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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 December 31, 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 File
Number
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|
Registrant, State of
Incorporation Address and Telephone
Number
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|
I.R.S.
Employer Identification No.
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1-2987
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|
Niagara Mohawk Power
Corporation (a New York
corporation) 300 Erie Boulevard
West Syracuse, New York
13202 315.474.1511
|
|
15-0265555
|
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 February 3, 2004, were as
follows:
Registrant
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Title
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Shares Outstanding
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|
|
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Niagara Mohawk Power Corporation
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Common Stock, $1.00 par
value (all held by Niagara
Mohawk Holdings,
Inc.)
|
|
187,364,863
|
|
|
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|
|
|
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NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
FORM 10-Q - For the Quarter Ended December 31,
2003
|
|
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PART I – FINANCIAL INFORMATION
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Item 1.
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Unaudited Financial Statements
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Condensed Consolidated Statements of Operations and Comprehensive
Income
|
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Condensed Consolidated Statements of Retained Earnings
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Condensed Consolidated Balance Sheets
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Condensed Consolidated Statements of Cash Flows
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Notes to Unaudited Consolidated Financial Statements
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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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Item 3.
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Quantitative and Qualitative Disclosures About Market Risk
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Item 4.
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Controls and Procedures
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PART II – OTHER INFORMATION
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Item 1.
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Legal Proceedings
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Item 6.
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Exhibits and Reports on Form 8-K
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Signature
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Exhibit Index
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PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
|
Condensed Consolidated Statements of
Operations
|
(In thousands of dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Three Months Ended
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Nine Months Ended
|
|
|
|
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December 31,
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December 31,
|
|
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2003
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2002
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2003
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2002
|
Operating revenues:
|
|
|
|
|
|
|
|
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Electric
|
$ 782,497
|
|
$ 805,351
|
|
$ 2,400,183
|
|
$ 2,463,960
|
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Gas
|
177,174
|
|
164,927
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|
439,512
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|
371,900
|
|
|
|
Total operating revenues
|
959,671
|
|
970,278
|
|
2,839,695
|
|
2,835,860
|
Operating expenses:
|
|
|
|
|
|
|
|
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Purchased energy:
|
|
|
|
|
|
|
|
|
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Electricity purchased
|
360,958
|
|
375,692
|
|
1,167,524
|
|
1,178,341
|
|
|
Gas purchased
|
97,706
|
|
83,665
|
|
240,174
|
|
169,222
|
|
Other operation and maintenance
|
227,731
|
|
211,337
|
|
601,926
|
|
618,728
|
|
Depreciation and amortization
|
49,938
|
|
49,789
|
|
150,280
|
|
148,000
|
|
Amortization of stranded costs
|
43,517
|
|
35,299
|
|
130,552
|
|
105,898
|
|
Other taxes
|
54,492
|
|
64,981
|
|
168,613
|
|
191,852
|
|
Income taxes
|
23,469
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|
24,552
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|
72,913
|
|
58,020
|
|
|
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Total operating expenses
|
857,811
|
|
845,315
|
|
2,531,982
|
|
2,470,061
|
Operating income
|
101,860
|
|
124,963
|
|
307,713
|
|
365,799
|
|
Other income (deduction), net
|
(1,779)
|
|
(731)
|
|
(4,627)
|
|
(4,962)
|
Operating and other income
|
100,081
|
|
124,232
|
|
303,086
|
|
360,837
|
Interest:
|
|
|
|
|
|
|
|
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Interest on long-term debt
|
49,482
|
|
72,017
|
|
171,955
|
|
243,806
|
|
Interest on debt to associated companies
|
16,083
|
|
6,338
|
|
39,890
|
|
8,436
|
|
Other interest
|
2,858
|
|
8,326
|
|
13,674
|
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20,374
|
|
|
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Total interest expense
|
68,423
|
|
86,681
|
|
225,519
|
|
272,616
|
Net income
|
31,658
|
|
37,551
|
|
77,567
|
|
88,221
|
|
Dividends on preferred stock
|
841
|
|
1,388
|
|
3,589
|
|
4,183
|
Income available to common shareholder
|
$ 30,817
|
|
$ 36,163
|
|
$ 73,978
|
|
$ 84,038
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Condensed Consolidated Statements of Comprehensive
Income
|
(In thousands of dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
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Nine Months Ended
|
|
|
|
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December 31,
|
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December 31,
|
|
|
|
|
2003
|
|
2002
|
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2003
|
|
2002
|
Net income
|
$ 31,658
|
|
$ 37,551
|
|
$ 77,567
|
|
$ 88,221
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
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Unrealized gains (losses) on securities
|
|
|
|
|
|
|
|
|
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(net of taxes of $451, $109, $1,047
|
|
|
|
|
|
|
|
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and ($589), respectively)
|
676
|
|
164
|
|
1,570
|
|
(884)
|
|
Hedging activity (net of taxes of $4,010,
|
|
|
|
|
|
|
|
|
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$355, $851 and $1,129, respectively)
|
6,015
|
|
533
|
|
1,276
|
|
1,693
|
|
Change in additional minimum pension
|
|
|
|
|
|
|
|
|
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Liability
|
-
|
|
-
|
|
(1,534)
|
|
-
|
|
|
|
Total other comprehensive income
|
6,691
|
|
697
|
|
1,312
|
|
809
|
Comprehensive income
|
$ 38,349
|
|
$ 38,248
|
|
$ 78,879
|
|
$ 89,030
|
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
|
Condensed Consolidated Statements of Retained
Earnings
|
(In thousands of dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
|
December 31,
|
|
December 31,
|
|
|
|
|
2003
|
|
2002
|
|
2003
|
|
2002
|
Retained earnings at beginning of period
|
$ 128,867
|
|
$ 13,278
|
|
$ 85,706
|
|
$ 29,317
|
|
Net income
|
31,658
|
|
37,551
|
|
77,567
|
|
88,221
|
|
Dividends on preferred stock
|
(841)
|
|
(1,388)
|
|
(3,589)
|
|
(4,183)
|
|
Dividends to Niagara Mohawk Holdings, Inc.
