
obligations (excluding district heating).
Under the settlement agreement, the former shareholders of REPGB paid
REPGB NLG 500 million ($202 million) in the first quarter of 2002. REPGB
deposited the settlement payment into an escrow account, withdrawals from which
are at the discretion of REPGB for use in discharging stranded cost obligations
related to the gas and electric import contracts. As of September 30, 2002, the
escrow funds equaled $62 million, of which $60 million and $2 million were
recorded in restricted cash and long-term assets, respectively. Any remaining
funds as of January 1, 2004 will be distributed to REPGB.
Under the settlement agreement, the former shareholders continue to be
under an obligation to indemnify REPGB for certain district heating contracts.
Under the terms of the indemnity, REPGB can elect between two forms of
indemnification within 21 days after the date that the Ministry of Economic
Affairs of the Netherlands publishes regulations for compensation of stranded
costs associated with district heating projects. If the compensation to be paid
by the Netherlands under these rules is at least as much as the compensation to
be paid
36
under the original indemnification agreement, REPGB can elect to receive a
one-time payment of NLG 60 million ($24 million). In addition, unless the decree
implementing the new compensation rules provides for compensation for the
lifetime of the district heating projects, REPGB can receive an additional cash
payment of NLG 15 million ($6 million). If the compensation rules do not provide
for compensation at least equal to that provided under the original
indemnification agreement, REPGB can claim indemnification for stranded cost
losses up to a maximum of NLG 700 million ($282 million) less the amount of
compensation provided by the new compensation rules and certain proceeds
received from arbitrations. If no new compensation rules have taken effect on or
prior to December 31, 2003, REPGB is entitled, but not obligated, to elect to
receive indemnification under the formula described above. As of November 8,
2002, the Ministry of Economic Affairs had not published its compensation rules.
Based on current assumptions, it is not anticipated that such rules will be
published until 2003.
Prior to the settlement agreement, pursuant to the purchase agreement
of REPGB, as amended, REPGB was entitled to a NLG 125 million (approximately $51
million) dividend from NEA with any remainder owing to the former shareholders.
Under the settlement agreement, the former shareholders waived all rights to
distributions of NEA.
As a result of this settlement, the Company recognized in the fourth
quarter of 2001 a net gain of $37 million for the difference between (a) the sum
of the cash settlement payment of $202 million and the additional rights to
claim distributions of the NEA investment recognized of $248 million and (b) the
sum of the amount recorded as stranded cost indemnity receivable related to the
stranded cost gas and electric commitments of $369 million and claims receivable
related to stranded costs incurred in 2001 of $44 million, both previously
recorded in the Company's Consolidated Balance Sheet.
Amendments to Stranded Cost Electricity Import Contracts. In May 2002,
NEA and its four shareholders (including REPGB) entered into agreements amending
the terms of the two remaining power supply agreements (Settlement Agreements).
These two contracts provide for the following capacities and terms: (a) 300 MW
through 2003, and (b) 600 MW through March 2002, increasing to 750 MW through
March 2009.
Under the terms of the Settlement Agreements, NEA paid the
counterparties a net aggregate payment of Euro 485 million, approximately $446
million (the Settlement Payment) (of which REPGB's proportionate share as a NEA
shareholder was Euro 109 million, approximately $100 million). In July 2002,
REPGB paid its share of the Settlement Payment with funds from the stranded cost
indemnity escrow account, as discussed above. In exchange for its portion of the
Settlement Payment, the counterparties to the power contracts replaced the
existing terms with a market-based electricity price index for comparable
electricity products in addition to other changes.
As a result of the Settlement Agreements, in the second quarter of
2002, the Company recognized a pre-tax net gain of $109 million for the
difference between (a) the fair values of the original power contracts ($203
million net liability previously recorded in non-trading derivative liabilities)
and the fair values of the amended power contracts ($6 million net asset
recorded in trading and marketing assets) and (b) the Settlement Payment of $100
million, as described above. The pre-tax net gain of $109 million was recorded
as a reduction of purchased power expense in the Statement of Consolidated
Income in the second quarter of 2002. In the future, these two power trading
contracts will be marked-to-market as a part of the Company's energy trading
activities.
Separately, in May 2002, following the execution of the Settlement
Agreements, NEA declared a Euro 625 million, approximately $616 million, cash
distribution to its shareholders, which was paid on July 1, 2002. REPGB's share
of the distribution was Euros 141 million, approximately $137 million.
Remaining Liability for Original Stranded Costs. In January 2001, the
Company recognized an out-of-market, net stranded cost liability for its gas and
electric import contracts and district heating commitments. At such time, the
Company recorded a corresponding asset of equal amount for the indemnification
of this obligation from REPGB's former shareholders and the Dutch government, as
applicable. As of December 31, 2001, the Company has recorded a liability of
$369 million for its stranded cost gas and electric commitments in non-trading
derivative liabilities and a liability of $206 million for its district heating
commitments in current and non-current other liabilities. As of September 30,
2002, the Company has recorded a liability of $141 million for its stranded cost
gas contract in non-trading derivative liabilities, an asset of $9 million for
its amended power contracts in trading and marketing assets, and a liability of
$229 million for its district heating commitments in current and non-current
other liabilities. As of December 31, 2001 and September 30, 2002, the Company
has recorded an indemnification receivable for the district heating stranded
cost liability of $206 million and $229 million, respectively.
37
Pursuant to SFAS No. 133, the Company marks-to-market the stranded cost
gas contract (see Note 4). Prior to the amendments to the remaining power
contacts, pursuant to SFAS No. 133, the power contracts were marked-to-market.
Subsequent to amending the remaining power contracts, the power contracts are
marked-to-market as a part of the Company's energy trading activities. Pursuant
to SFAS No. 133, during the nine months ended September 30, 2002, the Company
recognized a $16 million gain recorded in fuel expense related to changes in the
valuation of the stranded cost contracts, excluding the effects of the gain
related to amending the two power contracts discussed above and net of
derivative transactions entered into to economically hedge the stranded cost gas
contract.
NorNed Project. NEA entered into commitments with certain Norwegian
counterparties (the Norwegian Counterparties) for the construction of a grid
interconnector cable between the Netherlands and Norway, subject to the
operation of a bi-directional, long-term (25 years in duration) PEA. The PEA
contemplates, among other terms, exclusive use and cost free access to the cable
by NEA and the Norwegian counterparties. The PEA is subject to, among other
things, clearance by the European Commission and the Dutch regulatory
authorities of the terms and conditions of the PEA. In 2001, NEA and the
Norwegian counterparties filed a notification request regarding the PEA with the
European Commission. It is not expected that the European Commission will
respond to the notification request until the third quarter of 2003. Under the
Transition Act, NEA is entitled to recover the cable construction costs from
TenneT, the Netherlands grid operator. However, at this early stage it is not
entirely clear how NEA will receive the transport tariff funds intended to
recover the construction costs of the cable, and whether the ultimate transport
tariff rate approved by the Dutch power regulation (Dte) will be sufficient to
cover the ultimate construction costs. However, assuming that the Transition Act
is fully implemented with respect to this matter, REPGB believes that NEA will
ultimately recover the cost of the cable.
For additional information regarding the indemnification and settlement
of stranded costs, see Note 13(f) to the Reliant Resources 10-K/A Notes.
Investment in NEA. During the second quarter of 2001, the Company
recorded a $51 million pre-tax gain (NLG 125 million) recorded as equity income
for the preacquisition gain contingency related to the acquisition of REPGB for
the value of its equity investment in NEA. This gain was based on the Company's
evaluation of NEA's financial position and fair value. The fair value of the
Company's investment in NEA is dependent upon the ultimate resolution of its
existing contingencies and proceeds received from liquidating its remaining net
assets.
(e) Payment to CenterPoint Energy in 2004.
The Company may be required to make a payment to CenterPoint Energy in
early 2004, to the extent the Company's affiliated retail electric provider's
price to beat for providing retail electric service to residential and small
commercial customers in CenterPoint Energy's Houston service territory during
2002 and 2003 exceeds the market price of electricity. This payment is required
by the Texas electric restructuring law unless the Texas Utility Commission
determines that, on or prior to January 1, 2004, 40% or more of the amount of
electric power that was consumed in 2000 by residential or small commercial
customers, as applicable, within CenterPoint Energy's Houston service territory
is committed to be served by retail electric providers other than the Company.
This amount will not exceed $150 per customer, multiplied by the number of
residential or small commercial customers, as the case may be, that the Company
serves on January 1, 2004 in CenterPoint Energy's Houston service territory,
less the number of residential or small commercial electric customers, as the
case may be, the Company serves in other areas of Texas. As of September 30,
2002, the Company had approximately 1.7 million residential and small commercial
customers in CenterPoint Energy's Houston service area. In the Master Separation
Agreement between the Company and Reliant Energy, the Company has agreed to make
this payment, if any, to CenterPoint Energy. Currently, the Company believes it
is probable that it will be required to make such payment to CenterPoint Energy
related to its residential customers. As of September 30, 2002, the Company
believes that the payment related to its residential customers will be in the
range of $155 million to $185 million (pre-tax), with a most probable estimate
of $170 million. The Company will recognize the total obligation over the period
it recognizes the related revenues based on the difference between amount of the
price to beat and the estimated market price of electricity multiplied by the
estimated energy sold through January 1, 2004 not to exceed the maximum cap of
$150 per customer. During the third quarter of 2002, the Company recognized $89
million (pre-tax) of which $27 million was associated with the revenues for the
first half of 2002. The remainder of the Company's estimated obligation will be
recognized during the fourth quarter of 2002 and during 2003.
In the future, the Company will revise its estimates of this payment as
additional information about market price of electricity and the market share
that will be served by the Company and other retail electric providers on
January 1, 2004 becomes available and the Company will adjust the related
accrual at that time. Currently, the Company
38
believes that the 40% test for small commercial customers will be met and the
Company will not make a payment related to those customers. If the 40% test is
not met related to its small commercial customers and a payment is required, the
Company estimates this payment would be approximately $30 million.
(f) Construction Agency Agreements and Equipment Financing Structure.
In 2001, the Company, through several of its subsidiaries, entered into
operative documents with special purpose entities to facilitate the development,
construction, financing and leasing of several power generation projects. The
special purpose entities are not consolidated by the Company. As a result of the
decision to cancel one of the projects, the commitments were reallocated in June
2002 so that the special purpose entities now have an aggregate financing
commitment from equity and debt participants (Investors) for three electric
generating facilities of $1.9 billion of which the last $515 million is
currently available only if cash collaterized. The availability of the
commitment is subject to satisfaction of various conditions, including the
obligation to provide cash collateral for the loans and letters of credit
outstanding on November 29, 2004. The Company, through several of its
subsidiaries, acts as construction agent for the special purpose entities and is
responsible for completing construction of these projects by December 31, 2004.
However, the Company has generally limited its risk during construction to an
amount not to exceed 89.9% of costs incurred to date, except in certain events.
Upon completion of an individual project and exercise of the lease option, the
Company's subsidiaries will be required to make lease payments in an amount
sufficient to provide a return to the Investors. If the Company does not
exercise its option to lease any project upon its completion, the Company must
purchase the project or remarket the project on behalf of the special purpose
entities. The Company's ability to exercise the lease option is subject to
certain conditions. The Company must guarantee that the Investors will receive
an amount at least equal to 89.9% of their investment in the case of a
remarketing sale at the end of construction. At the end of an individual
project's initial operating lease term (approximately five years from
construction completion), the Company's subsidiary lessees have the option to
extend the lease with the approval of the Investors, purchase the project at a
fixed amount equal to the original construction cost, or act as a remarketing
agent and sell the project to an independent third party. If the lessees elect
the remarketing option, they may be required to make a payment of an amount not
to exceed 85% of the project cost, if the proceeds from remarketing are not
sufficient to repay the Investors. The Company has guaranteed the performance
and payment of its subsidiaries' obligations during the construction periods
and, if the lease option is exercised, each lessee's obligations during the
lease period. At any time during the construction period or during the lease,
the Company may purchase a facility by paying an amount approximately equal to
the outstanding balance plus costs or the Company may purchase the facility by
assuming, directly or indirectly, the obligations of the subsidiaries, in which
case the guarantee must remain in place and lender consent may be required.
Given general market conditions and the uncertainty surrounding accounting
changes in regard to special purpose entities, the Company is considering all
options, including the purchase option. As of September 30, 2002, the special
purpose entities had cash of $45 million, property, plant and equipment of $1.2
billion, net other liabilities of $13 million and debt obligations of $1.1
billion. As of September 30, 2002, the special purpose entities had equity from
unaffiliated third parties of $45 million.
Based on current projections regarding the rate of expenditures for the
three electric generating facilities, it appears likely that the full amount of
non-cash collateralized commitments will have been utilized by the end of the
first quarter of 2003. In order to complete the generating facilities on an
uninterrupted basis, the Company is considering the following alternatives to
fund the remaining $400 million obligation: (a) seek from the lenders an
increase in the non-cash collateralized portion of the $1.9 billion facility;
(b) invest unrestricted corporate cash into the structure with the existing
Investors, or (c) exercise its purchase option and assume the debt and fund the
remaining amount with cash on hand. If the Company does either of the latter two
options, the Company believes that the special purpose entities will be required
to be consolidated by the Company based on guidance in EITF No. 97-10,
"The Effect of Lessee Involvement in Asset Construction."
The Company, through its subsidiary, REPG, had entered into an
agreement with a bank whereby the bank, as owner, entered into contracts for the
purchase and construction of power generation equipment and REPG, or its
subagent, acted as the bank's agent in connection with administering the
contracts for such equipment. The agreement expired in September 2002. REPG, or
its designee, had the option at any time to purchase, or, at equipment
completion, subject to certain conditions, including the agreement of the bank
to extend financing, to lease the equipment, or to assist in the remarketing of
the equipment under terms specified in the agreement. REPG and its subagents had
to cash collateralize their obligation to administer the contracts. This cash
collateral was approximately equivalent to the total payments by the bank for
the equipment, interest and other fees. The cash collateral was deposited by
REPG or the subagent into a collateral account with the bank and earned interest
at LIBOR less 0.15%. Under certain circumstances, the collateral deposit or a
portion of it, would be returned to REPG
39
or its designee. Immediately prior to the expiration of the agreement in
September 2002, REPG was assigned and exercised purchase options for contracts
for steam and combustion turbines and two heat recovery steam generators with an
aggregate cost of $121 million under which payments and interest during
construction totaling $94 million had been made. REPG used $94 million of its
collateral deposits to complete the purchase. In May 2002, REPG was assigned and
exercised a purchase option for a contract for an air-cooled condenser totaling
$20 million under which payments and interest during construction totaling $8
million had been made. REPG used $8 million of its collateral deposits to
complete the purchase. After the purchase, REPG canceled the contract and paid a
cancellation payment of $1.7 million to the manufacturer. In January 2002, the
bank sold to the parties to the construction agency agreements discussed above,
equipment contracts with a total contractual obligation of $258 million, under
which payments and interest during construction totaled $142 million.
Accordingly, $142 million of collateral deposits were returned to the Company.
At December 31, 2001, REPG and/or its subagent had deposits of $230 million in
the collateral account.
Pursuant to SFAS No. 144, the Company evaluated for impairment the
steam and combustion turbines and two heat recovery steam generators purchased
in September 2002 for a total of $94 million. Based on the Company's analysis,
the Company determined this equipment was impaired and accordingly recognized a
$37 million pre-tax impairment loss which is recorded as depreciation expense
for the three and nine months ended September 30, 2002 in the Company's
Statement of Consolidated Income. The fair value of the equipment and thus the
impairments was determined using a combination of quoted market prices and
prices for similar assets.
(g) REMA Sale/Leaseback Transactions.
In August 2000, the Company entered into separate sale/leaseback
transactions with each of the three owner-lessors for the Company's respective
16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and Shawville
generating stations, respectively, acquired in the REMA acquisition. The lease
documents contain some restrictive covenants that restrict REMA's ability to,
among other things, make dividend distributions unless REMA satisfies various
conditions. As of September 30, 2002, these various conditions were satisfied by
REMA. As of December 31, 2001, REMA had $167 million of restricted funds that
were available for REMA's working capital needs and to make future lease
payments. For additional discussion of these lease transactions, please read
Notes 5(a) and 13(c) to the Reliant Resources 10-K/A Notes.
(h) Reliant Energy Desert Basin Contingency.
Reliant Energy Desert Basin (REDB), an indirect wholly owned subsidiary
of Reliant Resources, sells power to Salt River Project (SRP) under a long-term
power purchase agreement. Certain of REDB's obligations under the power purchase
agreement are guaranteed by Reliant Resources. In the event Reliant Resources is
downgraded to below investment grade by two major ratings agencies, SRP can
request performance assurance in the form of cash or a letter of credit from
REDB under the power purchase agreement and from Reliant Resources under the
guaranty. Under the power purchase agreement and guaranty, the total amount of
performance assurance cannot exceed $150 million. Under the terms of the power
purchase agreement, REDB is required to provide performance assurance within 30
days of the receipt of a demand from SRP. Failure by REDB to provide performance
assurance within the 30-day period constitutes a breach of the power purchase
agreement. The guaranty requires Reliant Resources to provide performance
assurance within 3 business days of receipt of a notice from SRP indicating that
REDB has failed to comply with its obligations under the power purchase
agreement to provide performance assurance. If Reliant Resources fails to comply
with this obligation, SRP may sue for damages. The power purchase agreement
allows REDB 30 days from the date of receipt of notice of a breach to cure. If
REDB fails to cure the breach within 30 days of receipt of notice, an event of
default has occurred. Upon the occurrence of an event of default, SRP has
certain rights that include termination of the power purchase agreement and the
right to sue for damages.
On September 16, 2002, following the downgrade of Reliant Resources to
below investment grade by Standard & Poor's and Moody's, SRP requested
performance assurance from Reliant Resources and REDB under the guaranty and the
power purchase agreement, respectively, in the total amount of $150 million.
