SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2001
--------------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
----------------- -------------
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
- ------------- -------------------------------------- ------------------
0-30338 RGS Energy Group, Inc. 16-1558410
(Incorporated in New York)
Rochester, NY 14649
Telephone (716)771-4444
1-672 Rochester Gas and Electric Corporation 16-0612110
(Incorporated in New York)
Rochester, NY 14649
Telephone (716)546-2700
Indicate by check mark whether each registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
--- ---
As of the close of business on October 31, 2001, (i) RGS Energy Group, Inc.
("RGS") had outstanding 34,663,542 shares of Common Stock ($.01 par value),and
(ii) all of the outstanding shares of Common Stock ($5 par value) of Rochester
Gas and Electric Corporation ("RG&E") were held by RGS.
RG&E meets the conditions set forth in General Instructions (H)(1)(a) and (b)
of Form 10-Q and is therefore filing this form with the reduced disclosure
format pursuant to General Instruction (H)(2).
INDEX
Page No.
PART I - FINANCIAL INFORMATION
RGS Energy Group, Inc.
Consolidated Balance Sheet - September 30, 2001 and
December 31, 2000........................................................................................ 1 - 2
Consolidated Statement of Income - Three Months and Nine Months Ended
September 30, 2001 and 2000.............................................................................. 3
Consolidated Statement of Cash Flows - Nine Months
Ended September 30, 2001 and 2000........................................................................ 4
Rochester Gas and Electric Corporation
Balance Sheet - September 30, 2001 and December 31, 2000................................................. 5 - 6
Statement of Income - Three Months and Nine Months Ended
September 30, 2001 and 2000............................................................................... 7
Statement of Cash Flows - Nine Months Ended
September 30, 2001 and 2000............................................................................... 8
Notes to Financial Statements.............................................................................. 9 - 16
Management's Discussion and Analysis of Financial
Condition and Results of Operations........................................................................ 16 - 26
Quantitative and Qualitative Disclosures About
Market Risk................................................................................................ 26 - 27
PART II - OTHER INFORMATION
Legal Proceedings......................................................................................... 27 - 28
Exhibits and Reports on Form 8-K.......................................................................... 28
Signatures................................................................................................ 29
---------------
Filing Format
This Quarterly report on Form 10-Q is a combined quarterly report being filed by
two different registrants: RGS and RG&E. RGS became the holding company for
RG&E on August 2, 1999. Except where the content clearly indicates otherwise,
any references in this report to "RGS" include all subsidiaries of RGS including
RG&E. RG&E makes no representation as to the information contained in this
report in relation to RGS and its subsidiaries other than RG&E.
Abbreviations and Glossary
Annual Report RGS and RG&E Combined Annual Report on Form 10-K for
the period ended December 31, 2000.
Company or RGS RGS Energy Group, Inc., a holding company formed
August 2, 1999, which is the parent company of RG&E,
RGS Development and Energetix
Electric Settlement Competitive Opportunities Case Settlement among
RG&E, PSC Staff and other parties which provides the
framework for the development of competition in the
electric energy marketplace through June 30, 2002
Energetix Energetix, Inc., a wholly-owned subsidiary of RGS
Energy Choice A competitive electric retail access program of RG&E
being phased-in during the term of the Electric
Settlement
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Ginna Plant Ginna Nuclear Plant which is wholly owned by RG&E
Griffith Griffith Oil Company Inc., an oil, gasoline and
propane distribution company acquired by Energetix
in 1998
Nine Mile Two Nine Mile Point Nuclear Plant Unit No. 2 of which
RG&E owns a 14% share
NRC Nuclear Regulatory Commission
