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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 JUNE 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 (I.R.S. Employer
incorporation or organization) Identification No.)
1111 Louisiana
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 207-3000
(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 August 9, 2002, Reliant Resources, Inc. (Reliant Resources) had
290,439,779 shares of common stock outstanding including 240,000,000 shares
which were held by Reliant Energy, Incorporated and excluding 9,364,221 shares
held as treasury stock. As of August 9, 2002, 50,402,716 shares of common
stock were held by non-affiliates of Reliant Resources, using the definition of
beneficial ownership contained in Rule 13d-3 promulgated pursuant to the
Securities Exchange Act of 1934.
RELIANT RESOURCES, INC.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2002
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Statements of Consolidated Income (unaudited)
Three and Six Months Ended June 30, 2001 (as restated) and
2002 ......................................................................1
Consolidated Balance Sheets (unaudited)
December 31, 2001 and June 30, 2002 .......................................2
Statements of Consolidated Cash Flows (unaudited)
Six Months Ended June 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 ................................................38
Item 3. Quantitative and Qualitative Disclosures About Market Risk................59
PART II OTHER INFORMATION
Item 1. Legal Proceedings.........................................................61
Item 2. Changes in Securities and Use of Proceeds.................................61
Item 5. Other Information.........................................................61
Item 6. Exhibits and Reports on Form 8-K..........................................63
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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------- -------------------------------
2001 2002 2001 2002
------------ ------------ ------------ ------------
(AS RESTATED) (AS RESTATED)
REVENUES .................................... $ 7,975,148 $ 8,560,903 $ 16,613,160 $ 15,590,885
EXPENSES:
Fuel and cost of gas sold ................. 4,053,830 4,096,400 9,808,369 6,729,816
Purchased power ........................... 3,355,424 3,622,800 5,750,556 7,490,315
Operation and maintenance ................. 131,855 235,714 246,688 414,483
General, administrative and development ... 97,765 166,912 292,747 279,936
Depreciation .............................. 29,315 101,649 60,581 168,903
Amortization .............................. 14,031 4,733 46,895 8,401
------------ ------------ ------------ ------------
Total .................................. 7,682,220 8,228,208 16,205,836 15,091,854
------------ ------------ ------------ ------------
OPERATING INCOME ............................ 292,928 332,695 407,324 499,031
------------ ------------ ------------ ------------
OTHER INCOME (EXPENSE):
Gain from investments, net ................ 4,592 2,286 11,315 4,831
Income from equity investments in
unconsolidated subsidiaries .............. 51,572 5,524 64,350 9,308
Other, net ................................ 3,481 4,082 6,902 3,594
Interest expense .......................... (19,627) (66,918) (43,865) (105,844)
Interest income ........................... 4,419 4,484 15,350 8,310
Interest income (expense) -- affiliated
companies, net .......................... 11,155 1,526 (3,431) 4,184
------------ ------------ ------------ ------------
Total other income (expense) ............. 55,592 (49,016) 50,621 (75,617)
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGE ............... 348,520 283,679 457,945 423,414
INCOME TAX EXPENSE .......................... 119,785 105,224 150,697 148,083
------------ ------------ ------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE ......................... 228,735 178,455 307,248 275,331
Cumulative effect of accounting change,
net of tax ............................... (47) -- 3,062 --
------------ ------------ ------------ ------------
NET INCOME .................................. $ 228,688 $ 178,455 $ 310,310 $ 275,331
============ ============ ============ ============
BASIC EARNINGS PER SHARE:
Income before cumulative effect of
accounting change ........................ $ 0.83 $ 0.62 $ 1.19 $ 0.95
Cumulative effect of accounting change,
net of tax ............................... -- -- 0.01 --
------------ ------------ ------------ ------------
Net Income ........................... $ 0.83 $ 0.62 $ 1.20 $ 0.95
============ ============ ============ ============
DILUTED EARNINGS PER SHARE:
Income before cumulative effect of
accounting change ........................ $ 0.82 $ 0.61 $ 1.19 $ 0.95
Cumulative effect of accounting change,
net of tax ............................... -- -- 0.01 --
------------ ------------ ------------ ------------
Net income ............................. $ 0.82 $ 0.61 $ 1.20 $ 0.95
============ ============ ============ ============
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, JUNE 30,
2001 2002
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents ........................................ $ 118,453 $ 459,561
Restricted cash .................................................. 167,421 375,773
Accounts and notes receivable, principally customer, net ......... 1,167,870 2,020,678
Accrued unbilled revenues ........................................ 14,270 498,322
Accounts and notes receivable - affiliated companies, net ........ 415,081 --
Fuel stock and petroleum products ................................ 109,036 197,289
Materials and supplies ........................................... 64,999 114,907
Stranded costs settlement receivable ............................. 201,503 --
Trading and marketing assets ..................................... 1,611,393 1,367,261
Non-trading derivative assets .................................... 392,900 467,946
Margin deposits on energy trading and hedging activities ......... 213,727 27,909
Collateral for electric generating equipment ..................... 141,701 --
Prepayments and other current assets ............................. 126,936 382,366
------------ ------------
Total current assets ............................................ 4,745,290 5,912,012
------------ ------------
Property, plant and equipment ...................................... 4,834,122 9,304,087
Less accumulated depreciation ...................................... (275,729) (434,433)
------------ ------------
Property, plant and equipment, net .............................. 4,558,393 8,869,654
------------ ------------
OTHER ASSETS:
Goodwill, net .................................................... 891,061 2,383,956
Air emissions regulatory allowances and other intangibles, net ... 315,438 405,697
Notes receivable - affiliated companies, net ..................... 30,278 31,898
Trading and marketing assets ..................................... 446,610 656,440
Non-trading derivative assets .................................... 254,168 348,795
Equity investments in unconsolidated subsidiaries ................ 386,841 289,978
Stranded costs indemnification receivable ........................ 203,693 227,031
Accumulated deferred income taxes ................................ 46,322 --
Prepaid rent ..................................................... 121,699 147,823
Restricted funds for stranded costs .............................. -- 63,008
Collateral for electric generating equipment ..................... 88,268 91,645
Other ............................................................ 203,645 203,220
------------ ------------
Total other assets .............................................. 2,988,023 4,849,491
------------ ------------
TOTAL ASSETS .................................................. $ 12,291,706 $ 19,631,157
============ ============
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, JUNE 30,
2001 2002
------------ ------------
CURRENT LIABILITIES:
Current portion of long-term debt ........................... $ 23,769 $ 16,031
Short-term borrowings ....................................... 296,769 5,831,613
Accounts payable, principally trade ......................... 1,002,326 1,604,485
Accounts and notes payable -- affiliated companies, net ..... -- 149,771
Trading and marketing liabilities ........................... 1,478,336 1,204,274
Non-trading derivative liabilities .......................... 399,277 370,728
Accumulated deferred income taxes ........................... 37,034 48,592
Margin deposits from customers on energy trading and
hedging activities ......................................... 144,700 162,240
Other ....................................................... 253,800 439,297
------------ ------------
Total current liabilities ............................... 3,636,011 9,827,031
------------ ------------
OTHER LIABILITIES:
Accumulated deferred income taxes ........................... -- 294,981
Trading and marketing liabilities ........................... 361,786 591,698
Non-trading derivative liabilities .......................... 639,211 395,720
Major maintenance reserve ................................... 16,784 21,173
Non-derivative stranded costs liability ..................... 203,693 227,031
Benefit obligations ......................................... 127,012 173,974
Other ....................................................... 455,865 431,611
------------ ------------
Total other liabilities ................................. 1,804,351 2,136,188
------------ ------------
LONG-TERM DEBT ................................................ 867,712 1,130,530
------------ ------------
COMMITMENTS AND CONTINGENCIES (NOTE 11)
STOCKHOLDERS' EQUITY:
Preferred stock (125,000,000 shares authorized; none
outstanding) ............................................... -- --
Common stock (2,000,000,000 shares authorized; 240,000,000
and 299,804,000 issued and outstanding, respectively) ...... 61 61
Additional paid-in capital .................................. 5,777,169 5,777,611
Treasury stock at cost, 11,000,000 shares and 10,140,283
shares ..................................................... (189,460) (174,676)
Retained earnings ........................................... 557,451 832,780
Accumulated other comprehensive (loss) income ............... (161,589) 101,632
------------ ------------
Stockholders' equity .................................... 5,983,632 6,537,408
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ............ $ 12,291,706 $ 19,631,157
============ ============
See Notes to the Company's Interim Financial Statements
3
RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
SIX MONTHS ENDED JUNE 30,
-----------------------------
2001 2002
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................... $ 310,310 $ 275,331
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization ................................ 107,476 177,304
Deferred income taxes ........................................ 61,443 94,645
Net trading and marketing assets and liabilities ............. (116,103) 20,422
Net non-trading derivative assets and liabilities ............ (15,987) (13,719)
Curtailment and related benefit enhancement .................. 99,523 --
Undistributed earnings of unconsolidated subsidiaries ........ (30,822) (7,941)
Gain on settlement of stranded costs ......................... -- (109,000)
Cumulative effect of accounting contracts..................... (3,062) --
Changes in other assets and liabilities, net of effects of
acquisitions:
Restricted cash ............................................ 50,000 67,804
Accounts and notes receivable and unbilled revenue, net .... (263,991) (929,355)
Accounts receivable/payable -- affiliated companies, net ... 115,357 176,598
Inventory .................................................. (65,764) (79,505)
Collateral for electric generating equipment, net .......... (66,726) 138,324
Margin deposits on energy trading activities, net .......... 430,219 203,358
Prepaid lease obligation ................................... (101,542) (26,324)
Settlement payment on stranded cost contracts .............. -- (100,280)
Settlement of hedges of net investment in foreign
subsidiaries ............................................ -- (143,982)
Other current assets ....................................... 11,631 (48,956)
Other assets ............................................... (22,026) (17,505)
Accounts payable ........................................... (179,333) 466,771
Taxes accrued .............................................. (23,080) 104,216
Other current liabilities .................................. 12,566 (54,896)
Other liabilities .......................................... 24,361 (83,803)
Other, net ................................................. (6,843) 4,038
----------- -----------
Net cash provided by operating activities ................. 327,607 113,545
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures .......................................... (499,578) (329,946)
Business acquisitions, net of cash acquired ................... -- (2,948,821)
Investments in unconsolidated subsidiaries .................... 26 --
Other, net .................................................... 10,572 (2,299)
----------- -----------
Net cash used in investing activities ..................... (488,980) (3,281,066)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt .................................. -- 22,356
Proceeds from issuance of stock, net .......................... 1,697,848 --
Payments of long-term debt .................................... (1,795) (227,958)
Increase in short-term borrowings, net ........................ 148,677 3,317,929
Change in notes with affiliated companies, net ................ (1,692,552) 386,603
Contributions from owner ...................................... 9,441 --
Other, net .................................................... (7) 7,920
----------- -----------
Net cash provided by financing activities ................. 161,612 3,506,850
----------- -----------
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS .... (4,845) 1,779
----------- -----------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS ............ (4,606) 341,108
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ................ 89,755 118,453
----------- -----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD ...................... $ 85,149 $ 459,561
=========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest (net of amounts capitalized) ......................... $ 101,176 $ 122,999
Income taxes .................................................. 112,801 --
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 of Reliant
Resources (Reliant Resources Form 10-K/A) for the year ended December 31, 2001
and the Quarterly Report on Form 10-Q of Reliant Resources for the quarter ended
March 31, 2002 (First 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), which is incorporated by reference herein, on May 9, 2002,
Reliant Resources determined 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, which 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 of each of
the Board of Directors of Reliant Resources and Reliant Energy, Incorporated
(Reliant Energy), a diversified international energy services and energy
delivery company that owns approximately 83% of Reliant Resources outstanding
common stock, (Audit Committees) 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.
The Company reports 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 41 MWh of power and 46 billion cubic feet (Bcf) of natural gas and 46 Bcf of
natural gas for the three and six months ended June 30, 2001, respectively.
These transactions, referred to above, collectively had the effect of
increasing revenues, fuel and cost of gas sold expense and purchased power
expense by $1.4 billion, $131 million and $1.3 billion, respectively, for the
three months ended June 30, 2001 and by $2.6 billion, $131 million and $2.5
billion, respectively, for the six months ended June 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 $17 million and
$19 million for the three and six months ended June 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 six months ended
June 30, 2001 were previously recorded on a gross basis with such transactions
being reported in revenues and expenses which resulted in $323 million of
revenues, $161 million in fuel and cost of gas sold and $162 million of
purchased power expense
5
being recognized in each period. Having further reviewed the transactions, the
Company now believes these transactions should have been accounted for on a net
basis.
The consolidated financial statements for the three and six months ended
June 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 six months ended June 30, 2001: (Note -- Those line items for which no
change in amounts are shown were not affected by the restatement.)
THREE MONTHS ENDED
JUNE 30, 2001
-------------------------------
AS PREVIOUSLY
AS RESTATED REPORTED(1)
----------- -------------
(IN MILLIONS)
Revenues ......................................... $ 7,975 $ 9,697
Expenses:
Fuel and cost of gas sold ...................... 4,054 4,360
Purchased power ................................ 3,355 4,771
Other expenses ................................. 273 273
------- -------
Total ......................................... 7,682 9,404
------- -------
Operating Income ................................. 293 293
Other Income, net ................................ 56 56
Income Tax Expense ............................... (120) (120)
------- -------
Net Income ....................................... $ 229 $ 229
======= =======
SIX MONTHS ENDED
JUNE 30, 2001
----------------------------
AS PREVIOUSLY
AS RESTATED REPORTED(1)
----------- -------------
(IN MILLIONS)
Revenues .............................................. $ 16,613 $ 19,568
Expenses:
Fuel and cost of gas sold ........................... 9,808 10,115
Purchased power ..................................... 5,751 8,399
Other expenses ...................................... 647 647
-------- --------
Total .............................................. 16,206 19,161
-------- --------
Operating Income ...................................... 407 407
Other Income, net ..................................... 51 51
Income Tax Expense .................................... (151) (151)
-------- --------
Income Before Cumulative Effect of Accounting Change .. 307 307
Cumulative effect of accounting change, net of tax .... 3 3
-------- --------
Net Income ............................................ $ 310 $ 310
======== ========
(1) 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 $4 million for both the three and
six months ended June 30, 2001 have been reclassified to conform to this
presentation.
The restatement did not impact earnings per share for 2001 or the Statements
of Consolidated Cash Flows for 2001.
6
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 10K/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 six months ended June 30, 2001 from amounts
previously reported, to effect this transaction as described above. The
restatement increased comprehensive income by $12 million from a total
comprehensive income of $569 million, as previously reported, to $581 million,
as restated, for the three months ended June 30, 2001 and decreased
comprehensive income by $146 million (including the $170 million transition
adjustment discussed above) from a total comprehensive income of $567 million,
as previously reported, to $421 million, as restated, for the six months ended
June 30, 2001. The restatement had no impact on the Company's reported
consolidated cash flows, operating income or net income.
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.
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. Energy sales and services
related to its electric power generation facilities not billed by month-end are
accrued based upon estimated energy and services delivered. 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.
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
market 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 physical
sale of natural gas, electric power and other energy related commodities are
recorded on a gross basis in the delivery period. 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. For information regarding the Company's
adoption of Emerging Issues Task Force (EITF) Issue No. 02-03 "Accounting for
Contracts involved in Energy Trading and Risk Management Activities" (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 2.
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 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, and (d) acquisitions and dispositions of
businesses, assets and other interests. 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. These notes, as updated herein, are incorporated herein by
reference:
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).
7
For information regarding certain legal, regulatory proceedings and
environmental matters, see Note 11.
Reliant Energy has 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 has 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 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), which is incorporated by reference herein, to the Reliant
Resources 10-K/A Notes.
