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SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period
ended June 30, 2003
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
__________ to __________
Commission
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Registrant, State of Incorporation
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I.R.S. Employer
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File Number
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Address and Telephone Number
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Identification No.
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1-2987
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Niagara Mohawk Power Corporation
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15-0265555
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(a New York corporation)
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300 Erie Boulevard West
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Syracuse, New York 13202
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315.474.1511
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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.
Indicate by check mark whether the registrant is
an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
The number of shares outstanding of each of the
issuer’s classes of common stock, as of August 1, 2003, were as
follows:
Registrant
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Title
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Shares Outstanding
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Niagara Mohawk Power Corporation
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Common Stock, $1.00 par value
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187,364,863
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(all held by Niagara Mohawk
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Holdings, Inc.)
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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
FORM 10-Q - For the Quarter Ended June 30, 2003
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PAGE
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PART I – FINANCIAL INFORMATION
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Item 1.
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Financial Statements
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Consolidated Statements of Operations, Retained Earnings, and Comprehensive
Income
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3
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Consolidated Balance Sheets
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4
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Consolidated Statements of Cash Flows
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6
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Notes to Unaudited Consolidated Financial Statements
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7
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Item 2.
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Management’s Discussion and Analysis of Financial Condition and
Results of Operations
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14
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Item 3.
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Quantitative and Qualitative Disclosures About Market Risk
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21
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Item 4.
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Controls and Procedures
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21
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PART II – OTHER INFORMATION
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Item 1.
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Legal Proceedings
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22
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Item 6.
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Exhibits and Reports on Form 8-K
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22
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Signature
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23
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Exhibit Index
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24
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PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
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Consolidated Statements of Operations
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(In thousands of
dollars)
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(UNAUDITED)
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Three Months Ended
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June 30,
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2003
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2002
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Operating revenues:
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Electric
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$ 761,400
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$ 782,121
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Gas
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187,977
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139,122
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Total operating revenues
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949,377
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921,243
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Operating expenses:
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Purchased energy:
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Electricity purchased
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384,589
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382,485
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Gas purchased
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116,474
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65,635
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Other operation and maintenance
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182,986
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179,811
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Amortization of stranded costs
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43,517
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35,299
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Depreciation and amortization
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50,752
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49,451
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Other taxes
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57,740
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66,754
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Income taxes
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19,694
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17,841
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Total operating expenses
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855,752
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797,276
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Operating income
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93,625
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123,967
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Other income (deductions), net
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(3,649)
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(2,791)
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Income before interest charges
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89,976
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121,176
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Interest:
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Interest on long-term debt
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70,777
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86,344
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Interest on debt to associated companies
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8,463
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613
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Other interest
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6,603
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6,039
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Total interest expense
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85,843
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92,996
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Net Income
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$ 4,133
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$ 28,180
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Consolidated Statements of Retained
Earnings
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(In thousands of
dollars)
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(UNAUDITED)
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Three Months Ended
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June 30,
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2003