|
-
|
|
-
|
|
-
|
|
(63,914)
|
Retained earnings at end of period
|
$ 159,684
|
|
$ 49,441
|
|
$ 159,684
|
|
$ 49,441
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral
part of these financial statements
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
|
Condensed Consolidated Balance Sheets
|
(In thousands of dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
March 31,
|
|
|
|
2003
|
|
|
|
2003
|
ASSETS
|
|
|
|
|
|
|
|
Utility plant, at original cost:
|
|
|
|
|
|
|
|
|
Electric plant
|
|
|
$ 5,149,531
|
|
|
|
$ 5,091,435
|
|
Gas plant
|
|
|
1,466,361
|
|
|
|
1,402,215
|
|
Common Plant
|
|
|
335,845
|
|
|
|
351,987
|
|
Construction work-in-progress
|
|
|
143,287
|
|
|
|
143,949
|
|
|
|
Total utility plant
|
|
|
7,095,024
|
|
|
|
6,989,586
|
|
Less: Accumulated depreciation and amortization
|
|
2,358,623
|
|
|
|
2,342,757
|
|
|
|
Net utility plant
|
|
|
4,736,401
|
|
|
|
4,646,829
|
Goodwill
|
|
1,225,742
|
|
|
|
1,225,742
|
Other property and investments
|
|
|
81,406
|
|
|
|
94,314
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
12,692
|
|
|
|
30,038
|
|
Restricted cash (Note A)
|
|
|
31,523
|
|
|
|
25,350
|
|
Accounts receivable (less reserves of $122,500 and
|
|
|
|
|
|
|
|
|
$100,200, respectively, and includes receivables
|
|
|
|
|
|
|
|
|
to associated companies of $247 and $227,
|
|
|
|
|
|
|
|
|
respectively)
|
|
|
532,579
|
|
|
|
543,280
|
|
Materials and supplies, at average cost:
|
|
|
|
|
|
|
|
|
|
Gas storage
|
|
|
79,016
|
|
|
|
4,795
|
|
|
Other
|
|
|
16,804
|
|
|
|
16,401
|
|
Derivative instruments
|
|
|
11,267
|
|
|
|
16,354
|
|
Prepaid taxes
|
|
|
35,421
|
|
|
|
90,770
|
|
Current deferred income taxes
|
|
|
58,761
|
|
|
|
35,458
|
|
Other
|
|
|
12,110
|
|
|
|
10,483
|
|
|
|
Total current assets
|
|
|
790,173
|
|
|
|
772,929
|
Regulatory and other non-current assets:
|
|
|
|
|
|
|
|
|
Regulatory assets (Note B):
|
|
|
|
|
|
|
|
|
|
Stranded costs
|
|
|
3,083,150
|
|
|
|
3,213,657
|
|
|
Swap contracts regulatory asset
|
|
|
712,170
|
|
|
|
793,028
|
|
|
Regulatory tax asset
|
|
|
143,861
|
|
|
|
143,765
|
|
|
Deferred environmental restoration costs (Note C)
|
|
332,000
|
|
|
|
301,000
|
|
|
Pension and postretirement benefit plans
|
|
595,102
|
|
|
|
713,779
|
|
|
Loss on reacquired debt
|
|
|
74,572
|
|
|
|
48,255
|
|
|
Other
|
|
|
294,480
|
|
|
|
242,290
|
|
|
|
Total regulatory assets
|
|
|
5,235,335
|
|
|
|
5,455,774
|
|
Other non-current assets
|
|
|
52,314
|
|
|
|
48,171
|
|
|
|
Total regulatory and other non-current assets
|
|
5,287,649
|
|
|
|
5,503,945
|
|
|
|
|
Total assets
|
|
|
$ 12,121,371
|
|
|
|
$ 12,243,759
|
The
accompanying notes are an integral part of these financial
statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
|
Condensed Consolidated Balance Sheets
|
(In thousands of dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
March 31,
|
|
|
|
2003
|
|
|
|
2003
|
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
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
|
|
|
2,929,501
|
|
|
|
2,621,440
|
|
|
Accumulated other comprehensive income (Note E)
|
|
1,328
|
|
|
|
16
|
|
|
Retained earnings
|
|
|
159,684
|
|
|
|
85,706
|
|
|
|
Total common stockholder's equity
|
|
|
3,277,878
|
|
|
|
2,894,527
|
|
Preferred equity:
|
|
|
|
|
|
|
|
|
|
Cumulative preferred stock ($100 par value, optionally
redeemable)
|
|
41,170
|
|
|
|
42,625
|
|
|
|
Authorized - 3,400,000 shares
|
|
|
|
|
|
|
|
|
|
|
Issued and outstanding - 411,705 and 426,248 shares, respectively
|
|
|
|
|
|
|
|
Cumulative preferred stock ($25 par value, optionally redeemable)
|
|
25,155
|
|
|
|
55,655
|
|
|
|