As part of its business separation plan, Reliant Energy has publicly
disclosed that it intends to restructure its corporate organization into a
public utility holding company structure (Reorganization) by August 31, 2002 and
to distribute, subject to further corporate approvals, market and other
conditions, all of the shares of Reliant Resources common stock that it owns to
its shareholders (Distribution) early in the fall of 2002. In December 2001,
Reliant Energy's shareholders voted to approve the merger required for the
holding company reorganization. Reliant Energy has publicly disclosed its goal
to complete the Reorganization and subsequent Distribution as quickly as
possible after all the necessary conditions are fulfilled. In July 2002, Reliant
Energy received an order from the Securities and Exchange Commission (SEC)
granting the required approvals under the Public Utility Holding Company Act of
1935 (1935 Act) to adopt a new holding company structure and allow it to compete
the Distribution. Also in July 2002, Reliant Energy received a supplemental
ruling from the IRS which confirms that the Distribution will be tax-free to
Reliant Energy and its shareholders. There can be no assurances that the
Distribution will be completed as described or within the time period outlined
above.
(2) 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 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
8
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. 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 3 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 6 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 on EITF No. 02-03 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. An entity should
disclose the gross transaction volumes for those energy trading contracts that
are physically settled. The EITF did not reach 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. 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 six months ended June 30, 2002, the Company recorded
$46 million of fair value of the contract inception related to trading and
marketing activities. The consensus on presenting gains and losses on energy
trading contracts net is effective for financial statements issued for periods
ending after July 15, 2002. Upon application of the consensus, comparative
financial statements for prior periods should be reclassified to conform to the
consensus. The Company currently reports 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. Beginning with the quarter ended September 30, 2002,
the Company will report all energy trading and marketing activities on a net
basis in the Statements of Consolidated Income pursuant to EITF No. 02-03.
Although the Company is in the process of determining the effect of adoption of
EITF No. 02-03 on its Statements of Consolidated Income, the Company expects the
adoption will result in a substantial reduction in operating revenues, fuel and
cost of gas sold, and purchased power.
(3) 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
9
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
impact the Company's consolidated financial statements.
Cash Flow Hedges. During the six months ended June 30, 2002, the amount of
hedge ineffectiveness recognized in earnings from derivatives that are
designated and qualify as cash flow hedges was a $12 million gain. During the
six months ended June 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 six months ended June
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 June 30, 2002, the
Company expects $27 million in accumulated other comprehensive income to be
reclassified into net income during the next twelve months.
Interest Rate Swaps. As of June 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 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 a future offering of long-term fixed-rate
notes. 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 8 years.
Hedge of Net Investment in Foreign Subsidiaries. The Company has
substantially hedged its net investment in its European subsidiaries to reduce
the Company's exposure to changes in foreign exchange rates through a
combination of Euro-denominated borrowings, foreign currency swaps and foreign
currency option contracts. During the six months ended June 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 $16
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 Reliant Energy
Power Generation Benelux N.V. (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 recorded a liability of $369 million
for the REPGB stranded cost gas and electric commitments in non-trading
derivative liabilities. As of June 30, 2002, the Company recorded a liability of
$155 million for the REPGB stranded cost gas supply contract in non-trading
derivative liabilities. Pursuant to SFAS No. 133, during the three and six
months ended June 30, 2002, the Company recognized a $3 million loss and net $16
million gain, respectively, recorded in fuel expense related to changes in the
valuation of these non-trading
10
derivative liabilities, excluding the effects of the gain related to amending
the two power contracts as discussed in Note 11(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 11(d) and Note 13(f) to the
Reliant Resources 10-K/A Notes.
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 six
months ended June 30, 2002, $26 million and $50 million, respectively, of net
non-trading derivative assets were settled related to these transactions, and a
$1 million and $2 million, respectively, pre-tax unrealized gain was recognized.
As of June 30, 2002, the Company has recognized $163 million of non-trading
derivative assets and $93 million of non-trading derivative liabilities related
to these transactions.
(4) HISTORICAL RELATED PARTY TRANSACTIONS
The Interim Financial Statements include significant transactions between
the Company and Reliant Energy 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 $2 million and $5 million for the three months
ended June 30, 2001 and 2002, respectively. Amounts charged and allocated to the
Company for these services were $4 million and $10 million for the six months
ended June 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 six months ended June 30, 2001, the Company
incurred costs primarily related to corporate support services which were billed
to Reliant Energy and its affiliates of $13 million and $20 million,
respectively. Some subsidiaries of the Company have entered into office rental
agreements with Reliant Energy. During the three months ended June 30, 2001 and
2002, the Company incurred $5 million and $8 million, respectively, of rent
expense to Reliant Energy. The Company incurred $8 million and $16 million of
rent expense to Reliant Energy during the six months ended June 30, 2001 and
2002, respectively.
Below is a detail of accounts and notes receivable to affiliated
companies that are not part of the Company:
DECEMBER 31, JUNE 30,
2001 2002
----------- --------
(IN MILLIONS)
Net accounts receivable (payable) -- affiliated companies .... $ 27 $(148)
Net short-term notes receivable (payable) -- affiliated
companies .................................................. 388 (2)
Net long-term notes receivable -- affiliated companies ....... 30 32
----- -----
Total net accounts and notes receivable (payable) --
affiliated companies ..................................... $ 445 $(118)
===== =====
Net accounts receivable/(payable) from affiliated companies, representing
primarily current month balances of transactions between the Company and Reliant
Energy or its subsidiaries, relate primarily to natural gas purchases and sales,
electric generation capacity purchases, electric transmission services, charges
for services and office space rental. Net short-term notes receivable/(payable)
from affiliated companies represent the accumulation of a variety of cash
transfers and operating transactions and generally bear interest at market-based
rates. Net long-term notes receivable from affiliated companies primarily relate
to specific negotiated financing transactions with Reliant Energy or its
subsidiaries that bear interest at market-based rates. Net interest income
related to these net borrowings/receivables was $11 million and $2 million
during the three months ended June 30, 2001 and 2002, respectively. Net interest
expense related to these net receivables was $3 million during the six months
ended June 30, 2001. Net interest income related to these receivables was $4
million during the six months ended June 30, 2002.
11
During 2001 and 2002, proceeds not initially utilized from the IPO were
advanced to a subsidiary of Reliant Energy (the Reliant Energy money fund) on a
short-term basis. The Company has reduced its advance to the Reliant Energy
money fund following the IPO to fund capital expenditures and to meet its
working capital needs. As of December 31, 2001, the Company had outstanding
advances to the Reliant Energy money fund of $390 million which is included in
accounts and notes receivable in the Company's Consolidated Balance Sheet.
During the six months ended June 30, 2002, these advances were returned to the
Company.
The Company purchases natural gas, electric generation capacity, electric
transmission services and natural gas transportation services from, supplies
natural gas to, and provides marketing and risk management services to
affiliates of Reliant Energy that are not part of the Company. Purchases of
electric generation capacity, electric transmission services, natural gas
transportation services and natural gas from Reliant Energy and its subsidiaries
were $44 million and $516 million for the three months ended June 30, 2001 and
2002, respectively, and $130 million and $881 million for the six months ended
June 30, 2001 and 2002, respectively. During the three months ended June 30,
2001 and 2002, the sales and services to Reliant Energy and its subsidiaries
totaled $137 million and $70 million, respectively, and $459 million and $185
million for the six months ended June 30, 2001 and 2002, respectively.
During the fourth quarter of 2001 and the first quarter of 2002, the Company
purchased entitlements to some of the generation capacity of Reliant Energy's
Texas electric utility generation assets (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 June 30, 2002, the Company has purchased
entitlements to capacity of Texas Genco averaging 6,917 MW per month for the
remainder of 2002 and 775 MW per 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 $149 million in 2002 and $58 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 three and six months ended June 30, 2001, Reliant Energy or its
subsidiaries made equity contributions to the Company of $1.7 billion and $1.8
billion, respectively. There were no contributions for the six months ended June
30, 2002. The contributions in the three months ended June 30, 2001, primarily
related to the conversion into equity of debt owed to Reliant Energy and its
subsidiaries and some related interest expense totaling $1.7 billion. The
contributions in the six months ended June 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.
(5) ACQUISITIONS
Orion Power Holdings, Inc. In February 2002, the Company 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.
The Company funded the Orion Power acquisition with a $2.9 billion credit
facility (see Note 8) 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 June 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 included adjustments in property, plant and
12
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 June 30, 2001 and six months ended June 30, 2001 and 2002, as if
the acquisition had occurred on January 1, 2001 and 2002, as applicable.
THREE MONTHS ENDED
JUNE 30, 2001
-------------------------
ACTUAL PRO FORMA
------ ---------
(IN MILLIONS)
Revenues ........................................... $7,975 $8,281
Net income ......................................... 229 238
Basic earnings per share ........................... $ 0.83 $ 0.86
Diluted earnings per share ......................... 0.82 0.86
SIX MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2001 JUNE 30, 2002
---------------------- ----------------------
ACTUAL PRO FORMA ACTUAL PRO FORMA
-------- ---------- ------- ---------
(IN MILLIONS)
Revenues ............................... $16,613 $17,195 $15,591 $15,713
Income before cumulative effect of
accounting change .................... 307 320 275 217
Net income ............................. 310 323 275 217
Basic and diluted earnings per share
before cumulative effect of accounting
change................................. $ 1.19 $ 1.24 $ 0.95 $ 0.75
Basic and diluted earnings per share..... 1.20 1.25 0.95 0.75
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 2 and 6.
(6) 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:
13
THREE MONTHS ENDED JUNE 30,
---------------------------
2001 2002
------- -------
(IN MILLIONS, EXCEPT PER
SHARE AMOUNTS)
Reported net income ................................ $ 229 $ 178
Add: Goodwill amortization, net of tax ............. 8 --
------- -------
Adjusted net income ................................ $ 237 $ 178
======= =======
Basic Earnings Per Share:
Reported net income ................................ $ 0.83 $ 0.62
Add: Goodwill amortization, net of tax ............. 0.03 --
------- -------
Adjusted basic earnings ............................ $ 0.86 $ 0.62
======= =======
Diluted Earnings Per Share:
Reported net income ................................ $ 0.82 $ 0.61
Add: Goodwill amortization, net of tax ............. 0.03 --
------- -------
Adjusted diluted earnings .......................... $ 0.85 $ 0.61
======= =======
SIX MONTHS ENDED JUNE 30,
-------------------------
2001 2002
------- -------
(IN MILLIONS, EXCEPT PER
SHARE AMOUNTS)
Reported net income ................................ $ 310 $ 275
Add: Goodwill amortization, net of tax ............. 17 --
------- -------
Adjusted net income ................................ $ 327 $ 275
======= =======
Basic and Diluted Earnings Per Share:
Reported net income ................................ $ 1.20 $ 0.95
Add: Goodwill amortization, net of tax ............. 0.07 --
------- -------
Adjusted basic and diluted earnings ................ $ 1.27 $ 0.95
======= =======
The components of the Company's other intangible assets consist of the
following:
DECEMBER 31, 2001 JUNE 30, 2002
----------------------- -------------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)
Air Emission Regulatory Allowances ..... $255 $(78) $268 $ (82)
Water Rights ........................... 68 (4) 68 (5)
Other Power Generation Site Permits .... 77 (3) 77 (5)
Contractual rights ..................... -- -- 91 (8)
Other .................................. -- -- 2 (1)
---- ---- ---- -----
Total .................................. $400 $(85) $506 $(100)
==== ==== ==== =====
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 June 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 that net fair value exceeded book value
at the date of acquisition were recorded to intangible assets (Contractual
Rights) and those contracts that net fair value were below book 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 pattern in which the economic effects
are estimated to be realized over the contractual lives. Amortization in future
periods will be disclosed as the purchase price allocation is finalized.
14
Amortization expense for other intangibles, excluding Contractual Rights,
for the three months ended June 30, 2001 and 2002 was $7 million and $4 million,
respectively. Amortization expense for other intangibles, excluding Contractual
Rights, for the six months ended June 30, 2001 and 2002 was $30 million and $8
million, respectively. The Company amortized $7 million of Contractual Rights
and $10 million of Contractual Obligations during both the three and six months
ended June 30, 2002. Estimated amortization expense, excluding Contractual
Rights, for the remainder of 2002 and the five succeeding fiscal years is as
follows (in millions):
2002 ......................... $ 7
2003 ......................... 13
2004 ......................... 13
2005 ......................... 13
2006 ......................... 13
2007 ......................... 13
---
Total ...................... $72
===
Changes in the carrying amount of goodwill for the six months ended June 30,
2002, by reportable segment, are as follows:
GOODWILL FOREIGN
AS OF ACQUIRED CURRENCY AS OF
JANUARY 1, DURING THE EXCHANGE JUNE 30,
2002 PERIOD IMPACT OTHER 2002
---------- ---------- --------- ----- -------
(IN MILLIONS)
Wholesale Energy ....... $184 $1,411 $-- $1 $1,596
European Energy ........ 675 -- 81 - 756
Retail Energy .......... 32 -- -- - 32
---- ------ --- -- ------
Total ................ $891 $1,411 $81 $1 $2,384
==== ====== === == ======
The Company is in the process of determining further effects of adoption
of SFAS No. 142 on its Consolidated Financial Statements, including the review
of goodwill for impairment. The Company has not completed its review pursuant to
SFAS No. 142. The Company has completed the first step of the goodwill
impairment test, used to identify potential impairments, which compares the fair
value of a reporting unit with its carrying amount, including goodwill. Based on
the first step of the goodwill impairment test, the Company's European Energy
segment's goodwill is impaired by approximately $250 million. The Company
believes that its final impairment loss will approximate the impairment loss
indicated in the first step of the goodwill impairment. The Company has retained
an outside valuation firm to assist in the Company's review and will finalize
its review of goodwill of the European Energy segment during 2002. The
impairment loss resulting from the transitional impairment test will be 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. 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.
15
(7) COMPREHENSIVE INCOME
The following table summarized the component of total comprehensive income:
FOR THE THREE MONTHS FOR THE SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
--------------------- -------------------
2001 2002 2001 2002
----- ----- ----- -----
(IN MILLIONS)
Net income ....................................... $ 229 $ 178 $ 310 $ 275
Other comprehensive income (loss):
Foreign currency translation adjustments ....... 5 115 5 105
Changes in minimum benefit liability ........... -- -- (6) --
Cumulative effect of adoption of SFAS
No. 133 ....................................... -- -- (460) --
Deferred gain from cash flow hedges ............ 251 33 437 186
Reclassification of deferred loss (gain) from
cash flow hedges realized in net income ....... 90 (8) 122 (27)
Unrealized gain on available-for-sale
securities ................................... 7 1 15 1
Reclassification adjustments for gains
on sales of available-for-sale securities
realized in net income ....................... (1) (1) (2) (2)
----- ----- ----- -----
Comprehensive income ............................. $ 581 $ 318 $ 421 $ 538
===== ===== ===== =====
Included in "Reclassification of deferred loss (gain) from cash flow hedges
realized in net income" above for the six months ended June 30, 2001 and 2002 is
$12 million of amortization for both the three months ended March 31, 2001 and
2002 related to the amortization of the transition adjustment arising from the
termination and replacement of two power generation swap contracts referred to
in Note 1. Included in "Cumulative effect of adoption of SFAS No. 133" above for
the six months ended June 30, 2001 is a $170 million transition adjustment
referred to in Note 1. Such amounts have not been previously reported in the
Company's comprehensive income disclosure for the three months ended March 31,
2001 and 2002.
(8) BORROWINGS FROM THIRD PARTIES
Credit Facilities. As of June 30, 2002, the Company had $8.3 billion in
committed credit facilities of which $1.2 billion remained unused. Credit
facilities aggregating $5.4 billion were unsecured. As of June 30, 2002, letters
of credit outstanding under these facilities aggregated $803 million. As of
June 30, 2002, borrowings of $6.3 billion were outstanding under these
facilities of which $602 million were classified as long-term debt, based upon
the availability of committed credit facilities and management's intention to
maintain these borrowings in excess of one year.
16
The following table provides a summary of the amounts owed and amounts
available as of June 30, 2002 under the Company's various credit facilities.