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2002
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Retained earnings, beginning of
period
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$ 85,706
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$ 29,317
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Net income
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4,133
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28,180
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Dividends on preferred stock
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(1,378)
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(1,402)
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Retained earnings, end of period
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$ 88,461
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$ 56,095
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Consolidated Statements of Comprehensive
Income
|
(In thousands of
dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
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Three Months Ended
|
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June 30,
|
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|
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2003
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2002
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Net income
|
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$ 4,133
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$ 28,180
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Other comprehensive income (loss):
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Unrealized gains (losses) on securities (net of taxes of
$498 and ($274), respectively)
|
688
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(368)
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Hedging activity (net of taxes of ($434) and ($88),
respectively)
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(572)
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(117)
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Change in additional minimum pension liability
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(1,534)
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-
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Total other comprehensive loss
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(1,418)
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(485)
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Comprehensive income
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$ 2,715
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$ 27,695
|
Per share data is not relevant because
Niagara Mohawk’s common stock is wholly-owned by Niagara Mohawk Holdings,
Inc.
The accompanying notes are an integral
part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
|
Consolidated Balance Sheets
|
(In thousands of dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
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|
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June 30,
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March 31,
|
ASSETS
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2003
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2003
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Utility plant, at original cost:
|
|
|
|
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|
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Electric plant
|
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|
$ 5,130,055
|
|
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$ 5,091,435
|
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Gas plant
|
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|
1,420,913
|
|
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1,402,215
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Common Plant
|
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354,939
|
|
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|
351,987
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Construction work-in-progress
|
|
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143,784
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|
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143,949
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Total utility plant
|
|
|
7,049,691
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6,989,586
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Less: Accumulated depreciation and amortization
|
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2,381,361
|
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|
|
2,342,757
|
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Net utility plant
|
|
|
4,668,330
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|
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|
4,646,829
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|
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Goodwill
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|
1,225,742
|
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|
1,225,742
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|
|
|
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|
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Other property and investments
|
|
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81,290
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|
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94,314
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|
|
|
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|
|
|
|
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Current assets:
|
|
|
|
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Cash and cash equivalents
|
|
|
26,942
|
|
|
|
30,038
|
|
Restricted cash (Note A)
|
|
|
45,692
|
|
|
|
25,350
|
|
Accounts receivable (less reserves of $112,100 and
|
|
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|
|
|
|
|
|
$100,200, respectively, and includes receivables
|
|
470,824
|
|
|
|
543,280
|
|
|
to associated companies of $295 and $227,
|
|
|
|
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respectively)
|
|
|
|
|
|
|
|
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Materials and supplies, at average cost:
|
|
|
|
|
|
|
|
|
|
Gas storage
|
|
|
43,073
|
|
|
|
4,795
|
|
|
Other
|
|
|
16,653
|
|
|
|
16,401
|
|
Derivative instruments
|
|
|
11,449
|
|
|
|
16,354
|
|
Prepaid taxes
|
|
|
48,289
|
|
|
|
90,770
|
|
Current deferred income taxes
|
|
|
52,011
|
|
|
|
35,458
|
|
Other
|
|
|
10,833
|
|
|
|
10,483
|
|
|
|
Total current assets
|
|
|
725,766
|
|
|
|
772,929
|
|
|
|
|
|
|
|
|
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|
|
Regulatory and other non-current assets:
|
|
|
|
|
|
|
|
|
Regulatory assets (Note C):
|
|
|
|
|
|
|
|
|
|
Stranded costs
|
|
|
3,170,139
|
|
|
|
3,213,657
|
|
|
Swap contracts regulatory asset
|
|
|
782,407
|
|
|
|
793,028
|
|
|
Regulatory tax asset
|
|
|
143,756
|
|
|
|
143,765
|
|
|
Deferred environmental restoration costs (Note B)
|
|
327,000
|
|
|
|
301,000
|
|
|
Pension and postretirement benefit plans
|
|
714,254
|
|
|
|
713,779
|
|
|
Loss on reacquired debt
|
|
|
52,257
|
|
|
|
48,255
|
|
|
Other
|
|
|
226,636
|
|
|
|
242,290
|
|
|
|
Total regulatory assets
|
|
|
5,416,449
|
|
|
|
5,455,774
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-current assets
|
|
|
57,042
|
|
|
|
48,171
|
|
|
|
Total regulatory and other non-current assets
|
|
5,473,491
|
|
|
|
5,503,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
$ 12,174,619
|
|
|
|
$ 12,243,759
|
The accompanying notes are
an integral part of these financial statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
|
Consolidated Balance Sheets
|
(In thousands of dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
|
March 31,
|
CAPITALIZATION AND LIABILITIES
|
|
|
2003
|
|
|
|
2003
|
Capitalization:
|
|
|
|
|
|
|
|
|
Common stockholder's equity:
|
|
|
|
|
|
|
|
|
|
Common stock ($1 par value)
|
|
|
$ 187,365
|
|
|
|
$ 187,365
|
|
|
|
Authorized - 250,000,000 shares
|
|
|
|
|
|
|
|
|
|
|
Issued and outstanding - 187,364,863 shares
|
|
|
|
|
|
|
|
|
Additional paid-in capital
|
|
|
2,621,563
|
|
|
|
2,621,440
|
|
|
Accumulated other comprehensive income (loss) (Note E)
|
|
(1,402)
|
|
|
|
16
|
|
|
Retained earnings
|
|
|
88,461
|
|
|
|
85,706
|
|
|
|
Total common stockholder's equity
|
|
|
2,895,987
|
|
|
|
2,894,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred equity:
|
|
|
|
|
|
|
|
|
|
Cumulative preferred stock ($100 par value, optionally
redeemable)
|
|
42,158
|
|
|
|
42,625
|
|
|
|
Authorized - 3,400,000 shares
|
|
|
|
|
|
|
|
|
|
|
Issued and outstanding - 421,583 and 426,248 shares,
respectively
|
|
|
|
|
|
|
|
Cumulative preferred stock ($25 par value, optionally redeemable)
|
|
55,655
|
|
|
|
55,655
|
|
|
|
Authorized - 19,600,000 shares
|
|
|
|
|
|
|
|
|
|
|
Issued and outstanding - 1,113,100 shares
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
2,576,216
|
|
|
|
3,453,989
|
|
Long-term debt to affiliates
|
|
|
850,000
|
|
|
|
500,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
6,420,016
|
|
|
|
6,946,796
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable (including payables to associated companies
|
|
269,866
|
|
|
|
375,767
|
|
|
of $31,131 and $34,029, respectively)
|
|
|
|
|
|
|
|
|
Customers' deposits
|
|