Reliant Resources and REDB replied to SRP's request on October 15, 2002, noting
that the power purchase agreement does not specify the amount of performance
assurance due in the event of a credit downgrade and demonstrating that under
prevailing market conditions and other factors, a letter of credit in the amount
of $3 million would provide commercially reasonable assurance of REDB's ability
to perform its obligations under the power purchase agreement. Reliant Resources
provided SRP with a $3 million letter of credit. SRP notified Reliant Resources
that it deemed the amount inadequate and returned the letter of credit to
Reliant Resources. On October 18, 2002, SRP sent a letter to Reliant Resources
alleging that Reliant Resources had breached its duty to provide performance
assurance by failing to provide the requested $150
40
million letter of credit. Reliant Resources and REDB maintain that provision of
a $3 million letter of credit fulfills their responsibilities under the power
purchase agreement to provide performance assurance and that SRP would be in
breach of the power purchase agreement, and therefore liable to REDB for
damages, if it were to terminate the power purchase agreement based on the
failure of Reliant Resources and REDB to provide performance assurance in the
amount of $150 million.
(i) Tolling Agreement for Liberty Electric Generating Station.
The output of the Liberty Electric Generating Station (the Liberty
Station) is contracted under a tolling agreement between LEP and PG&E Energy
Trading-Power, L.P. (PGET) for a term of approximately 14 years, with an option
to extend at the end of the term (the Tolling Agreement). Under the Tolling
Agreement, PGET has the exclusive right to receive all energy, capacity and
ancillary services produced by Liberty Station. PGET must pay for, and is
responsible for, all fuel used by Liberty Station.
Standard & Poor's and Moody's have downgraded to sub-investment grade
the senior unsecured debt of PG&E National Energy Group, Inc. (NEG), one of the
two guarantors of PGET's obligations under the Tolling Agreement. Because PGET
did not post replacement security within the period required by the Tolling
Agreement, the downgrade constitutes an event of default by PGET under the
Tolling Agreement. While LEP could terminate the Tolling Agreement pursuant to
the terms of the Tolling Agreement as a result of said failure, there are
certain limitations under the Liberty Credit Agreements on LEP's ability to take
unilateral action in response to a PGET event of default. Additionally, on
October 11, 2002, Standard & Poor's downgraded to sub-investment grade the
senior unsecured debt of PG&E Gas Transmission, Northwest Corp. (GTN) the other
guarantor of PGET's obligations under the Tolling Agreement. On October 16,
2002, Moody's also downgraded GTN's senior unsecured debt to sub-investment
grade.
In addition, on August 19, 2002, and September 10, 2002, PGET notified
LEP that it believed LEP had violated the Tolling Agreement by not following
PGET's instructions relating to the dispatch of the Liberty Station during
specified periods. The September 10, 2002 letter also claims that LEP did not
timely provide PGET with certain information to make a necessary FERC filing.
While LEP does not agree with PGET's interpretation of the Tolling Agreement
regarding the dispatch issue, LEP agreed to (a) compensate PGET approximately
$17,000 for the alleged damages attributable to the claims raised in the August
19, 2002 letter and (b) treat several hours of plant outages as forced outages
for purposes of the Tolling Agreement, thereby resolving the issues raised in
the August 19 letter (which compensation and treatment are not believed to be
material). The Tolling Agreement generally provides that covenant-related
defaults must be cured within 30 business days or they will (if material) result
in an event of default, entitling the non-defaulting party to terminate. PGET
has extended this cure period (relating to the September 10, 2002 letter) to
November 30, 2002. While there can be no assurances as to the outcome of this
matter, LEP believes that it will be able to resolve the issues raised in the
September 10, 2002 letter without causing an event of default under the Tolling
Agreement. However, if LEP is unable to resolve said issues and PGET declares an
event of default, then PGET would be in a position to terminate the Tolling
Agreement. In addition to the material adverse effect such a termination would
have on Liberty as discussed below, such a termination may also result in PGET
drawing on the $35 million letter of credit posted on behalf of LEP under the
Tolling Agreement.
Under the Tolling Agreement, a non-defaulting party who terminates the
Tolling Agreement is entitled to calculate its damages in accordance with
specified criteria set forth therein; the non-defaulting party is the only party
entitled to damages. The defaulting party would be entitled to refer such damage
calculation to arbitration. The institution of any arbitration could delay the
receipt of such damages for an extended period of time. In addition, if PGET is
the defaulting party, the payment of said damages could be further delayed if
PGET and one or more of GTN and NEG seeks protection from creditors under the
bankruptcy laws. Such filings also may result in LEP receiving significantly
less in damages than it might otherwise be entitled.
LEP and PGET are engaged in discussions seeking to resolve the disputes
and claims of both LEP and PGET under the Tolling Agreement. There is no
guarantee that these discussions will be successful. Any resolution would
require the approval of the parties providing the financing under the Liberty
Credit Agreements. In addition, any such settlement may have a material adverse
effect on LEP and Liberty.
It should be noted that the termination of the Tolling Agreement for
any reason most likely would have a material adverse effect on Liberty and LEP.
LEP currently receives a fixed monthly payment from PGET under the Tolling
Agreement. If the Tolling Agreement is terminated, then LEP would be required to
either find a power
41
purchaser or tolling customer to replace PGET or, if that effort is
unsuccessful, to sell the energy and/or capacity into the merchant energy market
without any assurance, in either of the foregoing cases, that LEP would be able
to earn enough revenues to pay all of its expenses or to enable Liberty to make
interest and scheduled principal payments under the Liberty Credit Agreements as
they become due. If the Tolling Agreement is terminated, the gas transportation
agreement that PGET utilizes in connection with the Tolling Agreement will
revert to LEP and LEP will be required to perform the obligations currently
being performed by PGET under said agreement. The termination of the Tolling
Agreement may cause both Liberty and LEP to seek other alternatives, including
reorganization under the bankruptcy laws. Orion Power would not be required to
reorganize under the bankruptcy laws due solely to Liberty or LEP seeking to
reorganize.
As noted above, the Liberty Credit Agreements restrict the ability of LEP to
terminate the Tolling Agreement. There is also a requirement in the Liberty
Credit Agreements that Liberty, the borrower under the Liberty Credit
Agreements, and LEP enforce all of their respective rights under the Tolling
Agreement. Liberty and LEP have received waivers from the lenders under the
Liberty Credit Agreements from the requirement that they enforce all of their
respective rights under the Tolling Agreement. These waivers extend through and
expire on December 8, 2002.
(j) Long-Term Maintenance Agreements.
Several of the wholly-owned subsidiaries of the Company have entered
into long-term maintenance agreements that cover certain periodic maintenance,
including parts, on their respective turbines. The long-term maintenance
agreements terminate over the next twelve to eighteen years based on turbine
usage.
As of September 30, 2002, no payments have been made under the
long-term maintenance agreements. Estimated cash payments over the remainder of
2002 and the five succeeding fiscal years estimated are as follows (in
millions):
2002........................................ $ 5
2003........................................ 52
2004........................................ 30
2005........................................ 31
2006........................................ 31
2007........................................ 33
----------
Total..................................... $ 182
==========
(13) BENEFIT CURTAILMENT, ENHANCEMENT CHARGE AND ACCOUNTING SETTLEMENT
During the three months ended March 31, 2001, the Company recognized a
pre-tax, non-cash charge of $100 million relating to the redesign of some of
Reliant Energy's benefit plans in anticipation of Reliant Resources' separation
from CenterPoint Energy. During the three months ended September 30, 2002, the
Company recognized a net pre-tax, non-cash charge of $47 million relating to the
settlement of some of the Company's benefit plan obligations as further
described below.
Effective March 1, 2001, the Company no longer accrues benefits under a
noncontributory pension plan for its domestic non-union employees (Resources
Participants). Effective March 1, 2001, each non-union Resources Participant's
unvested pension account balance became fully vested and a one-time benefit
enhancement was provided to some qualifying participants. During the first
quarter of 2001, the Company incurred a charge to earnings of $83 million
(pre-tax) for a one-time benefit enhancement and a gain of $23 million (pre-tax)
related to the curtailment of Reliant Energy's pension plan. In connection with
the Distribution, the Company incurred a loss of $65 million (pre-tax) related
to the settlement of the pension obligation. In connection with recording the
accounting settlement, CenterPoint Energy contributed certain benefit plan
deferred losses, net of taxes, totaling $18 million that were deemed to be
associated with the Company's benefit obligation. Upon the Distribution, the
Company effectively transferred to CenterPoint Energy its pension obligation.
After the Distribution, each Resources Participant may elect to have his accrued
benefit (a) left in the CenterPoint Energy pension plan for which CenterPoint
Energy is the plan sponsor, (b) rolled over to a new Company savings plan or an
individual IRA account, or (c) paid in a lump-sum or annuity distribution.
Effective March 1, 2001, the Company discontinued providing subsidized
postretirement benefits to its domestic non-union employees. The Company
incurred a pre-tax charge of $40 million during the first quarter of 2001
related to the curtailment of the Company's postretirement obligation. In
connection with the Distribution, the
42
Company incurred a pre-tax gain of $18 million related to the accounting
settlement of postretirement benefit obligations. For additional information
regarding these benefit plans, see Notes 11(b) and 11(d) to the Reliant
Resources 10-K/A Notes.
(14) PRICE TO BEAT FUEL FACTOR ADJUSTMENT
The Texas Utility Commission regulations allow the Company to request
an adjustment to the fuel factor in its price to beat up to twice a year for its
Houston area residential and small commercial customers based on the percentage
change in the price of natural gas, or increases in the price of purchased
energy. The Company's price to beat fuel factor was initially set by the Texas
Utility Commission in December 2001 based on an average forward 12-month natural
gas price of $3.11/mmbtu. On May 2, 2002, the Company filed a request with the
Texas Utility Commission to increase the price to beat fuel factor based on a
20% increase in the price of natural gas. The Company's requested increase was
based on an average forward 12-month natural gas price of $3.73/mmbtu. The
requested increase represents a 5.9% increase in the total bill of a residential
customer using, on average, 1,000 kWh per month. On June 6, 2002 the
administrative law judge recommended to the Texas Utility Commission approval of
a 19.9% increase to the price to beat fuel factor based on application of the
Texas Utility Commission's price to beat rule. On July 15, 2002, the Texas
Utility Commission issued an order delaying the Company's request as well as the
request of each of the other four affiliated retail electric providers
requesting adjustments to the price to beat fuel factors and remanded the cases
to the administrative law judges requesting additional information in order to
validate the Texas Utility Commission's rule. On July 24, 2002, the Company
filed a request in the Travis County District Court that the Court declare that
the Texas Utility Commission must apply its current rules to the Company's
request and grant the fuel factor adjustment in accordance with the formula in
the rule that the Texas Utility Commission had already approved. The other four
affiliated retail electric providers filed similar requests with the Travis
County District Court. The Court issued an order on August 9, 2002 agreeing with
the Company that the Texas Utility Commission must follow the existing rules
that govern the adjustment of the price to beat fuel factor. On August 26, 2002,
the Texas Utility Commission approved the administrative law judge's
recommendation for an increase in the price to beat fuel factor. Certain
consumer groups moved for rehearing of the Texas Utility Commission's August 26,
2002 Order granting the Company's requested price to beat fuel factor
adjustment. On September 26, 2002, the Texas Utility Commission denied all
motions for rehearing and the consumer groups have appealed the Texas Utility
Commission's August 26, 2002 Order to the Travis County District Court.
On August 26, 2002, the Texas Utility Commission initiated a rulemaking
to determine whether the price to beat rule should be amended. A preliminary
workshop was held on October 8, 2002 to address certain questions related to the
current rule. Among other issues, the workshop discussion focused on the timing
of price to beat fuel factor adjustment requests, the timeline for processing
requests, the use of a 10-day average of gas prices to determine if an
adjustment is necessary, appropriateness of an electricity index and whether an
adjustment based on gas price increases should be applied to only the gas
portion of the fuel factor. On November 7, 2002, the Texas Utility Commission
approved for publication a revised price to beat rule. The proposed changes from
the current rule relate to (a) the number of days used to calculate the natural
gas price average, (b) the threshold of what constitutes a significant change in
the market price of natural gas and purchased energy, (c) processing of
documents, (d) encouraging the development of liquid trading hubs in Texas and
(e) additional specificity as to what adjustments to the price to beat will be
considered following the true-up proceedings. After interested parties file
comments and reply comments, a public hearing on the proposed revisions will be
held on January 7, 2003. Texas Utility Commission issued a rule for comment. The
Company cannot predict what revisions, if any, the Texas Utility Commission will
make to the price to beat rule or the effect that this rulemaking will have on
its business and results of operations.
(15) REPORTABLE SEGMENTS
The Company has the following reportable segments: Wholesale Energy,
European Energy, Retail Energy and Other Operations. For descriptions of these
financial reporting segments, see Note 1 to the Reliant Resources 10-K/A Notes.
There were no material inter-segment revenues during the three and nine months
ended September 30, 2001 and 2002.
Beginning in the first quarter of 2002, the Company began to evaluate
segment performance on earnings (loss) before interest expense, interest income
and income taxes (EBIT). Prior to 2002, the Company evaluated performance on
operating income. EBIT is not defined under accounting principles generally
accepted in the United States (GAAP), and should not be considered in isolation
or as a substitute for a measure of performance prepared in accordance with GAAP
and is not indicative of operating income from operations as determined under
GAAP.
43
Financial data for business segments are as follows:
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2001
--------------------------------------------------
REVENUES FROM OPERATING INCOME
NON-AFFILIATES (LOSS) EBIT
--------------- ---------------- ----------
Wholesale Energy .................. $2,271 $ 400 $ 402
European Energy ................... 145 (5) (4)
Retail Energy ..................... 43 (7) (8)
Other Operations .................. 3 (36) (32)
------ ----- -----
Consolidated ...................... $2,462 $ 352 $ 358
====== ===== =====
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2002
--------------------------------------------------
REVENUES FROM OPERATING INCOME
NON-AFFILIATES (LOSS) EBIT
--------------- ---------------- ----------
Wholesale Energy .................. $3,513 $ 111 $ 119
European Energy ................... 148 (16) (13)
Retail Energy ..................... 1,694 237 235
Other Operations .................. -- (50) (50)
------ ----- -----
Consolidated ...................... $5,355 $ 282 $ 291
====== ===== =====
Reconciliation of Operating Income to EBIT and EBIT to Net Income:
FOR THE THREE MONTHS ENDED SEPTEMBER 30,
----------------------------------------
2001 2002
------------------ -------------------
(IN MILLIONS)
Operating income ............................................. $ 352 $ 282
Gains (losses) from investments, net ......................... 4 (2)
Income of equity investment of unconsolidated subsidiaries ... 2 1
Other income, net ............................................ -- 10
----- -----
EBIT ......................................................... 358 291
Interest expense ............................................. (8) (103)
Interest income .............................................. 3 11
Interest income - affiliated companies ....................... 11 1
----- -----
Income before income taxes ................................... 364 200
Income tax expense ........................................... 150 142
----- -----
Net income ................................................... $ 214 $ 58
===== =====
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001
-------------------------------------------- AS OF
DECEMBER 31, 2001
OPERATING -----------------
REVENUES INCOME (LOSS) EBIT TOTAL ASSETS
--------- ------------- -------- -----------------
(IN MILLIONS)
Wholesale Energy .......................... $5,073 $ 912 $ 929 $ 8,290
European Energy ........................... 478 23 80 3,380
Retail Energy ............................. 107 (13) (13) 391
Other Operations .......................... 8 (163) (148) 599
Reconciling Elimination ................... -- -- -- (368)
------ ----- ----- --------
Consolidated .............................. $5,666 $ 759 $ 848 $ 12,292
====== ===== ===== ========
44
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002
--------------------------------------------------
AS OF
SEPTEMBER 30, 2002
REVENUES FROM OPERATING ------------------
NON-AFFILIATES INCOME (LOSS) EBIT TOTAL ASSETS
-------------- ------------- -------- ------------------
(IN MILLIONS)
Wholesale Energy .............. $5,685 $ 241 $ 264 $ 14,057
European Energy ............... 457 103 110 3,172
Retail Energy ................. 3,368 491 489 1,494
Other Operations .............. 2 (54) (55) 1,355
Reconciling Elimination ....... -- -- -- (399)
------ ----- ----- --------
Consolidated .................. $9,512 $ 781 $ 808 $ 19,679
====== ===== ===== ========
Reconciliation of Operating Income to EBIT and EBIT to Net Income:
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
---------------------------------------
2001 2002
------------ ------------
(IN MILLIONS)
Operating income .................................................... $ 759 $ 781
Gains from investments, net ......................................... 15 3
Income of equity investment of unconsolidated subsidiaries .......... 67 10
Other income, net ................................................... 7 14
----- -----
EBIT ................................................................ 848 808
Interest expense .................................................... (52) (209)
Interest income ..................................................... 18 19
Interest income - affiliated companies .............................. 8 5
----- -----
Income before income taxes and cumulative effect of accounting change 822 623
Income tax expense .................................................. 301 290
Cumulative effect of accounting change .............................. 3 (234)
----- -----
Net income .......................................................... $ 524 $ 99
===== =====
(16) SUBSEQUENT EVENTS
(a) Default Under the Receivable Facility.
On October 21, 2002, the Company notified a financial institution under
the Receivables Facility of a violation of a certain compliance ratio test that
is considered an amortization event whereby the financial institution has the
right to liquidate the receivables it owns to collect the total amount
outstanding under the terms of the Receivable Facility. The past due ratio
(billed receivables over 90 days past due divided by total billed receivables)
has increased in excess of the 5% compliance limit due to a regulatory change.
The Company has received a waiver from the financial institution.
(b) Orion Power's Subsidiaries Amended and Restated Credit Facilities.