TOTAL EXPIRING BY
COMMITTED DRAWN LETTERS UNUSED JUNE 30, EXPIRATION
CREDIT AMOUNT OF CREDIT AMOUNT 2003 DATE
--------- ------- --------- ------- ----------- -----------
(IN MILLIONS)
RELIANT RESOURCES:
Orion acquisition term
loan.................... $ 2,908 $ 2,908 $ -- $ -- $ 2,908 February 2003
364-day revolver.......... 800 -- -- 800 800 August 2002(1)
Three-year revolver....... 800 400 386 14 -- August 2004
WHOLESALE ENERGY:
Orion Power and
Subsidiaries:
Orion Power.............. 75 43 24 8 75 December 2002
Orion MidWest............ 1,063 1,028 15 20 1,063 October 2002
Orion NY................. 532 502 10 20 532 December 2002
October 2002 -
Liberty Project.......... 292 270 17 5 6 April 2026
Reliant Energy Channelview LP:
Equity bridge............ 92 92 -- -- 92 November 2002
Construction term loan
and working capital October 2002 -
facility............... 383 340 -- 43 2(2) July 2024
REMA letter of credit
facility................. 81 -- 81 -- -- August 2003
EUROPEAN ENERGY:
Reliant Energy Capital
Europe, Inc.............. 595 595 -- -- 595 March 2003
REPGB 364-day revolver.... 248 124 -- 124 248 July 2002
REPGB letter of credit
facility................. 420 -- 270 150 -- July 2003
------- ------- ------- ------- -------
Total ...................... $ 8,289 $ 6,302 $ 803 $ 1,184 $ 6,321
======= ======= ======= ======= =======
- ------------
(1) The Company has given notice that it intends to exercise its option to
convert this facility to a one-year loan with a maturity of August 22, 2003.
(2) Excludes $369 million of facilities expiring in November 2002
as borrowings under such facilities are convertible into a long-term loan.
These facilities include a term loan facility entered into 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 London inter-bank offered rate (LIBOR) plus a
margin or a base rate. This facility was funded on February 19, 2002 for $2.9
billion. As of June 30, 2002, the weighted average interest rate on outstanding
borrowings was 2.79%. This term loan must be repaid within one year from the
date on which it was funded. For a discussion of the acquisition of Orion Power,
see Note 5.
In addition to credit facilities, the Company had long-term debt totaling
$529 million of which $411 million related to bonds issued by Orion Power.
Refinancing Issues. As a result of several recent events, including the
United States economic recession, the general common stock price decline of
participants in the Company's industry sector, the general credit rating
downgrades of the participants in the Company's industry sector, the Company's
credit rating downgrades and its placement on review for future downgrades, the
availability and cost of capital for the Company's business has been adversely
affected. The credit environment may require the Company's future facilities to
include terms that are more restrictive or burdensome or at higher borrowing
rates than those of the Company's current facilities and that may require us to
provide collateral as security. In addition, certain financial institutions may
limit the amount of additional financings or discontinue providing financings to
the Company. The terms of any new credit facilities may also be adversely
affected by any delay in the date of the Distribution. In addition, any future
reduction or withdrawal of one or more of the Company's credit ratings could
have a material adverse impact on the Company's ability to access capital on
acceptable terms, including the ability to refinance debt obligations as they
mature.
As of June 30, 2002, the Company had $6.3 billion of committed credit
facilities which will expire by June 30, 2003 of which $2.8 billion will expire
by December 31, 2002. The Company expects to extend or replace these facilities.
In order to meet the Company's future needs the Company may obtain financings
that are secured by certain of the Company's assets or the operations of the
Company's subsidiaries. In addition to giving security, other terms, conditions,
covenants or restrictions may be imposed as part of these financings that may
adversely affect the Company. Providing collateral to obtain future financings
or refinancings may adversely affect the Company's credit ratings thereby
increasing the cost of the Company's debt.
17
Although the Company expects to obtain future financings, there can be no
assurance that the Company will be successful.
The Company's $800 million unsecured 364-day revolving credit facility
expires on August 22, 2002. The facility agreement allows the Company the option
to borrow the entire amount and convert it, provided that there is no default on
the conversion date, to a one-year term loan with a maturity of August 22,
2003. The Company has given notice that the Company intends to exercise
this option.
The Company is currently negotiating with the banks regarding the
appropriate terms and conditions for an extension of the maturity of its $2.9
billion Orion acquisition term loan, which is scheduled to mature on February
19, 2003. The Company expects to complete this extension in the second half of
2002.
The Company is also in negotiations with the lead arrangers for a
refinancing of the facilities at Orion Power, Orion Power MidWest, LP (Orion
MidWest) and Orion Power New York, LP (Orion NY), which are discussed below. The
Company anticipates that the new financings will total approximately $1.3
billion and will be completed in September 2002. Similar to the existing Orion
MidWest and Orion NY credit agreements. The refinancings for Orion MidWest
and Orion NY will likely be secured by the assets of both Orion MidWest
and Orion NY.
The Company's refinancing plan contemplates the simultaneous refinancing of
the $2.9 billion term loan, the $800 million 364-day revolving credit facility,
the $800 million three-year revolving credit facility, and the Orion NY and
MidWest credit agreements.
The Euro 600 million (approximately $595 million) term loan facility at
Reliant Energy Capital Europe, Inc. matures on March 1, 2003. Preliminary work
has commenced on the refinancing of this term loan facility. The Company plans
to execute such refinancing during the fourth quarter of 2002 or first quarter
of 2003.
In May 2002, the Company established a $300 million commercial paper program
which is supported by its existing credit facilities. Due to market conditions
and the Company's current credit ratings, the Company has not yet attempted to
issue commercial paper. It is unlikely that the Company will be able to issue
commercial paper in the near future.
During July 2002, the Company, through a subsidiary, established a
receivables facility to finance certain of its Retail Energy segment's
receivables up to $250 million. For further discussion, see Note 15(a).
During July 2002, REPGB renewed its 364-day revolving credit facility
through July 2003. The amount of the credit facility was reduced from Euro 250
million (approximately $248 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. For
further discussion, see Note 15(b).
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.
New York Credit Agreement. As of June 30, 2002, Orion NY, a wholly owned
subsidiary of Orion Power, had a secured credit agreement (New York Credit
Agreement), which includes a $502 million acquisition facility and a $30 million
revolving working capital facility. As of June 30, 2002, Orion NY had $502
million of acquisition loans outstanding. As of June 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 bear interest at
the borrower's option at (a) a base rate or (b) LIBOR plus a margin. The
weighted average interest rate on outstanding borrowings as of June 30, 2002,
was 3.61%. The credit agreement is secured by substantially all of the assets of
Orion NY. The credit agreement expires in December 2002.
MidWest Credit Agreement. As of June 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. As of June 30, 2002, Orion MidWest had $988
million and $40 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 bear interest at the borrower's
option at (a) a base rate or (b) LIBOR plus a margin. The weighted average
interest rate on outstanding borrowings as of June 30, 2002, was 3.88%.
Borrowings under the MidWest Credit Agreement are secured by substantially all
the assets of Orion MidWest. The credit agreement expires in October 2002.
The New York Credit Agreement and the Midwest Credit Agreement
(collectively, the Orion Credit Agreements) contain restrictive covenants that
restrict the ability of Orion NY or Orion MidWest to, among other things, make
dividend distributions unless Orion NY or Orion MidWest satisfy various
conditions. As of June 30, 2002, restricted cash under the Orion Credit
Agreements totaled $346 million.
18
In connection with the Orion Power acquisition, the existing interest rate
swaps for 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 June 30, 2002, $3 million and $7 million was amortized to interest
expense for the New York Credit Agreement and MidWest Credit Agreement,
respectively. See Note 3 for information regarding the Company's derivative
financial instruments.
The Orion Credit Agreements contain 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 June 30, 2002, the
MidWest Credit Agreement was amended to provide that Orion MidWest is not
required to meet this ratio until the quarter ending September 30, 2002. Orion
MidWest may not be able to meet this debt service coverage ratio for the quarter
ending September 30, 2002. It is the Company's current intention to arrange for
the repayment, refinancing or amendment of these facilities prior to September
30, 2002. If the MidWest Credit Agreement is not repaid, refinanced or amended
prior to that date, and if a waiver is required under this credit facility, the
Company currently believes that it will be able to obtain such a waiver.
However, the Company currently has no assurance that it will be able to obtain
such a waiver or amendment from the lender group if required under the MidWest
Credit Agreement. If the debt service coverage ratio is not met, and the MidWest
Credit Agreement is not repaid, refinanced or amended or no waiver is obtained,
the MidWest Credit Agreement would be in default and the lenders could demand
payment of all outstanding amounts under the MidWest Credit Agreement.
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 in
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 fund.
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 (a) a base rate
or (b) LIBOR plus a margin, except for the institutional term loan which bears
interest at a fixed rate. At June 30, 2002, the weighted average interest rate
on the outstanding borrowings was 3.12% on the floating rate component and 9.02%
on the fixed rate portion. As of June 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 June 30, 2002, restricted cash under the Liberty Credit Agreement totaled
$20 million.
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
six months ended June 30, 2002, $2 million was amortized to interest expense for
the Senior Notes. The fair value of the Senior Notes is based on the Company's
current incremental borrowing rates for similar types of borrowing arrangements.
The Senior Notes indenture contains covenants that include among others,
restrictions on the payment of dividends by Orion Power.
19
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.
Revolving Senior Credit Facility. Orion Power has an unsecured $75 million
revolving senior credit facility that matures in December 2002. Amounts
outstanding under the facility bear interest at a floating rate. As of June 30,
2002, there were $43 million of borrowings outstanding under this facility, and
a total of $24 million in letters of credit were also outstanding. This credit
facility contains various covenants that include, among others, restrictions on
the payment of dividends by Orion Power. As of June 30, 2002, restricted cash
under this revolving senior credit facility totaled $7 million.
The senior credit facility of Orion Power contains various business and
financial covenants that require 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 March 31, 2002 and June
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 will not be considered to be
an event of default until September 30, 2002. It is the Company's current
intention to arrange for the repayment, refinancing or amendment of this
facility prior to September 30, 2002. If this facility is not repaid, refinanced
or amended prior to that date, and if a waiver is required under this credit
facility, the Company currently believes that it will be able to obtain such a
waiver. However, the Company currently has no assurance that it will be able to
obtain such a waiver or amendment from the lender groups if required under this
credit facility. If the debt service coverage ratio is not met, and the senior
credit facility is not repaid, refinanced or amended or no waiver is obtained,
the senior credit facility would be in default and the lenders could demand
payment of all outstanding amounts under the senior credit facility.
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 remains outstanding.
(9) 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 August 9, 2002, the Company has not purchased any shares
of its common stock under this program.
In January 2002, the Company sold 550,781 treasury shares to employees under
an employee stock purchase plan at a price of $14.07 per share. 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.
20
(10) EARNINGS PER SHARE
The following tables presents Reliant Resources' basic and diluted earnings
per share (EPS) calculation. There were no dilutive reconciling items to net
income.
FOR THE THREE MONTHS ENDED
JUNE 30,
--------------------------
2001 2002
------- -------
(IN THOUSANDS, EXCEPT PER
SHARE AMOUNTS)
Weighted average shares outstanding ..................... 276,944 289,591
======= =======
Diluted EPS Calculation:
Weighted average shares outstanding ..................... 276,944 289,591
Plus: Incremental shares from assumed conversions:
Stock options ........................................ 172 364
Restricted stock ..................................... 116 539
Employee stock purchase plan ......................... 14 139
------- -------
Weighted average shares assuming dilution ............. 277,246 290,633
======= =======
Basic EPS:
Income before cumulative effect of accounting change .. $ 0.83 $ 0.62
Cumulative effect of accounting change, net of tax .... -- --
------- -------
Net income ............................................ $ 0.83 $ 0.62
======= =======
Diluted EPS:
Income before cumulative effect of accounting change .. $ 0.82 $ 0.61
Cumulative effect of accounting change, net of tax .... -- --
------- -------
Net income ............................................ $ 0.82 $ 0.61
======= =======
For the three months ended June 30, 2002, the computation of diluted EPS
excludes purchase options for 7,966,882 shares of common stock that have an
exercise price (ranging from $14.23 -- $34.03 per share) greater than the per
share average market price ($11.97) for the period and would thus be
anti-dilutive if exercised. For the three months ended June 30, 2001, the
computation of diluted EPS excludes purchase options for 9,517 shares of common
stock that have an exercise price ($34.03) greater than the per share average
market price ($31.45) for the period and would thus be anti-dilutive if
exercised.
FOR THE SIX MONTHS ENDED
JUNE 30,
------------------------
2001 2002
------- -------
(IN THOUSANDS, EXCEPT PER
SHARE AMOUNTS)
Weighted average shares outstanding ...................... 258,574 289,464
======= =======
Diluted EPS Calculation:
Weighted average shares outstanding ...................... 258,574 289,464
Plus: Incremental shares from assumed conversions:
Stock options ......................................... 86 410
Restricted stock ...................................... 116 539
Employee stock purchase plan .......................... 14 139
------- -------
Weighted average shares assuming dilution .............. 258,790 290,552
======= =======
Basic and Diluted EPS:
Income before cumulative effect of accounting change ... $ 1.19 $ 0.95
Cumulative effect of accounting change, net of tax ..... 0.01 --
------- -------
Net income ............................................. $ 1.20 $ 0.95
======= =======
For the six months ended June 30, 2002, the computation of diluted EPS
excludes purchase options for 7,966,882 shares of common stock that have an
exercise price (ranging from $14.23 -- $34.03 per share) greater than the per
share average market price ($12.82) for the period and would thus be
anti-dilutive if exercised. For the six months ended June 30, 2001, the
computation of diluted EPS excludes purchase options for 9,517 shares of common
21
stock that have an exercise price ($34.03) greater than the per share average
market price ($31.45) for the period and would thus be anti-dilutive if
exercised.
(11) COMMITMENTS AND CONTINGENCIES
(a) Legal Matters.
Southern California Class Actions. Reliant Energy, Reliant Energy Services,
Inc. (Reliant Energy Services), REPG and several other subsidiaries of Reliant
Resources, as well as two former officers and one present officer of some of
these companies, 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 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, 2000, 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 Los Angeles Department of Water and Power
and the Bonneville Power Administration. Powerex Corp. and Bonneville Power
Administration 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 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 in April 2002, where it has been assigned to Judge Vaughn
Walker in the Northern District of California.
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
22
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 argues 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 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.
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 its 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. Judge Walker has denied
the California Attorney General's motion to remand the two above-mentioned
cases to state court and it is anticipated that he will rule in the near future
in the Company's motion to dismiss all three cases.
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 have been conditionally assigned to Judge Whaley by the
Panel on Multi-District Litigation. The plaintiffs in the Southern California
class actions have opposed this transfer and it is likely that there will be a
hearing before the Panel at its next meeting in September 2002.
Washington/Oregon 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. A motion has been made to transfer this
case to Judge Whaley.
The Company has not answered any of these cases; however, it has moved to
dismiss the cases on the grounds that the claims are barred by federal
preemption and by the filed rate doctrine.
On April 11, 2002, the FERC set for hearing a series of complaints filed by
Nevada Power Company, which seeks reformation of certain forward power
contracts, including 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 this case by May 31,
2003.
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
Reliant Energy for any damages arising under these lawsuits and may elect to
defend these lawsuits at the Company's own expense. The above-described lawsuits
and proceedings regarding California electricity sales are currently the subject
of intense, highly-charged media and political attention. Their ultimate outcome
cannot be predicted at this time.
Trading and Marketing Activities. The Company is party to numerous lawsuits
and regulatory proceedings relating to its trading and marketing activities,
including (i) round trip trades, as more fully described in Note 1, and (ii)
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.
23
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 and
Reliant Energy are 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
and requested information relating to Reliant Resources' natural gas and power
trading activities, including round trip trades, 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). While the Company is still in the process of reviewing the
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 11(c) should be
based, not on published indices but rather should be calculated using producing
basin spot prices plus regulated transportation costs. The use of such a
calculation for determining gas prices for refund purposes will 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 on.
In the Initial Report, the FERC 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 all power trading activity, natural gas
trading for specific periods or locations, Enron-like trading practices, round
trip trades and compliance with supplemental dispatch requests. The Company
expects to receive additional data requests regarding its plant operations and
gas and power 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 from the United States Attorney for the
Southern District of New York requesting documents pertaining to the round trip
trades, and anticipates investigations of energy trading activities by the
Company and numerous other companies that parallel those 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.
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, among other things. 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.
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 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.
24
The two remaining complaints allege 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.