NYISO New York Independent System Operator
NYPA New York Power Authority
NYSDEC New York State Department of Environmental
Conservation
PSC New York State Public Service Commission
Regulatory Assets Deferred costs whose classification as an asset on
the balance sheet is permitted by SFAS 71,
Accounting for the Effects of Certain Types of
Regulation
RG&E Rochester Gas and Electric Corporation, a wholly-
owned regulated electric and gas subsidiary of RGS
RGS Development RGS Development Corporation, a wholly-owned
subsidiary of RGS
RTO Regional Transmission Organization
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
1
PART 1 - FINANCIAL INFORMATION
- ------------------------------
ITEM 1. FINANCIAL STATEMENTS
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
September 30, December 31,
Assets 2001 2000
- ----------------------------------------------------------------------------------------
Utility Plant
Electric $ 1,629,151 $ 2,467,289
Gas 493,474 471,051
Common 187,124 164,872
Nuclear 219,701 292,588
----------- -----------
2,529,450 3,395,800
Less: Accumulated depreciation 1,240,643 1,750,493
Nuclear fuel amortization 201,985 254,435
----------- -----------
1,086,822 1,390,872
Construction work in progress 117,613 111,486
----------- -----------
Net Utility Plant 1,204,435 1,502,358
----------- -----------
Current Assets
Cash and cash equivalents 33,020 16,258
Accounts receivable, net of allowance
for doubtful accounts: 2001 - $29,988;
2000 - $34,550 103,480 136,374
Unbilled revenue receivable 30,715 71,120
Fuels 70,274 46,868
Materials and supplies 6,589 8,187
Prepayments 40,510 26,268
Derivatives (0) (0)
Other current assets 3,237 2,292
----------- -----------
Total Current Assets 287,825 307,367
----------- -----------
Intangible Assets
Goodwill, net 13,533 27,971
Other intangible assets, net 20,156 22,614
----------- -----------
Total Intangible Assets 33,689 50,585
----------- -----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning
fund 210,621 244,514
Nine Mile Two deferred costs 26,367 27,155
Unamortized debt expense 23,215 16,602
Regulatory assets 335,550 412,789
Regulatory assets - Nine Mile Two
(see note 3 to the financial statements) 398,507 -
Other 4,131 6,005
----------- -----------
Total Deferred Debits and
Other Assets 998,391 707,065
----------- -----------
Total Assets $ 2,524,340 $ 2,567,375
----------- -----------
The accompanying notes are an integral part of the financial statements.
2
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
September 30, December 31,
Capitalization and Liabilities 2001 2000
- -----------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $ 579,742 $ 580,132
- promissory notes 208,598 211,703
Preferred stock redeemable at option of RG&E 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholders' equity
Common stock
Authorized 100,000,000 shares; 39,007,682 shares issued at
September 30, 2001 and 38,956,726 shares issued at December 31, 2000 705,721 702,807
Retained earnings 191,047 181,546
---------- ----------
896,768 884,353
Less: Treasury stock at cost (4,379,300 shares at September 30, 2001
and December 31, 2000) 117,238 117,238
---------- ----------
Total Common Shareholders' Equity 779,530 767,115
---------- ----------
Total Capitalization 1,639,870 1,630,950
---------- ----------
Long Term Liabilities
Nuclear waste disposal 100,674 97,291
Uranium enrichment decommissioning 9,871 9,649
Other promissory notes 23,565 32,025
Site remediation 24,473 24,420
---------- ----------
Total Long Term Liabilities 158,583 163,385
---------- ----------
Current Liabilities
Long term debt due within one year 112,247 12,095
Preferred stock redeemable within one year - -
Short term debt - 122,400
Accounts payable 94,266 108,618
Dividends payable 16,485 16,515
Equal payment plan (0) 0
Accrued interest 14,952 13,000
Derivatives 18,480 -
Taxes Payable
Other 48,260 44,491
---------- ----------
Total Current Liabilities 304,690 317,119
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 254,753 277,787
Pension costs accrued 9,089 26,548
Kamine deferred credit 46,996 51,920
Post employment benefits 57,744 54,505
Other 52,615 45,161
---------- ----------
Total Deferred Credits and Other Liabilities 421,197 455,921
---------- ----------
Commitments and Other Matters - -
---------- ----------
Total Capitalization and Liabilities $2,524,340 $2,567,375
---------- ----------
The accompanying notes are an integral part of the financial statements.
3
RGS Energy Group Inc.