|
26,645
|
|
|
|
25,843
|
|
Accrued interest
|
|
|
65,826
|
|
|
|
108,927
|
|
Short-term debt to affiliates
|
|
|
116,000
|
|
|
|
198,000
|
|
Current portion of long-term debt
|
|
|
1,242,840
|
|
|
|
611,652
|
|
Other
|
|
|
123,597
|
|
|
|
111,904
|
|
|
Total current liabilities
|
|
|
1,844,774
|
|
|
|
1,432,093
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-current liabilities:
|
|
|
|
|
|
|
|
|
Accumulated deferred income taxes
|
|
|
1,181,323
|
|
|
|
1,157,796
|
|
Liability for swap contracts
|
|
|
782,407
|
|
|
|
793,028
|
|
Employee pension and other benefits
|
|
|
886,674
|
|
|
|
884,204
|
|
Other
|
|
|
732,425
|
|
|
|
728,842
|
|
|
Total other non-current liabilities
|
|
|
3,582,829
|
|
|
|
3,563,870
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Notes B and C):
|
|
|
|
|
|
|
|
|
Liability for environmental remediation costs
|
|
|
327,000
|
|
|
|
301,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization and liabilities
|
|
|
$ 12,174,619
|
|
|
|
$ 12,243,759
|
The
accompanying notes are an integral part of these financial
statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
|
Consolidated Statements of Cash Flows
|
(In thousands of dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months ended June 30,
|
|
|
|
|
|
|
|
|
|
2003
|
|
|
|
2002
|
Operating activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
|
$ 4,133
|
|
|
|
$ 28,180
|
|
Adjustments to reconcile net income to net cash
|
|
|
|
|
|
|
|
|
|
provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
50,752
|
|
|
|
49,451
|
|
|
Amortization of stranded costs
|
|
|
43,517
|
|
|
|
35,299
|
|
|
Provision for deferred income taxes
|
|
|
6,983
|
|
|
|
12,244
|
|
|
Change in restricted cash
|
|
|
(19,654)
|
|
|
|
(16,800)
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
Decrease in accounts receivable, net
|
|
78,556
|
|
|
|
32,200
|
|
|
|
Increase in materials and supplies
|
|
|
(38,530)
|
|
|
|
(25,994)
|
|
|
|
Increase (decrease) in accounts payable and accrued expenses
|
|
(105,099)
|
|
|
|
16,347
|
|
|
|
Decrease in accrued interest and taxes
|
|
|
(43,101)
|
|
|
|
(42,324)
|
|
|
|
Decrease in prepaid taxes
|
|
42,481
|
|
|
|
17,491
|
|
|
|
Changes in other assets and liabilities, net
|
|
29,250
|
|
|
|
26,968
|
|
|
|
|
Net cash provided by operating activities
|
|
49,288
|
|
|
|
133,062
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
Construction additions
|
|
|
(67,970)
|
|
|
|
(49,272)
|
|
Payments received on notes associated with the sale of generation
assets
|
|
-
|
|
|
|
249,792
|
|
Other investments
|
|
13,028
|
|
|
|
2,256
|
|
Other
|
|
|
(4,460)
|
|
|
|
(4,418)
|
|
|
|
|
Net cash provided by (used in) investing activities
|
|
(59,402)
|
|
|
|
198,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities:
|
|
|
|
|
|
|
|
|
Dividends paid on preferred stock
|
|
|
(1,378)
|
|
|
|
(1,402)
|
|
Reductions in long-term debt
|
|
|
(259,260)
|
|
|
|
(126,023)
|
|
Proceeds from long-term debt to affiliates
|
|
|
350,000
|
|
|
|
-
|
|
Redemption of preferred stock
|
|
|
(467)
|
|
|
|
(387)
|
|
Net change in short-term debt to affiliates
|
|
|
(82,000)
|
|
|
|
(201,000)
|
|
Other
|
|
|
123
|
|
|
|
108
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
7,018
|
|
|
|
(328,704)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
(3,096)
|
|
|
|
2,716
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
30,038
|
|
|
|
9,882
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
|
$ 26,942
|
|
|
|
$ 12,598
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
Interest paid
|
|
|
$ 120,150
|
|
|
|
$ 146,441
|
|
Income taxes paid
|
|
|
$ -
|
|
|
|
$ 5,333
|
The
accompanying notes are an integral part of these financial
statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Notes to Unaudited Consolidated Financial Statements
Note A – Summary of Significant Accounting
Policies
Basis of Presentation: Niagara Mohawk Power
Corporation and subsidiary companies (the “Company”), in the opinion
of management, have included all adjustments (which include normal recurring
adjustments) necessary for a fair statement of the results of operations for the
interim periods presented. These financial statements and notes thereto should
be read in conjunction with the audited financial statements included in the
Company’s Annual Report on Form 10-K for the year ended March 31,
2003.
The Company’s electric sales tend to be substantially higher
in summer and winter months as related to weather patterns in its service
territory; gas sales tend to peak in the winter. Notwithstanding other factors,
the Company’s quarterly net income will generally fluctuate accordingly.
Therefore, the earnings for the three-month period ended June 30, 2003 should
not be taken as an indication of earnings for all or any part of the balance of
the year.
The Company is a wholly owned subsidiary of Niagara Mohawk
Holdings, Inc. (“Holdings”) and, indirectly, National Grid Transco
plc.
Certain amounts from prior years have been reclassified on the
accompanying Consolidated Financial Statements to conform to the current year
presentation.
Restricted Cash: Restricted cash consists of
margin accounts for hedging activity, cash held in escrow in compliance with
certain debt agreements, health care claims deposits, New York State Department
of Conservation (“DEC”) securitization for certain site cleanup, and
worker’s compensation premium deposit.
New Accounting
Standards: In April 2003, the Financial Accounting Standards Board
(“FASB”) issued Statement of Financial Accounting Standards
(“SFAS”) No. 149 “Amendment of Statement 133 on Derivative
Instruments and Hedging activities, an amendment of Statement 133”
(“SFAS 149”). SFAS 149 amends and clarifies financial accounting
and reporting for derivative instruments and is effective for contracts entered
into after June 30, 2003. The Company does not expect the adoption of this
statement to have a material effect on its results of operations, financial
position, or cash flows.
Note B –
Contingencies
Environmental Contingencies: The public
utility industry typically utilizes and/or generates in its operations a broad
range of hazardous and potentially hazardous wastes and by-products. The
Company believes it is handling identified wastes and by-products in a manner
consistent with federal, state, and local requirements and has implemented an
environmental audit program to identify any potential areas of concern and aid
in compliance with such requirements. The Company is also currently conducting
a program to investigate and remediate, as necessary, to meet current
environmental standards, certain properties associated with former gas
manufacturing and other properties which the Company has learned may be
contaminated with industrial waste, as well as investigating identified
industrial waste sites as to which it may be determined that the Company has
contributed. The Company has also been advised that various federal, state, or
local agencies believe certain properties require investigation.
The
Company is currently aware of 116 sites with which it may be associated,
including 59, which are Company-owned. With respect to non-owned sites, the
Company may be required to contribute some proportionate share of remedial
costs. Although one party can, as a matter of law, be held liable for all of
the remedial costs at a site, regardless of fault, in practice costs are usually
allocated among Potentially Responsible Parties (“PRPs”). The
Company has denied any responsibility at certain of these PRP sites and is
contesting liability accordingly. At non-owned manufactured gas plant sites,
the Company may bear full or partial responsibility for remedial
costs.
Investigations at each of the Company-owned sites are designed to:
(1) determine if environmental contamination problems exist; (2) if necessary,
determine the appropriate remedial actions; and (3) where appropriate, identify
other parties who should bear some or all of the cost of remediation. Legal
action against such other parties will be initiated where appropriate. As site
investigations are completed, the Company expects to determine site-specific
remedial actions and to estimate the attendant costs for restoration. However,
since investigations and regulatory reviews are ongoing for most sites, the
estimated cost of remedial action is subject to change.
The Company
determines site liabilities through feasibility studies or engineering
estimates, the Company’s estimated share of a PRP allocation, or, where no
better estimate is available, the low end of a range of possible outcomes is
used. Estimates of the cost of remediation and post-remedial monitoring are
based upon a variety of factors, including identified or potential contaminants,
location, size and use of the site, proximity to sensitive resources, status of
regulatory investigation, and knowledge of activities at similarly situated
sites. Actual expenditures are dependent upon the total cost of investigation
and remediation and the ultimate determination of the Company’s share of
responsibility for such costs, as well as the financial viability of other
identified responsible parties since clean-up obligations are joint and several.
It is more difficult to estimate the costs to remediate certain non-owned sites,
since they primarily relate to sites that have been owned and operated by other
parties and because they have not undergone site investigations.