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 Reliant Energy Mid-Atlantic Power Holdings, LLC (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
June 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 $33 million as of June 30, 2002. The Company expects approximately $14
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 June 30, 2002, the recorded
undiscounted liability for this asbestos abatement and soil remediation 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 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
25
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 too 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 (CDWR) 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 CDWR 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 CDWR. The CDWR has now made payment through the
Cal ISO for its real-time energy deliveries subsequent to January 17, 2001,
although the Cal ISO's application of CDWR's payment for the month of January
2001, including the allocation of interest, which is subject of motions that the
Company has filed with the FERC objecting to the Cal ISO's failure to allocate
January payments 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. The
CPUC's plan 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 refunds ordered by the FERC. The stipulation does not
preclude the Company from approving other reorganization plans, including the
CPUC.
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
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 June 30, 2002, the Company was owed a total of
$302 million and $239 million (net of refund provision), respectively, by the
Cal ISO, the Cal PX, the CDWR, and California Energy Resources Scheduling for
energy sales in the California wholesale market during the fourth quarter of
2000 through June 30, 2002. From June 30, 2002 through August 9, 2002, the
Company has collected $1 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
six months ended June 30, 2002, $38 million of a previously accrued credit
provision for energy sales in California was reversed. The reversal resulted
from
26
collections of outstanding receivables during the period coupled with 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 $5
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 June 30, 2002, the Company had a
remaining pre-tax credit provision of $30 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, 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 has 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 six months ended June 30, 2001, the Company accrued refunds
of $15 million.
On April 26, 2001, the FERC issued an order replacing previous price review
procedures and establishing a market monitoring and mitigation plan, effective
May 29, 2001, for the California markets. The plan establishes a cap on prices
during periods when power reserves fall below 7% in the Cal ISO (reserve
deficiency periods). The Cal ISO was instructed to use data submitted
confidentially by gas-fired generators in California and daily indices of
natural gas to establish the proxy market-clearing price in real-time based on
the marginal cost of the highest-cost generator called to run. The plan also
requires generators in California to offer all their available capacity for sale
in the real-time market, and conditions sellers' market-based rate authority
such that prices charged by sellers engaging in certain bidding practices will
be subject to increased scrutiny by the FERC, such sellers could face potential
refunds and even revocation of their market-based rate authority. On June 19,
2001, the FERC issued an order modifying the market monitoring and mitigation
plan adopted, effective on June 20, 2001 and extending until September 30, 2002,
to apply price controls to all hours, instead of just hours of low operating
reserve, and to extend the mitigation measures to other Western states in
addition to California, including Arizona, Colorado, Idaho, Montana, Nevada, New
Mexico, Oregon, Utah, Washington and Wyoming. The FERC set July 2, 2001 as the
refund effective date for sales subject to the price mitigation plan throughout
the West region. This means that transactions after that date may be subject to
refund if they exceed the proxy market clearing price calculated under the June
19 order, during periods of reserve deficiency. In non-reserve deficiency hours
in California, the maximum price in California and the other Western states will
be capped at 85% of the highest Cal ISO hourly market clearing price established
during the most recent reserve deficiency period. Effective July 11, 2002, the
FERC modified the proxy market clearing price to establish a fixed price cap of
$91.87/MWh. Sellers other than marketers will be allowed to bid higher than the
capped price, but such bids are subject to justification and potential refund.
Justification of higher prices is limited to demonstrating higher actual gas
costs than the gas price index used in the proxy price calculation together with
showing that conditions in natural gas markets changed significantly.
On December 19, 2001, the FERC issued additional orders on price mitigation
in California and the West region. These orders largely maintained existing
mitigation mechanisms, including the June 19, 2001 order's requirement that
generators must offer all available capacity for sale in the real-time market.
As a result of this requirement, the Company's opportunity to sell ancillary
services in the West region is reduced. During 2001, the Company recorded $42
million in revenues related to ancillary services in the West region.
On May 15, 2002, the FERC issued several orders clarifying and modifying its
mitigation measures. These orders removed the possibility that the Cal ISO would
retroactively adjust mitigated market clearing prices for 2001 and provided the
Cal ISO with further instructions for payment of minimum load costs owed to
sellers complying with the must offer obligation.
On July 17, 2002, FERC issued an order directing short-term and longer-term
redesign of the California wholesale electricity market. These new principles
will replace the market mitigation measures discussed above. Effective October
1, 2002, the July 17 order imposes a $250/MWh bid cap in place of existing price
controls, and implements automatic mitigation procedures that may be applied if
a bid is in excess of $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. A variation of this formula will
be used to cap bids in congested areas. The order also approves new penalties
for generators that operate outside of Cal ISO instructed quantities, and
extends the requirement that generators offer all available supply into the
California market, effective October 1, 2002. In addition, the July 17 order
instructs that the Cal ISO develop a day-ahead market for implementation January
1, 2003, and that the Cal ISO and California market participants work to develop
a capacity procurement
27
system for implementation as soon as possible. Other long-term aspects of the
redesign of the Cal ISO market remain open for consideration by FERC.
In a separate order issued July 17, 2002, FERC ordered that the current Cal
ISO Board of Governors be disbanded and replaced with an independent Board by
January 1, 2003. There are some indications that the Cal ISO Board will seek to
stay the FERC's order or otherwise resist this instruction from FERC.
As noted above, the mitigation plan allows sellers, such as the Company, to
justify prices above the proxy price. However, previous efforts by the Company
to justify prices above the proxy price have been rejected by the FERC and there
is no certainty that the FERC will allow for the recovery of costs above the
proxy price.
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 (these amounts may
be in addition to or in place of the refund amounts previously determined by the
FERC); and (c) the amount currently owed to each supplier. The amounts of any
refunds will be determined by the FERC after the conclusion of the hearing
process which is scheduled to conclude in August 2002. On December 19, 2001, the
FERC issued an order modifying the methodology to be used to determine refund
amounts. The schedule currently anticipates that the Administrative Law Judge
will make his refund amount recommendations to the FERC in October 2002.
However, the Company does not know when the FERC will issue its final decision.
Based on the FERC's May 15, 2002 order, the Company estimates its refund
obligation to be $49 million to $79 million for energy sales in the West region.
During the second quarter of 2002, the Company recorded an additional reserve
for refunds of $34 million related to energy sales in the West region based on
the May 15, 2002 order. As discussed above, $15 million was recognized in the
second quarter of 2001. As of June 30, 2002, the Company's total reserve for
refunds related to energy sales in the West region is $49 million. Refunds will
likely be offset against unpaid amounts owed to the Company for its prior sales.
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 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. On March 11,
2002, the FERC's Staff held a conference with market participants to discuss the
comments FERC has received, and possible modification of the proposed conditions
to address concerns raised in the comments while protecting consumers against
anticompetitive behavior. The timing of further action by 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
does not modify or reject its proposed approach for dealing with
anti-competitive behavior, the implementation of the refund obligation could
effect 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. While this order does
not propose any action against the Company, if the investigation results in
findings that markets were dysfunctional during this period, those findings may
be used in support of existing or future claims by the FERC or others that
prices for sales in the West region after January 1, 2000 should be altered. As
part of the investigation and in response to the disclosure of documents
describing certain electricity trading strategies used by Enron Power Marketing,
the FERC issued several requests for admissions and associated data to all
sellers of wholesale electricity and ancillary services in the Cal ISO and Cal
PX markets during the years 2000 through 2001, including the Company. The May 8,
2002 data request sought information concerning whether the Company and
approximately 150 other sellers used the same or similar trading strategies and
practices as described in the Enron documents. The May 21 data request sought
information concerning whether the Company and approximately 150 other sellers
engaged in "wash" or "round trip" sales of energy in the west. A May 22 data
request sought the same information from sellers of wholesale natural gas
regarding natural gas trades. The FERC has not yet publicly stated whether it
may assert that any of these strategies and practices was impermissible under
market rules in effect during the period in question. After reviewing records
and conducting internal interviews, the Company responded to the data requests
regarding the trading strategies and practices as described in the Enron
documents. The Company also responded to FERC's data requests regarding round
trip electricity and natural gas trades, including the identification of a round
trip electricity trade responsive to the FERC's data request. The Company has
provided
28
similar information to the California Senate Select Committee for its
investigation of price manipulation of the wholesale energy market.
The above-described lawsuits and proceedings regarding California
electricity sales are currently the subject of intense, highly-charged media and
political attention. Their ultimate outcome cannot be predicted at this time.
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 11(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.
Legislative Efforts. Since the inception of the California energy crisis,
various pieces of legislation, including tax proposals, have been introduced in
the U.S. 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, 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 on 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
29
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 as further discussed below.
Settlement of Stranded Cost Indemnification Agreement. Until December 2001,
the former shareholders were obligated to indemnify REPGB for up to 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 of NEA (excluding district heating).
Under the settlement agreement, the former shareholders 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 June 30, 2002, the escrow funds
equaled $65 million, of which $2 million and $63 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
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 August 9, 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, at the earliest, the fourth quarter of 2002.
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 the sum of (a) 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
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.
30
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 $619 million, cash
dividend to its shareholders, which was paid on July 1, 2002. REPGB's share of
the dividend was Euros 141 million, approximately $139 million. As of June 30,
2002, the dividend receivable from NEA was recorded in other current assets in
the Company's Consolidated Balance Sheet.
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 June 30, 2002,
the Company has recorded a liability of $155 million for its stranded cost gas
contract in non-trading derivative liabilities, an asset of $7 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 June 30, 2002, the Company has recorded
an indemnification receivable for the district heating stranded cost liability
of $206 million and $229 million, respectively.
Pursuant to SFAS No. 133, the Company marks-to-market the stranded cost gas
contract (see Note 3). 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 three and six months ended June 30, 2002, the
Company recognized a $3 million loss and net $16 million gain, respectively,
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.
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 full 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. Prior to the settlement agreement discussed above, pursuant to the
purchase agreement of REPGB, as amended, REPGB was entitled to a NLG 125 million
dividend from NEA with any remainder owing to the former shareholders.
31
(e) Payment to Reliant Energy in 2004.
To the extent the Company's affiliated retail electric provider's price to
beat mandated by the Texas electric restructuring law for providing retail
electric service to residential and small commercial customers in Reliant
Energy's Houston service territory during 2002 and 2003 exceeds the market price
of electricity, the Company may be required to make a payment to Reliant Energy
in early 2004. This payment will be required 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 Reliant Energy's Houston service territory is
committed to be served by retail electric providers other than the Company. If
the 40% test is not met and a payment is required, the amount of this payment
will be equal to the amount that the price to beat, less non-bypassable delivery
charges, is in excess of the prevailing market price of electricity during such
period multiplied by the applicable class consumption from January 1, 2002
through January 1, 2004. 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 Reliant Energy's
Houston service territory, less the number of new retail electric customers the
Company serves in other areas of Texas. As of June 30, 2002, Reliant Energy had
approximately 1.7 million residential and small commercial customers. In the
Master Separation Agreement between the Company and Reliant Energy, the Company
has agreed to make this payment, if any, to Reliant Energy. Currently, the
Company is unable to estimate the amount of such payment due to uncertainty
about market price of electricity and the market share that will be served by
the Company on January 1, 2004.
(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) of $1.9 billion of
which the last $515 million is currently available only if cash collateralized.
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, but the Company has generally limited its risk during
construction to an amount not in excess of 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 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. As of June 30, 2002, the special purpose
entities had property, plant and equipment of $1.0 billion, net other assets of
$90 million and debt obligations of $1.1 billion. As of June 30, 2002, the
special purpose entities had equity from unaffiliated third parties of $40
million.
The Company, through its subsidiary, REPG, has entered into an agreement
with a bank whereby the bank, as owner, entered or will enter into contracts for
the purchase and construction of power generation equipment and REPG, or its
subagent, acts as the bank's agent in connection with administering the
contracts for such equipment. Under the agreement, the bank has agreed to
provide up to a maximum aggregate amount of $650 million. REPG and its subagents
must cash collateralize their obligation to administer the contracts. This cash
collateral is approximately equivalent to the total payments by the bank for the
equipment, interest and other fees. As of June 30, 2002, the bank had assumed
contracts for the purchase of three turbines and two heat recovery steam
generators with an aggregate cost of $121 million. REPG, or its designee, has
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. All costs,
32
including the purchase commitment on the turbines, are the responsibility of
the bank. The cash collateral is deposited by REPG or the subagent into a
collateral account with the bank and earns interest at LIBOR less 0.15%. Under
certain circumstances, the collateral deposit or a portion of it, will be
returned to REPG or its designee. Otherwise, it will be retained by the bank. At
December 31, 2001 and June 30, 2002, REPG and/or its subagent had deposits of
$230 million and $92 million, respectively, in the collateral account. 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. While the remaining equipment is not
designated for current planned power generation construction projects, the
Company believes the equipment will be used in future projects. Therefore, the
Company anticipates that it will purchase the equipment, but can also assist in
the remarketing of the equipment or negotiate to cancel the related contracts.
(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 June 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.
(12) BENEFIT CURTAILMENT AND ENHANCEMENT CHARGE
During the six months ended June 30, 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
Reliant Energy.
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 expects to incur a loss of $57 million (pre-tax)
related to the settlement of Reliant Energy's pension plan and non-qualified
pension plans.
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 Company expects to incur a pre-tax gain of
$21 million related to the 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 which are incorporated by reference
herein.
(13) 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 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%
33
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 also 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. Unless the Texas
Utility Commission convenes a special meeting, the earliest a new price to beat
could go into effect would be after August 23, 2002, the date of the Texas
Utility Commission's next normally scheduled meeting.
(14) REPORTABLE SEGMENTS
The Company's determination of reportable segments considers the strategic
operating units under which the Company manages sales, allocates resources and
assesses performance of various products and services to wholesale or retail
customers. The Company has identified 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 six months ended June 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.
Financial data for business segments are as follows:
FOR THE THREE MONTHS ENDED JUNE 30, 2001
-------------------------------------------
REVENUES OPERATING
FROM INCOME
NON-AFFILIATES (LOSS) EBIT
-------------- ---------- ------
(IN MILLIONS)
Wholesale Energy ............... $7,660 $ 297 $ 298
European Energy ................ 276 9 62
Retail Energy .................. 36 (3) (2)
Other Operations ............... 3 (10) (5)
------ ----- -----
Consolidated ................... $7,975 $ 293 $ 353
====== ===== =====
FOR THE THREE MONTHS ENDED JUNE 30, 2002
------------------------------------------
REVENUES
FROM OPERATING
NON-AFFILIATES INCOME EBIT
-------------- ---------- ------
(IN MILLIONS)
Wholesale Energy ................. $6,495 $ 23 $ 31
European Energy .................. 641 103 105
Retail Energy .................... 1,425 205 205
Other Operations ................. -- 2 3
------ ---- ----
Consolidated ..................... $8,561 $333 $344
====== ==== ====
34
Reconciliation of Operating Income to EBIT and EBIT to Net Income:
FOR THE THREE MONTHS ENDED
JUNE 30,
--------------------------
2001 2002
------- ------
(IN MILLIONS)
Operating income ........................................... $ 293 $ 333
Gains from investments, net ................................ 4 2
Income of equity investment of unconsolidated subsidiaries.. 52 6
Other income, net .......................................... 4 3
----- -----
EBIT ....................................................... 353 344
Interest expense ........................................... (19) (67)
Interest income ............................................ 4 4
Interest income -- affiliated companies .................... 11 2
----- -----
Income before income taxes ................................. 349 283
Income tax expense ......................................... 120 105
----- -----
Net income ................................................. $ 229 $ 178
===== =====
FOR THE SIX MONTHS ENDED JUNE 30, 2001 AS OF
-------------------------------------- DECEMBER 31,
REVENUES OPERATING 2001
FROM INCOME ------------
NON-AFFILIATES (LOSS) EBIT TOTAL ASSETS
-------------- --------- --------- ------------
(IN MILLIONS)
Wholesale Energy ........ $16,020 $ 513 $ 527 $ 8,290
European Energy ......... 524 28 83 3,380
Retail Energy ........... 63 (7) (5) 391
Other Operations ........ 6 (127) (115) 599
Eliminations ............ -- -- -- (368)
------- ----- ----- --------
Consolidated ............ $16,613 $ 407 $ 490 $ 12,292
======= ===== ===== ========
FOR THE SIX MONTHS ENDED JUNE 30, 2002 AS OF
--------------------------------------- JUNE 30,
REVENUES OPERATING 2002
FROM INCOME ------------
NON-AFFILIATES (LOSS) EBIT TOTAL ASSETS
-------------- --------- --------- ------------
(IN MILLIONS)
Wholesale Energy ........ $12,009 $ 130 $ 145 $ 14,195
European Energy ......... 1,176 119 123 3,561
Retail Energy ........... 2,404 254 254 1,754
Other Operations ........ 2 (4) (5) 474
Eliminations ............ -- -- -- (353)
------- ----- ----- --------
Consolidated ............ $15,591 $ 499 $ 517 $ 19,631
======= ===== ===== ========
Reconciliation of Operating Income to EBIT and EBIT to Net Income:
FOR THE SIX MONTHS
ENDED JUNE 30,
----------------------
2001 2002
---- -----
(IN MILLIONS)
Operating income ............................................ $ 407 $ 499
Gains from investments, net ................................. 11 4
Income of equity investment of unconsolidated subsidiaries .. 65 10
Other income, net ........................................... 7 4
----- -----
EBIT ........................................................ 490 517
Interest expense ............................................ (44) (106)
Interest income ............................................. 15 8
Interest (expense)/income -- affiliated companies ........... (3) 4
----- -----
Income before income taxes and cumulative effect of
accounting change ......................................... 458 423
Income tax expense .......................................... 151 148
Cumulative effect of accounting change ...................... 3 --
----- -----
Net income .................................................. $ 310 $ 275
===== =====
35
(15) SUBSEQUENT EVENTS
(a) 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, a maximum of $250 million can be sold from a
designated pool. The term of the Receivables Facility is one year and may be
renewed at the Company's option and the option of the financial institutions
participating in the Receivables Facility. The Company received net proceeds in
an initial amount of $230 million. The amount of funding available to the
Company under the Receivables Facility will fluctuate based on the amount of
receivables available. 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 institutions. Pursuant
to the Receivables Facility, the Company formed a qualified special purpose
entity (QSPE), a bankruptcy remote subsidiary. The QSPE was formed for the sole
purpose of buying and selling receivables generated by the Company. The Company,
irrevocably and without recourse, will transfer receivables to the QSPE. The
QSPE, in turn, will sell an undivided interest in these receivables to the
participating financial institutions. The Company is not ultimately liable for
any failure of payment of the obligors on the receivables. The Company has,
however, guaranteed the obligations of the sellers and the servicer of the
receivables under the related documents.