During October 2002, the Company restructured the Orion Power revolving
senior credit facility, the Orion MidWest credit facility and the Orion NY
credit facility. As part of this restructuring, the Orion Power revolving credit
facility was terminated, and the Orion MidWest and Orion NY credit facilities
were extended until October 2005. The amended and restated Orion MidWest credit
facility includes an acquisition term loan of approximately $974 million, and a
$75 million revolving working capital facility. The amended and restated Orion
NY credit facility includes an acquisition term loan of approximately $353
million, and a $30 million revolving working capital facility. The loans under
each facility bear interest at LIBOR plus a margin or at a base rate plus a
margin. The LIBOR margin is 2.50% during the first twelve months, 2.75% during
the next six months, 3.25% for the next six months, and 3.75% thereafter. The
base rate margin is 1.50% during the first twelve months, 1.75% for the next six
months, 2.25% for the next six months and 2.75% thereafter. The amended and
restated Orion NY credit facility is secured by a first lien on substantially
all of the assets of Orion NY and its subsidiaries (excluding certain plant
assets) and a second lien on substantially all of the assets of Orion MidWest
and its subsidiary; the amended and restated Orion MidWest credit facility is,
in turn, secured by a first lien on substantially all of the assets of Orion
MidWest and its subsidiary and a second lien on substantially all of the assets
of Orion NY and its subsidiaries (excluding certain plant assets). Both the
Orion MidWest and Orion NY credit facilities contain certain covenants and
negative pledges that must be met by each borrower under its respective facility
to borrow funds or obtain letters of credit, and which require Orion MidWest and
Orion NY to maintain a
45
combined debt service coverage ratio of 1.5 to 1.0. These covenants are not
anticipated to materially restrict either borrower's ability to borrow funds or
obtain letters of credit under its respective credit facility. These covenants
do, however, increase the loan compliance burden on the Company and increase the
risk of default under the respective credit facilities. The restructured
facilities also provide for any available cash under one facility to be made
available to the other borrower to meet shortfalls in the other borrower's
ability to make certain payments, including operating costs. Although cash
sufficient to make the November and December 2002 payments on Orion Power's 12%
senior notes and 4.5% convertible senior notes was provided in connection with
the restructuring, the ability of the borrowers to make subsequent dividends to
Orion Power for such interest payments or otherwise is subject to certain
requirements that are likely to restrict such dividends.
(c) Price to Beat Fuel Factor Adjustment.
On November 13, 2002, the Company filed a request with the Texas
Utility Commission to increase the price to beat fuel factor for residential and
small commercial customers, based on a 7.7% increase in the price of natural gas
from its previous request in May 2002. The Company's requested increase was
based on a 10 trading day, average forward 12-month natural gas price of
$4.02/mmbtu. The requested increase represents a 2.6% increase in the total bill
of a residential customer using, on average, 1,000 kWh per month. If no hearing
is requested, the earliest the new price to beat could go into effect would be
December 3, 2002. For additional information regarding the current price to beat
fuel factor, see Note 14.
(d) Liquidation of Interest Rate Swaps
In November, 2002, the Company liquidated $500 million of the
forward-starting interest rate swaps that were entered into in January 2002.
The liquidation of these hedges resulted in a loss of $52 million, which was
recorded in other comprehensive income and will be amortized into interest
expense in the same period during which the forecasted interest payment affects
earnings. Should the forecasted interest payment be no longer probable, any
remaining deferred amount will be recognized immediately as an expense.
46
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EFFECTS OF RESTATEMENT ON THE INTERIM FINANCIAL STATEMENTS FOR THE
THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2001
As more fully described in Note 1 to the Reliant Resources 10-K/A
Notes, on May 9, 2002, we determined that we had engaged in same-day commodity
trading transactions involving purchases and sales with the same counterparty
for the same volume at substantially the same price. The personnel who effected
these transactions apparently did so with the sole objective of increasing
volumes. We commenced a review to quantify the amount and assess the impact of
these trades (round trip trades). The Audit Committees (Audit Committees) of
each of the Board of Directors of Reliant Resources and Reliant Energy,
Incorporated (Reliant Energy) also directed an internal investigation by outside
legal counsel, with assistance by outside accountants, of the facts and
circumstances relating to the round trip trades and related matters. CenterPoint
Energy, Inc. (CenterPoint Energy) was formed on August 31, 2002 as the new
holding company of Reliant Energy. CenterPoint Energy is a diversified
international energy services and energy delivery company that owned the
majority of Reliant Resources outstanding common stock prior to September 30,
2002.
Prior to the third quarter of 2002, we reported all trading, marketing
and risk management services transactions on a gross basis with such
transactions being reported in revenues and expenses except primarily for
financial gas transactions such as swaps. Therefore, the round trip trades were
reflected in both our revenues and expenses. The round trip trades should not
have been recognized in revenues or expenses (i.e., they should have been
reflected on a net basis). However, since the round trip trades were done at the
same volume and substantially the same price, they had no impact on our reported
cash flows, operating income or net income.
Based on our review, we determined that we engaged in such round trip
trades in 1999, 2000 and 2001. The results of the Audit Committees'
investigation were consistent with the results of our review. The round trip
trades were for 20 million megawatt hours (MWh) of power and 61 MWh of power for
the three and nine months ended September 30, 2001, respectively, and 46 Bcf of
natural gas for the nine months ended September 30, 2001.
These round trip trades collectively had the effect of increasing each
of revenues and purchased power expense by $847 million, respectively, for the
three months ended September 30, 2001 and increasing revenues, fuel and gas sold
expense and purchased power expense by $3.5 billion, $180 million and $3.3
billion, respectively, for the nine months ended September 30, 2001.
In the course of our review, we also identified and determined that we
should record on a net basis several transactions for energy related services
(not involving round trip trades) that totaled $13 million and $30 million for
the three and nine months ended September 30, 2001, respectively. These
transactions were originally recorded on a gross basis.
In addition, during the May 2001 through September 2001 time frame, we
entered into four structured transactions involving a series of forward or swap
contracts to buy and sell an energy commodity in 2001 and to buy and sell an
energy commodity in 2002 or 2003 (four structured transactions). The four
structured transactions were intended to increase future cash flow and earnings
and to increase certainty associated with future cash flow and earnings, albeit
at the expense of 2001 cash flow and earnings. Each series of contracts in a
structure were executed with the same counterparty. The contracts in each
structure were offsetting in the aggregate in terms of physical attributes. The
transactions that settled during the three and nine months ended September 30,
2001 were previously recorded on a gross basis with such transactions being
reported in revenues and expenses which resulted in $700 million of revenues,
$206 million in fuel and cost of gas sold and $494 million of purchased power
expense, and in $1.0 billion of revenues, $367 million in fuel and cost of gas
sold and $656 million of purchased power expense being recognized in each
period, respectively. These transactions should have been accounted for on a net
basis.
The consolidated financial statements for the three and nine months
ended September 30, 2001 have been restated from amounts previously reported to
reflect the transactions discussed above on a net basis. The restatement had no
impact on previously reported consolidated cash flows, operating income or net
income. A summary of the principal effects of the restatement on our interim
financial statements are set forth in Note 1 to our Interim Financial
Statements.
47
Furthermore, in September 2002, during our review of certain trading
transactions in connection with various pending investigations, we identified
four natural gas financial swap transactions that should not have been recorded
in our records. We have concluded, based on the offsetting nature of the
transactions and manner in which the transactions were documented, that none of
the transactions should have been given accounting recognition. We accounted for
the transactions in our financial statements as a reduction in revenues in
December 2000 and an increase in revenues in January 2001, with the effect of
decreasing net income in the fourth quarter of 2000 and increasing net income in
the first quarter of 2001, in each case by $20.0 million pre-tax ($12.7 million
after-tax), and the effect of increasing basic and diluted earnings per share by
$0.05 in the first quarter of 2001. There were no cash flows associated with the
transactions. We have further concluded, after considering both qualitative and
quantitative factors, that a restatement of our financial statements for this
item is not required. However, on November 12, 2002, we amended our annual
report on Form 10-K/A for the year ended December 31, 2001 to disclose this
transaction in our unaudited quarterly information footnote to the consolidated
financial statements (please read Note 15 to the Reliant Resources 10-K/A
Notes).
OVERVIEW
The following discussion and analysis should be read in combination
with our Interim Financial Statements contained in this Form 10-Q.
We provide electricity and energy services with a focus on the
competitive wholesale and retail segments of the electric power industry in the
United States. We acquire, develop and operate electric power generating
facilities that are not subject to traditional cost-based regulation and
therefore can generally sell power at prices determined by the market. We also
trade and market power, natural gas and other energy-related commodities and
provide related risk management services.
In this section we discuss our results of operations on a consolidated
basis and individually for each of our business segments. We also discuss our
liquidity and capital resources. Our financial reporting segments include
Wholesale Energy, European Energy, Retail Energy and Other Operations. For
segment reporting information, please read Note 15 to our Interim Financial
Statements.
On February 19, 2002, we acquired all of the outstanding shares of
common stock of Orion Power Holdings, Inc. (Orion Power) for $26.80 per share in
cash for an aggregate purchase price of $2.9 billion. As of February 19, 2002,
Orion Power's debt obligations were $2.4 billion ($2.1 billion net of restricted
cash pursuant to debt covenants). For additional information regarding our
acquisition of Orion Power, please read Note 6 to our Interim Financial
Statements.
In May 2001, we offered 59.8 million shares of our common stock to the
public at an initial public offering (IPO) price of $30 per share and received
net proceeds of $1.7 billion. Pursuant to the master separation agreement
between Reliant Resources and Reliant Energy (Master Separation Agreement), we
used $147 million of the net proceeds to repay certain indebtedness owed to
Reliant Energy. On September 30, 2002, CenterPoint Energy distributed all of the
240 million shares of Reliant Resources common stock it owned to its common
shareholders of record as of the close of business on September 20, 2002
(Distribution). The Distribution completed the separation of Reliant Resources
and CenterPoint Energy into two separate publicly held companies.
We may experience changes in our cost structure, funding and operations
as a result of our separation from CenterPoint Energy, including increased costs
associated with reduced economies of scale, and increased costs associated with
being a publicly traded, independent company. We cannot currently predict, with
any certainty, the actual amount of increased costs we may incur, if any.
During 2002, weaker pricing for capacity, ancillary services and power
coupled with a narrowing of the spread between power prices and natural gas fuel
costs (spark spread) in the United States as well as the effects of market
contraction, reduced volatility and reduced liquidity in the United States and
Northwest Europe power trading markets; and downgrades in our credit ratings to
below investment grade by each of the major rating agencies has negatively
impacted us, among other factors. We expect this trend to continue in 2003.
However, in the long-term we anticipate that supply surpluses will tighten,
regulatory intervention will be more balanced, prices will improve for capacity,
ancillary services and power and spark spreads will widen. This view is
consistent with our fundamental belief that long run market prices must reach
levels sufficient to support an adequate rate of return on the construction of
new generation. However, if in the long term the current weak environment
persists, we could have significant impairments of our property and equipment
and goodwill.
48
The following table provides summary data regarding our consolidated
results of operations for the three and nine months ended September 30, 2001 and
2002.
CONSOLIDATED RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
--------------------------------- --------------------------------
2001 2002 2001 2002
-------------- ---------------- ------------- ----------------
(IN MILLIONS)
Operating Revenues(1) ................. $ 2,462 $ 5,355 $ 5,666 $ 9,512
Operating Expenses .................... 2,110 5,073 4,907 8,731
------- ------- ------- -------
Operating Income ...................... 352 282 759 781
Other Income (Expense), net ........... 12 (82) 63 (158)
Income Tax Expense .................... (150) (142) (301) (290)
------- ------- ------- -------
Income Before Cumulative Effect of .... 214 58 521 333
Accounting Change
Cumulative Effect of Accounting Change,
net of tax .......................... -- -- 3 (234)
------- ------- ------- -------
Net Income ............................ $ 214 $ 58 $ 524 $ 99
======= ======= ======= =======
Basic Earnings Per Share .............. 0.71 0.20 1.93 0.34
======= ======= ======= =======
Diluted Earnings Per Share ............ 0.71 0.20 1.92 0.34
======= ======= ======= =======
- -----------------
(1) Operating Revenues reflect trading activities on a net basis as described
in Note 3 to our Interim Financial Statements.
Three months ended September 30, 2001 compared to three months ended September
30, 2002
Net Income. We reported consolidated net income of $58 million ($0.20
per diluted share) for the three months ended September 30, 2002 compared to
$214 million ($0.71 per diluted share) for the three months ended September 30,
2001. The decrease in earnings was primarily due to the following:
- a $283 million decrease in earnings before interest and income
taxes (EBIT) from our Wholesale Energy segment;
- a $97 million increase in net interest expense; and
- changes in the effective tax rate which are further described
below.
The above items were partially offset by a $243 million increase in
EBIT from our Retail Energy segment.
Earnings before Interest and Income Taxes. For an explanation of
changes in EBIT, please read the discussion below under "- Earnings Before
Interest and Income Taxes by Business Segment."
Interest Expense. We incurred net interest expense of $91 million
during the three months ended September 30, 2002 compared to net interest income
of $6 million in the same period of 2001. The increase in net interest expense
of $97 million in 2002 as compared to 2001 resulted primarily from a $95 million
increase in interest expense to third parties, net of interest expense
capitalized on projects, primarily as a result of higher levels of borrowings
related to the acquisition of Orion Power in February 2002 and a $10 million
decrease in interest income from affiliated companies as a result of decreased
excess cash being invested with a subsidiary of CenterPoint Energy during the
three months ended September 30, 2002 as compared to the same period in 2001.
This was partially offset by an increase in interest income from third parties
of $8 million primarily due to the investment on a short-term basis of cash on
hand during the three months ended September 30, 2002 compared to the same
period in 2001.
Income Tax Expense. During the three months ended September 30, 2001
and 2002, our effective tax rate was 41.3% and 71.1%, respectively. Our
reconciling items from the federal statutory rate of 35% to the effective tax
rate totaled $72 million for the three months ended September 30, 2002. During
the three months ended September 30, 2002, we accrued a $45 million United
States federal tax provision for future cash distributions from our equity
investment in NEA, the former coordinating body for the Dutch electric
generating sector prior to Wholesale competition, which is held by our European
Energy segment. Based on our current tax position, during the third quarter of
2002, we determined that we would be obligated to pay United States taxes on
future cash distributions from NEA in excess of our tax basis. As of September
30, 2002, our investment in NEA was $192 million. For further discussion of our
investment in NEA, please read Note 13(f) to the Reliant Resources Form 10-K/A
and Note 12(d) to our Interim Financial Statements. In addition, we had
increased reconciling items from state income taxes
49
and valuation allowances partially offset by the effect of the cessation of
goodwill amortization. During the third quarter of 2002, our state income taxes
increased primarily due to Texas franchise tax associated with our Retail Energy
operations. Our valuation allowances increased primarily due to losses incurred
by our European Energy trading and origination operations during the third
quarter of 2002. Our reconciling items from the federal statutory rate of 35% to
the effective tax rate totaled $23 million for the three months ended September
30, 2001. These items primarily related to nondeductible goodwill, state income
taxes and valuation allowances partially offset by income earned by REPGB. In
2001, the earnings of REPGB were subject to a zero percent Dutch corporate
income tax rate as result of the Dutch tax holiday related to the Dutch
electricity industry. In 2002, European Energy's earnings in the Netherlands are
subject to the standard Dutch corporate income tax rate, which is currently
34.5%.
Nine months ended September 30, 2001 compared to nine months ended September 30,
2002
Net Income. We reported consolidated net income of $99 million ($0.34
per diluted share) for the nine months ended September 30, 2002 compared to $524
million ($1.92 per share) for the nine months ended September 30, 2001. The 2001
results included a cumulative effect of accounting change of $3 million, net of
tax, related to the adoption of Statement of Financial Accounting Standards
(SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities"
(SFAS No. 133), as amended. For additional discussion of the adoption of SFAS
No. 133, please read Note 6 to the Reliant Resources 10-K/A Notes. The 2002
results included a cumulative effect of accounting change of $234 million,
related to the adoption of SFAS No. 142 "Goodwill and Other Intangible Assets"
(SFAS No. 142). For additional discussion of the adoption of SFAS No. 142,
please read Note 7 to our Interim Financial Statements. The decrease in earnings
was primarily due to the following:
- a $665 million decrease in EBIT from our Wholesale Energy
segment; and
- a $159 million increase in net interest expense.
The above items were partially offset by:
- a $502 million increase in EBIT from our Retail Energy
segment;
- a $30 million increase in EBIT from our European Energy
segment;
- a $53 million decrease in charges incurred relating to the
redesign and settlement of some of Reliant Energy's benefit
plans related to our separation from CenterPoint Energy;
- $33 million in pre-tax disposal charges and impairments of
goodwill and fixed assets related to exiting our
Communications business recorded in the third quarter of 2001
by our Other Operations segment; and
- changes in our effective tax rate which are further discussed
below.
Earnings before Interest and Income Taxes. For an explanation of
changes in EBIT, please read the discussion below under "- Earnings Before
Interest and Income Taxes by Business Segment."
Interest Expense. We incurred net interest expense of $185 million
during the nine months ended September 30, 2002 compared to $26 million in the
same period of 2001. The increase in net interest expense of $159 million in
2002 as compared to 2001 resulted primarily from a $157 million increase in
interest expense to third parties, net of interest expense capitalized on
projects, primarily as a result of higher levels of borrowings related to the
acquisition of Orion Power in February 2002. Interest income on net advances to
affiliated companies in the first nine months of 2002 as compared to the first
nine months of 2001, decreased $3 million. This decrease resulted primarily from
decreased net advancements of excess cash to a subsidiary of CenterPoint Energy
during the nine months ended September 30, 2002 partially offset by interest
expense incurred prior to the conversion into equity of $1.7 billion of debt
owed to CenterPoint Energy and its subsidiaries in connection with the
completion of the IPO in 2001.
Income Tax Expense. During the nine months ended September 30, 2001 and
2002, our effective tax rate was 36.6% and 46.6%, respectively. Our reconciling
items from the federal statutory rate of 35% to the effective tax rate totaled
$72 million for the nine months ended September 30, 2002. Our reconciling items
from the federal statutory rate of 35% to the effective tax rate totaled $13
million for the nine months ended September 30, 2001. The items impacting the
effective tax rate for the nine months ended September 30, 2001 and 2002 are
primarily consistent with those impacting the three months ended September 30,
2001 and 2002 discussed above.