Authorized - 19,600,000 shares
|
|
|
|
|
|
|
|
|
|
|
Issued and outstanding – 503,100 and 1,113,100 shares,
respectively
|
|
|
|
|
|
Long-term debt
|
|
|
2,272,868
|
|
|
|
3,453,989
|
|
Long-term debt to affiliates
|
|
|
1,200,000
|
|
|
|
500,000
|
|
|
|
Total capitalization
|
|
|
6,817,071
|
|
|
|
6,946,796
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable (including payables to associated companies
|
|
299,235
|
|
|
|
375,767
|
|
|
of $41,848 and $34,029, respectively)
|
|
|
|
|
|
|
|
|
Customers' deposits
|
|
|
25,665
|
|
|
|
25,843
|
|
Accrued interest
|
|
|
54,132
|
|
|
|
108,927
|
|
Derivative instruments
|
|
|
12,914
|
|
|
|
-
|
|
Short-term debt to affiliates
|
|
|
701,600
|
|
|
|
198,000
|
|
Current portion of long-term debt
|
|
|
533,022
|
|
|
|
611,652
|
|
Other
|
|
|
135,409
|
|
|
|
111,904
|
|
|
Total current liabilities
|
|
|
1,761,977
|
|
|
|
1,432,093
|
Other non-current liabilities:
|
|
|
|
|
|
|
|
|
Accumulated deferred income taxes
|
|
|
1,226,960
|
|
|
|
1,157,796
|
|
Liability for swap contracts
|
|
|
712,170
|
|
|
|
793,028
|
|
Employee pension and other benefits
|
|
|
585,742
|
|
|
|
884,204
|
|
Liability for environmental remediation costs (Note C)
|
|
332,000
|
|
|
|
301,000
|
|
Other
|
|
685,451
|
|
|
|
728,842
|
|
|
Total other non-current liabilities
|
|
|
3,542,323
|
|
|
|
3,864,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Notes B and C)
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization and liabilities
|
|
|
$ 12,121,371
|
|
|
|
$ 12,243,759
|
The
accompanying notes are an integral part of these financial
statements.
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY
COMPANIES
|
Condensed Consolidated Statements of Cash
Flows
|
(In thousands of dollars)
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months ended December 31,
|
|
|
|
|
|
|
|
|
|
2003
|
|
|
|
2002
|
Operating activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
|
$ 77,567
|
|
|
|
$ 88,221
|
|
Adjustments to reconcile net income to net cash
|
|
|
|
|
|
|
|
|
|
provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
150,280
|
|
|
|
148,000
|
|
|
Amortization of stranded costs
|
|
|
130,552
|
|
|
|
105,898
|
|
|
Provision for deferred income taxes
|
|
|
45,765
|
|
|
|
2,476
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
Decrease in accounts receivable, net
|
|
10,701
|
|
|
|
20,957
|
|
|
|
Increase in materials and supplies
|
|
|
(74,624)
|
|
|
|
(45,036)
|
|
|
|
Decrease in prepaid taxes
|
|
55,349
|
|
|
|
17,491
|
|
|
|
Increase (decrease) in accounts payable and accrued expenses
|
|
(52,196)
|
|
|
|
22,420
|
|
|
|
Increase (decrease) in accrued interest and taxes
|
|
(54,795)
|
|
|
|
(33,890)
|
|
|
|
Increase (decrease) in employee pension and other benefits
|
|
(298,462)
|
|
|
|
185,777
|
|
|
|
Decrease (increase) in pension and postretirement benefit plans
regulatory asset
|
|
118,677
|
|
|
|
40,483
|
|
|
|
Other, net
|
|
(93,629)
|
|
|
|
(140,067)
|
|
|
|
|
Net cash provided by operating activities
|
|
15,185
|
|
|
|
412,730
|
Investing activities:
|
|
|
|
|
|
|
|
|
Construction additions
|
|
|
(228,954)
|
|
|
|
(172,388)
|
|
Payments received on notes associated with the sale of generation
assets
|
-
|
|
|
|
249,799
|
|
Change in restricted cash
|
|
|
(6,173)
|
|
|
|
(1,296)
|
|
Other investments
|
|
13,725
|
|
|
|
833
|
|
Other
|
|
|
(12,347)
|
|
|
|
(11,829)
|
|
|
|
|
Net cash provided by (used in) investing activities
|
|
(233,749)
|
|
|
|
65,119
|
Financing activities:
|
|
|
|
|
|
|
|
|
Dividends paid on preferred stock
|
|
|
(3,589)
|
|
|
|
(4,183)
|
|
Common stock dividend paid to Niagara Mohawk Holdings, Inc.