As a
consequence of site characterizations and assessments completed to date and
negotiations with other PRPs or with the appropriate environmental regulatory
agency, the Company has accrued a liability in the amount of $327 million which
is reflected in the Company’s Consolidated Balance Sheets at June 30,
2003. The potential high end of the range is presently estimated at
approximately $550 million.
The Merger Rate Plan provides for the
continued application of deferral accounting for variations in spending from
amounts provided in rates. The Company has recorded a regulatory asset
representing the investigation, remediation, and monitoring obligations to be
recovered from ratepayers. As a result, the Company does not believe that site
investigation and remediation costs will have a material adverse effect on its
results of operations or financial condition.
Legal matters:
Alliance for Municipal Power v. New York State Public Service
Commission
On February 17, 2003, the Alliance for Municipal Power
(“AMP”) filed with the New York state court a petition for review of
decisions by the New York State Public Service Commission (the
“PSC”) that maintain the PSC’s established policy of using
average distribution rates when calculating the exit fees that may be charged to
municipalities that seek to leave the Company’s system and establish their
own municipal light departments. Changes in the methodology for the calculation
of the exit fee are not likely to have a material effect on the Company’s
financial statements. However, AMP’s petition for review also challenges
the lawfulness of the Company’s collection of exit fees from departing
municipalities, regardless of the methodology used to calculate those fees. If
the court were to rule that the Company is not authorized to collect exit fees,
and if the AMP communities proceeded with their plans to municipalize power, the
Company could experience a significant shortfall of revenue. In addition, such
a ruling could encourage other municipalities to consider municipalizing. The
Company would seek to defer any lost revenue for eventual recovery from its
remaining customers pursuant to the terms of its rate plan. The Company
believes that it has strong defenses to AMP’s petition and is contesting
the petition vigorously.
New York State v. Niagara Mohawk Power Corp.
et al.
On January 10, 2002, New York State filed a civil action
against the Company and NRG Energy, Inc. in federal district court in Buffalo,
New York, for alleged violations of the federal Clean Air Act and related state
environmental laws at the Dunkirk and Huntley power plants, which the Company
sold in 1999 to affiliates of NRG Energy, Inc. (collectively,
“NRG”). The state alleged, among other things, that between 1982
and 1999, the Company modified the two plants 55 times without obtaining proper
preconstruction permits and implementing proper pollution equipment controls.
The state sought, among other relief, statutory penalties under the Clean Air
Act, which could have a maximum value of $25,000 to $27,500 per day per
violation.
The Company and NRG moved to dismiss the complaint on statute of
limitations and other grounds in 2002, and on March 27, 2003, the court granted
the motions in part, holding that the violations of the Clean Air Act prior to
November 1996 were barred by the federal five-year statute of limitations, and
that related state statutory violations prior to November 1999 were barred by
the state three-year statute of limitations. This eliminated the
Company’s potential exposure to statutory daily penalties prior to these
dates. At the same time, the court preserved the state’s non-regulatory
claims against the Company and dismissed NRG from the suit.
On April 25, 2003, the state filed a motion for leave to amend the
complaint to assert new claims against both the Company and NRG for unspecified
amounts. Among other things, the state is seeking to reassert daily violations
of the Clean Air Act going back to 1982, the time period covered by its original
complaint. On May 30, 2003, the Company filed papers in opposition to the
state’s petition. Oral argument was held on July 2, 2003 and the parties
are awaiting the court’s decision.
Prior to the commencement of the enforcement action, on July 13, 2001,
the Company filed a declaratory judgment action in New York State court in
Syracuse against NRG seeking a ruling that NRG is responsible for the costs of
pollution controls and mitigation that might result from the state’s
enforcement action. As a result of NRG’s voluntary bankruptcy petition,
filed in New York federal bankruptcy court on May 14, 2003, the Company’s
declaratory judgment action is stayed.
Niagara Mohawk Power Corp. v.
Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor, L.L.C.
The Company is engaged in collections litigation to recover bills for
station service rendered to the owners of three power plants (the
“Plants”), which the Company sold in 1999 to three affiliates of NRG
Energy, Inc.: Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego
Harbor, L.L.C (collectively, the “Defendants”). After suit was
filed, the parties agreed to stay the litigation to permit the Federal Energy
Regulatory Commission (“FERC”) to try to resolve the
dispute.
NRG Energy, Inc. and the Defendants filed voluntary
bankruptcy petitions in federal bankruptcy court in New York on May 14,
2003. According to the Company’s records, the Defendants owed the
Company approximately $35 million as of the date of the bankruptcy
filing. The court approved relief from the automatic bankruptcy stay,
permitting the litigation before FERC to proceed. The FERC proceeding will
address the Company’s ability to charge for, and the
Defendants’ obligation to pay for, station service electricity
post-bankruptcy, but the recovery of amounts due for station service prior to
the bankruptcy filing date will be governed by the bankruptcy court
proceedings.
Note C – Rate and Regulatory
Issues
The Company’s financial statements conform to
Generally Accepted Accounting Principles, including the accounting principles
for rate-regulated entities with respect to its regulated operations.
Substantively, SFAS No. 71 “Accounting for the Effects of Certain Types of
Regulation” permits a public utility, regulated on a cost-of-service
basis, to defer certain costs, which would otherwise be charged to expense, when
authorized to do so by the regulator. These deferred costs are known as
regulatory assets, which in the case of the Company, are approximately $5.4
billion at June 30, 2003. These regulatory assets are probable of recovery
under the Company’s Merger Rate Plan and Gas Multi-Year Rate and
Restructuring Agreement. The Company believes that the regulated cash flows to
be derived from prices it will charge for electric service in the future,
including the Competitive Transition Charges (“CTCs”), and assuming
no unforeseen reduction in demand or bypass of the CTC or exit fees, will be
sufficient to recover the Merger Rate Plan stranded regulatory assets over the
planned amortization period with a return. Under the Merger Rate Plan, the
Company’s remaining electric business (electric transmission and
distribution business) continues to be rate-regulated on a cost-of-service basis
and, accordingly, the Company continues to apply SFAS No. 71 to these
businesses. Also, the Company’s Independent Power Producer
(“IPP”) contracts, and the Purchase Power Agreements entered into in
connection with the generation divestiture, continue to be the obligations of
the regulated business, and remain recoverable from customers.