Consolidated Statement of Income
(Thousands of dollars)
(Unaudited)
For the Three Months Ended Year To Date
September 30, September 30,
2001 2000 2001 2000
---------- ---------- ---------- ----------
OPERATING REVENUES
Electric $ 196,194 $ 189,569 $ 564,825 $ 543,375
Gas 37,727 37,428 262,389 214,249
Liquid fuels and other 91,843 87,308 354,766 253,237
---------- ---------- ---------- ----------
Total Operating Revenues 325,764 314,305 1,181,980 1,010,861
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 17,852 13,382 43,856 35,419
Purchased electricity 30,791 27,928 73,232 64,366
Gas purchased for resale 24,447 24,915 177,278 121,180
Unregulated fuel expenses 83,433 80,310 314,499 229,323
---------- ---------- ---------- ----------
Total Fuel Expenses 156,523 146,535 608,865 450,288
---------- ---------- ---------- ----------
Operating Revenues Less Fuel Expenses 169,241 167,770 573,115 560,573
Other Operating Expenses
Operations and maintenance excluding fuel 80,033 80,053 217,276 218,534
Unregulated operating and maintenance expenses excluding fuel 11,209 6,974 33,540 21,182
Depreciation and amortization 30,906 29,200 92,003 87,415
Taxes - state, local and other 20,791 21,541 70,346 71,229
Income taxes 4,887 3,189 45,186 46,592
---------- ---------- ---------- ----------
Total Other Operating Expenses 147,826 140,957 458,351 444,952
---------- ---------- ---------- ----------
Operating Income 21,415 26,813 114,764 115,621
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds used during construction (237) (225) (714) (605)
Income taxes (21,009) 323 (21,064) 1,302
RGS/Energy East Merger Expenses 5,330 - 13,643 -
Accelerated Amortization (Nine Mile Two) 20,000 - 20,000 -
Other - net (2,634) (2,590) (5,710) (2,346)
---------- ---------- ---------- ----------
Total Other (Income) and Deductions 1,450 (2,492) 6,155 (1,649)
INTEREST CHARGES
Long term debt 15,026 14,458 45,284 43,540
Other - net 1,738 1,113 4,911 2,967
Allowance for borrowed funds used during construction (380) (361) (1,143) (968)
---------- ---------- ---------- ----------
Total Interest Charges 16,384 15,210 49,052 45,539
---------- ---------- ---------- ----------
Net Income 3,581 14,095 59,557 71,731
---------- ---------- ---------- ----------
Preferred Stock Dividend Requirements 925 925 2,775 2,775
---------- ---------- ---------- ----------
Net Income Applicable to Common Stock $ 2,656 $ 13,170 $ 56,782 $ 68,956
---------- ---------- ---------- ----------
Average Number of Common Shares (000's)
Common Stock 34,590 34,928 34,583 35,365
Common Stock and Equivalents 34,992 35,009 34,946 35,436
Earnings per Common Share - Basic $0.08 $0.38 $1.64 $1.95
Earnings per Common Share - Diluted $0.07 $0.38 $1.62 $1.95
Cash Dividends Paid per Common Share $0.45 $0.45 $1.35 $1.35
The accompanying notes are an integral part of the financial statements.
4
RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Nine Months Ended
September 30,
- ---------------------------------------------------------------------------------------------------------------------------------
2001 2000
------------ -----------
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 59,557 $ 71,731
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 105,526 100,298
Deferred recoverable fuel costs 216 10,112
Income taxes deferred 3,470 (22,643)
Allowance for funds used during construction (1,857) (1,573)
Unbilled revenue 40,405 22,097
Post employment benefit/pension costs 2,581 4,581
Provision for doubtful accounts (4,562) 210
Changes in certain current assets and liabilities; net of assets
acquired and liabilities assumed in acquisitions:
Accounts receivable 37,745 (108)
Materials, supplies and fuels (2,748) (27,048)
Taxes accrued (7,225) (8,570)
Accounts payable (14,312) 29,718
Other current assets and liabilities, net (3,891) (4,946)
Other, net 3,183 23,193
------------ -----------
Total Operating 218,088 197,052
------------ -----------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (102,805) (102,605)
Nuclear generating plant decommissioning fund (15,536) (15,536)
Acquisitions, net of cash - (7,676)
------------ -----------
Total Investing (118,341) (125,817)
------------ -----------
CASH FLOW FROM FINANCING ACTIVITIES
Redemption of long term debt (100,000) (30,000)
Sale/Issuance of common stock 729 -
Proceeds from issuance of long-term debt, net 199,534 -
Repayment of promissory notes (10,398) (2,810)
Short term borrowings, net (122,400) 33,500
Payments of dividends on preferred stock (2,775) (2,775)
Payments of dividends on common stock (46,680) (47,960)
Purchase of treasury stock - (29,559)
Other, net (995) 1,766
------------ -----------
Total Financing (82,985) (77,838)
------------ -----------
Increase (Decrease) in cash and cash equivalents 16,762 (6,603)
Cash and cash equivalents at beginning of period 16,258 8,288
------------ -----------
Cash and cash equivalents at end of period $ 33,020 $ 1,685
------------ -----------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Nine Months Ended
(Thousands of Dollars) September 30,
- ----------------------------------------------------------------------------------------------------------------------------------
2001 2000
------------ -----------
Adjustment to Goodwill $ (13,212) -
Establishment of Nine Mile Two Regulatory Asset 398,507 -
The accompanying notes are an integral part of the financial statements.