The two-step transaction 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 will be excluded from the Consolidated Balance Sheet. Costs
associated with the sale of receivables, primarily the discount and loss on
sale, will be included in other expense in the Company's Statement of
Consolidated Income.
(b) 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 $248 million) to Euro 184 million (approximately $182 million).
An option was added that permits REPGB to utilize up to Euro 100 million of the
facility for letters of credit. The revolving credit facility bears interest at
the rate of EURIBOR plus a margin depending on REPGB's credit rating. As of
August 9, 2002, the facility bears interest at an annual rate of 4.77%. 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 the Company from borrowing funds or obtaining
letters of credit, as applicable, under this facility.
(c) Credit Ratings.
Credit ratings impact the Company's ability to obtain short- and long-term
financing, the cost of such financing and the execution of its commercial
strategies. As of August 9, 2002, the Company's credit ratings for its senior
unsecured debt were as follows:
DATE ASSIGNED RATING AGENCY RATING
- ------------- ------------- ------
July 31, 2002 Moody's(1) Ba3, review for potential downgrade
August 7, 2002 Fitch (2) BBB-, rating watch negative
July 31, 2002 Standard & Poor's(3) BBB-, credit watch with negative
implications
- ------------
(1) On July 31, 2002, Moody's downgraded the issuer rating and bank loan ratings
assigned to the Company to Ba3 from Baa3 and assigned a senior implied
rating of Ba3. Moody's stated in its press release that the Company's
downgrade reflects Moody's view that the Company's cash flow from operations
is unpredictable relative to the Company's debt load and its financial
flexibility is limited. Going forward, the review for downgrade will focus
on: 1) the timing for stabilization of cash flow in the Company's Wholesale
Energy segment; 2) the Company's ability to refinance its bank debt and the
terms of such refinancings; 3) the resolution of various government
investigations into trading improprieties, including round trip trades; and
4) the Company's ability to execute its business plan including the
implementation of cost cutting measures.
36
(2) On August 7, 2002, Fitch downgraded the Company's senior unsecured debt
rating to BBB- from BBB. The ratings remain on rating watch negative. The
rating action reflects the Company's reduced financial flexibility and the
substantial debt refinancing burden the Company faces over the next several
months.
(3) On July 31, 2002, Standard & Poor's lowered the Company's corporate credit
ratings and those of its rated subsidiaries to BBB- from BBB. The ratings
remain on credit watch with negative implications. Standard & Poor's stated
in its press release that the ratings action reflects the Company's
downgrade by another rating agency to non-investment grade, and the
increased collateral calls that will be triggered by this action.
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. 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 an
additional 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 requirement for security
and other terms that are typically imposed on split-rated or sub-investment
grade borrowers.
The Company has commercial arrangements that have been adversely impacted by
its recent downgrade to sub-investment grade by Moody's. The Company also has
numerous commercial arrangements that would be further adversely impacted in the
event of any downgrades to sub-investment grade by Fitch or Standard & Poor's.
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; (b) certain Texas Utility Commission
requirements related to the credit strength of retail electric providers in the
State of Texas; and (c) 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 provides credit
support to the counterparties in the form of a pledge of cash collateral, a
letter of credit or other similar credit support. In some instances, if the
Company's credit ratings decline below certain credit rating thresholds, its
trading partners and other commercial counterparties may refuse to trade with
the Company or trade only on terms less favorable to the Company. In addition,
certain of the Company's retail electricity contracts with large commercial,
industrial and institutional customers of the Retail Energy segment provide the
customers the ability to terminate their contract early if the Company's
unsecured debt ratings fall below investment grade or if its investment grade
ratings are withdrawn entirely by a rating agency.
The Company is working with its various commercial counterparties so as to
minimize their possible demands for credit support and in order to minimize the
disruption to the Company's normal commercial activities. In addition, the
Company has been working with many counterparties to reduce the magnitude of the
collateral the Company must post in support of its obligations to such
counterparties.
As of August 9, 2002, the Company has posted cash collateral and letters of
credit in support of various obligations in the amount of $263 million and $350
million, respectively. These relate primarily to commercial activities in the
Company's wholesale and retail businesses. The Company expects these collateral
requirements to grow, and, in the event that Standard & Poor's were to reduce
the credit rating of the Company to below investment grade, management estimates
that the Company would post additional credit support (cash and letters of
credit) of up to approximately $570 million over time, excluding the effects of
commodity price volatility. As of August 9, 2002, the Company had $1.2 billion
in unrestricted available cash and short-term investments and $18.8 million
available under committed corporate credit facilities of the Company. These
amounts are available to meet the possible future requirements for credit
support related to the Company's credit ratings.
37
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EFFECTS OF RESTATEMENT ON THE INTERIM FINANCIAL STATEMENTS FOR THE
THREE AND SIX MONTHS ENDED JUNE 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, which 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 of each of the Board of
Directors of Reliant Resources and Reliant Energy, Incorporated (Reliant
Energy), a diversified international energy services and energy delivery company
that owns approximately 83% of Reliant Resources outstanding common stock,
(Audit Committees) 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.
We report 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 41 MWh of power and 46 billion cubic
feet (Bcf) of natural gas and 46 Bcf of natural gas for the three and six months
ended June 30, 2001, respectively.
These transactions, referred to above, collectively had the effect of
increasing revenues, fuel and cost of gas sold expense and purchased power
expense by $1.4 billion, $131 million and $1.3 billion, respectively, for the
three months ended June 30, 2001 and by $2.6 billion, $131 million and $2.5
billion, respectively, for the six months ended June 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 $17 million and $19 million for
the three and six months ended June 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 six months ended June 30, 2001
were previously recorded on a gross basis with such transactions being reported
in revenues and expenses which resulted in $323 million of revenues, $161
million in fuel and cost of gas sold and $162 million of purchased power expense
being recognized in each period. Having further reviewed the transactions, we
now believe these transactions should have been accounted for on a net basis.
The consolidated financial statements for the three and six months ended
June 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.
38
The following discussion and analysis should be read in combination with our
Interim Financial Statements contained in this Form 10-Q.
OVERVIEW
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 14 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 5 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. As part of its business separation plan, Reliant Energy has
publicly disclosed that it intends to restructure its corporate organization
into a public utility holding company structure (Reorganization) by August 31,
2002 and to distribute, subject to further corporate approvals, market and other
conditions, all of the shares of Reliant Resources common stock that it owns to
its shareholders (Distribution) early in the fall of 2002. In December 2001,
Reliant Energy's shareholders voted to approve the merger required for the
holding company reorganization. Reliant Energy has publicly disclosed its goal
to complete the Reorganization and subsequent Distribution as quickly as
possible after all the necessary conditions are fulfilled. In July 2002, Reliant
Energy received an order from the Securities and Exchange Commission (SEC)
granting the required approvals under the Public Utility Holding Company Act of
1935 (1935 Act) to adopt a new holding company structure and allow it to
complete the Distribution. Also in July 2002, Reliant Energy received a
supplemental ruling from the IRS which confirms that the Distribution will be
tax-free to Reliant Energy and its shareholders. There can be no assurances that
the Distribution will be completed as described or within the time period
outlined above.
We may experience changes in our cost structure, funding and operations as a
result of our separation from Reliant 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.
The following table provides summary data regarding our consolidated results
of operations for the three and six months ended June 30, 2001 and 2002.
39
CONSOLIDATED RESULTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2001 2002 2001 2002
------ ------- ------- --------
(IN MILLIONS)
Operating Revenues ....................... $7,975 $ 8,561 $16,613 $ 15,591
Operating Expenses ....................... 7,682 8,228 16,206 15,092
------ ------- ------- --------
Operating Income ......................... 293 333 407 499
Other Income (Expense), net .............. 56 (50) 51 (76)
Income Tax Expense ....................... 120 105 151 148
------ ------- ------- --------
Income Before Cumulative Effect of
Accounting Change ...................... 229 178 307 275
Cumulative Effect of Accounting Change,
net of tax ............................. -- -- 3 --
------ ------- ------- --------
Net Income ............................... $ 229 $ 178 $ 310 $ 275
====== ======= ======= ========
Basic Earnings Per Share ................. 0.83 0.62 1.20 0.95
====== ======= ======= ========
Diluted Earnings Per Share ............... 0.82 0.61 1.20 0.95
====== ======= ======= ========
Three months ended June 30, 2001 compared to three months ended June 30, 2002
Net Income. We reported consolidated net income of $229 million ($0.82
per diluted share) for the three months ended June 30, 2001 compared to $178
million ($0.61 per diluted share) for the three months ended June 30, 2002. The
decrease in earnings was primarily due to the following:
- a $267 million decrease in earnings before interest and income
taxes (EBIT) from our Wholesale Energy segment; and
- a $57 million increase in net interest expense.
The above items were partially offset by:
- a $207 million increase in EBIT from our Retail Energy segment;
and
- a $43 million increase in EBIT from our European 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 $4 million during
the three months ended June 30, 2001 compared to $61 million in the same period
of 2002. The increase in net interest expense of $57 million in 2002 as compared
to 2001 resulted primarily from a $48 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 $9 million decrease in interest income from affiliated
companies as a result of decreased excess cash being invested with a subsidiary
of Reliant Energy during the three months ended June 30, 2002 as compared to the
same period in 2001.
Income Tax Expense. During the three months ended June 30, 2001 and 2002,
our effective tax rate was 34% and 37%, respectively. The increase in the
effective tax rate from three months ended June 30, 2001 compared to the three
months ended June 30, 2002 was primarily due to the expiration of the Dutch tax
holiday related to the earnings of REPGB and an adjustment to the European
Energy segment's effective tax rate in the second quarter of 2002, partially
offset by the utilization of a valuation allowance by our Canadian operations in
2002 and a decrease in state income taxes. In 2001, the earnings of REPGB were
subject to a zero percent Dutch corporate income tax rate as a result of the
Dutch tax holiday related to the Dutch electricity industry. In 2002, European
Energy's earnings in the Netherlands is subject to the standard Dutch corporate
income tax rate, which is currently 34.5%.
Six months ended June 30, 2001 compared to six months ended June 30, 2002
Net Income. We reported consolidated net income of $310 million ($1.20
per share) for the six months ended June 30, 2001 compared to $275 million
($0.95 per share) for the six months ended June 30, 2002. The 2001 results
included a cumulative effect of accounting change of $3 million, net of tax,
related to the adoption of Statement of
40
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 which is incorporated by reference herein. The decrease
in earnings was primarily due to the following:
- a $382 million decrease in EBIT from our Wholesale Energy segment; and
- a $62 million increase in net interest expense.
The above items were partially offset by:
- a $259 million increase in EBIT from our Retail Energy segment;
- a $40 million increase in EBIT from our European Energy segment; and
- a $100 million pre-tax, non-cash charge incurred in the first quarter
of 2001 relating to the redesign of some of Reliant Energy's benefit
plans in anticipation of our separation from Reliant Energy.
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 $32 million during
the six months ended June 30, 2001 compared to $94 million in the same period of
2002. The increase in net interest expense of $62 million in 2002 as compared to
2001 resulted primarily from a $62 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 $7 million decrease in interest income as a result of
decreased margin deposits on energy trading and hedging activities. This
increase was partially offset by a $7 million decrease in interest expense on
debt owed to affiliated companies in the first six months of 2002 as compared to
the first six months of 2001, primarily due to the conversion into equity of
$1.7 billion of debt owed to Reliant Energy and its subsidiaries in connection
with the completion of the IPO in May 2001, and increased interest income in the
six months ended June 30, 2002 from the advancement of excess cash to a
subsidiary of Reliant Energy.
Income Tax Expense. During the six months ended June 30, 2001 and 2002, our
effective tax rate was 33% and 35%, respectively. The increase in the effective
tax rate from six months ended June 30, 2001 compared to the six months ended
June 30, 2002 was primarily due to the expiration of the Dutch tax holiday
related to the earnings of REPGB, partially offset by a decrease in state income
taxes.
As discussed in Note 13(f) to the Reliant Resources 10-K/A Notes which is
incorporated by reference herein, and Note 11(d) to our Interim Financial
Statements, the Dutch parliament has adopted legislation allocating to the Dutch
generation sector, including REPGB, financial responsibility for certain
stranded costs and other liabilities incurred by NEA prior to the deregulation
of the Dutch wholesale market. These obligations include NEA's obligations under
an out-of-market gas supply contract and three out-of-market electricity
contracts. REPGB's allocated share of these liabilities is 22.5%. As a result,
we recorded a net stranded cost liability of $369 million and a related deferred
tax asset of $127 million at December 31, 2001 for our statutorily allocated
share of these gas supply and electricity contracts. Prior to the second quarter
of 2002, we believed that the costs incurred by REPGB subsequent to the tax
holiday ending in 2001 related to these contracts would be deductible for Dutch
tax purposes. However, due to uncertainties related to the deductibility of
these costs, we recorded an offsetting liability in other liabilities in our
consolidated financial statements of $127 million as of December 31, 2001. We
now believe, based upon discussions with the Dutch tax authorities, obtaining a
tax deduction for these costs will require litigation in the Netherlands, and
accordingly, we reversed both the deferred tax assets and related liability in
the second quarter of 2002.
EARNINGS BEFORE INTEREST AND INCOME TAXES BY BUSINESS SEGMENT
The following table presents EBIT for each of our business segments for the
three and six months ended June 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
41
it in the same fashion. For a reconciliation of our operating income to EBIT and
EBIT to net income, please read Note 14 to our Interim Financial Statements.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ------------------
2001 2002 2001 2002
----- ---- ----- -----
(IN MILLIONS)
Wholesale Energy .................. $ 298 $ 31 $ 527 $ 145
European Energy ................... 62 105 83 123
Retail Energy ..................... (2) 205 (5) 254
Other Operations .................. (5) 3 (115) (5)
----- ---- ----- -----
Total Consolidated .......... $ 353 $344 $ 490 $ 517
===== ==== ===== =====
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. Trading and marketing purchases
fuel to supply existing generation assets, sells the electricity produced by
these assets, and manages the day-to-day trading and dispatch associated with
these portfolios.