50
EARNINGS BEFORE INTEREST AND INCOME TAXES BY BUSINESS SEGMENT
The following table presents EBIT for each of our business segments for
the three and nine months ended September 30, 2001 and 2002. EBIT represents
earnings (loss) before interest expense, interest income and income taxes. EBIT,
as defined, is shown because it is a widely accepted measure of financial
performance used by some analysts and investors to analyze and compare companies
on the basis of operating performance. It is not defined under accounting
principles generally accepted in the United States of America (GAAP), and should
not be considered in isolation or as a substitute for a measure of performance
prepared in accordance with GAAP and is not indicative of operating income from
operations as determined under GAAP. Additionally, our computation of EBIT may
not be comparable to other similarly titled measures computed by other
companies, because all companies do not calculate it in the same fashion. For a
reconciliation of our operating income to EBIT and EBIT to net income, please
read Note 15 to our Interim Financial Statements.
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
------------------------------- --------------------------------
2001 2002 2001 2002
------------- -------------- -------------- ----------------
(IN MILLIONS)
Wholesale Energy ...................... $ 402 $ 119 $ 929 $ 264
European Energy ....................... (4) (13) 80 110
Retail Energy ......................... (8) 235 (13) 489
Other Operations ...................... (32) (50) (148) (55)
------- ------- ------- -------
Total Consolidated .............. $ 358 $ 291 $ 848 $ 808
======= ======= ======= =======
WHOLESALE ENERGY
Wholesale Energy includes our non-regulated power generation operations
in the United States and our wholesale energy trading, marketing, origination
and risk management operations in North America. Wholesale Energy's activities
include purchasing fuel to supply existing generation assets, selling
electricity produced by these assets, purchasing natural gas for resale to
customers, managing the day-to-day trading, scheduling of power and natural gas,
and dispatching of the generation portfolios.
During 2002, we have evaluated our trading, marketing, power
origination and risk management services strategies. In the third quarter of
2002, we began to reduce our trading, marketing and power origination activities
in order to significantly reduce collateral usage and focus commercial
organization on the highest return activities primarily around our core asset
positions. In addition, trading activity across the industry has decreased
dramatically. The restructuring of our commercial and support groups resulted in
severance costs of $6 million in the third quarter of 2002. Both commercial
margins and general and administrative costs are expected to be lower going
forward.
During 2002, weaker pricing for capacity, ancillary services and power
coupled with a narrowing of the spread between power prices and natural gas fuel
costs (spark spread) negatively impacted the Wholesale Energy segment. In
addition, the effects of market contraction, reduced volatility and reduced
liquidity in the United States power trading markets have also negatively
impacted the Wholesale Energy segment. We expect this trend to continue in 2003.
However, in the long-term we anticipate that supply surpluses will tighten,
regulatory intervention will be more balanced, prices will improve for capacity,
ancillary services and power and spark spreads will widen. This view is
consistent with our fundamental belief that long run market prices must reach
levels sufficient to support an adequate rate of return on the construction of
new generation. However, if in the long term the current weak environment
persists the Wholesale Energy segment could have significant impairments of its
property and equipment and goodwill.
We have identified certain non-strategic domestic generating assets for
potential sale to enhance our liquidity position. To date, we have not reached
an agreement to dispose of any material assets nor have we contemplated any
proceeds from asset sales in our current liquidity plan. Due to unfavorable
market conditions in the wholesale power markets, there can be no assurance that
we will be successful in disposing of domestic generating assets at reasonable
prices or on a timely basis. Specific plans to dispose of assets could result in
impairment losses in property and equipment.
SFAS No. 142 requires goodwill to be tested annually and between annual
tests if events occur or circumstances change that would more likely than not
reduce the fair value of a reporting unit below its carrying amount. We have
elected to perform our annual test for indications of goodwill impairment as of
November 1, in conjunction with our
51
annual planning process. We anticipate finalizing our annual impairment test
during the fourth quarter of 2002 and currently cannot estimate the outcome. As
of September 30, 2002, the Wholesale Energy segment has goodwill of $1.6
billion.
For additional information regarding factors that may affect the future
results of operations of Wholesale Energy, please read "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Certain Factors
Affecting Our Future Earnings - Factors Affecting the Results of Our Wholesale
Energy Operations" in the Reliant Resources Form 10-K/A.
The following table provides summary data, including EBIT, of Wholesale
Energy for the three and nine months ended September 30, 2001 and 2002.
WHOLESALE ENERGY
------------------------------------------------------------------
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- --------------------------------
2001 2002 2001 2002
------------ --------------- -------------- ----------------
(IN MILLIONS)
Revenues ..................................... $ 2,227 $ 3,479 $ 4,797 $ 5,554
Trading Margins .............................. 44 34 276 131
------- ------- ------- -------
Total Operating Revenues ................... 2,271 3,513 5,073 5,685
Operating Expenses:
Fuel and Cost of Gas Sold .................. 385 428 1,451 829
Purchased Power ............................ 1,298 2,606 2,174 3,687
Operation and Maintenance .................. 87 167 243 412
General, Administrative and Development .... 73 86 203 268
Depreciation and Amortization .............. 28 115 90 248
------- ------- ------- -------
Total Operating Expenses ................. 1,871 3,402 4,161 5,444
------- ------- ------- -------
Operating Income ............................. 400 111 912 241
------- ------- ------- -------
Other Income:
Income of equity investment of unconsolidated
subsidiaries ............................... 2 1 16 11
Other, net ................................... -- 7 1 12
------- ------- ------- -------
Earnings Before Interest and Income Taxes .... $ 402 $ 119 $ 929 $ 264
======= ======= ======= =======
Margins:
Power generation(1) ........................ $ 544 $ 445 $ 1,172 $ 1,038
Trading .................................... 44 34 276 131
------- ------- ------- -------
Total .................................... $ 588 $ 479 $ 1,448 $ 1,169
======= ======= ======= =======
Operations Data:
Physical Wholesale Power Generation Sales
(in thousand MWh(2)(4)) .................. 20,107 60,544 48,974 105,852
Trading Power Volumes (4) .................. 59,936 123,310 145,548 244,332
Trading Natural Gas Sales (in Bcf(3))(4) 880 897 2,324 2,925
- --------------
(1) Revenues less fuel and cost of gas sold and purchased power.
(2) Megawatt hours.
(3) Billion cubic feet.
(4) Includes physically delivered volumes, physical transactions that are settled prior to delivery and hedge activity
related to our power generation portfolio
Wholesale Energy's EBIT decreased by $283 million for the three months
ended September 30, 2002 compared to the same period in 2001. Wholesale Energy's
EBIT decreased by $665 million for the nine months ended September 30, 2002
compared to the same period in 2001. The decline in EBIT is primarily due to
decreases in gross margin from our power generation operations and decreases in
trading margin, partially offset by the effect of the acquisition of Orion Power
which closed in February 2002.
In addition to the various market-related reasons for changes in
Wholesale Energy's EBIT in 2002, EBIT has been impacted by Federal Energy
Regulatory Commission (FERC) staff interpretations of a May 15, 2002 FERC order
revising the methodology for calculating refunds of California energy sales. In
the third quarter of 2002,
52
Wholesale Energy recorded an additional reserve of $21 million for potential
refunds owed by the Company. For the nine months ended September 30, 2002, we
have recorded a reserve of $55 million for such potential refunds. The Company's
inception-to-date reserve for such refunds totals $70 million as of September
30, 2002. We estimate the range of our refund obligations for California energy
sales to be $70 million to $190 million. Wholesale Energy's EBIT was also
impacted by changes to the credit reserve for California receivable balances.
The changes in the credit reserves resulted from the FERC refunds described
above, collections during the period as well as a determination that credit risk
had been reduced on certain outstanding receivables following payments made by
one creditor to the California Power Exchange. Accordingly, the credit reserve
was reduced by $6 million and $44 million in the three and nine months ended
September 30, 2002, respectively. The credit reserve increased by $33 million
for the nine months ended September 30, 2001. During the three months ended
September 30, 2001, the credit reserve was not adjusted. For information
regarding the reserves against receivables, FERC refund methodology and
uncertainties in the California wholesale energy market, please read Notes 12(a)
and 12(c) to our Interim Financial Statements.
Wholesale Energy's gross margin from power generation operations
decreased by $99 million in the three months ended September 30, 2002 compared
to the same period in 2001. This decrease was primarily due to a $289 million
decline in 2002 margin caused by deterioration in favorable conditions that
existed in the West in 2001 and by increased refund requirements discussed
above. In addition, the Mid-Atlantic region experienced an $85 million decrease
in gross margin in 2002 due to a 28% decline in prices for power sales and
reduced capacity as a result of the expiration of a capacity contract. The gross
margin for this period benefited by $263 million from the Orion acquisition in
February 2002 and by $35 million in gross margin from new plants that became
commercially operational in the second half of 2001.
Wholesale Energy's gross margin from power generation operations is
comprised of revenues less fuel and cost of gas sold and purchased power.
Revenues increased by $1.3 billion (56%) in the three months ended September 30,
2002 compared to the same period in 2001. The major components of this increase
are $421 million in revenues from Orion Power, which we acquired in February
2002, and $2.0 billion in revenues from the Mid-Atlantic region due to favorable
hedging, marketing and operating results. These were offset by a reduction in
hedging, marketing and operating results of the California region of $1.5
billion. Wholesale Energy's revenues and gross margin for the three months ended
September 30, 2001 benefited from favorable conditions in the West caused by a
combination of factors including reduction in available hydroelectric generation
resources, increased demand, and decreased electric imports. Wholesale Energy's
fuel and cost of gas sold and purchased power increased by $1.4 billion in the
three months ended September 30, 2002. The major components of this increase are
due to increased hedging and marketing activities in the Mid-Atlantic region
($2.1 billion) partially offset by a reduction in the hedging and marketing
results in the California region ($1.2 billion) coupled with increased fuel
expense due to a 79% increase in power generation sales volumes, excluding
hedging activity, largely due to the Orion Power acquisition that closed in
February 2002.
Trading gross margins decreased $10 million in the three months ended
September 30, 2002 compared to the same period in 2001, primarily due to changes
in our physical gas businesses that had been profitable but were creating high
collateral demands. Also during the third quarter 2002, Wholesale Energy reduced
trading activities not associated with our core generation asset positions.
For the nine-month period ending September 30, 2002, Wholesale Energy's
gross margin from power generation operations decreased by $134 million compared
to the same period in 2001. The decline in favorable conditions that existed in
the West region in 2001 coupled with the increased refund requirements discussed
above caused an unfavorable variance in the West region of $634 million. In
addition, the Mid-Atlantic region experienced a $108 million decrease in gross
margin in 2002 due to a 20% decline in prices for power sales and reduced
capacity as a result of the expiration of a capacity contract. This unfavorable
variance was offset by $526 million in gross margin from the Orion Power
acquisition that closed in February 2002 and by $76 million in gross margin from
new plants that became commercially operational in the second half of 2001.
Wholesale Energy's revenues increased by $757 million (16%) in the nine
months ended September 30, 2002 compared to the same period in 2001. The major
components of this increase are $2.4 billion in the Mid-Atlantic region as a
result of favorable hedging, marketing and operating results and $824 million in
revenues contributed by Orion Power. These increased revenues were offset by a
decline of $2.7 billion in California revenues for this period. Wholesale
Energy's fuel and cost of gas sold and purchased power increased by $891 million
in the nine months ended September 30, 2002 due primarily to $2.5 billion in the
Mid-Atlantic region as a result of hedging and
53
marketing activities and an increase of $297 million due to Orion Power. This
partially was offset by a reduction of hedging and marketing activities in the
California region of $2.2 billion.
Trading gross margins decreased $145 million primarily as a result of
lower commodity volatility and decreased trading activity across the industry
including the reduction in trading activity associated with our core generation
asset positions.
Operation and maintenance expenses for Wholesale Energy increased $80
million in the three months ended September 30, 2002 compared to the same period
in 2001. This was primarily due to $90 million of operation and maintenance
expenses of our Orion Power generating plants acquired in February 2002
partially offset by savings generated from a cost reduction program. General,
administrative and development expenses increased $13 million in the three
months ended September 30, 2002 compared to the same period in 2001, primarily
due to higher administrative costs and corporate overhead allocations to support
wholesale commercial activities, which included the integration of Orion Power,
and $6 million in severance expense incurred in the three months ended September
30, 2002 for staff reductions related to the reduction of our trading and
marketing activities.
Operation and maintenance expenses for Wholesale Energy increased $169
million in the nine months ended September 30, 2002 compared to the same period
in 2001. This was primarily due to $185 million of operation and maintenance
expenses of our Orion Power generating plants acquired in February 2002
partially offset by savings generated from a cost reduction program. General,
administrative and development expenses increased $65 million in the nine months
ended September 30, 2002 compared to the same period in 2001, primarily due to
higher administrative costs and corporate overhead allocations to support
wholesale commercial activities, including the integration of Orion Power, and
$12 million of severance expense as discussed above. In addition, during the
nine months ended September 30, 2002, Wholesale Energy incurred increased
expenses related to development activities of $28 million, which includes
write-offs of $17 million in previously capitalized costs related to projects
that have been terminated.
Depreciation and amortization expense increased by $87 million in the
three months ended September 30, 2002 compared to the same period in 2001
primarily as a result of $46 million in depreciation expense related to our
Orion Power plants and other generating plants placed into service after the
third quarter of 2001 and a $37 million impairment charge on turbines and
generators. For the three months ended September 30, 2001, Wholesale Energy
recorded $2 million in amortization expense related to goodwill.
Depreciation and amortization expense increased by $158 million in the
nine months ended September 30, 2002 compared to the same period in 2001
primarily as a result of $116 million in depreciation expense related to our
Orion Power plants and other generating plants placed into service after the
third quarter of 2001, a $15 million write-off for the closure of a plant, and a
$37 million equipment impairment related to turbines and generators. These were
partially offset by lower amortization of air emission allowances of $21 million
primarily related to our California power generation operations. For the nine
months ended September 30, 2001, Wholesale Energy recorded $4 million in
amortization expense related to goodwill. For information regarding the
cessation of goodwill amortization, please read Note 2(q) to the Reliant
Resources 10-K/A Notes and Note 7 to our Interim Financial Statements.
Our Wholesale Energy segment reported income from equity investments
for the three and nine months ended September 30, 2002 of $1 million and $11
million, respectively, compared to $2 million and $16 million in the same
periods in 2001, respectively. The equity income in both periods primarily
resulted from an investment in an electric generation plant in Boulder City,
Nevada. The equity income related to our investment in the plant decreased
during the nine months ended September 30, 2002 compared to the same period in
2001, primarily due to decreases in margins due to lower prices realized in
2002, partially offset by the receipt of business interruption and other
insurance claims totaling $12 million.
EUROPEAN ENERGY
European Energy generates and sells power from its generation
facilities in the Netherlands and participates in the emerging wholesale energy
trading and power origination industry in Northwest Europe.
In September 2002, we concluded a comprehensive evaluation of our
European Energy segment's businesses and it was decided that proprietary trading
would be significantly reduced in order to focus on optimization of our power
generation assets in the Netherlands. Accordingly, on September 25, 2002, we
announced the closure of
54
our London-based natural gas and electricity trading operations. In addition, we
are in the process of consolidating facilities, centralizing activities and
reducing personnel in other operating centers. As a result, European Energy
recorded a $8 million reorganization charge, primarily related to severance, in
operating and maintenance and general and administrative expenses as discussed
below.
During the third quarter of 2002, we completed the transitional
impairment test for the adoption of SFAS No. 142, including the review of
goodwill for impairment. Based on this impairment test, we recorded an
impairment of European Energy segment's goodwill of $234 million. This
impairment loss was recorded retroactively as a cumulative effect of a change in
accounting principle for the quarter ended March 31, 2002. Our measurement of
the fair value of European Energy was based on both an income approach, using
future discounted cash flows, and a market approach, using acquisition
multiples, including price per Megawatt, based on publicly available data for
recently completed European transactions. For further discussion of the
impairment, please read Note 7 to our Interim Financial Statements.
The circumstances leading to the impairment of our European Energy
segment's goodwill included a significant decline in electric margins
attributable to the deregulation of the European electricity market in 2001,
lack of growth in the wholesale energy trading markets in Northwest Europe and
continued regulation of the European fuel markets. We anticipate that power
prices will continue to be depressed throughout 2003, but we believe that prices
will improve over the long-term. If prices do not improve or there are
additional declines in prices, the European Energy segment could have
significant impairments of its property and equipment and goodwill.
SFAS No. 142 requires goodwill to be tested annually and between annual
tests if events occur or circumstances change that would more likely than not
reduce the fair value of a reporting unit below its carrying amount. We have
elected to perform our annual test for indications of goodwill impairment as of
November 1, in conjunction with our annual planning process. We anticipate
finalizing our annual impairment test during the fourth quarter of 2002 and
currently cannot estimate the outcome. As of September 30, 2002, the European
Energy segment has goodwill of $492 million.
For additional information regarding factors that may affect the future
results of operations of European Energy, please read "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Certain Factors
Affecting Our Future Earnings - Factors Affecting the Results of Our European
Energy Operations" in the Reliant Resources Form 10-K/A.
55
The following table provides summary data, including EBIT, of European
Energy for the three and nine months ended September 30, 2001 and 2002.
EUROPEAN ENERGY
---------------------------------------------------------------------
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2001 2002 2001 2002
--------------- ---------------- --------------- ---------------
(IN MILLIONS)
Revenues ................................... $ 142 $ 145 $ 472 $ 447
Trading Margins ............................ 3 3 6 10
------- ------- ------- -------
Total Operating Revenues ................. 145 148 478 457
Operating Expenses:
Fuel ..................................... 91 67 294 254
Purchased Power .......................... 9 38 15 (55)
Operation and Maintenance ................ 17 25 56 87
General, Administrative and Development .. 13 18 33 26
Depreciation and Amortization ............ 20 16 57 42
------- ------- ------- -------
Total Operating Expenses ............... 150 164 455 354
------- ------- ------- -------
Operating (Loss) Income .................... (5) (16) 23 103
------- ------- ------- -------
Other Income:
Income of equity investment of
unconsolidated subsidiaries .............. -- -- 51 --
Other, net ................................. 1 3 6 7
------- ------- ------- -------
(Loss) Earnings Before Interest and Income
Taxes .................................... $ (4) $ (13) $ 80 $ 110
======= ======= ======= =======
Margins:
Power Generation(1) ...................... $ 42 $ 40 $ 163 $ 248
Trading .................................. 3 3 6 10
------- ------- ------- -------
Total .................................. $ 45 $ 43 $ 169 $ 258
======= ======= ======= =======
Electricity (in thousand MWh):
Power Generation Sales ................... 4,013 4,257 11,885 13,198
Trading Sales ............................ 5,687 17,883 14,641 52,436
- -------------
(1) Revenues less fuel and purchased power.