|
|
-
|
|
|
|
(150,000)
|
|
(of which $86 million was a return of capital)
|
|
|
|
|
|
|
|
|
Reductions in long-term debt
|
|
|
(1,273,890)
|
|
|
|
(667,626)
|
|
Proceeds from long-term debt to affiliates
|
|
|
700,000
|
|
|
|
500,000
|
|
Redemption of preferred stock
|
|
|
(33,903)
|
|
|
|
(1,589)
|
|
Net change in short-term debt to affiliates
|
|
|
503,600
|
|
|
|
(128,000)
|
|
Equity contribution from parent
|
|
|
309,000
|
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
|
2,993
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
201,218
|
|
|
|
(448,405)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
(17,346)
|
|
|
|
29,444
|
Cash and cash equivalents, beginning of period
|
|
|
30,038
|
|
|
|
9,882
|
Cash and cash equivalents, end of period
|
|
|
$ 12,692
|
|
|
|
$ 39,326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures of cash flow information:
|
|
|
|
|
|
|
|
|
Interest paid
|
|
|
$ 274,921
|
|
|
|
$ 268,901
|
|
Income taxes paid
|
|
|
$ 15,372
|
|
|
|
$ 11,829
|
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. The March 31, 2003 condensed balance sheet data
included in this quarterly report on Form 10-Q was derived from audited
financial statements included in the Company’s Annual Report on Form 10-K
for the year ended March 31, 2003. As such, the March 31, 2003 balance sheet
included in this Form 10-Q is considered unaudited as it does not include all
the footnote disclosures contained in the Company’s Form 10-K. These
financial statements and the 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 and nine-month periods ended December 31, 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.
Restricted Cash: Restricted cash consists of margin accounts
for hedging activity, health care claims deposits, New York State Department of
Conservation securitization for certain site cleanup, and worker’s
compensation premium deposit.
Reclassifications: Certain amounts
from prior years have been reclassified in the accompanying consolidated
financial statements to conform to the current year presentation.
New Accounting Standards: In December 2003 the Financial
Accounting Standards Board revised Statement on Financial Accounting Standards
No. 132, “Employers’ Disclosures about Pensions and Other
Postretirement Benefits” (“FAS 132”). The revised statement
retains the disclosure requirements contained in the original statement and adds
new disclosures about the assets, obligations, cash flows, and net periodic
benefit cost of defined benefit pension and other defined benefit postretirement
plans. The revised FAS 132 is effective for fiscal years ending after December
15, 2003 and for interim periods beginning thereafter, so it does not apply to
the Company in the quarter ended December 31, 2003. FAS 132 does not change the
measurement or recognition of the aforementioned plans and, as such, the
adoption of this statement will not have any effect on the Company’s
financial position, results of operations, or cash flows.
NOTE B
– RATE AND REGULATORY ISSUES
The Company’s financial
statements conform to Generally Accepted Accounting Principles, including the
accounting principles for rate-regulated entities. Substantively, Statement of
Financial Accounting Standards No. 71 “Accounting for the Effects of
Certain Types of Regulation” (“FAS 71”) 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 $5.2 billion at December 31, 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 FAS
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 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
FAS 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 FAS 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 most 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 C –
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 in
accordance with federal, state and local environmental agency requirements to
investigate and remediate, as necessary, 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 is currently aware of 111 sites with which it
may be associated, including 60 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 $332 million which
is reflected in the Company’s Condensed Consolidated Balance Sheets at
December 31, 2003. The potential high end of the range is presently estimated
at approximately $555 million. The reserve has been increased by $31 million
since March 31, 2003 primarily due to the accrual of an additional $26 million
associated with its Harbor Point site after the State of New York Supreme
Court’s denial of the Company’s Article 78 petition which had
incorporated lower costs than the State’s recommended alternative as set
forth in the Record of Decision.
On November 7, 2003, the New York
State Department of Environmental Conservation (“DEC”) executed a
new multi-site consent order with the Company. This new order supersedes the
original 1992 order for the owned Manufactured Gas Plant (“MGP”)
sites and provides the Company with many benefits including the ability to
contest future DEC decisions and scheduling flexibility in the investigation and
remediation of MGP sites.
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. On
October 27, 2003 the court dismissed the petition. In late November 2003, AMP
made a timely filing to appeal the court’s decision.
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. By order dated
December 31, 2003, the court granted the state’s motion to leave to amend
the complaint to assert claims against NRG and the Company based on violations
of the plants’ operating permits. The court order brings NRG back into
the case for injunctive relief but does not disturb the prior ruling that
monetary penalties for Clean Air Act violations five years prior to the suit are
barred by the statute of limitations.
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 had been stayed. The stay has now been lifted by
virtue of the bankruptcy court’s confirmation of NRG’s plan of
reorganization on November 24, 2003 and those of Dunkirk Power L.L.C. and
Huntley L.L.C.’s on November 25, 2003. The Company cannot predict the
outcome of this litigation.
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
with NRG Energy, Inc., “NRG”). 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 emerged from bankruptcy in December 2003 and the Plants did
not discharge their debt. According to the Company’s records, the
Defendants owed the Company approximately $35 million as of the date of the
bankruptcy filing.
The FERC has not yet rendered a decision
on this matter. However, on December 23, 2003, it issued two orders on related
complaints filed by AES Somerset, L.L.C. (“AES”) and Nine Mile Point
Nuclear Station, L.L.C., both of which are station service customers of the
Company. The orders do not control the outcome of the NRG case but may be
indicative of the FERC’s disposition in station service matters. The two
orders allow these generators to net their station service electricity over a
30-day period and to avoid state-authorized charges for deliveries made over
distribution facilities. While it is not entirely clear from reading the AES
order, it is possible to construe it to have retroactive effect back to the date
the plant was sold to AES by a third party. The net effect of these decisions
is that the two generators will no longer have to pay the Company for station
service charges for electricity. The Company is seeking rehearing on these
decisions and is awaiting a decision on NRG. In the event that the FERC
orders are finally upheld, the Company believes it would recover the lost
revenues under its rate plans.