5
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
September 30, December 31,
Assets 2001 2000
- --------------------------------------------------------------------------------------------------------
Utility Plant
Electric $1,629,151 $2,467,289
Gas 493,474 471,051
Common 132,494 117,473
Nuclear 219,701 292,588
---------- ----------
2,474,820 3,348,401
Less: Accumulated depreciation 1,231,830 1,735,752
Nuclear fuel amortization 201,985 254,435
---------- ----------
1,041,005 1,358,214
Construction work in progress 117,613 111,486
---------- ----------
Net Utility Plant 1,158,618 1,469,700
---------- ----------
Current Assets
Cash and cash equivalents 27,011 4,851
Accounts receivable, net of allowance for doubtful accounts:
2001 - $29,482; 2000 - $33,482 76,660 93,130
Affiliate receivable 72,304 51,558
Unbilled revenue receivable 22,498 61,838
Fuels 59,246 33,896
Materials and supplies 6,589 8,187
Prepayments 37,507 23,782
Derivatives 0 -
----------
Other current assets 1,084 -
---------- ----------
Total Current Assets 302,899 277,242
---------- ----------
Intangible Assets
Goodwill, net - -
Other intangible assets, net - -
---------- ----------
Total Intangible Assets - -
---------- ----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 210,621 244,514
Nine Mile Two deferred costs 26,367 27,155
Unamortized debt expense 23,215 16,602
Regulatory assets 335,550 412,789
Other assets - -
Regulatory assets - Nine Mile Two (see note 3 to the
financial statements) 398,507 -
Other 3,053 4,673
---------- ----------
Total Deferred Debits and Other Assets 997,313 705,733
---------- ----------
Total Assets $2,458,830 $2,452,675
---------- ----------
The accompanying notes are an integral part of the financial statements.
6
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
September 30, December 31,
Capitalization and Liabilities 2001 2000
- -------------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $ 579,742 $ 580,132
- promissory notes 208,598 211,703
Preferred stock redeemable at option of RG&E 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholder's equity
Authorized 50,000,000 shares; 39,007,682 shares issued at
September 30, 2001 and 38,885,813 shares issued at December 31, 2000 700,318 700,318
Retained earnings 177,690 166,184
---------- ----------
878,008 866,502
Less: Treasury stock at cost (4,379,300 shares at September 30, 2001
and December 31, 2000) 117,238 117,238
---------- ----------
Total Common Shareholder's Equity 760,770 749,264
---------- ----------
Total Capitalization 1,621,110 1,613,099
---------- ----------
Long Term Liabilities
Nuclear waste disposal 100,674 97,291
Uranium enrichment decommissioning 9,871 9,649
Site remediation 22,356 22,356
---------- ----------
Total Long Term Liabilities 132,901 129,296
---------- ----------
Current Liabilities
Long term debt due within one year 104,306 4,227
Preferred stock redeemable within one year - -
Short term debt - 98,000
Accounts payable 76,515 79,356
Affiliate payable 23,838 18,451
Dividends payable to parent 16,485 16,515
Equal payment plan (0) 0
Accrued interest 14,721 12,339
Derivatives 18,480 -
Taxes Payable
Other 33,928 29,325
---------- ----------
Total Current Liabilities 288,273 258,213
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 250,670 274,299
Pension costs accrued 9,089 26,548
Kamine deferred credit 46,996 51,920
Post employment benefits 57,744 54,505
Other 52,047 44,795
---------- ----------
Total Deferred Credits and Other Liabilities 416,546 452,067
---------- ----------
Commitments and Other Matters - -
---------- ----------
Total Capitalization and Liabilities $2,458,830 $2,452,675
---------- ----------
The accompanying notes are an integral part of the financial statements.