European Energy's EBIT decreased $9 million and increased $30 million
for the three and nine months ended September 30, 2002 compared to the same
periods in 2001 due to changes in gross margins (revenues less fuel and
purchased power) as explained below. During the nine months ended September 30,
2002, European Energy recognized a one-time $109 million gain resulting from the
amendment of our stranded cost electricity supply contracts which is recorded as
a reduction in purchase power expense and is included in gross margins. For
additional discussion regarding the amendment of these contracts please read
Note 12(d) to our Interim Financial Statements.
European Energy's revenues increased $3 million for the three months
ended September 30, 2002 compared to the same period in 2001, while trading
margins remained flat. Driving the increase in revenues was an increase in the
volume of electricity sales and higher average sales prices realized in 2002,
compared to the third quarter of 2001. Trading margins remained flat, despite
substantially higher settlement volumes, as margins have declined from 2001
levels due to credit and liquidity concerns which continue to impact the
European power and gas markets.
European Energy's revenues decreased $25 million for the nine months
ended September 30, 2002 compared to the same period in 2001, while trading
margins increased by $4 million. While electricity sales increased by $32
million, period on period, ancillary services and district heating revenues
decreased by a combined total of $11 million. Also contributing to the decline
from 2001 was a non-recurring efficiency and energy payment of $30 million
received during the second quarter of 2001 from NEA, which was the coordinating
body for the Dutch electric generating sector prior to wholesale competition.
Trading margins increased $4 million for the nine months ended September 30,
2002 compared to 2001 primarily due to an increase in power trading volumes and
trading origination transactions. However, there has been a significant decrease
in overall market liquidity from prior year levels and we have ceased trading on
a proprietary basis during the third quarter of 2002. In addition, the overall
decrease in total operating revenues was impacted by an unfavorable foreign
exchange effect of $16 million.
56
Fuel and purchased power costs increased $5 million for the three
months ended September 30, 2002 compared to the same period in 2001 primarily
due to higher volumes of purchased power and higher consumption of natural gas
partially offset by lower consumption of coal in the third quarter of 2002
relative to the third quarter of 2001. During the third quarter of 2002, we
consumed comparatively less coal, a less expensive fuel than natural gas, due to
planned maintenance of a coal burning unit. Also, the comparatively higher level
of electricity sales during the third quarter of 2002, in combination with our
fuels optimization strategy, have led to higher levels of purchased power. This
overall increase in fuel cost was impacted by a favorable foreign exchange
effect of $4 million.
Fuel and purchased power costs decreased $110 million for the nine
months ending September 30, 2002 compared to the same period in 2001 primarily
due to a one-time $109 million gain as discussed above and a net $16 million
gain related to changes in the valuation of certain out-of-market contracts in
the first half of 2002. In addition, higher electricity sales levels have driven
comparatively higher levels of fuel consumption and purchased power during the
nine months ended September 30, 2002 as compared to the same period in 2001. For
further discussion of these out-of-market contracts, please read Notes 6 and
13(f) to the Reliant Resources 10-K/A Notes and Note 12(d) to our Interim
Financial Statements.
Gross margin decreased $2 million for the three months ended September
30, 2002 compared to the same period in 2001 primarily due to our power
generation operations discussed above.
Gross margin increased $89 million for the nine months ended September
30, 2002 compared to the same period in 2001 primarily due to (a) the one-time
$109 million gain discussed above, (b) the $16 million net gain recognized in
fuel expense discussed above and (c) a $4 million increase in trading margin due
to a increase in power trading volumes and trading origination transactions.
Partially offsetting these increases were the $30 million payment received
during the second quarter of 2001 from NEA, and decreased margins on ancillary
services and district heating of $6 million. Further offsetting the increase in
gross margin were unscheduled plant outages at certain of our electric
generating facilities in the first half of 2002. We estimate that these
unplanned outages resulted in a net decrease in gross margin of approximately $7
million. We also estimate that planned outages of certain facilities further
negatively impacted margins by approximately $3 million during the third quarter
of 2002.
Operation and maintenance and general and administrative expenses
increased by $13 million for the three months ended September 30, 2002 compared
to the same period in 2001. The increase was primarily attributable to $8
million in reorganization and severance charges associated with our business
restructuring as discussed above. Also contributing to the increase were
increased consulting fees and employee benefit expenses, as well as increased
expenses associated with the trading business.
Operation and maintenance and general and administrative expenses
increased by $24 million for the nine months ended September 30, 2002 compared
to the same period in 2001. The increase was primarily attributable to the
reasons discussed above plus increased environmental expenditures of $2 million,
and reversal of a reserve for environmental tax subsidies receivable in 2001 of
$4 million.
Depreciation and amortization expenses decreased $4 million during the
third quarter of 2002 compared to the same period in 2001 primarily due to the
cessation of goodwill amortization effective January 1, 2002. During the three
months ended September 30, 2001, European Energy recorded $6 million in
amortization expense related to goodwill. For additional discussion regarding
the cessation of goodwill amortization, please read Note 2(q) to Reliant
Resources Form 10-K/A Notes and Note 7 to our Interim Financial Statements. This
decrease was partially offset by an increase of $1 million in depreciation
expense during the same period as a result of capital expenditures in late 2001
associated with our trading business.
Depreciation and amortization expenses decreased $15 million for the
nine months ended September 30, 2002 compared to the same period in 2001
primarily due to the cessation of goodwill amortization effective January 1,
2002. During the nine months ended September 30, 2001, European Energy recorded
$19 million in amortization expense related to goodwill. This decrease was
partially offset by an increase of $3 million in depreciation expense during the
same period as a result of capital expenditures in late 2001 associated with our
trading business.
Other non-operating income increased $2 million during the three months
ended September 30, 2002 compared to the same period in 2001 due to investment
income and lease income. Other non-operating income decreased $50 million during
the nine months ended September 30, 2002 compared to the same period in 2001
primarily due to a $51 million gain recorded in the second quarter of 2001, as
equity income for the preacquisition gain contingency
57
related to the acquisition of REPGB for the value of its equity investment in
NEA. For further discussion of this gain, please read Note 13(f) to the Reliant
Resources 10-K/A Notes and Note 12(d) to our Interim Financial Statements.
RETAIL ENERGY
Our Retail Energy segment provides electricity products and services to
end-use customers, ranging from residential and small commercial customers to
large commercial, industrial and institutional customers. In addition, this
segment manages the procurement of electricity supply for these customers. For
further information regarding our contract to purchase supply from Texas Genco,
please read Note 5 to our Interim Financial Statements. Retail Energy provided
billing, customer service, credit and collection and remittance services to
CenterPoint Energy's regulated electric utility and two of its natural gas
distribution divisions. The service agreement governing these services
terminated on December 31, 2001. Retail Energy charged the regulated electric
and natural gas utilities for these services at cost. We received approximately
1.7 million electric customers in the Houston metropolitan area when the Texas
market opened to full competition in January 2002. During the first nine months
of 2002, the Retail Energy segment was largely focused on the extensive efforts
necessary to transition customers from the utilities to the affiliated retail
electric providers. We recently began marketing efforts outside of the Houston
metropolitan area, primarily in the Dallas/Fort Worth area.
The Electric Reliability Council of Texas (ERCOT) independent system
operator (ERCOT ISO) is responsible for ensuring that information relating to a
customer's choice of retail electric provider is conveyed in a timely manner.
Problems in the flow of information between the ERCOT ISO, the transmission and
distribution utility and the retail electric providers have resulted in delays
in enrolling and billing customers. While the flow of information is improving,
operational problems in the new systems and processes are still being worked
out.
We depend on the local transmission and distribution utilities to read
our customers' electric meters. We are required to rely on the local utility or,
in some cases, the independent transmission system operator, to provide us with
our customers' information regarding electricity usage, such as historical usage
patterns, and we may be limited in our ability to confirm the accuracy of the
information. The provision of inaccurate information or delayed provision of
such information by the local utilities or system operators could have a
material negative impact on our business, results of operations and cash flows.
The Company records its electricity sales and services to retail
customers under the accrual method and these revenues generally are recognized
upon delivery, except for sales to large commercial, industrial and
institutional customers under contract. Contracted electricity sales to large
commercial, industrial and institutional customers are currently accounted for
under the mark-to-market method of accounting, and are presented net in trading
margins. Historically, these energy contracts are recorded at fair value in
trading margins upon contract execution. The net changes in their market values
are recognized in the income statement in trading margins in the period of the
change. Realized gains and losses are recognized in trading margins on a net
basis in the results of operations. Electricity sales and services related to
retail customers not billed are recognized based upon estimated electricity and
services delivered. At September 30, 2002, the amount not billed is $372
million, including approximately $77 million related to delayed billings.
Problems or delays in the flow of information between the ERCOT ISO, the
transmission and distribution utility and the retail electric providers and
operational problems with our new systems and processes could impact our ability
to accurately estimate the amount not billed at September 30, 2002. In addition,
we must bill the customer within six months of delivering the electricity. Any
electricity that cannot accurately be billed within that time frame cannot be
billed or collected. At September 30, 2002, the amount of electricity that
cannot be billed does not have a material impact on our results of operations or
cash flows.
The ERCOT ISO is responsible for maintaining reliable operations of the
bulk electric power supply system in the ERCOT market. The ERCOT ISO is also
responsible for handling scheduling and settlement for all electricity supply
volumes in the Texas deregulated electricity market. As part of settlement, the
ERCOT ISO communicates the actual volumes delivered compared to the volumes
scheduled. The ERCOT ISO calculates an additional charge or credit based on the
difference between the actual and scheduled volumes, based on a market clearing
price. Settlement charges also include allocated costs such as unaccounted-for
energy. Preliminary settlement information is due from ERCOT within two months
after electricity is delivered. Final settlement information is due from ERCOT
within twelve months after electricity is delivered. As a result, we record our
estimated supply costs using scheduled supply volumes and adjust those costs
upon receipt of settlement and consumption information. The ERCOT settlement
process was delayed due to operational problems between the ERCOT ISO, the
transmission and
58
distribution utility and the retail electric providers. During the third quarter
of 2002, the ERCOT ISO began issuing final settlements for the pilot time period
of July 31, 2001 to December 31, 2001. Currently, the final settlements are
being received within the 12 month time frame. The delay in the ERCOT settlement
process could impact our ability to accurately reflect our supply costs.
The Company records its transmission and distribution charges using the
same method detailed above for its electricity sales and services to retail
customers. At September 30, 2002 the transmission and distribution charges not
billed by the transmission and distribution utilities to us totaled $54 million.
Delays or inaccurate billings from the transmission and distribution utilities
could impact our ability to accurately reflect our transmission and distribution
costs.
For additional information regarding factors that may affect the future
results of operations of Retail Energy, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Certain Factors
Affecting Our Future Earnings - Factors Affecting the Results of Our Retail
Energy Operations" in the Reliant Resources Form 10-K/A.
The following table provides summary data, including EBIT, of Retail
Energy for the three and nine months ended September 30, 2001 and 2002.
RETAIL ENERGY
-------------------------------------------------------------------
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
---------------------------------- --------------------------------
2001 2002 2001 2002
--------------- ------------------ ------------- ------------------
(IN MILLIONS)
Electricity Sales and Services .................. $ 28 $ 1,196 $ 78 $ 2,487
Hedging Revenues ................................ -- 416 -- 731
Trading Margins ................................. 15 82 29 150
---- ------- ----- -------
Operating Revenues ............................ 43 1,694 107 3,368
Operating Expenses:
Purchased Power ............................... 2 1,220 2 2,430
Accrual for Payment to CenterPoint Energy, Inc. -- 89 -- 89
Operation and Maintenance ..................... 29 67 71 172
General and Administrative .................... 16 74 40 167
Depreciation and Amortization ................. 3 7 7 19
---- ------- ----- -------
Total Operating Expenses .................... 50 1,457 120 2,877
---- ------- ----- -------
Operating (Loss) Income ......................... (7) 237 (13) 491
---- ------- ----- -------
Other Loss, net ................................. (1) (2) -- (2)
---- ------- ----- -------
(Loss) Earnings Before Interest and Income Taxes $ (8) $ 235 $ (13) $ 489
==== ======= ===== =======
perations Data:
Energy Sales (gigawatt-hours (GWh)):
Residential.................................... 8,606 17,055
Small commercial............................... 3,986 10,026
Large commercial, industrial and institutional. 6,465 17,740
------- -------
Total........................................ 19,057 44,821
======= =======
Customers as of September 30, 2002 (in thousands,
metered locations):
Residential.................................... 1,469
Small commercial............................... 219
Large commercial, industrial and institutional. 22
-------
Total........................................ 1,710
=======
Our Retail Energy segment's EBIT increased $243 million and $502
million in the three and nine months ended September 30, 2002, respectively,
compared to the same period in 2001. The increase in EBIT was primarily due to
increased gross margins (revenues less purchased power) related to retail
electric sales to residential, small commercial and large commercial, industrial
and institutional customers resulting from full competition. The increases in
gross margins were partially offset by increased operating expenses as further
discussed below.
59
Electric sales and services increased $1.2 billion and $2.4 billion in
the three and nine months ended September 30, 2002, respectively, compared to
the same periods in 2001, due primarily to retail electric sales in the Texas
retail market to residential and small commercial customers and large
commercial, industrial and institutional customers that did not sign contracts.
Revenues related to the hedging, managing and optimizing of our electric energy
supply contributed approximately $416 million and $731 million, respectively, of
the increase in revenues for the three and nine months ended September 30, 2002
compared to the same periods in 2001. Purchased power expense increased $1.2
billion and $2.4 billion, respectively, for the three and nine months ended
September 30, 2002 due to costs of approximately $829 million and $1.8 billion,
respectively, associated with retail electric sales and $389 million and $656
million, respectively, associated with hedging, managing and optimizing of our
electric energy supply.
Our Retail Energy segment's gross margins increased $433 million and
$833 million in the three and nine months ended September 30, 2002,
respectively, compared to the same periods in 2001 primarily due to increased
margins of $462 million and $895 million, respectively, from retail electric
sales of which $67 million and $121 million, respectively, was increased gross
margin for electric sales to contracted energy sales to large commercial,
industrial and institutional customers due primarily to the opening of the Texas
market to full competition in January 2002, as discussed above. The increase in
our price to beat fuel factor occurring in August 2002 contributed approximately
$35 million of this increase in retail electric sales margins for the three and
nine months ended September 30, 2002. During the three and nine months ended
September 30, 2002, the Retail Energy segment recognized $82 million and $150
million, respectively, of gross margins related to commercial, industrial and
institutional electricity contracts compared to $15 million and $29 million in
the same periods in 2001, respectively. Included in these margins are unrealized
gains related to these contracts which were $38 million and $30 million in the
three and nine months ended September 30, 2002, respectively, compared to
unrealized gains of $15 million and $29 million, respectively, in the same
periods in 2001. For additional information regarding the price to beat fuel
factor increase, please read Note 14(a). For information regarding the
accounting for contracted electricity sales to large commercial, industrial and
institutional customers, please read Note 2(d) and Note 6 to the Reliant
Resources 10-K/A Notes.
In addition, in the three and nine months ended September 30, 2001, $14
million and $37 million, respectively, of revenues were recorded for billing,
customer service, credit and collection and remittance services charged to
Reliant Energy's regulated electric utility and two of its natural gas
distribution divisions. The associated costs are included in operation expenses
and general and administrative expenses. The service agreement governing these
services terminated on December 31, 2001.
To the extent that our price for providing retail electric service to
residential and small commercial customers in CenterPoint Energy's Houston
service territory during 2002 and 2003, which price is mandated by the Texas
electric restructuring law, exceeds the market price of electricity, we may be
required to make a payment to CenterPoint Energy in early 2004 unless the Texas
Utility Commission determines that, on or prior to January 1, 2004, 40% or more
of the amount of electric power that was consumed in 2000 by residential or
small commercial customers, as applicable, within CenterPoint Energy's Houston
service territory as of January 1, 2002 is committed to be served by retail
electric providers other than us. Currently, we believe it is probable that we
will be required to make such payment to CenterPoint Energy related to our
residential customers up to the cap amount. Our estimate for the payment related
to residential customers is between $155 million and $185 million (pre-tax),
with a most probable estimate of $170 million. We will recognize the total
obligation over the period we recognized the related revenues. During the third
quarter of 2002, we recognized $89 million (pre-tax) of which $27 million was
associated with the revenues for the first half of 2002. The remainder of our
estimated obligation will be recognized during the fourth quarter of 2002 and
during 2003. For further discussion of this payment to CenterPoint Energy and
the related accounting, please read Note 13(f) to the Reliant Resources 10-K/A
Notes and Note 12(e) to our Interim Financial Statements.
Operations and maintenance expenses and general and administrative
expenses increased $96 million and $228 million in the three and nine months
ended September 30, 2002 compared to the same periods in 2001, respectively,
primarily due to (a) increased gross receipts taxes of $31 million and $64
million, respectively, (b) personnel and employee related costs and other
administrative costs (including allocated corporate overhead) of $45 million and
$128 million, respectively, primarily due to the Texas retail market opening to
full competition in January 2002, (c) increased bad debt reserves of $23 million
and $46 million, respectively, associated with increased retail electric sales
and (d) increased marketing costs of $5 million and $15 million, respectively,
primarily due to the Texas retail market opening to full competition.