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
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, 2003
|
|
|
|
|
|
|
|
Operating revenue
|
$ 64
|
|
$ 719
|
|
$ 177
|
|
$ 960
|
|
Operating income before
|
|
|
|
|
|
|
|
|
|
income taxes
|
21
|
|
86
|
|
18
|
|
125
|
|
Depreciation and amortization
|
9
|
|
32
|
|
9
|
|
50
|
|
Amortization of stranded costs
|
-
|
|
44
|
|
-
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December 31, 2002
|
|
|
|
|
|
|
|
Operating revenue
|
$ 55
|
|
$ 750
|
|
$ 165
|
|
$ 970
|
|
Operating income before
|
|
|
|
|
|
|
|
|
|
income taxes
|
15
|
|
114
|
|
21
|
|
150
|
|
Depreciation and amortization
|
8
|
|
33
|
|
9
|
|
50
|
|
Amortization of stranded costs
|
-
|
|
35
|
|
-
|
|
35
|
Nine Months Ended December 31, 2003
|
|
|
|
|
|
|
|
Operating revenue
|
$ 191
|
|
$ 2,209
|
|
$ 440
|
|
$ 2,840
|
|
Operating income before
|
|
|
|
|
|
|
|
|
|
income taxes
|
70
|
|
285
|
|
26
|
|
381
|
|
Depreciation and amortization
|
26
|
|
97
|
|
27
|
|
150
|
|
Amortization of stranded costs
|
-
|
|
131
|
|
-
|
|
131
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended December 31, 2002
|
|
|
|
|
|
|
|
Operating revenue
|
$ 185
|
|
$ 2,279
|
|
$ 372
|
|
$ 2,836
|
|
Operating income before
|
|
|
|
|
|
|
|
|
|
income taxes
|
68
|
|
331
|
|
25
|
|
424
|
|
Depreciation and amortization
|
24
|
|
97
|
|
27
|
|
148
|
|
Amortization of stranded costs
|
-
|
|
106
|
|
-
|
|
106
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions of dollars)
|
|
|
|
|
|
Electric -
|
|
Electric -
|
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
Distribution
|
|
Gas
|
|
Corporate
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2003
|
|
|
|
|
|
|
|
|
|
Goodwill
|
$ 303
|
|
$ 709
|
|
$ 214
|
|
$ -
|
|
$ 1,226
|
|
Total assets
|
$ 1,456
|
|
$ 8,603
|
|
$ 1,690
|
|
$ 372
|
|
$ 12,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
1,570
|
|
|
|
|
|
1,570
|
|
Hedging activity, net of taxes
|
|
|
|
|
|
1,276
|
|
1,276
|
|
Change in minimum pension liability
|
|
|
|
(1,534)
|
|
|
|
(1,534)
|
December 31, 2003
|
|
$ 986
|
|
$ (1,534)
|
|
$ 1,876
|
|
$ 1,328
|
NOTE F – VOLUNTARY EARLY RETIREMENT OFFER
In the
quarter ended December 31, 2003, the enrollment period ended with respect to the
voluntary early retirement offer (“VERO”) made by National Grid USA.
The VERO was made to eligible non-union employees in New York and New England in
areas including transmission, retail operations (in New England), and corporate
administrative functions such as finance, human resources, legal, and
information technology. The majority of employees will retire by November 1,
2004, with the remainder retiring by November 1, 2007. The Company expensed
approximately $19 million of VERO costs in the fiscal quarter ended December 31,
2003. This amount included approximately $9 million allocated to the Company
from National Grid USA Service Company, an affiliate. A total of 53 employees
of the Company accepted the VERO.
NOTE G – PENSION SETTLEMENT
LOSSES
As a result of the decline in the stock market since the close
of the merger and a reduction in the discount rate applied to pension
obligations, the Company has an unrecognized loss in its pension plans. Under
Statement of Financial Accounting Standards No. 88 “Employers’
Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and
for Termination Benefits” (“FAS 88”), the Company must
recognize a portion of this loss immediately when payouts from the plans exceed
a certain amount. Accordingly, the Company recognized a loss of $29.4 million
in its fiscal year ended March 31, 2003. In February 2004, the Company reached
an agreement with PSC Staff that would provide rate recovery for $14.5 million
of the $29.4 million pension settlement loss. The agreement also covers the
funding of the entire settlement loss to benefit plan trust funds. This
agreement is subject to approval by the full New York State Public Service
Commission. Under the agreement, within 30 days of approval, the Company will
fund the nonrecoverable portion of this loss.
In December 2003, the
Company recorded a new pension settlement loss of $20 million under FAS 88
associated with pension payouts in its fiscal year ending March 31, 2004.
Additional losses may be recorded in the remaining months of the fiscal year.
The Company plans to file a petition with the PSC seeking to recover these
losses.
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) acts of terrorism;
(i) climatic changes or unexpected changes in weather patterns;
and
(j) failure to recover costs currently deferred under the provisions of
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
(“PSC”).
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:
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 that leave the Company’s
system. The retail tariff governs the application and calculation of the exit
fee. 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 different type of retail bypass
issue was presented in a filing with FERC by the New York Independent System
Operator (“NYISO”) seeking to implement a new station service rate.
On November 22, 2002, FERC issued an order accepting the NYISO’s new rate,
over the Company’s protest. The NYISO order 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 July 10,
2003, the Company filed modifications to its standby service rates with the PSC,
which the PSC approved on November 25, 2003. The tariff modifications unbundle
the transmission service component provided under the NYISO tariff but continue
the Company’s own retail distribution charges to these customers.