We are in the process of evaluating our trading, marketing, power
origination and risk management services strategies. In the future, we may
reduce our trading, marketing and origination activities, which would likely
result in a corresponding decrease in earnings and cash flows.
For 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, which is incorporated
herein by reference.
The following table provides summary data, including EBIT, of Wholesale
Energy for the three and six months ended June 30, 2001 and 2002.
WHOLESALE ENERGY
------------------------------------------------------
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
--------------------------- -------------------------
2001 2002 2001 2002
------- ------- -------- --------
(IN MILLIONS)
Operating Revenues .......................... $ 7,660 $ 6,495 $ 16,020 $ 12,009
Operating Expenses:
Fuel and Cost of Gas Sold ................. 3,952 3,990 9,606 6,543
Purchased Power ........................... 3,239 2,141 5,553 4,775
Operation and Maintenance ................. 86 143 157 246
General, Administrative and Development ... 66 115 130 182
Depreciation and Amortization ............. 20 83 61 133
------- ------- -------- --------
Total Operating Expenses ................. 7,363 6,472 15,507 11,879
------- ------- -------- --------
Operating Income ............................ 297 23 513 130
------- ------- -------- --------
Other Income:
Income of equity investment of
unconsolidated subsidiaries ............... 1 6 14 10
Gains from investments ...................... -- 1 -- --
Other, net .................................. -- 1 -- 5
------- ------- -------- --------
Earnings Before Interest and Income Taxes ... $ 298 $ 31 $ 527 $ 145
======= ======= ======== ========
Operations Data:
Electricity Wholesale Power Sales
(in thousand MWh(1)) ..................... 61,267 74,830 114,478 166,303
Natural Gas Sales (in Bcf(2)) ............. 720 1,077 1,444 2,028
- --------------
(1) Million megawatt hours.
(2) Billion cubic feet.
42
Wholesale Energy's EBIT decreased by $267 million for the three months ended
June 30, 2002 compared to the same period in 2001. The decline in EBIT is
primarily due to decreases in gross margin (revenues less fuel and cost of gas
sold and purchased power), and increases in operating expenses both of which are
discussed, in detail below. In addition, Wholesale Energy's EBIT was impacted by
a $34 million reserve recorded during the three months ended June 30, 2002 for
refunds owed by the Company as a result of a May 15, 2002 Federal Energy
Regulatory Commission (FERC) order which revised the methodology for calculating
refunds for California energy sales. During the same period in 2001, Wholesale
Energy recorded a $15 million reserve related to an earlier FERC order.
Wholesale Energy's EBIT decreased by $382 million for the six months ended
June 30, 2002 compared to the same period in 2001. The decrease in EBIT is
primarily due to decreases in gross margin, increases in operating expenses, and
recording of a reserve for potential refunds in the second quarter of 2002, as
discussed above. These decreases in EBIT were partially offset by changes in the
credit provisions related to energy sales in California. In the six months ended
June 30, 2002, $38 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 coupled with a determination that
credit risk had been reduced on the remaining outstanding receivables as a
result of payments in 2002 to the California Power Exchange. In addition, during
the six months ended June 30, 2001, Wholesale Energy recorded a $34 million
credit provision against receivable balances related to energy sales in the West
and a $15 million reserve for refunds, as discussed above.
Wholesale Energy's revenues decreased by $1.2 billion (15%) in the three
months ended June 30, 2002 compared to the same periods in 2001. The decreased
revenues were primarily due to decreased prices for natural gas sales
(approximately $1.7 billion) and decreased prices for power sales (approximately
$2.2 billion) compared to the same period in 2001. These decreases in prices
were partially offset by increased volumes for natural gas and power of sales
approximately $1.8 billion and $0.9 billion, respectively. Wholesale Energy's
fuel and cost of gas sold and purchased power decreased by $1.1 billion in the
three months ended June 30, 2002, largely due to decreased prices for natural
gas and purchased power compared to the same period in 2001. These decreases in
fuel and cost of gas sold and purchased power were partially offset by increased
volumes for natural gas and purchased power, and increased fuel expense due to a
171% increase in power generation sales volumes largely due to the Orion Power
acquisition that closed in February 2002.
Wholesale Energy's revenues decreased by $4.0 billion (25%) in the six
months ended June 30, 2002 compared to the same period in 2001. The decreased
revenues were primarily due to decreased prices for natural gas sales
(approximately $6.3 billion) and decreased prices for power sales (approximately
$4.6 billion) compared to 2001. These decreases in revenues were partially
offset by increased volumes for natural gas and power sales of approximately
$3.6 billion and $3.2 billion, respectively. Wholesale Energy's fuel and cost of
gas sold and purchased power decreased by $3.8 billion in the six months ended
June 30, 2002, largely due to the same factors discussed above.
Wholesale Energy's gross margin decreased by $105 million in the three
months ended June 30, 2002 compared to the same period in 2001. This decrease
was primarily due to lower margins from both our power generation operations and
our trading and marketing activities, and a $19 million increase in reserves
related to potential refunds related to energy sales in the West in the second
quarter 2002 as compared to the same period in 2001 as discussed above. Margins
on power sales from our generation facilities, decreased by $193 million
partially offset by $177 million from the Orion Power acquisition that closed in
February 2002. Wholesale Energy's gross margin for the three months ended June
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. The absence of these market
conditions over the same period in 2002 resulted in a 65% decrease in prices and
58% decrease in volumes for power sales in the West. Trading and marketing gross
margins decreased $70 million from $119 million in the three months ended June
30, 2001 to $49 million in the three months ended June 30, 2002 compared to the
same period in 2001, primarily as a result of higher natural gas and power
volatility levels in the three months ended June 30, 2001 provided for greater
trading opportunities compared to the three months ended June 30, 2002,
particularly in the West.
Wholesale Energy's gross margin decreased by $170 million in the six months
ended June 30, 2002 compared to the same period in 2001. This decrease was
primarily due to lower margins from both our power generation operations and our
trading and marketing activities, and a $19 million increase in reserves related
to potential refunds related to energy sales in the West, as discussed above.
These factors were partially offset by a $72 million change in the credit
provision for California energy sales, as discussed above. Margins on power
sales from our generation facilities decreased by $353 million. This decrease
was partially offset by $264 million of margins on power sales from the Orion
Power acquisition that closed in February 2002. Trading and marketing gross
margins
43
decreased $134 million from $231 million in the six months ended June 30, 2001
to $97 million in the six months ended June 30, 2002 compared to the same period
in 2001 primarily as a result of higher natural gas and power volatility levels
in the six months ended June 30, 2001 which provided for greater trading
opportunities compared to the six months ended June 30, 2002.
The following table provides further summary data regarding gross margins by
commodity of Wholesale Energy for the three and six months ended June 30, 2001
and 2002.
WHOLESALE ENERGY
--------------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- --------------------
2001 2002 2001 2002
------ ------ ------- -------
(IN MILLIONS)
Gas revenues ...................... $3,708 $3,859 $ 8,997 $ 6,341
Power revenues .................... 3,928 2,620 6,983 5,648
Other commodity revenues .......... 24 16 40 20
------ ------ ------- -------
Total revenues .................. 7,660 6,495 16,020 12,009
------ ------ ------- -------
Cost of gas sold .................. 3,628 3,809 8,838 6,238
Fuel and purchased power .......... 3,545 2,310 6,294 5,063
Other commodity costs ............. 18 12 27 17
------ ------ ------- -------
Total cost of sales ............. 7,191 6,131 15,159 11,318
------ ------ ------- -------
Gross margin .................... $ 469 $ 364 $ 861 $ 691
====== ====== ======= =======
Operation and maintenance expenses for Wholesale Energy increased $57
million in the three months ended June 30, 2002 compared to the same period in
2001, primarily due to $62 million of operation and maintenance expenses of our
Orion Power generating plants acquired in February 2002. General, administrative
and development expenses increased $49 million in the three months ended June
30, 2002 compared to the same period in 2001, primarily due to higher
administrative costs to support growing wholesale commercial activities,
including Orion Power, and 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.
Operation and maintenance expenses for Wholesale Energy increased $89
million in the six months ended June 30, 2002 compared to the same period in
2001, primarily due to $95 million of operation and maintenance expenses of our
Orion Power generating plants. General, administrative and development expenses
increased $52 million in the six months ended June 30, 2002 compared to the same
period in 2001, primarily due to higher administrative costs to support growing
wholesale commercial activities, including Orion Power, and increased expenses
related to development activities of $26 million, which includes write-offs of
$17 million as discussed above.
Depreciation and amortization expense increased by $63 million in the three
months ended June 30, 2002 compared to the same period in 2001 primarily as a
result of depreciation expense related to our Orion Power plants, and other
generating plants placed into service during the second half of 2001 and a $15
million write-off of a plant which we expect to close during the third quarter
of 2002. For the three months ended June 30, 2001, Wholesale Energy recorded $1
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, which is incorporated by reference herein, and Note 6 to
our Interim Financial Statements.
Depreciation and amortization expense increased by $72 million in the six
months ended June 30, 2002 compared to the same period in 2001 primarily as a
result of depreciation expense related to our Orion Power plants, other
generating plants placed into service during the second half of 2001 and the
plant closure as discussed above, partially offset by a decrease in amortization
of air emissions regulatory allowances of $20 million. For the six months ended
June 30, 2001, Wholesale Energy recorded $2 million in amortization expense
related to goodwill.
Our Wholesale Energy segment reported income from equity investments for the
three and six months ended June 30, 2002 of $6 million and $10 million,
respectively, compared to $1 million and $14 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 increased during the three months
ended June 30, 2002 compared to the same period in 2001, primarily due to the
receipt of business interruption and other insurance claims totaling $12
million, partially offset by decreases in margins due to lower prices realized
by the project company in 2002. The equity income related to our investment in
the plant decreased during the six months ended June 30, 2002 compared to the
same period in 2001, primarily due to decreases in
44
margins as a result of lower prices realized by the project company in 2002,
partially offset by the insurance claims received during the second quarter of
2002 as discussed above.
For information regarding the reserves against receivables, FERC refund
methodology and uncertainties in the California wholesale energy market, please
read Notes 11(a) and 11(c) to our Interim Financial Statements.
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.
We are in the process of evaluating our trading and power origination
strategies in Europe. In the future, we may reduce our trading and origination
activities in order to concentrate on our core power generation asset position
in the Netherlands.
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, which is incorporated
herein by reference.
The following table provides summary data, including EBIT, of European
Energy for the three and six months ended June 30, 2001 and 2002.
EUROPEAN ENERGY
----------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- -----------------
2001 2002 2001 2002
---- ---- ---- ------
(IN MILLIONS)
Operating Revenues .......................... $276 $641 $524 $1,176
Operating Expenses:
Fuel ...................................... 102 107 203 187
Purchased Power ........................... 116 381 197 772
Operation and Maintenance ................. 19 32 38 63
General, Administrative and Development ... 11 4 20 8
Depreciation and Amortization ............. 19 14 38 27
---- ---- ---- ------
Total Operating Expenses ................. 267 538 496 1,057
---- ---- ---- ------
Operating Income ............................ 9 103 28 119
---- ---- ---- ------
Other Income:
Income of equity investment of
unconsolidated subsidiaries ............... 51 -- 51 --
Other, net .................................. 2 2 4 4
---- ---- ---- ------
Earnings Before Interest and Income Taxes ... $ 62 $105 $ 83 $ 123
==== ==== ==== ======
Electricity (in thousand MWh):
Wholesale Sales......................... 3,743 4,376 7,308 8,941
Trading Sales........................... 5,936 19,474 8,954 34,553
European Energy's EBIT increased $43 million and $40 million for the three
and six months ended June 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 three months ended June 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 power expense
and is included in gross margins. For additional discussion regarding the
amendment of these contracts please read Note 11(d) to our Interim Financial
Statements.
European Energy's operating revenues increased $365 million for the three
months ended June 30, 2002 compared to the same period in 2001. Approximately
$345 million of the increase was attributable to increased trading volumes
associated with our participation in the Dutch, German, Austrian, United Kingdom
and Nordic power markets, and to a lesser extent, the increase was due to a 17%
increase in volume of electric generation sales representing an approximate $11
million net increase in sales in the second quarter of 2002 as compared to the
same period in 2001. The increase in electric sales revenues as a result of
increased sales volumes was partially offset by decreases in power prices of
approximately 7% in the second quarter of 2002 as compared to the same period in
45
2001. The overall increases were also partially offset by the impact of a $30
million efficiency and energy payment received during the second quarter of 2001
from NEA, which was the coordinating body for the Dutch electric generating
sector prior to wholesale competition. Also contributing to the increase in
operating revenues was a favorable foreign exchange effect of approximately $40
million.
European Energy's operating revenues increased $652 million for the six
months ended June 30, 2002 compared to the same period in 2001. Revenues derived
from trading volumes associated with our participation in the Dutch, German,
Austrian, United Kingdom and Nordic power markets, increased approximately $678
million. In addition, and to a lesser extent, the increase in revenues was due
to a 22% increase in volume of electric generation sales representing an
approximate $24 million net increase in sales for the six months ended June 30,
2002 compared to the same period in 2001. The increase in electric sales
revenues as a result of increased sales volume was partially offset by decreases
in power prices that decreased approximately 10% in the six months ended June
30, 2002 as compared to the same period in 2001. The overall increases were also
offset by a $30 million efficiency and energy payment received during the second
quarter of 2001 from NEA as described above. In addition, ancillary services
revenues decreased approximately $7 million period on period. This overall
increase in operating revenues was impacted by an unfavorable foreign exchange
effect of approximately $13 million.
Fuel and purchased power costs increased $270 million for the three months
ended June 30, 2002 compared to the same period in 2001 primarily due to a $343
million increase in purchased power for trading activities associated with the
growth in our trading business. Offsetting the increase was a one-time $109
million gain recognized as a result of the amendment of our stranded cost
electricity supply contracts which is recorded as a reduction of purchased power
expense. For additional discussion regarding the amendment of these contracts
please read Note 11(d) to our Interim Financial Statements. The overall increase
in fuel and purchased power was impacted by an unfavorable foreign exchange
effect of approximately $37 million.
Fuel and purchased power costs increased $559 million for the six month
period ending June 30, 2002 compared to the same period in 2001 primarily due to
a $693 million increase in purchased power for trading activities associated
with the growth in our trading business. Offsetting this increase was 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 six
months of 2002 recorded in fuel expense. 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 11(d) to our Interim Financial Statements. The overall
increase in fuel and purchased power was impacted by a favorable foreign
exchange effect of approximately $11 million.
Gross margin increased $95 million for the three months ended June 30, 2002
compared to the same period in 2001 primarily due to (a) the one-time $109
million gain discussed above, (b) a $2 million increase in trading and power
origination gross margins which increased from $2 million for the three months
ended June 30, 2001 to $4 million for the same period in 2002 due to an increase
in power trading volumes and trading origination transactions, and (c) a $15
million increase in plant margins due to increases in electric sales volumes and
decreased fuel prices. Offsetting the above increases was a $30 million
efficiency and energy payment received during the second quarter of 2001 from
NEA. In addition, in the three months ended June 30, 2002, a net $3 million loss
was recognized related to changes in the valuation of certain out-of-market
contracts.
Gross margin increased $93 million for the six months ended June 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, (c) a $4 million increase in trading and power
origination gross margins which increased from $3 million for the six months
ended June 30, 2001 to $7 million for the same period in 2002 due to an increase
in power trading volumes and trading origination transactions, and (d) a $5
million increase in plant margins due to increases in electric sales volumes and
decreased fuel prices. Offsetting these increases were the $30 million payment
received during the second quarter of 2001 from NEA, and decreased margins on
ancillary services of $4 million. Further offsetting the increase in gross
margin were unscheduled plant outages at certain of our electric generating
facilities in the first six months of 2002. We estimate that these unplanned
outages resulted in a net decrease in gross margin of approximately $7 million.
Operation and maintenance and general and administrative expenses increased
by $6 million for the three months ended June 30, 2002 compared to the same
period in 2001. The increase was primarily attributable to increased consulting
fees and employee benefit expenses, as well as increased expenses associated
with overall trading business growth, primarily stemming from our United Kingdom
operations, which began in July 2001.