60
Depreciation and amortization expense increased $4 million and $12
million in the three and nine months ended September 30, 2002, respectively,
compared to the same periods in 2001 primarily due to depreciation of
information systems developed and placed in service to meet the needs of our
retail businesses. In addition, for the three and nine months ended September
30, 2001, Retail Energy recorded $1 million and $2 million for the three and
nine months ended September 30, 2001 for amortization expense related to
goodwill. For information regarding the cessation of goodwill amortization,
please read Note 2(q) to the Reliant Resources 10-K/A Notes and Note 7 to our
Interim Financial Statements.
On November 13, 2002, we filed a request with the Texas Utility
Commission to increase the price to beat fuel factor for residential and small
commercial customers based on a 7.7% increase in the price of natural gas from
our previous request in May 2002. Our requested increase was based on a 10
trading day, average forward 12-month natural gas price of $4.02/mmbtu. The
requested increase represents a 2.6% increase in the total bill of a residential
customer using, on average, 1,000 kWh per month. If no hearing is requested, the
earliest the new price to beat could go into effect would be December 3, 2002.
For additional information regarding the current price to beat fuel factor,
please read Note 14 to our Interim Financial Statements.
OTHER OPERATIONS
Our Other Operations segment includes the operations of our venture
capital and Communications businesses, and unallocated corporate costs.
During the third quarter of 2001, we decided to exit our Communications
business. The business served as a facility-based competitive local exchange
carrier and Internet services provider and owned network operations centers and
managed data centers in Houston and Austin. Our exit plan was substantially
completed in the first quarter of 2002.
The following table provides summary data regarding the results of
operations of Other Operations for the three and nine months ended September 30,
2001 and 2002.
OTHER OPERATIONS
-----------------------------------------------------------------
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2001 2002 2001 2002
------ ------ ------- ------
(IN MILLIONS)
Operating Revenues ............................... $ 3 $ -- $ 8 $ 2
Operating Expenses:
Operation and Maintenance ...................... 6 -- 15 3
General, Administrative and Development ........ 12 46 131 43
Depreciation and Amortization .................. 21 4 25 10
------ ------ ------- ------
Total Operating Expenses ..................... 39 50 171 56
------ ------ ------- ------
Operating Loss ................................... (36) (50) (163) (54)
------ ------ ------- ------
Other Income (Expense):
Gain from Investments, net ..................... 5 -- 16 4
Other, net ..................................... (1) -- (1) (5)
------ ------ ------- ------
Loss Before Interest and Income Taxes ............ $ (32) $ (50) $ (148) $ (55)
====== ====== ======= ======
Other Operations' loss before interest and income taxes increased by
$18 million and declined by $93 million for the three and nine months ended
September 30, 2002, respectively, compared to the same periods in 2001.
For the three months ended September 30, 2002, the increase in loss
before interest and taxes is primarily due to a net pre-tax, non-cash $47
million charge relating to the accounting settlement of certain benefit
obligations associated with our separation from CenterPoint Energy partially
offset by $14 million in restructuring charges and $19 million of goodwill
impairment related to the exiting of our Communications business recognized
during the third quarter of 2001 and $4 million in decreased operating losses
from our Communications business. In addition, during the three months ended
September 30, 2002, gains from investments decreased $5 million and depreciation
expense related to corporate assets increased $3 million.
For the nine months ended September 30, 2002, the decline in loss
before interest and income taxes is primarily due to (a) a pre-tax, non-cash
charge of $100 million recorded in the first quarter of 2001 relating to the
redesign of some of Reliant Energy's benefit plans in anticipation of our
separation from CenterPoint Energy, (b) decreased operating losses of $15
million related to our Communications business, and (c) $14 million in
restructuring charges
61
and $19 million of goodwill impairment related to the exiting of our
Communications business recognized during third quarter of 2001. Partially
offsetting these items are a net pre-tax, non-cash accounting settlement charge
of $47 million recognized during the third quarter of 2002 as discussed above
and increased depreciation expense related to corporate assets of $8 million. In
addition, other income decreased $16 million during the nine months ended
September 30, 2002 compared to the same period in 2001, primarily due to a
decrease in gains from investments of $12 million coupled with a $6 million
accrual for investment bank services recorded during the first quarter of 2002.
Gains from investments decreased due to an impairment of an investment in an
internet company in 2002 and decreased gains from other investments.
For additional information about the benefit charges noted above, please
read Note 13 to our Interim Financial Statements.
TRADING AND MARKETING OPERATIONS
We trade and market power, natural gas and other energy-related
commodities and provide related risk management services to our businesses and
our customers. Historically, we apply mark-to-market accounting for all of our
energy trading, marketing, power origination and risk management services
activities. For information regarding mark-to-market accounting, please read
Notes 2(d) and 6(a) to the Reliant Resources 10-K/A Notes and Notes 1 and 3 to
our Interim Financial Statements. These trading activities consist of:
- the domestic energy trading, marketing, power origination and
risk management services operations of our Wholesale Energy
segment;
- the European energy trading and power origination operations
of our European Energy segment; and
- the large commercial, industrial and institutional customers
under retail electricity contracts of our Retail Energy
segment.
Our domestic and European energy trading and marketing operations enter
into derivative transactions with goals of optimizing our current power
generation asset position and taking a market position.
During 2002, we have evaluated our trading, marketing, power
origination and risk management services strategies. In the third quarter of
2002, we began to reduce our Wholesale Energy segment's trading, marketing and
power origination activities due to liquidity concerns and in order to
significantly reduce collateral usage and focus on our commercial organization
on the highest return activities primarily around our core asset positions. In
September 2002, we concluded a comprehensive evaluation of our European Energy
segment's businesses and it was decided that proprietary trading would be
significantly reduced in order to focus on optimization of our generation assets
in the Netherlands.
Our realized and unrealized trading, marketing and risk management
services margins are as follows:
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------- -------------------------------
2001 2002 2001 2002
------- ------ ------ ------
(IN MILLIONS)
Realized ..................... $ 132 $ 87 $ 262 $ 278
Unrealized ................... (70) 32 49 13
------- ------ ------ ------
Total ........................ $ 62 $ 119 $ 311 $ 291
======= ====== ====== ======
Below is an analysis of our net trading and marketing assets and
liabilities for 2002 (in millions):
Fair value of contracts outstanding at December 31, 2001 ...................................... $ 218
Fair value of new contracts when entered into during the period ............................... 54
Contracts realized or settled during the period ............................................... (278)
Changes in fair values attributable to changes in valuation techniques and assumptions ........ 31
Changes in fair value attributable to market price and other market changes ................... 200
-------
Fair value of contracts outstanding at September 30, 2002 ................................... $ 225
=======
During the nine months ended September 30, 2002, our Retail Energy
segment entered into electric sales contracts with large commercial,
industrial and institutional customers ranging from one-half to four years in
duration. These contracts had an aggregate fair value of $42 million at the
contract inception dates. We have
62
entered into energy supply contracts to substantially economically hedge these
contracts. The fair value of these Retail Energy electric sales contracts to
large commercial, industrial and institutional customers was determined by
comparing the contract price to an estimate of the market cost of delivered
retail energy and applying the estimated volumes under the provisions of these
contracts. The calculation of the estimated cost of delivered retail energy
involves estimating the customer's anticipated load volume, and using the
forward ERCOT over-the-counter (OTC) commodity prices, adjusted for the
customer's anticipated load characteristics. Load characteristics in the
valuation model include: the customer's expected hourly electricity usage
profile, the potential variability in the electricity usage profile (due to
weather or operational uncertainties), and the electricity usage limits included
in the customer's contract. In addition, estimates include anticipated delivery
costs, such as electric line losses, ERCOT system operator administrative fees
and other market interaction charges, estimated credit risk and administrative
costs to serve, and may include estimated transmission and distribution fees.
The remaining weighted-average duration of these contracts is approximately
eighteen months.
Our Retail Energy segment also enters into supply contracts to
substantially economically hedge the sales contracts entered into with large
commercial, industrial and institutional customers. During the nine months ended
September 30, 2002, these contracts had an aggregate fair value of $6 million at
the contract inception dates. The fair values of these contracts are estimated
using ERCOT OTC forward price and volatility curves and correlation among power
and fuel prices specific to ERCOT, net of credit risk. A significant portion of
the value of these contracts required utilization of internal models that yield
similar results to externally developed standard industry models. For the
contracts extending beyond September 30, 2002, the remaining weighted-average
duration of these contracts, based on volumes, is less than two years.
The remaining fair value of new contracts recorded at inception of $6
million primarily relates to natural gas transportation contracts entered into
by the Wholesale Energy segment. The fair values of these Wholesale Energy
contracts at inception require the utilization of a spread option model and are
estimated using OTC forward price and volatility curves and correlation among
natural gas prices at differing locations, net of estimated credit risk. For the
contracts extending beyond September 30, 2002, the remaining weighted-average
duration of these contracts, based on volumes, is less than five years.
During the third quarter of 2002, our Retail Energy segment eliminated
one valuation factor adjustment and added another to its fair value calculation.
Retail Energy eliminated a valuation factor for potential claims for delays in
switching under the liquidated damage clauses in contracts. Retail Energy
eliminated this valuation factor because there is now enough data to
substantiate that these claims will not be submitted. This change in methodology
reduced credit reserves by $5 million. Retail Energy added a valuation factor
adjustment to capture the potential earnings loss associated with customers
terminating contracts due to a provision in some of its contracts that allows
customers to terminate their contracts if our unsecured debt ratings fall below
investment grade or if our ratings are withdrawn entirely by a rating agency.
During the third quarter of 2002, each of the major rating agencies downgraded
our credit ratings to sub-investment grade. We performed an analysis at the
customer level to estimate our exposure for these provisions. To date, no
customers have terminated according to this provision. This change in
methodology increased credit reserves by $1 million. Retail Energy also changed
the methodology related to recording its estimate of unaccounted for energy
(UFE). Retail Energy changed its UFE factor from 1.6% to zero. The reason for
the change is that Retail Energy believes the UFE is included in its volatility
valuation factor and its results from energy sales in 2001 were not negatively
impacted by the UFE. This change in methodology reduced credit reserves by $9
million.
During the second quarter of 2002, we changed our methodology for
allocating credit reserves between our trading and non-trading portfolios. Total
credit reserves calculated for both the trading and non-trading portfolios,
which are less than the sum of the independently calculated credit reserves for
each portfolio due to common counterparties between the portfolios, are
allocated to the trading and non-trading portfolios based upon the independently
calculated trading and non-trading credit reserves. Previously, credit reserves
were independently calculated for the trading portfolio while credit reserves
for the non-trading portfolio were calculated by deducting the trading credit
reserves from the total credit reserves calculated for both portfolios. This
change in methodology reduced credit reserves relating to the trading portfolio
by $18 million.
63
Below are the maturities of our contracts related to our trading and
marketing assets and liabilities as of September 30, 2002 (in millions):
FAIR VALUE OF CONTRACTS AT SEPTEMBER 30, 2002
---------------------------------------------------------------------------------------
2007 AND TOTAL
SOURCE OF FAIR VALUE 2003 (1) 2003 (2) 2004 2005 2006 THEREAFTER FAIR VALUE
------- -------- ----- ---- ----- ---------- ----------
Prices actively quoted ....... $ 6 $ 16 $ (10) $ -- $ -- $ -- $ 12
Prices provided by other
external sources ........... 120 30 12 1 12 19 194
Prices based on models and
other valuation methods .... (15) 12 13 3 (4) 10 19
------ ---- ----- --- ----- ---- -----
Total ........................ $ 111 $ 58 $ 15 $ 4 $ 8 $ 29 $ 225
====== ==== ===== ==== ===== ==== =====
- ------------
(1) Twelve months ended September 30, 2003
(2) The fourth quarter of 2003
The "prices actively quoted" category represents our New York
Mercantile Exchange (NYMEX) futures positions in natural gas and crude oil.
NYMEX had quoted prices for natural gas and crude oil for the next 72 and 30
months, respectively.
The "prices provided by other external sources" category represents our
forward positions in natural gas and power at points for which OTC broker quotes
are available. On average, OTC quotes for natural gas and power extend 72 and 36
months into the future, respectively. We value these positions against
internally developed forward market price curves that are constantly validated
and recalibrated against OTC broker quotes. This category also includes some
transactions whose prices are obtained from external sources and then modeled to
hourly, daily or monthly prices, as appropriate.
The "prices based on models and other valuation methods" category
contains (a) the value of our valuation adjustments for liquidity, credit and
administrative costs, (b) the value of options not quoted by an exchange or OTC
broker, (c) the value of transactions for which an internally developed price
curve was constructed as a result of the long-dated nature of the transaction or
the illiquidity of the market point, and (d) the value of structured
transactions. In certain instances structured transactions can be composed and
modeled by us as simple forwards and options based on prices actively quoted.
Options are typically valued using Black-Scholes option valuation models.
Although the valuation of the simple structures might not be different from the
valuation of contracts in other categories, the effective model price for any
given period is a combination of prices from two or more different instruments
and therefore has been included in this category due to the complex nature of
these transactions.
The fair values in the above table are subject to significant changes
based on fluctuating market prices and conditions. Changes in the assets and
liabilities from trading, marketing, power origination and price risk management
services result primarily from changes in the valuation of the portfolio of
contracts, newly originated transactions and the timing of settlements. The most
significant parameters impacting the value of our portfolio of contracts include
natural gas and power forward market prices, volatility and credit risk. For the
Retail Energy sales discussed above, significant variables affecting contract
values also include the variability in electricity consumption patterns due to
weather and operational uncertainties (within contract parameters). Market
prices assume a normal functioning market with an adequate number of buyers and
sellers providing market liquidity. Insufficient market liquidity could
significantly affect the values that could be obtained for these contracts, as
well as the costs at which these contracts could be hedged. Please read
"Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of the
Reliant Resources Form 10-K/A for further discussion and measurement of the
market exposure in the trading and marketing businesses and discussion of credit
risk management.
64
The following table presents the distribution by credit ratings of our
total non-trading derivatives and trading and marketing assets as of September
30, 2002, after taking into consideration netting and set-off agreements with
counterparties within each balance sheet caption (in millions).
PERCENTAGE OF
COLLATERAL EXPOSURE NET OF EXPOSURE NET OF
CREDIT RATING EQUIVALENT EXPOSURE HELD (3) COLLATERAL COLLATERAL
- ------------------------ -------- ---------- --------------- ---------------
AAA/Aaa ........................... $ 1 $ -- $ 1 0%
AA/Aa2 ............................ 239 -- 239 10%
A/A2 .............................. 631 -- 631 25%
BBB/Baa2 .......................... 1,173 (95) 1,078 44%
BB/Ba2 or lower ................... 570 (65) 505 20%
Unrated (1)(2) .................... 22 (8) 14 1%
-------- -------- -------- ---
2,636 (168) 2,468 100%
Less: Credit and other reserves ... (66) -- (66)
-------- -------- --------
$ 2,570 $ (168) $ 2,402
======== ======== ========
- ----------
(1) For unrated counterparties, we perform financial statement analysis,
considering contractual rights and restrictions, and collateral, to
create a synthetic credit rating.
(2) In lieu of making an individual assessment of the credit of unrated
counterparties, we may make a determination that the collateral held in
respect of such obligations is sufficient to cover a substantial
portion of our exposure. In making this determination, we take into
account various factors, including market volatility.
(3) Collateral consists of cash and standby letters of credit.
For additional information, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Certain Factors
Affecting Our Future Earnings - Factors Affecting the Results of Our Wholesale
Energy Operations - Price Volatility," and "- Risks Associated with Our Hedging
and Risk Management Activities" in Item 7 of the Reliant Resources Form 10-K/A.
For a description of accounting policies for our trading and marketing
activities, please read Notes 2(d) and 6 to the Reliant Resources 10-K/A Notes.
We seek to monitor and control our trading risk exposures through a
variety of processes and committees. For additional information, please read
"Quantitative and Qualitative Disclosures About Market Risk - Risk Management
Structure" in Item 7A of the Reliant Resources Form 10-K/A.
CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS
For information on other developments, factors and trends that may have
an impact on our future earnings, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Certain Factors
Affecting Our Future Earnings" in the Reliant Resources Form 10-K/A. For
additional information regarding (a) the California wholesale market and related
litigation, please read Notes 12(a) and 12(c) to our Interim Financial
Statements, and (b) Dutch stranded costs, please read Note 12(d) to our Interim
Financial Statements.
FERC Notice of Proposed Rulemaking. On July 31, 2002, FERC issued a
Notice of Proposed Rulemaking proposing requirements for standardization of
basic market rules in the wholesale electricity markets. The stated intent of
FERC's proposal is to implement standard rules that will provide for more equal
access to electricity markets and more predictability and uniformity in the
operation of wholesale electricity markets in the various parts of the country.
The proposal includes provisions for capacity commitments, price mitigation,
independent market monitoring, transmission and congestion revenue rights, and
operation of transmission systems by independent entities that satisfy specified
governance provisions. The new requirements are not scheduled to be fully
implemented until at least Fall 2004. We cannot predict at this time the final
form of this rulemaking or the effect that this rulemaking will have on our
business and results of operations.
65
FINANCIAL CONDITION
The following table summarizes the net cash provided by (used in)
operating, investing and financing activities for the nine months ended
September 30, 2001 and 2002.
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
2001 2002
------- ---------
(IN MILLIONS)
Cash provided by (used in):
Operating activities ........... $ 262 $ 319
Investing activities ........... (709) (3,301)
Financing activities ........... 635 4,301
Net cash provided by operating activities during the nine months ended
September 30, 2002 increased by $57 million compared to the same period 2001.
This increase was primarily due to (a) cash flows provided by our Retail Energy
segment for retail sales in the first nine months of 2002 due to the Texas
retail market opening to full competition in January 2002, (b) $250 million net
proceeds related to an arrangement with a financial institution to sell an
undivided interest in accounts receivable from residential and small commercial
retail electric customers (please see Note 9 to our Interim Financial
Statements), (c) $136 million of net collateral deposits related to an equipment
financing structure returned to us in 2002 coupled with collateral deposits paid
in 2001 (please see Note 12(f) to our Interim Financial Statements), (d) reduced
lease prepayments related to the REMA sale-leaseback agreements (please read
Note 12(g) to our Interim Financial Statements) and (e) $96 million related to
the settlement of four structured transactions in 2002 (please read Note 4 to
our Interim Financial Statements). These items were partially offset by (a)
decreased operating cash flows from our Wholesale Energy segment; (b) a $100
million settlement payment related to certain stranded costs contracts (please
read Note 12(d) to our Interim Financial Statements), (c) settlement of hedges
of our net investment in foreign subsidiaries totaling $156 million, (d) cash
flows for margin deposits related to our trading and hedging activities and (e)
other changes in working capital.