A
number of generators have complained or withheld payments associated with the
Company’s delivery of station service to their generation facilities,
including NRG Energy, Inc. (For a description of the NRG station service
matter, see Item 1, Note C – Contingencies.) On December 23, 2003, FERC
issued two orders on complaints filed by AES Somerset, L.L.C.
(“AES”) and Nine Mile Point Nuclear Station, L.L.C. (“Nine
Mile”), both of which are station service customers of the Company. The
two orders allow these generators to net their station service electricity over
a 30-day period and to avoid state-authorized charges for deliveries made over
distribution facilities. While it is not entirely clear from reading the AES
order, it is possible to construe it to have retroactive effect back to the date
the plant was sold to AES by a third party. The net effect of these FERC
decisions is that the two generators will no longer have to pay the Company for
station service charges for electricity. The FERC orders are in direct conflict
with the orders of the NYPSC on station service rates. The FERC orders, if
upheld, will permit these generators to completely bypass the Company’s
state-jurisdictional retail charges, including those set forth in the filing
that was approved by the PSC on November 25, 2003. The Company is seeking
rehearing on these FERC decisions but cannot predict the outcome of these
cases.
Other generators have also taken the position that
they are not required to pay station service charges, on grounds similar to
those alleged in the AES and Nine Mile complaints. These FERC orders have
increased the risk that ISOs will be able to bypass local distribution company
charges (including stranded cost recovery charges) when providing transmission
level power to generating stations and, potentially, that other customers will
also be able to bypass those charges when taking service at transmission
voltages. The FERC orders appear to be limited to delivery service provided to
generators in the context of station service, but if FERC were to extend these
orders to other customers, the Company could experience a potentially
significant reduction in revenue. In the event that the FERC orders are
finally upheld, the Company believes it would recover the lost revenues under
its rate plans.
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. Regional transmission organizations (“RTOs”) and
independent system operators (“ISOs”) and individual transmission
owners in the affected regions were required to make compliance filings by
January 20, 2004. The Company sought rehearing of various aspects of these
rules which could have materially adverse impacts on the Company, and it is
actively working in the regional stakeholder process to implement the rules in a
manner that will mitigate such adverse impacts. In particular, the rules
appear to require the implementation of pro forma agreements for generator
interconnections without recognizing the Company’s rights under the
Federal Power Act to set the rates, terms and conditions of access to its
transmission facilities, and without clearly delineating the rights and
obligations of the Company relative to an ISO or an RTO and relative to
neighboring control areas that might be affected by the interconnection.
In addition, FERC issued a formal notice of proposed rulemaking for special
rules governing the interconnection of generators with capacities under
20MW.
On January 20, 2004, the Company made a compliance filing jointly
with other New York transmission owners and the New York ISO
(“NYISO”) to address interconnections to transmission facilities in
New York. In this filing, NYISO and the New York transmission owners sought
authority to implement variations from FERC’s pro forma agreement and
procedures primarily to reflect current practices but also to address concerns
similar to those raised by the Company on rehearing. In particular, the filing
sought variations with respect to cost allocation, standards for
interconnection, authority to file amendments to the pro forma documents and
specific interconnection agreements, and other issues. The filing parties
also sought to defer compliance with respect to interconnections to distribution
facilities, which appeared to be within the scope of FERC’s order but
which is also the subject to various pending rehearing requests concerning
FERC’s jurisdiction and a separate rulemaking proceeding. It is unclear
whether these changes will be accepted by FERC or whether FERC may require
revisions to the compliance filings.
Regional Transmission
Organizations: On September 16, 2003, FERC issued an order terminating its
proceeding on the NYISO’s filing of several years ago to become an RTO.
FERC had previously rejected that filing on several grounds, and a rehearing
request by the New York transmission owners, including the Company, was pending
for some time. On October 23, 2003, the transmission owners filed a petition
for rehearing of FERC’s September 16, 2003 order because it terminated the
proceeding without addressing the transmission owners’ pending rehearing
petition. The transmission owners took this action due to concern that the
prior adverse order, if left unchallenged, could be damaging precedent. On
December 22, 2003, FERC issued an order indicating that the September 16, 2003
order did not reach any substantive ruling on the pending rehearing requests.
Although discussions are ongoing in New York on whether and how to change the
governance structure of the NYISO to better align with FERC’s requirements
for RTOs (including the requirement that the market operator be independent from
the market), there are currently no formal efforts underway in New York to
establish an RTO.
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.
CRITICAL ACCOUNTING POLICIES
Certain critical accounting policies are based on assumptions and
conditions that, if changed, could have a material effect on the financial
condition, results of operations and liquidity of the Company. 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 - “Critical Accounting Policies”
for a detailed discussion of these policies.
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 December 31, 2003, the Company’s
principal sources of liquidity included cash and cash equivalents of
approximately $13 million and accounts receivable of approximately $533 million.
The Company has a negative working capital balance of $972 million, primarily
due to short-term debt due to affiliates of $702 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
December 31, 2003, the Company had short-term debt outstanding of approximately
$702 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 provided by
operating activities was approximately $15 million for the Company in the
nine months ended December 31, 2003. The primary reason for the decline in
operating cash flow was the funding of the pension and postretirement benefits
trusts pursuant to a settlement with the PSC 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. (For a more detailed
discussion, see the Company’s Form 10-K, Part II, Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations - “PSC Issues”.)
The Company’s net cash
used in investing activities increased by approximately $299 million in the
nine months ended December 31, 2003 as compared to the same period in the prior
year. This increase was primarily due to $250 million of cash received last
year in connection with a November 2002 nuclear station sale, and a $57 increase
in capital expenditures from the prior year.