In the
event the Company determines, as a result of lower than expected revenues and/or
higher than expected costs, that its net regulatory assets are not probable of
recovery, it can no longer apply the principles of SFAS No. 71 and would be
required to record an after-tax, non-cash charge against income for any
remaining unamortized regulatory assets and liabilities. If the Company could
no longer apply SFAS No. 71, the resulting charge would be material to the
Company’s reported financial condition and results of
operations.
Under the Merger Rate Plan, the Company is earning a return
on all of its regulatory assets.
Stranded Costs: Under the
Merger Rate Plan, a regulatory asset was established that included the costs of
the Master Restructuring Agreement (“MRA”), the cost of any
additional IPP contract buyouts and the deferred loss on the sale of the
Company’s generation assets. The MRA represents the cost to terminate,
restate or amend IPP contracts. The Company is also permitted to defer and
amortize the cost of any new IPP contract buyouts. Beginning January 31, 2002,
the Merger Rate Plan stranded costs regulatory asset is being amortized unevenly
over ten years with larger amounts being amortized in the latter years,
consistent with projected recovery through rates.
Note D –
Segment Information
The Company’s reportable segments are
electricity-transmission, electricity-distribution, and gas. The Company is
engaged principally in the business of purchase, transmission, and distribution
of electricity and the purchase, distribution, sale, and transportation of
natural gas in New York State. Certain information regarding the
Company’s segments is set forth in the following table. General corporate
expenses, property common to the various segments, and depreciation of such
common property have been allocated to the segments based on labor or plant,
using a percentage derived from total labor or plant dollars charged directly to
certain operating expense accounts or certain plant accounts. Corporate assets
consist primarily of other property and investments, cash, restricted cash,
current deferred income taxes, and unamortized debt expense.
(in millions of dollars)
|
|
|
|
|
|
Electric -
|
|
Electric -
|
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
Distribution
|
|
Gas
|
|
Corporate
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2003
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
$ 61
|
|
$ 700
|
|
$ 188
|
|
$ -
|
|
$ 949
|
|
Operating income before
|
|
|
|
|
|
|
|
|
|
|
|
income taxes
|
24
|
|
76
|
|
13
|
|
-
|
|
113
|
|
Depreciation and amortization
|
9
|
|
33
|
|
9
|
|
-
|
|
51
|
|
Amortization of stranded costs
|
-
|
|
44
|
|
-
|
|
-
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2002
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
$ 65
|
|
$ 717
|
|
$ 139
|
|
$ -
|
|
$ 921
|
|
Operating income before
|
|
|
|
|
|
|
|
|
|
|
|
income taxes
|
29
|
|
96
|
|
17
|
|
-
|
|
142
|
|
Depreciation and amortization
|
9
|
|
31
|
|
9
|
|
-
|
|
49
|
|
Amortization of stranded costs
|
-
|
|
35
|
|
-
|
|
-
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2003
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
$ 303
|
|
$ 709
|
|
$ 214
|
|
$ -
|
|
$ 1,226
|
|
Total assets
|
$ 1,443
|
|
$ 8,707
|
|
$ 1,586
|
|
$ 439
|
|
$ 12,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2003
|
|
|
|
|
|
|
|
|
|
|
Goodwill
|
$ 303
|
|
$ 709
|
|
$ 214
|
|
$ -
|
|
$ 1,226
|
|
Total assets
|
$ 1,444
|
|
$ 8,780
|
|
$ 1,576
|
|
$ 444
|
|
$ 12,244
|
Note E – Accumulated Other Comprehensive Income
(Loss)
|
|
|
|
Unrealized
|
|
|
|
|
|
Total
|
|
|
|
|
Gains and
|
|
Minimum
|
|
|
|
Accumulated
|
(in thousands of dollars)
|
|
Losses on
|
|
Pension
|
|
|
|
Other
|
|
|
|
|
Available-for-
|
|
Liability
|
|
Cash Flow
|
|
Comprehensive
|
|
|
|
|
Sale Securities
|
|
Adjustment
|
|
Hedges
|
|
Income (Loss)
|
March 31, 2003
|
|
$ (584)
|
|
$ -
|
|
$ 600
|
|
$ 16
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
Unrealized gains on securities,
|
|
|
|
|
|
|
|
|
|
|
net of taxes
|
|
688
|
|
|
|
|
|
688
|
|
Hedging activity, net of taxes
|
|
|
|
|
|
(572)
|
|
(572)
|
|
Change in minimum pension liability
|
|
|
|
(1,534)
|
|
|
|
(1,534)
|
June 30, 2003
|
|
$ 104
|
|
$ (1,534)
|
|
$ 28
|
|
$ (1,402)
|
Note F – Subsequent Events
On July 7, 2003,
the Company redeemed $487 million of Senior Notes, 8.5% due 2010. The Company
borrowed funds for this redemption from the National Grid USA Money Pool.
Premiums paid resulting from the early redemption of debt are deferred
and amortized as interest expense ratably over the lives of the related issues
in accordance with PSC directives.
On July 11, 2003, the Company issued a
note payable to National Grid USA for $350 million, 3.72% due July 31,
2009.
In July 2003, National Grid USA announced an upcoming voluntary
early retirement offer (“VERO”) to approximately 450 eligible
non-union employees in New York and New England who work in areas where
workforce reductions are targeted, including transmission, retail operations (in
New England), and corporate administrative functions such as finance, human
resources, legal, and information technology. Eligible employees will include
non-union employees in the targeted functions who will be age 55 with at least
ten years of service by December 31, 2004. National Grid USA sets the actual
retirement dates for individuals based on business operational needs.
Retirement dates will conclude no later than November 1, 2004 for the majority
of enrollees, but in some cases retirements may not occur until as late as
November 1, 2007. The Company will expense the VERO costs of its employees and
a portion of the costs of retiring National Grid USA Service Company
employees.