Net cash used in investing activities during the nine months ended
September 30, 2002 increased $2.6 billion compared to the same period in 2001,
primarily due to funding the acquisition of Orion Power for $2.9 billion on
February 19, 2002, partially offset by a decrease in capital expenditures
related to the construction of domestic power generation projects during the
nine months ended September 30, 2002 as compared to the same period in 2001 and
a $137 million cash dividend from our European Energy segment's equity
investment in NEA (please see Note 12(d) to our Interim Financial Statements).
Cash flows provided by financing activities during the nine months
ended September 30, 2002 increased $3.7 billion compared to the same period in
2001, primarily due to an increase in short-term borrowings used to fund the
acquisition of Orion Power and other working capital requirements and due to
increased working capital to meet future obligations, decreased investments of
excess cash in an affiliate of CenterPoint Energy, partially offset by $1.7
billion in net proceeds from our IPO in 2001.
Acquisition of Orion Power Holdings, Inc. On February 19, 2002, we
acquired all of the outstanding shares of common stock of Orion Power for $26.80
per share in cash for an aggregate purchase price of $2.9 billion. As of
February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1
billion net of restricted cash pursuant to debt covenants). We funded the
purchase of Orion Power with a $2.9 billion credit facility and $41 million of
cash on hand.
This basis of accounting in our Interim Financial Statements
contemplates the recovery of our assets and the satisfaction of our liabilities
in the normal course of conducting business, which in turn is dependent upon our
ability to successfully execute our refinancing plans. We expect to successfully
execute our refinancing plans; accordingly, management believes we will be able
to meet our obligations in a manner consistent with this accounting treatment.
However, there can be no assurance that we will be successful in executing our
refinancing plans. If we are unable to complete the necessary future
refinancings on acceptable terms and conditions, given the magnitude of the
refinancings we may be forced to consider a reorganization under the protection
of bankruptcy laws. For discussion of our refinancing plans, please read Note 2
to our Interim Financial Statements.
66
FUTURE SOURCES OF CASH FLOWS
For a discussion of factors affecting our sources of cash and
liquidity, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources" in the
Reliant Resources Form 10-K/A and Notes 2, 9, 12(h), 12(i), 16(a) and 16(b) to
our Interim Financial Statements.
Credit Facilities. As of September 30, 2002, we had $8.1 billion in
committed credit facilities of which $365 million remained unused. Credit
facilities aggregating $5.3 billion were unsecured. As of September 30, 2002,
letters of credit outstanding under these facilities aggregated $597 million. As
of September 30, 2002, borrowings of $7.1 billion were outstanding under these
facilities. As of September 30, 2002, we have $6.6 billion of committed credit
facilities which will expire by September 30, 2003 of which $1.7 billion will
expire by December 31, 2002. For a discussion of the repayment, refinancing
and/or amendment of certain of these committed credit facilities and our
liquidity concerns, please read Notes 2 and 9 to our Interim Financial
Statements.
Credit Ratings. Credit ratings impact our ability to obtain short- and
long-term financing, the cost of such financing and the execution of our
commercial strategies. For a discussion of our credit ratings and the related
factors affecting our future financial position, results of operations and cash
flows, please read Note 2 to our Interim Financial Statements.
Orion Power and its Subsidiaries Credit Facilities Covenant Waivers.
For a discussion of Orion Power and its subsidiaries covenant waivers during the
third quarter of 2002, please read Note 9 to our Interim Financial Statements.
For additional information regarding Orion Power and its subsidiaries'
debt obligations, please read Notes 2 and 9 to our Interim Financial Statements.
Receivable Facility Covenant Violation. For a discussion of a covenant
violation under the Receivable Facility, please read Note 16(a) to our Interim
Financial Statements.
California Trade Receivables. As of September 30, 2002, the Company was
owed a total of $233 million, net of a $70 million reserve for refund, by the
Cal ISO, the Cal PX, the DWR, and California Energy Resources Scheduling for
energy sales in the California wholesale market during the fourth quarter of
2000 through September 30, 2002. From September 30, 2002 through November 8,
2002, the Company has collected $9 million of these receivable balances. As of
September 30, 2002, we had a pre-tax credit provision of $24 million against
these receivable balances. For additional information regarding uncertainties in
the California wholesale market, please read Notes 12(a) and 12(c) to our
Interim Financial Statements and Notes 13(e) and 13(i) to the Reliant Resources
10-K/A Notes.
FUTURE USES OF CASH FLOWS
For a discussion of items impacting our liquidity and uses of cash,
including the impact of our downgrade to sub-investment grade, commercial
obligations related to our wholesale and retail operations, various collateral
requirements and capital obligations, please read Notes 2, 9, 12(h), 12(i) and
16(a) to our Interim Financial Statements.
Generating Projects. As of September 30, 2002, we had one generating
facility under construction. Total estimated costs of constructing this facility
is $498 million. As of September 30, 2002, we had incurred $280 million of the
total projected costs of this project, which was funded primarily from equity
and a debt facility. In addition to this generating facility, we are
constructing facilities as construction agents under construction agency
agreements, which permit us to lease or buy each of these facilities at the
conclusion of their construction.
In connection with the acquisition of Orion Power, we acquired
contracts to purchase additional power generation equipment, consisting of steam
and combustion turbines and heat recovery steam generators. As of September 30,
2002, we have cancelled all but one contract, having determined the equipment is
in excess of our current needs. We plan to pay an additional $1 million in early
2003 to cancel the remaining contract.
Construction Agency Agreement and Equipment Financing Structure. In
2001, we, through several of our subsidiaries, entered into operative documents
with special purpose entities to facilitate the development, construction,
financing and leasing of several power generation projects. These special
purpose entities are not
67
consolidated by us. In addition, we, through our subsidiary, REPG, entered into
an agreement, which was terminated in September 2002, with a bank whereby the
bank, as owner, entered or would enter into contracts for the purchase and
construction of power generation equipment and REPG, or its subagent, would act
as the bank's agent in connection with administering the contracts for such
equipment. For information regarding these transactions, please read Note 12(f)
to our Interim Financial Statements.
Payment to CenterPoint Energy. To the extent that our price for
providing retail electric service to residential and small commercial customers
in CenterPoint Energy's Houston service territory during 2002 and 2003, which
price is mandated by the Texas electric restructuring law, exceeds the market
price of electricity, we may be required to make a payment to CenterPoint Energy
in early 2004 unless the Texas Utility Commission determines that, on or prior
to January 1, 2004, 40% or more of the amount of electric power that was
consumed in 2000 by residential or small commercial customers, as applicable,
within CenterPoint Energy's Houston service territory as of January 1, 2002 is
committed to be served by retail electric providers other than us. As of
September 30, 2002, our estimate for the payment related to residential
customers is between $155 million and $185 million (pre-tax), with a most
probable estimate of $170 million. For additional information regarding this
payment, please read Note 12(e) to our Interim Financial Statements.
Restricted Cash. All of our operations are conducted by our
subsidiaries. Our cash flow and our ability to service parent-level indebtedness
when due is dependent upon our receipt of cash dividends, distributions or other
transfers from our subsidiaries. The terms of some of our subsidiaries'
indebtedness restrict their ability to pay dividends or make restricted payments
to us in some circumstances. Under the restructured credit facilities of Orion
NY and Orion MidWest, these subsidiaries are restricted from distributing cash
to Orion Power. In addition, the 12% senior notes of Orion Power restrict its
ability to pay dividends to us unless Orion Power meets certain conditions,
including the ability to incur additional indebtedness without violating the
required fixed charge coverage ratio of 2.0 to 1.0. As of September 30, 2002, we
had restricted cash totaling $380 million related to Orion Power and its
subsidiaries.
In addition, the ability of REMA, our subsidiary that owns some of the
power generation facilities in our Northeast regional portfolio, to pay
dividends or make payments to us is restricted under the terms of three lease
agreements under which we lease all or an undivided interest in these generating
facilities. These agreements allow REMA to pay dividends or make restricted
payments only if specified conditions are satisfied, including maintaining
specified fixed charge coverage ratios. As of September 30, 2002, the specified
conditions were satisfied.
In addition, the terms of two of our subsidiaries' indebtedness
restrict their ability to pay dividends or make restricted payments to us in
some circumstances. Specifically, our subsidiary which owns an electric power
generation facility in Channelview, Texas (Channelview) and our subsidiary which
holds an equity investment in the entity owning and operating an electric power
generation facility in Nevada (El Dorado) are each party to credit agreements
used to finance construction of their generating plants. Both the Channelview
credit agreement and the El Dorado credit agreement allow the respective
subsidiary to pay dividends or make restricted payments only if specified
conditions are satisfied, including maintaining specified debt service coverage
ratios and debt service reserve account balances. In both cases, the amount of
the dividends or restricted payments that may be paid if the conditions are met
is limited to a specified level and may be paid only from a particular account.
As of September 30, 2002, we had restricted cash of $7 million related to
Channelview.
Counterparty Credit Risk. We are exposed to the risk that
counterparties who owe us money or physical commodities, such as energy or gas,
as a result of market transactions fail to perform their obligations. Should the
counterparties to these arrangements fail to perform, we might incur losses if
we are forced to acquire alternative hedging arrangements or replace the
underlying commitment at then-current market prices. In addition, we might incur
additional losses to the extent of amounts, if any, already paid to the
defaulting counterparties.
Liberty Electric Generating Station Contingency. The output of the
Liberty Station is contracted under a tolling agreement between Liberty Electric
Power, LLC, a wholly owned subsidiary of Orion Power, and PG&E Energy
Trading-Power, LP for a term of approximately 14 years, with an option to extend
at the end of the term (Tolling Agreement). For information regarding the
Tolling Agreement, issues related to the financing of the Liberty Station and
other related contingencies, please read Note 12(i).
Reliant Energy Desert Basin Contingency. Reliant Energy Desert Basin
(REDB), an indirect wholly owned subsidiary of Reliant Resources, sells power to
Salt River Project (SRP) under a long-term power purchase
68
agreement. Certain of REDB's obligations under the power purchase agreement are
guaranteed by Reliant Resources. In the event Reliant Resources is downgraded to
below investment grade by two major ratings agencies, SRP can request
performance assurance in the form of cash or a letter of credit from REDB under
the power purchase agreement and from Reliant Resources under the guaranty.
Under the power purchase agreement and guaranty, the total amount of performance
assurance cannot exceed $150 million. For information regarding the REDB's
obligations, Reliant Resources related guarantee and other related
contingencies, please read Note 12(h).
Generating Capacity Auction Letter of Credit. Effective October 1,
2002, Texas Genco, LP, a subsidiary of CenterPoint Energy, entered into a Master
Power Purchase and Sale Agreement with Reliant Energy Electric Solutions LLC,
guaranteed by certain of the indirect retail energy subsidiaries of the Company,
which provides a basis for purchasing power to serve the Company's Texas retail
electric customers for a primary term ending December 31, 2003. The Company does
not anticipate that it will be required to post any collateral to secure payment
for its purchases under such agreement. Please read Note 2 to our Interim
Financial Statements for additional information on this agreement.
Treasury Stock Purchases. On December 6, 2001, our Board of Directors
authorized us to purchase up to 10 million additional shares of our common stock
through June 2003. Purchases will be made on a discretionary basis in the open
market or otherwise at times and in amounts as determined by management subject
to market conditions, legal requirements and other factors. Since the date of
this authorization through November 8, 2002, we have not purchased any shares of
our common stock under this program.
Other Sources/Uses of Cash. Our liquidity and capital requirements are
affected primarily by the results of operations, capital expenditures, debt
service requirements, working capital needs and collateral requirements. We
expect to complete the construction of new generation facilities that are in
progress; however, we do not anticipate the construction of any new generation
facilities in the near future. We will evaluate opportunities to enter retail
electric markets for large commercial, industrial and institutional customers,
in particular, in regions in which we have electric generating facilities and
capacity. We expect our capital requirements to be met with cash flows from
operations, and proceeds from debt and equity offerings, project financings,
securitization of assets, other borrowings and off-balance sheet financings.
Additional capital expenditures, some of which may be substantial, depend to a
large extent upon the nature and extent of future project commitments, which are
discretionary. We believe that our current level of cash and borrowing
capability, along with our future anticipated cash flows from operations and
assuming successful refinancings of credit facilities as they mature, will be
sufficient to meet the existing operational and collateral needs of our business
for the next 12 months. If cash generated from operations is insufficient to
satisfy our liquidity requirements, we may seek to sell assets or obtain
additional credit facilities or financings from financial institutions. If we
are unable to complete the necessary future refinancings on acceptable terms and
conditions, given the magnitude of the refinancings we may be forced to consider
a reorganization under the protection of bankruptcy laws. For additional
discussion regarding our capital commitments, please read Note 2 to our Interim
Financial Statements.
NEW ACCOUNTING PRONOUNCEMENTS AND CRITICAL ACCOUNTING POLICIES
New Accounting Pronouncements.
In July 2001, the Financial Accounting Standards Board (FASB) issued
SFAS No. 141 "Business Combinations" (SFAS No. 141). SFAS No. 141 requires
business combinations initiated after June 30, 2001 to be accounted for using
the purchase method of accounting and broadens the criteria for recording
intangible assets separate from goodwill. Recorded goodwill and intangibles will
be evaluated against these new criteria and may result in certain intangibles
being transferred to goodwill, or alternatively, amounts initially recorded as
goodwill may be separately identified and recognized apart from goodwill. We
adopted the provisions of the statement which apply to goodwill and intangible
assets acquired prior to June 30, 2001 on January 1, 2002. The adoption of SFAS
No. 141 did not have a material impact on our historical results of operations
or financial position.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of
a liability for an asset retirement legal obligation to be recognized in the
period in which it is incurred. When the liability is initially recorded,
associated costs are capitalized by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted to its present
value each period, and the capitalized cost is depreciated over the useful life
of the related asset. SFAS No. 143 is effective for fiscal years beginning after
June 15, 2002, with earlier application encouraged. SFAS No. 143 requires
entities to record a cumulative effect of change in accounting principle in the
income statement in the period of adoption. We
69
plan to adopt SFAS No. 143 on January 1, 2003, and are in the process of
determining the effect of adoption on our consolidated financial statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144
provides new guidance on the recognition of impairment losses on long-lived
assets to be held and used or to be disposed of and also broadens the definition
of what constitutes a discontinued operation and how the results of a
discontinued operation are to be measured and presented. SFAS No. 144 supercedes
SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" and Accounting Principles Board Opinion No.
30, "Reporting the Results of Operations - Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," while retaining many of the requirements of these two
statements. Under SFAS No. 144, assets held for sale that are a component of an
entity will be included in discontinued operations if the operations and cash
flows will be or have been eliminated from the ongoing operations of the entity
and the entity will not have any significant continuing involvement in the
operations prospectively. SFAS No. 144 did not materially change the methods
used by us to measure impairment losses on long-lived assets, but may result in
additional future dispositions being reported as discontinued operations. We
adopted SFAS No. 144 on January 1, 2002.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current requirement
that gains and losses on debt extinguishment must be classified as extraordinary
items in the income statement. Instead, such gains and losses will be classified
as extraordinary items only if they are deemed to be unusual and infrequent.
SFAS No. 145 also requires sale-leaseback accounting for certain lease
modifications that have economic effects that are similar to sale-leaseback
transactions. The changes related to debt extinguishment will be effective for
fiscal years beginning after May 15, 2002, and the changes related to lease
accounting will be effective for transactions occurring after May 15, 2002. We
will apply this guidance prospectively.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
nullifies EITF No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred
in a Restructuring)" (EITF No. 94-3). The principal difference between SFAS No.
146 and EITF No. 94-3 relates to the requirements for recognition of a liability
for cost associated with an exit or disposal activity. SFAS No. 146 requires
that a liability be recognized for a cost associated with an exit or disposal
activity when it is incurred. A liability is incurred when a transaction or
event occurs that leaves an entity little or no discretion to avoid the future
transfer or use of assets to settle the liability. Under EITF No. 94-3, a
liability for an exit cost was recognized at the date of an entity's commitment
to an exit plan. In addition, SFAS No. 146 also requires that a liability for a
cost associated with an exit or disposal activity be recognized at its fair
value when it is incurred. SFAS No. 146 is effective for exit or disposal
activities that are initiated after December 31, 2002 with early application
encouraged. We will apply the provisions of SFAS No. 146 to all exit or disposal
activities initiated after December 31, 2002.
See Note 4 for a discussion regarding our adoption of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," as amended (SFAS
No. 133) on January 1, 2001 and adoption of subsequent cleared guidance. See
Note 7 for a discussion regarding our adoption of SFAS No. 142 "Goodwill and
Other Intangible Assets" (SFAS No. 142) on January 1, 2002.
In June 2002, the EITF reached a consensus that all mark-to-market
gains and losses on energy trading contracts should be shown net in the income
statement whether or not settled physically. In October 2002, the EITF issued a
consensus that superceded the June 2002 consensus. The October 2002 consensus
required, among other things, that energy derivatives held for trading purposes
be shown net in the income statement. This new consensus is effective for fiscal
periods beginning after December 15, 2002. However, consistent with the new
consensus and as allowed under EITF No. 98-10 "Accounting for Contracts Involved
in Energy Trading and Risk Management Activities" (EITF No. 98-10), beginning
with the quarter ended September 30, 2002, we now report all energy trading and
marketing activities on a net basis in the Statements of Consolidated Income.
Comparative financial statements for prior periods have been reclassified to
conform to this presentation.