The Company’s net
cash provided by financing activities increased by approximately $650
million in the nine months ended December 31, 2003 as compared to the same
period in the prior year. This increase is primarily due to an equity
contribution of $309 million in the current period from the Company’s
parent company used to fund contributions to the pension and postretirement
trusts. Reductions in long-term debt were funded through long-term and
short-term intercompany borrowings which contributed to approximately $225
million of net cash inflow. These inflows were partially offset by $34 million
of buybacks of preferred stock.
Long-Term Liquidity. The
Company’s total capital requirements consist of amounts for its
construction program, working capital needs, and maturing debt issues. See the
Company’s Annual Report on 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 - “Financial Position, Liquidity and
Capital Resources” for further information on long-term
commitments.
RESULTS OF OPERATIONS
EARNINGS
Net income for the three and nine months ended
December 31, 2003 decreased by approximately $1 million and $6 million,
respectively, from the comparable periods in the prior year. The decrease for
the nine months is primarily due to weather-driven lower sales margins offset by
lower interest costs.
REVENUES
Electric revenues
decreased $23 and $64 million in the three and nine months ended December 31,
2003, respectively, from the comparable periods in the prior year. The table
below details components of this fluctuation.
Period ended December 31, 2003
|
(In millions of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
|
Retail sales
|
$ (35)
|
|
$ (87)
|
|
|
Sales for resale
|
8
|
|
26
|
|
|
Transmission
|
4
|
|
(3)
|
|
|
|
Total
|
$ (23)
|
|
$ (64)
|
|
The decrease in retail sales for the three and nine months ended
December 31, 2003 was primarily attributable to a decrease in electric
kilowatt-hour (“KWh”) deliveries to 8.2 billion and 25.0 billion
from 8.4 billion and 25.8 billion, respectively, in the comparable periods in
the prior year. The KWh decrease is due to a return to more normal weather in
the current fiscal year, versus the more extreme weather last year, particularly
in the months of June, July and August for the nine months. The effects of
weather account for 94% and 86% of the decline in KWh sales for the quarter and
nine months, respectively. For the quarter and nine months, revenue comparisons
were also affected by lower purchase power costs (due to lower demand) being
recovered through the commodity adjustment clause.
The increase in
transmission revenue for the three months ended December 31, 2003 is due to
prior year activity in which certain pre-merger revenues that were initially
recorded in the first half of fiscal 2003 to transmission revenue, were reversed
and recorded to goodwill in the third quarter of fiscal 2003. The decrease in
transmission revenue for the nine months ended December 31, 2003 is due to a
prior period adjustment recorded in fiscal 2003 related to regulatory
deferrals.
Gas revenues increased $12 million and $68 million in
the three and nine months ended December 31, 2003, respectively, from the
comparable periods in the prior year. These increases are primarily a result of
higher gas prices being passed through to customers, offset by milder weather
during the three months ended December 31, 2003. The table below details
components of this fluctuation.
Period ended December 31, 2003
|
(In millions of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
|
Cost of purchased gas
|
$ 14
|
|
$ 71
|
|
|
Delivery revenue
|
(2)
|
|
(3)
|
|
|
Other
|
-
|
|
-
|
|
|
|
Total
|
$ 12
|
|
$ 68
|
|
The volume of gas sold for the three and nine months ended December 31,
2003, excluding transportation of customer-owned gas, decreased approximately
1.1 million Dekatherms (“Dth”) and decreased 1.6 million Dth, or a 7
percent decrease and a 5 percent decrease, respectively, from the comparable
periods in the prior year.
OPERATING EXPENSES
Electricity purchased decreased $15 million and $11 million for the
three and nine months ended December 31, 2003, respectively, from the comparable
periods in the prior year. Corresponding to lower electric sales, the Company
purchased less KWh of electricity for the periods versus the same periods last
year. In addition, contractual obligations to certain higher cost suppliers
expired during fiscal 2004 which resulted in reductions to purchased power
expense of $23 million and $15 million, as compared to the comparable periods in
the prior year. However, increases in the market price of electricity,
partially offset these decreases. In addition, $5 million of purchased power
related to pre-merger reconciliations was transferred to goodwill in the third
quarter of fiscal 2003.
Despite lower gas sales volumes, gas purchased expense
increased $14 million and $71 million for the three months and nine months ended
December 31, 2003, respectively, from the comparable periods in the prior year.
This increase is primarily a result of $19 million and $77 million increases in
gas prices for the three and nine month periods ended December 31, 2003,
respectively.
Other operation and maintenance expense increased
$16 million and decreased $17 million for the three and nine months ended
December 31, 2003, respectively, from the comparable periods in the prior year.
The table below details components of this fluctuation.
Period ended December 31, 2003
|
(In millions of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
|
|
|
|
|
|
|
|
|
VERO expense
|
|
$ 19
|
|
$ 19
|
|
Decrease in amortization of VERO regulatory asset
|
(5)
|
|
(11)
|
|
Increased (decreased) pension settlement loss
|
17
|
|
(2)
|
|
Decreased bad debt expense
|
(16)
|
|
(20)
|
|
April 2003 storm costs
|
-
|
|
6
|
|
Other
|
|
|
|
1
|
|
(9)
|
|
|
|
Total
|
$ 16
|
|
$ (17)
|
|
In the fiscal quarter ended December 31, 2003, the Company expensed
approximately $19 million in connection with the voluntary early retirement
offer (the “VERO”). This amount included approximately $9 million
allocated to the Company from National Grid USA Service Company, an affiliate.