Item 2. Management’s Discussion and Analysis of Financial
Condition
and Results of Operations
Forward-Looking Information
This report and other presentations made by Niagara Mohawk Power
Corporation (the “Company”) contain forward-looking statements
within the meaning of Section 21E of the Securities Exchange Act of 1934, as
amended. Throughout this report, forward looking statements can be identified
by the words or phrases “will likely result”, “are expected
to”, “will continue”, “is anticipated”,
“estimated”, “projected”, “believe”,
“hopes”, or similar expressions. Although the Company believes
that, in making any such statements, its expectations are based on reasonable
assumptions, any such statements may be influenced by factors that could cause
actual outcomes and results to differ materially from those projected.
Important factors that could cause actual results to differ materially from
those in the forward-looking statements include, but are not limited
to:
(a) the impact of further electric and gas industry restructuring;
(b) the impact of general economic changes in New York;
(c)
federal and state regulatory developments and changes in law, including those
governing municiplization and exit fees, which may have a substantial adverse
impact on revenues or on the value of the Company’s assets;
(d)
federal regulatory developments concerning regional transmission
organizations;
(e) changes in accounting rules and interpretations, which
may have an adverse impact on the Company’s statements of financial
position and reported earnings;
(f) timing and adequacy of rate
relief;
(g) adverse changes in electric load;
(h) climatic changes
or unexpected changes in weather patterns; and
(i) failure to recover
costs currently deferred under the provisions Statement of Financial Accounting
Standards No. 71, “Accounting for the Effects of Certain Types of
Regulations”, as amended, and the Merger Rate Plan in effect with the New
York State Public Service Commission.
VERO
In July 2003, National Grid USA announced an upcoming voluntary early
retirement offer (“VERO”) to approximately 450 eligible non-union
employees in New York and New England who work in areas where workforce
reductions are targeted, including transmission, retail operations (in New
England), and corporate administrative functions such as finance, human
resources, legal, and information technology. Eligible employees will include
non-union employees in the targeted functions who will be age 55 with at least
ten years of service by December 31, 2004. National Grid USA sets the actual
retirement dates for individuals based on business operational needs.
Retirement dates will conclude no later than November 1, 2004 for the majority
of enrollees, but in some cases retirements may not occur until as late as
November 1, 2007. The Company will expense the VERO costs of its employees and
a portion of the costs of retiring National Grid USA Service Company
employees.
Regulatory Agreements and the Restructuring of the
Regulated Electric Utility Business
For a discussion of the Merger Rate Plan, see the Company’s Form
10-K for the fiscal year ended March 31, 2003, Part II, Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations - “Regulatory Agreements and the Restructuring of the Regulated
Electric Utility Business - Merger Rate Plan.”
Retail Bypass
Exit Fees: In approving Power Choice, the rate plan in effect prior to the
Merger Rate Plan, the PSC authorized changes to the Company’s retail
tariff providing for the recovery of an exit fee for customers bypassing the
Company’s system. The application and calculation of the exit fee is
governed by Rule 52 of the Company’s retail tariff. The exit fee also
applies to municipalities seeking to serve customers in the Company’s
service area. A number of communities served by the Company are considering
municipalizing power delivery and have requested an estimate of their exit
fees.
On September 22, 2002, a retail bypass issue was presented by a New
York Independent System Operator (“NYISO”) filing with FERC to
implement a new station service rate. The NYISO filing has allowed generators
to argue that they should be able to avoid paying state-approved charges
for retail deliveries when they take service under the NYISO tariff. On
November 22, 2002, FERC issued an order accepting the NYISO’s station
service filing, over the Company’s protest. On July 10, 2003, the Company
filed modifications to its standby service rates with the New York Public
Service Commission (the “PSC”). If approved, these modifications
would unbundle the transmission service component provided under the NYISO
tariff but would continue the Company’s own retail distribution charges to
these customers. The PSC has not acted on the filing.
In addition, a
number of generators have complained or withheld payments associated with the
Company’s delivery of station service to their generation facilities.
Cases related to these disputes are pending before FERC and the state courts,
and the Company cannot predict the outcome of these cases. Any lost revenue
attributable to the modification or elimination of Rule 52 of the
Company’s retail tariff, or from retail bypass, is recoverable under the
Merger Rate Plan provided that the lost revenue in combination with lost revenue
attributable to Rules 12 and 44 exceeds $2 million per year.
FERC Proceedings:
The FERC is
contemplating major changes to the regulatory structure that governs the
Company’s business. Several proposals are under consideration, any of
which may affect how the Company does business. The Company cannot predict which
or how many of the proposals the FERC will adopt or in what form, or whether
they will have a material impact on the Company’s financial position or
results of operations.
Generator Interconnections: On July 24, 2003, FERC issued
final rules seeking to standardize the procedures and contractual arrangements
for new generators with capacities over 20MW to interconnect to the transmission
grid. While the Company is still assessing the full impact of these rules
and whether to pursue legal or administrative challenges to them, some aspects
of the rules may have a materially adverse impact on the Company. In
particular, the rules appear to require the implementation of pro forma
agreements for generator interconnections without clearly delineating the rights
and obligations of the Company relative to an independent system operator
(“ISO”) or regional transmission organization (“RTO”)
and relative to neighboring control areas that might be affected by the
interconnection. In addition, FERC issued a formal notice of proposed
rulemaking (“NOPR”) for special rules governing the interconnection
of generators with capacities under 20MW.
Regional Transmission
Organizations: The FERC has indicated that it wants RTOs formed that would
cover a larger geographic area than ISOs. In response to an order by the FERC,
participants in the New England ISO (including Niagara Mohawk Holdings,
Inc.’s parent company, National Grid USA), the New York ISO, and the
Pennsylvania-New Jersey-Maryland ISO took part in a mediation to establish an
RTO. The FERC has not yet ruled on the mediator’s report. Pending the
FERC’s ruling, transmission owners, including the Company, have been
working to develop an alternative RTO structure. It is not clear what structure
will emerge from these negotiations or what the geographic scope will be of the
RTO in which the Company participates. In August 2002, the New York and New
England ISOs filed a proposal with the FERC to form an RTO but withdrew it in
November 2002 after several parties, including National Grid USA, filed
protests.