46
Operation and maintenance and general and administrative expenses increased
by $13 million for the six months ended June 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 $5 million during the
second 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 June 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 6 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 $11 million for the six
months ended June 30, 2002 compared to the same period in 2001 primarily due to
the cessation of goodwill amortization effective January 1, 2002. During the six
months ended June 30, 2001, European Energy recorded $13 million in amortization
expense related to goodwill. This decrease was partially offset by an increase
of $2 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 decreased $51 million during the three and six
months ended June 30, 2002 compared to the same periods in 2001 due to a $51
million gain recorded in the three months ended June 30, 2001, as equity income
for the preacquisition gain contingency 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 11(d) to
our Interim Financial Statements.
RETAIL ENERGY
Our Retail Energy segment provides energy products and services to end-use
customers, ranging from residential and small commercial customers to large
commercial, industrial and institutional customers. In addition, Retail Energy
provided billing, customer service, credit and collection and remittance
services to Reliant 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 acquired approximately
1.7 million electric retail customers in the Houston metropolitan area when the
Texas market opened to full competition in January 2002. During the first half
of 2002, the Texas electric retail market was largely focused on the extensive
efforts necessary to transition customers from the utilities to the affiliated
retail electric providers.
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, which is incorporated
herein by reference.
47
The following table provides summary data, including EBIT, of Retail Energy
for the three and six months ended June 30, 2001 and 2002.
RETAIL ENERGY
-----------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ------------------
2001 2002 2001 2002
---- ------ ---- ------
(IN MILLIONS)
Operating Revenues ..................... $ 36 $1,425 $ 63 $2,404
Operating Expenses:
Purchased Power ...................... -- 1,099 -- 1,941
Operation and Maintenance ............ 22 62 42 105
General and Administrative ........... 15 53 24 93
Depreciation and Amortization ........ 2 6 4 11
---- ------ ---- ------
Total Operating Expenses ............ 39 1,220 70 2,150
---- ------ ---- ------
Operating (Loss) Income ................ (3) 205 (7) 254
---- ------ ---- ------
Other Income, net ...................... 1 -- 2 --
---- ------ ---- ------
(Loss) Earnings Before Interest and
Income Taxes ......................... $ (2) $ 205 $ (5) $ 254
==== ====== ==== ======
Operations Data
Electric Sales (gigawatt-hours (GWh)):
Residential.......................... 5,294 8,449
Small commercial..................... 2,756 6,043
Large commercial, industrial and
institutional...................... 6,880 11,275
------ ------
Total.............................. 14,930 25,767
====== ======
Customers as of June 30, 2002
(in thousands, metered locations):
Residential............................ 1,440
Small commercial....................... 213
Large commercial, industrial and
institutional........................ 18
------
Total................................ 1,671
======
Our Retail Energy segment's EBIT increased $207 million and $259 million in
the three and six months ended June 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.
Operating revenues increased $1.4 billion and $2.3 billion in the three and
six months ended June 30, 2002, respectively, compared to the same periods in
2001, due to revenues of $1.0 billion and $1.7 billion, respectively, from
retail electric sales in the Texas retail market which opened to full
competition in January 2002. Revenues related to the managing and optimizing of
electric energy supply contributed approximately $395 million and $630 million,
respectively, of the increase in revenues for the three and six months ended
June 30, 2002 compared to the same periods in 2001. Purchased power expense
increased $1.1 billion and $1.9 billion, respectively, for the three and six
months ended June 30, 2002 due to costs of approximately $765 million and $1.4
billion, respectively, associated with the retail electric sales and $334
million and $568 million, respectively, associated with managing and optimizing
of electric energy supply.
Our Retail Energy segment's gross margins increased $290 million and $400
million in the three and six months ended June 30, 2002, respectively, compared
to the same periods in 2001 primarily due to increased margins of $309 million
and $438 million, respectively, from retail electric sales of which $237 million
and $343 million, respectively, was increased gross margin for electric sales
exclusive of contracted energy sales to large commercial, industrial and
institutional customers. Contracted energy sales to large commercial, industrial
and institutional customers are accounted for under the mark-to-market method of
accounting, and are included in the margins mentioned above. These energy
contracts are recorded at fair value in revenues upon contract execution. The
net changes in their market values are recognized in the income statement in
revenues in the period of the change. Realized gains and losses are included in
operating revenues and operating expenses in the results of operations. During
the three and six months ended June 30, 2002, the Retail Energy segment
recognized $66 million and $77 million, respectively, of gross margins related
to commercial, industrial and institutional energy contracts compared to $11
million and $15 million, respectively, in the same periods in 2001,
respectively. Included in these margins are unrealized losses
48
related to these contracts which were $13 million and $8 million in the three
and six months ended June 30, 2002, respectively, compared to unrealized gains
of $11 million and $15 million, respectively, in the same periods in 2001. For
information regarding the accounting for contracted energy sales to large
commercial, industrial and institutional customers, please read Note 2(d), which
is incorporated by reference herein, and note 6 to the Reliant Resources 10-K/A
Notes.
In addition, in the three and six months ended June 30, 2001, $11 million
and $24 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.
Operations and maintenance expenses and general and administrative expenses
increased $78 million and $132 million in the three and six months ended June
30, 2002 compared to the same periods in 2001, respectively, primarily due to
(a) increased gross receipts taxes of $19 million and $33 million, respectively,
(b) personnel and employee related costs and other administrative costs of $47
million and $83 million, respectively, due to the Texas retail market opening to
full competition in January 2002, (c) increased bad debt reserves of $14 million
and $24 million, respectively, associated with increased retail electric sales
and (d) increased marketing costs of $6 million and $9 million, respectively,
due to the Texas retail market opening to full competition.
Depreciation and amortization expense increased $4 million and $7 million in
the three and six months ended June 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 six months ended June 30, 2001, Retail Energy recorded $1
million for both periods 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 6 to our Interim Financial
Statements.
The Electric Reliability Council of Texas (ERCOT) independent system
operator (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
supply costs using scheduled supply volumes and adjust those costs upon receipt
of settlement and consumption information.
The ERCOT ISO is also responsible for ensuring that information relating to
a customer's choice of retail electric provider is conveyed in a timely manner
to anyone needing the information. 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 are dependent on the local transmission and distribution utilities for
the reading of our customers' energy 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 energy 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 and results of operations and
cash flows.
The Public Utility Commission of Texas (Texas Utility Commission)
regulations allow us to request an adjustment to the fuel factor in our price to
beat up to twice a year for our 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. Our 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, we
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. Our 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
49
rule. On July 15, 2002, the Texas Utility Commission issued an order delaying
our 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, we filed a request in the Travis County District Court that the
court declare that the Texas Utility Commission must apply its current rules to
our 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 also filed similar requests with the
Travis County District Court. The Court issued an order on August 9, 2002
agreeing with us that the Texas Utility Commission must follow the existing
rules that govern the adjustment of the price to beat fuel factor. Unless the
Texas Utility Commission convenes a special meeting, the earliest a new price to
beat could go into effect would be after August 23, 2002, the date of the Texas
Utility Commission's next normally scheduled meeting.
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 six months ended June 30, 2001
and 2002.
OTHER OPERATIONS
----------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------- ----------------
2001 2002 2001 2002
---- ---- ----- ----
(IN MILLIONS)
Operating Revenues ............................ $ 3 $-- $ 6 $ 2
Operating Expenses:
Operation and Maintenance ................... 5 -- 10 3
General, Administrative and Development ..... 6 (5) 119 (3)
Depreciation and Amortization ............... 2 3 4 6
---- --- ----- ---
Total Operating Expenses ................... 13 (2) 133 6
---- --- ----- ---
Operating (Loss) Income ....................... (10) 2 (127) (4)
---- --- ----- ---
Other Income (Expense):
Gain from Investments, net .................. 4 1 11 4
Other, net .................................. 1 -- 1 (5)
---- --- ----- ---
(Loss) Earnings Before Interest and
Income Taxes ................................ $ (5) $ 3 $(115) $(5)
==== === ===== ===
Other Operations' loss before interest and income taxes declined by $8
million and $110 million for the three and six months ended June 30, 2002,
respectively, compared to the same periods in 2001. For the six months ended
June 30, 2002, the decline in loss before interest and income taxes is primarily
due to 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 Reliant Energy. In addition, for the three
and six months ended June 30, 2002 compared to the same period in 2001, general
and administrative costs decreased due to additional cost being allocated to the
segments in 2002 and certain ebusiness activities being performed at the
business units totaling $9 million and $13 million, respectively. Also, our
Communications business operating loss decreased $6 million and $11 million for
the three and six months ended June 30, 2002, respectively, compared to the same
periods in 2001. This was partially offset by a $6 million accrual for
investment bank services recorded in other expense during the first quarter of
2002. During the six months ended June 30, 2002 compared to the same period in
2001, gain from investments decreased $7 million due to an impairment of an
investment in an internet company and decreased gains from other investments.
For additional information about the benefit charge noted above, please read
Note 12 to our Interim Financial Statements.
50
TRADING AND MARKETING OPERATIONS
We trade and market power, natural gas and other energy-related commodities
and provide related risk management services to our customers. 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 Note 1 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.
We are in the process of evaluating our trading, marketing, power
origination and risk management services strategies. In the future, we may
reduce our trading, marketing and origination activities, which would likely
result in a corresponding decrease in earnings and cash flows.
Our realized and unrealized trading, marketing and risk management services
margins are as follows:
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- -------------------
2001 2002 2001 2002
---- ----- ---- -----
(IN MILLIONS)
Realized ................ $ 27 $ 120 $129 $ 201
Unrealized .............. 105 (1) 120 (20)
---- ----- ---- -----
Total ................... $132 $ 119 $249 $ 181
==== ===== ==== =====
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 .............. 46
Contracts realized or settled during the period .............................. (201)
Changes in fair values attributable to changes in valuation techniques and ... 18
assumptions
Changes in fair value attributable to market price and other market changes .. 147
-----
Fair value of contracts outstanding at June 30, 2002 ....................... $ 228
=====
During the six months ended June 30, 2002, our Retail Energy segment
entered into 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 $35 million at the contract inception dates. We have
entered into energy supply contracts to substantially economically hedge these
contracts. The fair value of these Retail Energy electric supply contracts was
determined by comparing the contractual pricing to the estimated market price
for the retail energy delivery and applying the estimated volumes under the
provisions of these contracts. This calculation 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 pattern.
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 regulatory and transmission charges,
electric line losses, ERCOT system operator administrative fees and other market
interaction charges, estimated credit risk and administrative costs to serve.
The remaining weighted-average duration of these contracts is approximately
eighteen months.
Our Retail Energy segment also enters into contracts to supply the contracts
entered into with large commercial, industrial and institutional customers.
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
51
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 June 30, 2002, the remaining weighted-average
duration of these contracts is less than 2 years.
The remaining fair value of new contracts recorded at inception of $5
million dollars 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 June 30, 2002, the remaining weighted-average
duration of these contracts is less than five years.
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.
Below are the maturities of our contracts related to our trading and
marketing assets and liabilities as of June 30, 2002 (in millions):
FAIR VALUE OF CONTRACTS AT JUNE 30, 2002
-----------------------------------------------------------------------
2007 AND TOTAL
SOURCE OF FAIR VALUE 2003(1) 2003(2) 2004 2005 2006 THEREAFTER FAIR VALUE
- -------------------- ------- ------- ---- ---- ----- ---------- ----------
Prices actively quoted ......... $ 11 $ 2 $(3) $-- $ -- $-- $ 10
Prices provided by other
external sources ............. 137 87 9 5 12 1 251
Prices based on models and
other valuation methods ...... 15 (55) 1 (8) (2) 16 (33)
---- ---- --- --- ---- --- ----
Total .......................... $163 $ 34 $ 7 $(3) $ 10 $17 $228
==== ==== === === ==== === ====
- ---------
(1) Twelve months ended June 30, 2003
(2) The third and fourth quarter of 2003
The "prices actively quoted" category represents our New York Mercantile
Exchange (NYMEX) futures positions in natural gas and crude oil. At June 30,
2002, 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
52
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.
Based on our analysis, we believe our increased exposure to non-investment
grade or unrated counterparties from December 31, 2001 is not material to our
financial position. In addition, our increase in exposure to non-investment
grade or unrated counterparties compared to our total trading and marketing
assets and total non-trading derivative assets has not increased significantly
from December 31, 2001. For additional information regarding our credit exposure
to counterparties, please read Notes 6 to the Reliant Resources 10-K/A Notes and
"Quantitative and Qualitative Disclosures About Market Risk -- Credit Risk" in
Item 7A of the Reliant Resources Form 10-K/A. Although a number of our
counterparties have experienced downgrades in credit worthiness since December
31, 2001, we have taken steps to mitigate our credit risk to these
counterparties through position reductions and credit enhancements.
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, which is incorporated
herein by reference. For additional information regarding (a) the California
wholesale market and related litigation, please read Notes 11(a) and 11(c) to
our Interim Financial Statements, and (b) Dutch stranded costs, please read Note
11(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 various
parts of the country. The proposal includes provisions for capacity payments,
market mitigation, independent market monitoring, transmission and congestion
revenue rights, and independent transmission operations and governance. The new
requirements will not take effect 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.
FINANCIAL CONDITION
The following table summarizes the net cash provided by (used in) operating,
investing and financing activities for the six months ended June 30, 2001 and
2002.
SIX MONTHS ENDED JUNE 30,
-------------------------
2001 2002
---- -------
(IN MILLIONS)
Cash provided by (used in):
Operating activities........................................ $ 328 $ 110
Investing activities........................................ (489) (3,278)
Financing activities........................................ 162 3,507
Net cash provided by operating activities during the six months ended June
30, 2002 decreased by $218 million compared to the same period 2001. This
decrease was primarily due to (a) decreased operating income from our Wholesale
Energy segment; (b) a $100 million settlement payment related to certain
stranded costs contracts (please read Note 11(d) to our Interim Financial
Statements), (c) settlement of hedges of our net investment in foreign
subsidiaries totaling $144 million, and (d) decreased cash flows from margin
deposits related to our trading and hedging activities. These items were
partially offset by (a) cash flows provided by our Retail Energy segment for
retail sales in the first six months of 2002 due to the Texas retail market
opening to full competition in January 2002, (b) $142 million of collateral
deposits related to an equipment financing structure returned to us in 2002
coupled with collateral deposits paid in 2001 (please see
53
Note 11(f) to our Interim Financial Statements), (c) reduced lease prepayments
related to the REMA sale-leaseback agreements (please read Note 11(g) to our
Interim Financial Statements), (d) $50 million related to the settlement of
four structured transactions in 2002 (please read Note 3 to our Interim
Financial Statements), and (e) other changes in working capital.
Net cash used in investing activities during the six months ended June 30,
2002 increased $2.8 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 six months ended
June 30, 2002 as compared to the same period in 2001.
Cash flows provided by financing activities during the six months ended June
30, 2002 increased $3.3 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, decreased investments of
excess cash in an affiliate of Reliant 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.
FUTURE SOURCES OF CASH FLOWS
Credit Facilities. As of June 30, 2002, we had $8.3 billion in committed
credit facilities of which $1.2 billion remained unused. Credit facilities
aggregating $5.4 billion were unsecured. As of June 30, 2002, letters of credit
outstanding under these facilities aggregated $803 million. As of June 30, 2002,
borrowings of $6.3 billion were outstanding under these facilities. As of June
30, 2002, we have $6.3 billion of committed credit facilities which will expire
by June 30, 2003 of which $2.8 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 Note 8 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 15(c) 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
second quarter of 2002, please read Note 8 to our Interim Financial Statements.
For additional information regarding Orion Power and its subsidiaries' debt
obligations, please read Note 8 to our Interim Financial Statements.
For a discussion of other 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, which is incorporated herein by reference, and
Note 8 to our Interim Financial Statements.
California Trade Receivables. As of June 30, 2002, the Company was owed a
total of $239 million, net of a $49 million reserve for refund, by the Cal ISO,
the Cal PX, the CDWR, and California Energy Resources Scheduling for energy
sales in the California wholesale market during the fourth quarter of 2000
through June 30, 2002. From June 30, 2002 through August 9, 2002, the Company
has collected $1 million of these receivable balances. As of June 30, 2002, we
had a pre-tax credit provision of $30 million against these receivable balances.