For further information, see Note F – Voluntary Early Retirement Offer, in
Part I, Item 1. Notes to Unaudited Consolidated Financial Statements.
The amortization of the VERO regulatory asset is lower than in the same
periods last year because that asset is being amortized unevenly at levels that
decrease over the ten-year term of the Merger Rate Plan.
In the most
recent fiscal quarter, the Company recorded a pension settlement loss of $20
million associated with pension payouts in its current fiscal year. It plans to
file a petition with the PSC seeking to recover these losses. For further
information, see Note G, Pension Settlement Losses, in Part I, Item 1. Notes to
Unaudited Consolidated Financial Statements.
The bad debt expense figures
reflect increases for one-time adjustments of $24 million and $42 million
respectively for the three and nine months ended December 31, 2002.
Other
changes includes reduced administrative and general expenses resulting from
merger-related efficiencies, partially offset by increased electric distribution
and other expenses.
Amortization of stranded costs increased $8
million and $25 million for the three and nine months ended December 31, 2003,
respectively, from the comparable periods in the prior year 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 $10 million and
$23 million for the three and nine months ended December 31, 2003, respectively,
from the comparable period in the prior year. These decreases are primarily due
to a reduction of Gross Receipts Tax (“GRT”) rates that resulted in
decreased GRT of $8 million and $26 million for the three and nine months ended
December 31, 2003, respectively, as compared to the comparable period in the
prior year, and decreased sales tax. Partially offsetting these decreases were
increased property taxes of $8 million for the nine months ended December 31,
2003.
Income taxes increased $18 million for the nine months ended
December 31, 2003, from the comparable period in the prior year primarily due to
higher book taxable income. In addition, in the nine months ended December 31,
2003 there was a $9 million adjustment to taxes that increased income tax
expense.
Interest charges decreased $18 million and $47 million
for the three and nine months ended December 31, 2003, respectively, from the
comparable periods in the prior year, primarily due to the repayment of
third-party debt using affiliated company debt at lower interest rates. Also,
the expiration of the Master Restructuring Agreement interest savings deferral
in the second quarter of fiscal 2004 contributed to the decrease for the
periods.
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 nine months ended December 31, 2003. For a detailed
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 the President. The Disclosure Committee monitors
and evaluates these disclosure controls and procedures. The Chief Financial
Officer and the President 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. During the most recent
fiscal quarter, there were no changes in internal control over financial
reporting that could materially affect internal control over financial
reporting.
PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Alliance for Municipal
Power v. New York State Public Service Commission
As
described in the Company’s Form 10-K for the fiscal year ended March 31,
2003 and in the Company’s Form 10-Q for the quarter ended September 30,
2003, the Alliance for Municipal Power (“AMP”) has asked the New
York State court to review 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. On October 27, 2003 the
court dismissed AMP’s petition, and in late November 2003, AMP made a
timely filing to appeal the court’s decision.
New York
State v. Niagara Mohawk Power Corp. et al.
As described in the
Company’s Form 10-K for the fiscal year ended March 31, 2003, the Company
and NRG Energy, Inc. are defendants in a civil action by New York State 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”). On December
31, 2003, the court granted the State’s motion for leave to amend the
complaint to assert claims against NRG and the Company based on violations of
the plants’ operating permits. The court order brings NRG back into the
case for injunctive relief but does disturb the prior ruling that monetary
penalties for Clean Air Act violations five years prior to the suit are barred
by the statute of limitations.
The Company is also
seeking a ruling that NRG is responsible for the costs of pollution
controls and mitigation that might result from the state’s enforcement
action, which is also described in the Company’s Form
10-K for the fiscal year ended March 31, 2003. The Company’s action
had been stayed pending NRG’s voluntary bankruptcy petition, but the stay
has now been lifted by virtue of the bankruptcy court’s confirmation in
late November of NRG’s plan of reorganization.
Niagara Mohawk
Power Corp. v. Huntley Power L.L.C., Dunkirk Power L.L.C. and Oswego Harbor,
L.L.C.
As described in the Company’s Form 10-K for the fiscal
year ended March 31, 2003, the Company is engaged in collections litigation to
recover bills for station service rendered to the owners of three power plants
that 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
with NRG Energy, Inc., “NRG”). 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.
The FERC has not yet rendered a decision on this
matter. However, on December 23, 2003, it issued two orders on related
complaints filed by AES Somerset, L.L.C. (“AES”) and Nine Mile Point
Nuclear Station, L.L.C., both of which are station service customers of the
Company. The orders do not control the outcome of the NRG case but may be
indicative of the FERC’s disposition in station service matters. The two
orders allow these generators to net their station service electricity over a
30-day period and to avoid state-authorized charges for deliveries made over
distribution facilities. While it is not entirely clear from reading the AES
order, it is possible to construe it to have retroactive effect back to the date
that AES purchased the plant from a third party. The net effect of these
decisions is that the two generators will no longer have to pay the Company for
station service charges for electricity. The Company is seeking rehearing on
these decisions and is awaiting a decision on NRG.
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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The Company did not file any reports on Form 8-K during the fiscal quarter
ended December 31, 2003.
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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
December 31, 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: February 17, 2004
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By
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/s/ Edward A.
Capomacchio Edward
A. Capomacchio 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 pursuant to Rule
13a-14(a)
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31.2
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Certification of Principal Financial Officer pursuant to Rule
13a-14(a)
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32
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Section 1350 Certifications
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