Standard Market Design: In July 2002, the FERC issued a
NOPR on standard market design (“SMD”). The proposed rules address
transmission pricing and planning, the role of merchant transmission, and other
issues that would directly affect the Company. The Company would have to either
meet the requirements of an independent transmission provider ("ITP") or permit
an ITP to operate its transmission facilities. Under the proposed rules, the ITP
would be required to file a new transmission tariff covering the Company’s
transmission facilities by September 30, 2004. The ITP would be authorized to
design rates (with limited input from the Company) and to file proposed changes
to the Company’s transmission rates with the FERC. The FERC has also
proposed that it assume jurisdiction over transmission rates to retail
customers. In prior orders, the FERC has held that deliveries at retail will
continue to be subject to state-approved retail charges as well as the
FERC-approved transmission rate, even if the delivery is made over transmission
facilities. The introduction of an ITP with its own transmission tariff would
require coordination between the state and federally approved charges. In
addition, to the extent the Company wishes to pursue opportunities related to
transmission projects, the FERC rulings in the SMD proceeding and other
proceedings may limit the Company's ability to do so. The Company cannot
predict when the FERC will issue final rules on SMD, or in what form, or if they
will have a material impact on the Company’s financial position or results
of operations.
Standards of Conduct: In September 2001, the FERC
initiated a NOPR regarding affiliate standards of conduct in both the electric
and gas industries. In its proposed rules, the FERC proposed a broad definition
of "energy affiliate," which would include the Company’s affiliate
National Grid USA Service Company, Inc., as well as the Company’s electric
distribution company affiliates. If the FERC were to adopt these rules as
proposed, the Company would have to change the way it interacts with its
so-called energy affiliates in a manner that could increase costs.
Incentive Pricing: In January 2003, the FERC proposed a pricing
policy statement indicating that it may provide incentives to transmission
owners to join an RTO or an independent transmission company and to invest in
new facilities. The FERC has solicited comments on this statement, and the
Company cannot predict what the final policy statement will say or whether it
will have a material impact on the Company’s financial position or results
of operations.
Financial Position, Liquidity and Capital
Resources
(See the Company’s Annual Report on Form 10-K for the period ended
March 31, 2003, Part II, Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations - “Financial Position,
Liquidity and Capital Resources”).
Short Term Liquidity. At June 30, 2003, the Company’s
principal sources of liquidity included cash and cash equivalents of $27 million
and accounts receivable of $471 million. The Company has a negative working
capital balance of $1.1 billion, primarily due to long-term debt due within one
year of $1.2 billion, which reflects a reclassification
of $ 487 million of long term notes that were redeemed
in early July, and short-term inter-company debt of $116 million.
Ordinarily, construction-related short-term borrowings are refunded with
long-term securities on a periodic basis. This approach generally results in a
working capital deficit. Working capital deficits may also be a result of the
seasonal nature of the Company’s operations as well as the timing of
differences between the collection of customer receivables and the payments of
purchased power costs. The Company believes that it will be able to meet its
working capital needs through a combination of parent company equity infusions,
long and short-term inter-company borrowings as well as cash flows generated
from operations. The resources of the Company's affiliates are sufficient to
meet the equity and debt financing requirements of the Company.
At
June 30, 2003, the Company had short-term debt outstanding of $116 million from
the inter-company money pool. The Company has regulatory approval to issue up
to $1.0 billion of short-term debt. National Grid USA and certain subsidiaries,
including the Company, operate a money pool to more effectively utilize cash
resources and to reduce outside short-term borrowings. Short-term borrowing
needs are met first by available funds of the money pool participants.
Borrowing companies pay interest at a rate designed to approximate the cost of
outside short-term borrowings. Companies that invest in the pool share the
interest earned on a basis proportionate to their average monthly investment in
the money pool. Funds may be withdrawn from or repaid to the pool at any time
without prior notice.
Net cash from operating activities was $49
million for the Company in the three months ended June 30, 2003, which was used
in funding its acquisition of utility plant and the retirement of certain debt
obligations.
The Company’s net cash used in investing
activities increased by $258 million in the three months ended June 30, 2003
as compared to the same period in the prior year. This increase was primarily
due to $250 million of cash received from Constellation in the prior period as
part of the generation asset sale.
The Company’s net cash
provided by financing activities increased $336 million in the three months
ended June 30, 2003 as compared to the same period in the prior year, primarily
due to the receipt of $350 million from the issuance of a note payable to
National Grid USA to fund early redemptions of debt and to reduce borrowings
under the money pool.
The Company had established a single-purpose,
financing subsidiary, NM Receivables LLC (“NMR”), whose business
consisted of the purchase and resale of an undivided interest in a designated
pool of the Company’s customer receivables, including accrued unbilled
revenues. No receivables have been sold to NMR during the current year. NMR had
an agreement with a bank, whereby it sold the Company’s customer
receivables to the bank. The agreement was terminated as of August 6, 2003 and
NMR will be dissolved. See the Company’s Annual Report on Form 10-K for
period ended March 31, 2003, Part II, Item 8. Financial Statements and
Supplementary Data - Note I. Commitments and Contingencies, for a further
discussion of this customer receivables program.
As stated in Item 1.,
Footnotes to the Unaudited Consolidated Financial Statements, Footnote F
“Subsequent Event”, the Company redeemed approximately $487 million
of Senior Notes, 8.5% due 2010, on July 7, 2003. The Company borrowed funds for
this redemption from the National Grid USA Money Pool. Also, on July 11, 2003,
the Company issued a note payable to National Grid USA for $350 million, 3.72%
due July 31, 2009.
As noted in the Company’s Annual Report on Form
10-K for the period ended March 31, 2003, Part II, Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
“PSC Issues”, in connection with an audit performed by the New York
Public Service Commission Staff (“Staff”), the Company reached a
settlement with the Staff that resolves all issues associated with its pension
and other postretirement benefit obligations for the period prior to the
acquisition of the Company by National Grid. The settlement was approved by the
full New York State Public Service Commission in July 2003.
Results of Operations
Earnings
Net income for the three months ended
June 30, 2003 decreased approximately $24 million compared to the three months
ended June 30, 2002. This decrease is primarily due to decreased electric and
gas sales resulting from milder weather and increased income tax expense.