For additional information regarding uncertainties in the California wholesale
market, please read Notes 11(a) and 11(c) to our Interim Financial Statements
and Notes 13(e) and 13(i) to the Reliant Resources 10-K/A Notes, which are
incorporated by reference herein.
FUTURE USES OF CASH FLOWS
Generating Projects. As of June 30, 2002, we had one generating facility
under construction. Total estimated costs of constructing this facility is $496
million. As of June 30, 2002, we had incurred $212 million of the total
projected costs of this project, which was funded primarily from equity and
debt facilities. In addition, in connection was the acquisition of Orion Power,
we acquired contracts to purchase additional power generation
54
equipment, consisting of steam and combustion turbines and heat recovery steam
generators. Remaining costs under the contracts are $548 million or we may
cancel the contracts for a total cost of $25 million. We are actively attempting
to market this equipment, having determined that it is in excess of our current
needs. In addition to these facilities, we are constructing facilities as
construction agents under the construction agency agreements, which permit us to
lease or buy each of these facilities at the conclusion of their construction.
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 consolidated by us. In addition, we, through our subsidiary, REPG, have
entered into an agreement with a bank whereby the bank, as owner, entered or
will enter into contracts for the purchase and construction of power generation
equipment and REPG, or its subagent, acts as the bank's agent in connection with
administering the contracts for such equipment. For information regarding these
transactions, please read Note 11(f) to our Interim Financial Statements.
Payment to Reliant Energy. To the extent that our price for providing retail
electric service to residential and small commercial customers in Reliant
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 Reliant 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 Reliant
Energy's electric utility's Houston service territory as of January 1, 2002 is
committed to be served by retail electric providers other than us. Currently, we
are unable to estimate the amount of such payment, if any. For additional
information regarding this payment, please read Note 11(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 credit agreements of certain of Orion Power's
subsidiaries, these subsidiaries are restricted from distributing cash to Orion
Power. In addition, covenants under some indebtedness 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. A credit facility of Orion
Power also restricts its ability to pay dividends to us unless the restrictions
contained in certain of its subsidiaries' credit agreements have terminated and
no restrictions remain under their credit agreements. As of June 30, 2002, we
had restricted cash totaling $374 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 June 30, 2002, the specified
conditions were satisfied.
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.
The output of the Liberty Electric Generating Station is contracted under a
tolling agreement (Tolling Agreement) for a term of approximately 14 years, with
an option to extend at the end of the term. Standard & Poor's and Moody's have
downgraded to below investment grad status the senior unsecured debt of PG&E
National Energy Group, Inc., one of the two guarantors of PG&E Energy
Trading-Power, L.P.'s (PGET) obligations under the Tolling Agreement. The
downgrade constitutes an Event of Default by PGET under the Tolling Agreement
unless PGET posts replacement security within ten business days after Liberty
Electric Power, LLC (LEP) notifies PGET of the default. On August 5, LEP
notified PGET of the default. PGET has informed LEP that it will not post the
replacement credit support within the 10 business days period. While LEP could
terminate the Tolling Agreement pursuant to the terms of the Tolling Agreement,
there are certain limitations in the Liberty Credit Agreement on LEP's ability
to take unilateral action in response to a PGET Event of Default.
Generating Capacity Auction Letter of Credit. After the Distribution, we
will be required to post letters of credit to secure the entitlements to the
generation capacity of Reliant Energy's Texas electric utility generation assets
(Texas Genco) that we purchase in the capacity auctions conducted by Texas
Genco. If we were not an affiliate as of June 30, 2002, we would have been
required to post letters of credit to secure our entitlements to Texas Genco's
capacity.
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 August 9, 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. Energy
and capital markets permitting, we expect to grow through the construction of
new generation facilities and the acquisition of generation facilities, and the
expansion of our energy retail business. We expect any resulting capital
requirements to be met with cash flows from operations, and proceeds from debt
and equity offerings, project
55
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 either
equity or debt securities, sell assets or obtain additional credit facilities or
long-term financings from financial institutions.
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 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. 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
56
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 3 to our Interim Financial Statements for 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 6 to our Interim Financial Statements for our adoption of SFAS No. 142
"Goodwill and Other Intangible Assets" (SFAS No. 142).
In June 2002, the EITF reached a consensus on EITF No. 02-03 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. An entity should
disclose the gross transaction volumes for those energy trading contracts that
are physically settled. The EITF did not reach 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. 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. The consensus on presenting gains and losses on energy trading
contracts net is effective for financial statements issued for periods ending
after July 15, 2002. Upon application of the consensus, comparative financial
statements for prior periods should be reclassified to conform to the consensus.
We currently report 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.
Beginning with the quarter ended September 30, 2002, we will report all energy
trading and marketing activities on a net basis in the Statements of
Consolidated Income pursuant to EITF No. 02-03. Although we are in the process
of determining the effect of adoption of EITF No. 02-03 on our Statements of
Consolidated Income, we expect the adoption will result in a substantial
reduction in operating revenues, fuel and cost of gas sold, and purchased power.
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 11(f) and 11(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
perceived 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 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, which is incorporated
herein by reference, Notes 2(d) and 6 to the Reliant Resources 10-K/A
Notes and Notes 1 and 3 to our Interim Financial Statements); and
- 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
57
Form 10-K/A, which is incorporated herein by reference, Notes 2(d) and
6 to the Reliant Resources 10-K/A Notes and Notes 1 and 3 to our
Interim Financial Statements).
- 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, which is incorporated herein by reference, Note 2(f), which is
incorporated by reference herein, and Note 2(q) to the Reliant
Resources 10-K/A Notes and Note 6 to our Interim Financial Statements).
- 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, which is incorporated herein by reference).
For a description of all significant accounting policies, please read Note 2
to the Reliant Resources 10-K/A Notes, which is incorporated by reference
herein.
58
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. A
decrease of 10% in the market prices of energy commodities from their June 30,
2002 levels would have decreased the fair value of our Energy Derivatives from
their levels on those respective dates by $63 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 3 and 11(d) our Interim Financial Statements. A decrease of 10% in market
prices of energy commodities from their June 30, 2002 levels would result in a
loss of earnings of $73 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
$29 million, $13 million and $17 million, respectively, during the second
quarter of 2002 and $29 million, $13 million and $18 million, respectively,
during the first six months of 2002 based on a 95% confidence level and a one
day holding period. During the second quarter of 2001, our highest, lowest and
average daily VAR were $16 million, $3 million and $7 million, respectively, and
during the first six months of 2001, our highest, lowest and average monthly VAR
were $18 million, $3 million and $8 million, respectively, based on a 95%
confidence level and 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
$6.2 billion at June 30, 2002. If the floating rates were to increase by 10%
from June 30, 2002 rates, our combined interest expense to third parties would
increase by a total of $1.7 million each month in which such increase continued.
We hold interest rate swaps 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 June 30, 2002, the swaps relating to
short-term and long-term debt, could be terminated at a cost of $18 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 June 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 June 30, 2002 by $15 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 June 30, 2002, these
swaps could be terminated at a cost of $17 million. These swaps qualify as cash
flow hedges under SFAS No. 133. Should the forecasted interest payments no
longer be probable, any deferred amount will be recognized immediately into
income. A decrease of 10% in the June 30, 2002 level of interest rates would
increase the cost of terminating these swaps by $10 million.
For information regarding the accounting for these interest rate swaps,
please read Note 3 to our Interim Financial Statements.
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At June 30, 2002, we had issued fixed-rate debt aggregating $771
million. As of June 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 $51 million if interest rates were to decline by 10% from their
rates at June 30, 2002.
FOREIGN CURRENCY EXCHANGE RATE RISK
As of June 30, 2002, we have entered into foreign currency swaps and
foreign currency option contracts and have issued Euro-denominated debt to hedge
our net investment in our European Energy segment. Changes in the value of the
swaps, options and debt are recorded as foreign currency translation adjustments
as a component of accumulated other comprehensive income (loss) in stockholders'
equity. As of June 30, 2002, we have recorded a $9 million gain 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 June 30, 2002, our European Energy segment had entered into
transactions to purchase approximately $249 million at fixed exchange rates in
order to hedge future fuel purchases payable in U.S. dollars. As of June 30,
2002, the fair value of these financial instruments was a $7 million liability.
An increase in the value of the Euro of 10% compared to the U.S. dollar from its
June 30, 2002 level would result in a loss in the fair value of these foreign
currency financial instruments of $24 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. An increase of 10% in the U.S. dollar relative to the Euro
from their June 30, 2002 levels would result in a loss of earnings of $14
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 June 30, 2002, the value of the
Itron investment was $7 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 June 30, 2002 level would decrease the fair
value by less than $1 million.
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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
For a description of legal proceedings affecting Reliant Resources, please
read Note 11 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 Note 13 to the Reliant Resources 10-K/A Notes, all of
which are incorporated herein by reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.
Reliant Resources' registration statement on Form S-1 (Registration No.
333-48038) covering the initial public offering of up to 59,800,000 shares of
its common stock (including up to 7,800,000 shares issuable under the
underwriters' overallotment option) was declared effective by the SEC on April
30, 2001. Reliant Resources raised net proceeds of approximately $1.7 billion
from its initial public offering. Pursuant to the terms of the Master Separation
Agreement between Reliant Energy and Reliant Resources, Reliant Resources used
$216 million of the net proceeds to repay certain indebtedness owed to Reliant
Energy. In addition, Reliant Resources used $418 million for the repayment of
third party borrowings, $333 million of the net proceeds for capital
expenditures, $189 million for the purchase of its common stock, $315 million
for tax, interest and payments and other payables, $189 million for the
repurchase of 4.5% convertible senior notes and $41 million for the acquisition
of Orion Power.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
At the annual meeting of Reliant Resources' stockholders held on
June 6, 2002, the matters voted upon and the number of votes cast for, against
or withheld, as well as the number of abstentions and broker non-votes as to
such matters (including a separate tabulation with respect to each nominee for
office) were as stated below:
The following nominees for directors were elected to serve a one-year
term expiring at the 2003 annual meeting of stockholders:
For Withheld
--- ---------
Milton Carroll 282,447,376 345,189
R. Steve Letbetter 276,865,004 5,927,561
Laree Perez 282,570,379 222,186
Previous directors James A. Baker, III, L. Lowry Mays and Phillip B.
Miller retired from the board of directors at the expiration of their terms.
The proposal to adopt the 2002 Annual Incentive Compensation Plan for
Executive Officers was approved with 281,047,576 votes for, 1,360,572 votes
against, and 381,975 abstentions.
The proposal to adopt the 2002 Long-Term Incentive Plan was approved
with 263,995,049 votes for, 11,327,846 votes against, 381,975 abstentions and
7,087,695 broker non-votes.
The ratification of the appointment of Deloitte & Touche LLP as
independent accountants and auditors for Reliant Resources for 2002 was approved
with 281,812,626 votes for, 960,999 votes against, and 18,940 abstentions.
ITEM 5. OTHER INFORMATION.
Organizational Changes. In May 2002, Stephen W. Naeve, formerly
executive vice president and chief financial officer, was named president and
chief operating officer of Reliant Resources. Mr. Naeve has been with Reliant
Resources or Reliant Energy for nearly 30 years. Reliant Resources also
announced in May 2002 that Joe Bob Perkins, the then executive vice president
and group president, wholesale businesses, and Shahid Malik, the then president
of trading in the Company's wholesale group, had resigned to pursue other
interests. In July 2002, Mark M. Jacobs was appointed as executive vice
president and chief financial officer of Reliant Resources. Prior to his
appointment, Mr. Jacobs served as a managing director of Goldman Sachs & Co. In
August 2002, Thomas C. Livengood was appointed as vice president and controller
of Reliant Resources. Prior to his appointment, Mr. Livengood served as
executive vice president and chief financial officer of Carriage Services, Inc.
In addition, in August 2002, Reliant Resources announced that Mary Ricciardello
had informed the Company in May 2002 that she intends to resign from her
position of senior vice president and chief accounting officer effective August
16, 2002.
Forward-Looking Statements. 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 timing of our separation from our parent company, Reliant Energy,
Incorporated, which currently remains subject to receipt of certain
regulatory approvals,
- 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,
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- 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 of
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, and
- the resolution of the refusal by California market participants to pay
our receivables balances.
- 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."
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" and similar words are intended to identify forward-looking
statements.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
10.1 Reliant Resources, Inc. 2002 Stock Plan (incorporated by
reference from the Company's Registration Statement on Form S-8
(Registration Number 333-86610) (Exhibit 4.5).
10.2 Reliant Resources, Inc. 2002 Annual Incentive Compensation Plan
for Executive Officers (incorporated by reference from the
Company's Proxy Statement on Schedule 14A (SEC File Number
1-16455) (Appendix I).
10.3 Reliant Resources, Inc. 2002 Long-Term Incentive Plan
(incorporated by reference from the Company's Proxy Statement on
Schedule 14A (SEC File Number 1-16455) (Appendix II).
10.4 Reliant Resources, Inc. Deferral Plan (incorporated by reference
from the Company's Registration Statement on Form S-8
(Registration Number 333-74790) (Exhibit 4.1).
10.5 Reliant Resources, Inc. Savings Plan (incorporated by reference
from the Company's Registration Statement on Form S-8
(Registration Number 333-86608) (Exhibit 4.5).
10.6 Reliant Resources, Inc. Union Savings Plan (incorporated by
reference from the Company's Registration Statement on Form S-8
(Registration Number 333-74754) (Exhibit 4.5).
Exhibit 99(a) Items incorporated by reference from Reliant
Resources Form 10-K/A: "Our Business --
Environmental Matters," "-- Legal Proceedings,"
"Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain
Factors Affecting Our Future Earnings," "--
Liquidity and Capital Resources," "-- Trading
and Marketing Operations," and "Quantitative and
Qualitative Disclosure about Market Risk." Items
incorporated by reference from Reliant Resources
10-K/A Notes: Note 1 (Background and Basis of
Presentation), Note 2 (Summary of Significant
Accounting Policies), Note 4 (Related Party
Transactions -- Agreements between Reliant Energy
and the Company), Note 5 (Business Acquisitions),
Note 6 (Derivative Instruments), Note 9
(Stockholder's Equity), (Stock-Based Incentive
Compensation Plans and Retirement Plans --
Pension), Note 11(d) (Stock-Based Incentive
Compensation Plans and Retirement Plans --
Postretirement Benefits), Note 13 (Commitments and
Contingencies), Note 17 (Bankruptcy of Enron Corp.
and its Affiliates) and Note 19 (Subsequent
Events).
(b) Reports on Form 8-K.
- Current Report on Form 8-K dated April 5, 2002, as filed with the SEC on
April 8, 2002 (Items 5 and 7).
- Amended Current Report on Form 8-K/A dated February 19, 2002, as filed
with the SEC on April 9, 2002 (Item 7 - financial statements relating to
the consummation of Orion Power acquisition).
- Current Report on Form 8-K dated April 22, 2002, as filed with the SEC
on April 22, 2002 (Item 7 -- financial statements describing the pro
forma effect of the Orion Power acquisition on the Company's historical
financial statements).
- Current Report on Form 8-K dated April 29, 2002, as filed with the SEC
on April 29, 2002 (Items 5 and 7).
- Current Report on Form 8-K dated May 29, 2002, as filed with the SEC on
May 29, 2002 (Item 2).
- Current Report on Form 8-K dated May 31, 2002, as filed with the SEC on
May 31, 2002 (Item 5).
- Current Report on Form 8-K dated June 6, 2002, as filed with the SEC on
June 10, 2002 (Item 5).
- Current Report on Form 8-K dated May 23, 2002, as filed with the SEC on
June 11, 2002 (Item 5).
- 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 (Item 5).
- Current Report on Form 8-K dated July 31, 2002, as filed with the SEC on
August 1, 2002 (Item 5).
- Amended Current Report on Form 8-K/A dated February 19, 2002, as filed
with the SEC on August 2 , 2002 (Item 7 -- Restated pro forma financial
statements relating to Reliant Resources' acquisition of Orion Power
Holdings, Inc.).
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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/ Mary P. Ricciardello
----------------------------------
Mary P. Ricciardello
Senior Vice President
and Chief Accounting Officer
Date: August 14, 2002
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