70
FOR THE THREE FOR THE NINE FOR THE SIX
MONTHS ENDED MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, 2001 SEPTEMBER 30, 2001 JUNE 30, 2002
------------------ ------------------ -------------
Revenues .......................... $ 6,278 $ 19,687 $ 11,434
Fuel and cost of gas sold ......... 2,471 11,011 6,142
Purchased power ................... 3,807 8,676 5,292
-------- --------- ---------
Net impact on margins ........ $ -- $ -- $ --
======== ========= =========
Furthermore, in October 2002, under EITF No. 02-03, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities" (EITF No.
02-03) the EITF reached a consensus to rescind EITF No. 98-10. All new contracts
that would have been accounted for under EITF No. 98-10, and that do not fall
within the scope of SFAS No. 133, should no longer be marked-to-market through
earnings beginning October 25, 2002. In addition, inventories used in the
trading and marketing operations should no longer be marked-to-market through
earnings. This transition is effective for us for the first quarter of 2003.
A cumulative effect of a change in accounting principle should be recorded
effective January 1, 2003 related to all contracts and inventories that will no
longer be recorded at fair value that were entered into or held, as applicable,
prior to October 25, 2002. We are in process of determining the effect of
adoption on our consolidated financial statements.
Finally, the EITF has not reached a consensus on whether recognition of
dealer profit, or unrealized gains and losses at inception of an energy trading
contract is appropriate in the absence of quoted market prices or current market
transactions for contracts with similar terms. In the June 2002 EITF meeting and
again in the October 2002 EITF meeting, the FASB staff indicated that until such
time as a consensus is reached, the FASB staff will continue to hold the view
that previous EITF consensus does not allow for recognition of dealer profit,
unless evidenced by quoted market prices or other current market transactions
for energy trading contracts with similar terms and counterparties. During the
three and nine months ended September 30, 2002, we recorded $8 million and $54
million, respectively, of fair value at the contract inception related to
trading and marketing activities. We believe that any material inception gains
recorded subsequent to the FASB staff comment regarding this issue were
evidenced by quoted market prices and other current market transactions for
energy trading contracts with similar terms and counterparties.
During the first quarter of 2002, the FASB considered proposed
approaches related to identifying and accounting for special-purpose entities.
The current proposal being considered by the FASB would limit special purpose
entities used by a company for financing and other purpose not being
consolidated with its results of operations. One criterion being considered is
to require consolidation of a special purpose entity if the equity investments
held by third-party owners in the special purpose entity is less than 10% of
capitalization. The FASB likely will not grandfather special purpose entities
existing at the date the final interpretation is issued. Special purpose
entities in existence at the date of adoption of this interpretation will likely
be consolidated by the primary beneficiary. For information regarding special
purpose entities affiliated with us, please read Notes 12(f) and 12(g) to our
Interim Financial Statements.
Critical Accounting Policies.
A critical accounting policy is one that is both important to the
portrayal of our financial condition and results of operations and requires
management to make difficult, subjective or complex judgments. The circumstances
that make these judgments difficult, subjective and/or complex have to do with
the need to make estimates about the effect of matters that are inherently
uncertain. Estimates and assumptions about future events and their effects
cannot be made with certainty. We base our estimates on historical experience
and on various other assumptions that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgments. These
estimates may change as new events occur, as more experience is acquired, as
additional information is obtained and as our operating environment changes.
We believe the following are the most significant estimates used in the
preparation of our consolidated financial statements.
- determination of fair value of trading and marketing assets
and liabilities for our energy trading, marketing and price
risk management services operations, and non-trading
derivative assets and liabilities, including stranded costs
obligations related to our European Energy operations (please
read "Management's
71
Discussion and Analysis of Financial Condition and Results of
Operations - Trading and Marketing Operations" and
"Quantitative and Qualitative Disclosures About Market Risk"
in the Reliant Resources Form 10-K/A, Notes 2(d) and 6 to the
Reliant Resources 10-K/A Notes and Notes 1 and 4 to our
Interim Financial Statements);
- determination of impairment of long-lived assets and
intangibles (please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations - European
Energy" in the Reliant Resources Form 10-K/A, Note 2(f) and
Note 2(q) to the Reliant Resources 10-K/A Notes, Note 7 to our
Interim Financial Statements, "Management's Discussion and
Analysis of Financial Condition and Results of Operations -
Earnings Before Interest and Taxes by Business Segment -
Wholesale Energy" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Earnings
Before Interest and Taxes by Business Segment - European
Energy" within this Form 10-Q);
- estimation of revenues for delivered energy sales and services
to retail customers and the related supply costs (please read
"Management's Discussion and Analysis of Financial Condition
and Results of Operations - Retail Energy" and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations - Certain Factors Affecting Our Future Earnings -
Factors Affecting the Results of Our Retail Energy Operations"
in the Reliant Resources Form 10-K/A and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations - Earnings Before Interest and Taxes by Business
Segment - Retail Energy" within this Form 10-Q); and
- estimation of credit provisions for uncollectible receivables
and potential refunds related to energy sales in the
California market (please read Notes 12(a) and 12(c) to our
Interim Financial Statements).
For a description of all significant accounting policies, please read
Note 2 to the Reliant Resources 10-K/A Notes.
72
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
We assess the risk of our non-trading derivatives (Energy Derivatives)
using a sensitivity analysis method, and we assess the risk of our trading
derivatives (Trading Derivatives) using the value-at-risk (VAR) method, in order
to maintain our total exposure within management-prescribed limits.
The sensitivity analysis performed on our Energy Derivatives measures
the potential loss based on a hypothetical 10% movement in energy prices. An
increase of 10% in the market prices of energy commodities from their September
30, 2002 levels would have decreased the fair value of our Energy Derivatives
from their levels on those respective dates by $64 million, excluding
non-trading derivative liabilities associated with our European Energy segment's
stranded cost gas contract.
Our European Energy segment's stranded cost gas contract has exposure
to commodity price movements. For information regarding this contract, please
read Notes 4 and 12(d) to our Interim Financial Statements. A decrease of 10% in
market prices of energy commodities from their September 30, 2002 levels would
result in a loss of earnings of $9 million.
We utilize the variance/covariance model of VAR, which is a
probabilistic model that measures the estimated risk of loss to earnings in
market sensitive instruments based on historical experience. With respect to
trading and marketing activities, our highest, lowest and average daily VAR were
$21 million, $15 million and $18 million, respectively, during the third quarter
of 2002 and $29 million, $13 million and $18 million, respectively, during the
first nine months of 2002 based on a 95% confidence level and primarily a
one-day holding period. During the third quarter of 2001, our highest, lowest
and average daily VAR were $11 million, $3 million and $5 million, respectively,
and during the first nine months of 2001, our highest, lowest and average
monthly VAR were $18 million, $3 million and $7 million, respectively, based on
a 95% confidence level and primarily a one-day holding period.
We cannot assure you that market volatility, failure of counterparties
to meet their contractual obligations, transactions entered into after the date
of this Form 10-Q or a failure of risk controls will not lead to significant
losses from our trading, marketing and risk management activities.
INTEREST RATE RISK
We have issued long-term debt and have obligations under bank
facilities which subject us to the risk of loss associated with movements in
market interest rates.
Our floating-rate obligations borrowed from third parties aggregated
$6.9 billion at September 30, 2002. If the floating rates were to increase by
10% from September 30, 2002 rates, our combined interest expense to third
parties would increase by a total of $2 million each month in which such
increase continued.
We have entered into interest rate swap contracts with an aggregate
notional amount of $1.2 billion that fix the interest rate applicable to
floating rate short-term debt and floating rate long-term debt. At September 30,
2002, the swaps relating to short-term and long-term debt, could be terminated
at a cost of $63 million. The swaps relating to both short-term and long-term
debt qualify for hedge accounting under SFAS No. 133 and the periodic
settlements are recognized as an adjustment to interest expense in the
Statements of Consolidated Income over the term of the swap agreement. A
decrease of 10% in the September 30, 2002 level of interest rates would increase
the cost of terminating the swaps related to short-term debt and long-term debt
outstanding at September 30, 2002 by $10 million.
In addition, during 2002, we entered into forward-starting interest
rate swaps having an aggregate notional amount of $500 million to hedge the
interest rate on a future offering of long-term fixed-rate notes. At September
30, 2002, these swaps could be liquidated at a cost of $51 million. These swaps
qualify as cash flow hedges under SFAS No. 133. In November 2002, we liquidated
these swaps at a cost of $52 million. For further discussion of the liquidation
of these swaps, please read Note 16(d) to our Interim Financial Statements.
73
For information regarding the accounting for these interest rate swaps,
please read Note 4 to our Interim Financial Statements.
At September 30, 2002, we had issued fixed-rate debt aggregating $812
million. As of September 30, 2002, fair values were estimated to be equivalent
to the carrying amounts of these instruments. These instruments are fixed-rate
and, therefore, do not expose us to the risk of loss in earnings due to changes
in market interest rates. However, the fair value of these instruments would
increase by $48 million if interest rates were to decline by 10% from their
rates at September 30, 2002.
FOREIGN CURRENCY EXCHANGE RATE RISK
As of September 30, 2002, we have entered into foreign currency option
contracts and have issued Euro-denominated debt to hedge our entire net
investment in our European Energy segment against a material decline of the
Euro. Changes in the value of the options and debt are recorded as foreign
currency translation adjustments as a component of accumulated other
comprehensive income (loss) in stockholders' equity. As of September 30, 2002,
we have recorded a $34 million loss in cumulative net translation adjustments.
The cumulative translation adjustments will be realized in earnings and cash
flows only upon the disposition of the related investments.
As of September 30, 2002, our European Energy segment had entered into
transactions to purchase approximately $150 million at fixed exchange rates in
order to hedge future fuel purchases payable in U.S. dollars. As of September
30, 2002, the fair value of these financial instruments was a $6 million
liability. An increase in the value of the Euro of 10% compared to the U.S.
dollar from its September 30, 2002 level would result in a loss in the fair
value of these foreign currency financial instruments of $15 million. For
information regarding the accounting for these financial instruments, see Note
6(b) to the Reliant Resources 10-K/A Notes.
Our European Energy segment's stranded cost gas contract has foreign
currency exposure. A decrease of 10% in the U.S. dollar relative to the Euro
from their September 30, 2002 levels would result in a loss of earnings of $13
million.
EQUITY MARKET VALUE RISK
We have an investment in Itron, Inc. (Itron), which is classified as
"available-for-sale" under SFAS No. 115. As of September 30, 2002, the value of
the Itron investment was $3 million. The Itron investment exposes us to losses
in the fair value of Itron common stock. A 10% decline in the market value per
share of Itron common stock from the September 30, 2002 level would decrease the
fair value by less than $1 million.
74
CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The Company's Chief Executive Officer and Chief Financial Officer have
evaluated the effectiveness of the Company's disclosure controls and procedures
(as such term is defined in Rules 13a-14(c) and 15d-14(c) under the Securities
Exchange Act of 1934, as amended (the Exchange Act) as of a date within 90 days
prior to the filing date of this quarterly report (the Evaluation Date). Based
on such evaluation, such officers have concluded that, as of the Evaluation
Date, the Company's disclosure controls and procedures are effective in alerting
them on a timely basis to material information relating to the Company
(including its consolidated subsidiaries) required to be included in the
Company's reports filed or submitted under the Exchange Act.
It should be noted that the design of any system of controls is based,
in part, upon certain assumptions about the likelihood of future events, and
there can be no assurance that any design will be successful in achieving its
stated goal under all potential future conditions, regardless of how remote.
CHANGES IN INTERNAL CONTROLS
Since the Evaluation Date, there have not been any significant changes
in the Company's internal controls or in other factors that could significantly
affect such controls.
75
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
For a description of legal proceedings affecting Reliant Resources,
please read Note 12 to our Interim Financial Statements, and the discussion
under "Our Business - Environmental Matters" and "Legal Proceedings" in the
Reliant Resources Form 10-K/A and Notes 13 and 17 to the Reliant Resources
10-K/A Notes.
ITEM 5. OTHER INFORMATION.
From time to time, Reliant Resources makes statements concerning its
expectations, beliefs, plans, objectives, goals, strategies, future events or
performance and underlying assumptions and other statements, which are not
historical facts. These statements are "forward-looking statements" within the
meaning of the Private Securities Litigation Reform Act of 1995. Although
Reliant Resources believes that the expectations and the underlying assumptions
reflected in its forward-looking statements are reasonable, it cannot assure you
that these expectations will prove to be correct. Forward-looking statements
involve a number of risks and uncertainties, and actual results may differ
materially from the results discussed in the forward-looking statements.
The following are some of the factors that could cause actual results
to differ materially from those expressed or implied in forward-looking
statements:
- state, federal and international legislative and regulatory
developments, including deregulation, re-regulation and
restructuring of the electric utility industry and changes in
or application of environmental and other laws and regulations
to which we are subject, and changes in or application of laws
or regulations applicable to other aspects of our business,
such as commodities trading and hedging activities,
- the outcome of pending lawsuits, governmental proceedings and
investigations,
- the effects of competition, including the extent and timing of
the entry of additional competitors in our markets,
- liquidity concerns in our markets,
- the degree to which we successfully integrate the operations
and assets of Orion Power Holdings, Inc. into our Wholesale
Energy segment,
- the successful and timely completion of our construction
projects, as well as the successful start-up of completed
projects,
- any reduction in our trading, marketing and origination
activities,
- our pursuit of potential business strategies, including
acquisitions or dispositions of assets or the development of
additional power generation facilities,
- the timing and extent of changes in commodity prices and
interest rates,
- the availability of adequate supplies of fuel, water, and
associated transportation necessary to operate our generation
portfolio,
- weather variations and other natural phenomena, which can
effect the demand for power from or our ability to produce
power at, our generating facilities,
- financial market conditions, our access to capital and the
results of our financing and refinancing efforts, including
availability of funds in the debt/capital markets for merchant
generation companies,
- the credit worthiness or bankruptcy or other financial
distress of our counterparties,
- actions by rating agencies with respect to us or our
competitors
- acts of terrorism or war,
- the availability and price of insurance,
- the reliability of the systems, procedures and other
infrastructure necessary to operate our retail electric
business, including the systems owned and operated by the
independent system operator in the Electric Reliability
Council of Texas,
- political, legal, regulatory and economic conditions and
developments in the United States and in foreign countries in
which we operate, including the effects of fluctuations in
foreign currency exchange rates,
- the successful operation of deregulating power markets,
- the resolution of the refusal by California market
participants to pay our receivables balances, and
- other factors affecting Reliant Resources discussed in the
Reliant Resources Form 10-K/A, including those outlined and in
"Management's Discussion and Analysis of Financial Condition
and Results of Operations - Certain Factors Affecting Our
Future Earnings."
76
When used in Reliant Resources' documents or oral presentations, the
words "anticipate," "estimate," "believes," "continues," "could," "intends,"
"may," "plans," "potential," "should," "will," "expect," "objective,"
"projection," "forecast," "goal," "guidance," "outlook" and similar words are
intended to identify forward-looking statements.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
EXHIBIT NUMBER DOCUMENT DESCRIPTION
-------------- --------------------
10.1 Separation Agreement dated July 2, 2002 between
Reliant Resources, Inc. and Joe Bob Perkins
10.2 Employment Agreement effective July 29, 2002 between
Reliant Resources, Inc. and Mark M. Jacobs
99.1 Certification of Chairman and Chief Executive Officer
of Reliant Resources, Inc. Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63
of Title 18, United States Code)
99.2 Certification of Executive Vice President and Chief
Financial Officer of Reliant Resources, Inc.
Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b)
of Section 1350, Chapter 63 of Title 18, United
States Code)
(b) Reports on Form 8-K.
- Current Report on Form 8-K dated July 5, 2002, as filed with
the SEC on July 5, 2002 (Item 5).
- Current Report on Form 8-K dated July 25, 2002, as filed with
the SEC on July 25, 2002 (Items 5, 7 and 9).
- Current Report on Form 8-K dated July 31, 2002, as filed with
the SEC on August 1, 2002 (Items 5, 7 and 9).
- Current Report on Form 8-K/A dated February 19, 2002, as filed
with the SEC on August 2, 2002 (Item 7).
- Current Report on Form 8-K dated August 14, 2002, as filed
with the SEC on August 14, 2002 (Items 7 and 9).
- Current Report on Form 8-K dated September 5, 2002, as filed
with the SEC on September 9, 2002 (Items 5 and 7).
- Current Report on Form 8-K dated September 13, 2002, as filed
with the SEC on September 13, 2002 (Items 5 and 7).
- Current Report on Form 8-K dated September 18, 2002, as filed
with the SEC on September 18, 2002 (Items 5 and 7).
- Current Report on Form 8-K dated September 30, 2002, as filed
with the SEC on September 30, 2002 (Items 5 and 7).
77
SIGNATURE
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.
RELIANT RESOURCES, INC.
(Registrant)
By: /s/ Thomas C. Livengood
-----------------------------------------
Thomas C. Livengood
Vice President and Controller
(Principal Accounting Officer)
Date: November 14, 2002
78
CERTIFICATIONS
I, R. Steve Letbetter, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Reliant
Resources, 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 officers 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 we 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 officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
function):
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 officers and I have
indicated in this quarterly report whether or not 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: November 14, 2002 /s/ R. Steve Letbetter
----------------------------------
R. Steve Letbetter
Chairman and
Chief Executive Officer
79
CERTIFICATIONS
I, Mark M. Jacobs, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Reliant
Resources, 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 officers 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 we 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 officers and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
function):
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 officers and I have
indicated in this quarterly report whether or not 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: November 14, 2002 /s/ Mark M. Jacobs
----------------------------------
Mark M. Jacobs
Executive Vice President and
Chief Financial Officer
80
EXHIBIT INDEX
10.1 Separation Agreement dated July 2, 2002 between
Reliant Resources, Inc. and Joe Bob Perkins
10.2 Employment Agreement effective July 29, 2002 between
Reliant Resources, Inc. and Mark M. Jacobs
99.1 Certification of Chairman, President and Chief
Executive Officer of Reliant Resources, Inc.
Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b)
of Section 1350, Chapter 63 of Title 18, United
States Code)
99.2 Certification of Executive Vice President and Chief
Financial Officer of Reliant Resources, Inc.
Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b)
of Section 1350, Chapter 63 of Title 18, United
States Code)