Revenues
Electric revenues decreased $21
million in the three months ended June 30, 2003 as compared to the three months
ended June 30, 2002. The table below details components of this
fluctuation.
(In millions of dollars)
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Retail sales
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$ (21)
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Sales for resale
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11
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Transmission wheeling
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(11)
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Total
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$ (21)
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The decrease in retail sales was primarily attributable to a decrease
in electric kilowatt-hour (“KWh”) deliveries to 8.0 billion for the
three months ended June 30, 2003 from 8.1 billion for the three months ended
June 30, 2002. The decrease is primarily due to milder weather this year versus
last year, particularly in the month of June. This decrease is partially offset
by increased purchased energy cost recovery. Transmission wheeling revenue
includes the revenue received for power transmitted over the Company’s
transmission lines for other utilities and power generators, as well as proceeds
from auctions conducted by the New York ISO and charges from the New York ISO
for transmission congestion related items. The decrease in transmission
wheeling revenue reflects higher NY ISO charges for congestion balancing
activities. The decrease is also attributable to revenue from a one-time buy
out of a contract by a former transmission customer and the expiration of other
wheeling contracts.
Gas revenues increased $49 million in the
three months ended June 30, 2003 from the same period in prior year. This
increase is primarily a result of higher gas prices being passed through to
customers. The table below details components of this
fluctuation.
(In millions of dollars)
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Cost of purchased gas
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$ 51
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Delivery revenue
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(3)
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Other
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1
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Total
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$ 49
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The volume of gas sold for the three months ended June 30, 2003
excluding transportation of customer-owned gas decreased .492 million Dekatherms
(“Dth”) or a 3.6 percent decrease from the comparable period in
prior year.
Operating Expenses
Electricity purchased increased $2 million for the three months
ended June 30, 2003 as compared to the three months ended June 30, 2002.
Although the Company purchased less KWh of electricity for the period, this was
more than offset by the increased price of electricity due to higher fuel
costs.
Gas purchased expense increased $51 million for the three
months ended June 30, 2003 as compared to the same period in the prior year
primarily as a result of $54 million increase in gas prices and a decrease of $3
million in the volume of gas purchased.
Other operation and
maintenance expense increased $3 million for the three months ended June 30,
2003 as compared to the three months ended June 30, 2002. Increased costs of $6
million associated with an April 2003 ice storm and higher bad debt expense of
$6 million were substantially offset by reduced administrative and general
expenses resulting from merger-related efficiencies and the effects of the early
retirement program that was implemented in fiscal 2003.
Depreciation
and amortization expense increased $1 million for the three months ended
June 30, 2003 as compared to the three months ended June 30, 2002, primarily due
to fixed asset additions.
Amortization of stranded costs increased
$8 million for the three months ended June 30, 2003 as compared to the three
months ended June 30, 2002 in accordance with the Merger Rate Plan. Under the
Merger Rate Plan, which began on January 1, 2002, the stranded investment
balance per the Merger Rate plan is being amortized unevenly at levels that
increase during the term of the ten-year plan that ends December 31,
2011.
Other taxes decreased $9 million for the three months ended
June 30, 2003 as compared to the three months ended June 30, 2002. Gross
Receipts Tax (GRT) decreased $12 million primarily due to a decrease in the GRT
tax rates, reduced revenue during the quarter, and as a result of a prior period
GRT tax adjustment that was booked in the quarter ended June 30, 2002 that
increased expense in that quarter. This decrease was partially offset by an
increase in property taxes of $3 million.
Income taxes increased
$2 million for the three months ended June 30, 2003 as compared to the three
months ended June 30, 2002 primarily due to lower book taxable income offset by
a $9 million adjustment.
Interest charges decreased $7 million for
the three months ended June 30, 2003 as compared to the three months ended June
30, 2002, primarily due to the repayment of third-party debt using related party
debt at lower interest rates.
Item 3. Quantitative and Qualitative
Disclosure About Market Risk
There were no material changes in the Company’s market risk or market
risk strategies during the three months ended June 30, 2003. For a detail
discussion of market risk, see the Company’s Annual Report on Form 10-K
for fiscal year ended March 31, 2003, Part II, Item 7A. Quantitative and
Qualitative Disclosures About Market Risk.
Item 4. Controls and Procedures
The Company maintains disclosure controls and procedures which are designed
to provide reasonable assurance that material information relating to the
Company, including its consolidated subsidiaries, is made known to management by
others within those entities, particularly during the period in which this
report is being prepared. The Company maintains a Disclosure Committee, which
is made up of several key management employees and which reports directly to the
Chief Financial Officer and Chief Executive Officer. The Disclosure Committee
monitors and evaluates these disclosure controls and procedures. The Chief
Financial Officer and Chief Executive Officer have evaluated the effectiveness
of the Company’s disclosure controls and procedures as of the end of the
period covered by this report. Based on this evaluation, it was determined that
these disclosure controls and procedures were effective in providing reasonable
assurance during the period covered in this report. There were no significant
changes in internal controls or in other factors that could significantly affect
internal controls subsequent to the date of the most recent
evaluation.
PART II – OTHER INFORMATION
Item 1. Legal Proceedings
For a discussion of pending legal proceedings, see
Note B, Contingencies, in Part I, Item 1. Notes to Unaudited Consolidated
Financial Statements.
Item 6. Exhibits and Reports on Form 8-K
(a)
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Exhibits
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The exhibit index is incorporated herein by reference.
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(b)
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Reports on Form 8-K
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On April 14, 2003, the Company filed a Current Report on Form 8-K
containing Item 5.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report on Form 10-Q for the quarter ended
June 30, 2003 to be signed on its behalf by the undersigned thereunto duly
authorized.
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NIAGARA MOHAWK POWER CORPORATION
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Date: August 13, 2003
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By
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/s/ Edward A.
Capomacchio
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Edward A. Capomacchio
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Authorized Officer and Controller and Principal Accounting
Officer
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EXHIBIT INDEX
Exhibit Number
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Description
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31.1
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Certification of Principal Executive Officer
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31.2
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Certification of Principal Financial Officer
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32
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Certifications under Section 1350
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