7
Rochester Gas and Electric Corporation
Statement of Income
(Thousands of dollars)
(Unaudited)
For the Three Months Ended Year To Date
September 30, September 30,
2001 2000 2001 2000
---------- ---------- ---------- --------
OPERATING REVENUES
Electric $ 194,201 $ 187,472 $ 559,819 $535,451
Gas 34,639 36,214 225,604 205,651
---------- ---------- ---------- --------
Total Operating Revenues 228,840 223,686 785,423 741,102
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 17,852 13,382 43,856 35,418
Purchased electricity 30,301 27,205 71,370 59,800
Gas purchased for resale 20,694 23,530 140,532 113,129
---------- ---------- ---------- --------
Total Fuel Expenses 68,847 64,117 255,758 208,347
---------- ---------- ---------- --------
Operating Revenues Less Fuel
Expenses 159,993 159,569 529,665 532,755
Other Operating Expenses
Operations and maintenance
excluding fuel 80,033 80,053 217,276 218,534
Depreciation and
amortization 29,064 28,239 86,033 84,549
Taxes - state, local and
other 20,109 20,453 67,362 67,938
Income taxes 7,347 3,685 45,837 46,318
---------- ---------- ---------- --------
Total Other Operating
Expenses 136,553 132,430 416,508 417,339
---------- ---------- ---------- --------
Operating Income 23,440 27,139 113,157 115,416
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds
used during construction (237) (225) (714) (605)
Income taxes (20,981) 262 (21,279) 1,075
RGS/Energy East Merger
Expenses 5,314 - 13,393 -
Accelerated Amortization
(Nine Mile Two) 20,000 - 20,000 -
Other - net (2,763) (2,469) (5,513) (1,945)
---------- ---------- ---------- --------
Total Other (Income) and
Deductions 1,333 (2,432) 5,887 (1,475)
INTEREST CHARGES
Long term debt 14,760 14,130 44,404 42,476
Other - net 1,391 1,006 3,270 2,965
Allowance for borrowed
funds used during
construction (380) (361) (1,143) (968)
---------- ---------- ---------- --------
Total Interest Charges 15,771 14,775 46,531 44,473
---------- ---------- ---------- --------
Net Income 6,336 14,796 60,739 72,418
---------- ---------- ---------- --------
Dividends on Preferred Stock 925 925 2,775 2,775
---------- ---------- ---------- --------
Net Income Applicable to
Common Stock $ 5,411 $ 13,871 $ 57,964 $ 69,643
---------- ---------- ---------- --------
The accompanying notes are an integral part of the financial statements.
8
ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Nine Months Ended
September 30,
- -----------------------------------------------------------------------------------------
2001 2000
--------- ---------
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 60,739 72,418
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 99,680 97,459
Deferred recoverable fuel costs 216 10,112
Income taxes deferred 2,876 (21,461)
Allowance for funds used during construction (1,857) (1,573)
Unbilled revenue 39,340 25,789
Post employment benefit/pension costs 2,581 4,581
Provision for doubtful accounts (4,000) 117
Changes in certain current assets and liabilities:
Accounts receivable (275) (10,675)
Materials, supplies and fuels (4,692) (20,387)
Taxes accrued (6,753) (8,928)
Accounts payable 14,568 31,905
Other current assets and liabilities, net (2,350) (7,912)
Other, net (664) 22,774
--------- ---------
Total Operating 199,409 194,219
--------- ---------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (98,458) (101,182)
Nuclear generating plant decommissioning fund (15,536) (15,536)
Other, net - 769
--------- ---------
Total Investing (113,994) (115,949)
--------- ---------
CASH FLOW FROM FINANCING ACTIVITIES
Redemption of long term debt (100,000) (30,000)
Proceeds from issuance of long term debt, net 199,534 -
Repayment of promissory notes (3,026) (2,810)
Short term borrowings, net (98,000) 31,500
Payments of dividends on preferred stock (2,775) (2,775)
Payments of dividends on common stock (46,680) (47,960)
Purchase of treasury stock - (29,559)
Other, net (12,308) 648
--------- ---------
Total Financing (63,255) (80,956)
--------- ---------
Increase (Decrease) in cash and cash equivalents 22,160 (2,686)
Cash and cash equivalents at beginning of period 4,851 6,443
--------- ---------
Cash and cash equivalents at end of period $ 27,011 $ 3,757
--------- ---------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Nine Months Ended
(Thousands of Dollars) September 30,
- ------------------------------------------------------------------------------------------
2001 2000
--------- ---------
Establishment of Nine Mile Two Regulatory Asset $ 398,507 -
The accompanying notes are an integral part of the financial statements.
9
PART 1 - FINANCIAL INFORMATION
- ------------------------------
ITEM 1. FINANCIAL STATEMENTS
RGS ENERGY GROUP, INC.
ROCHESTER GAS AND ELECTRIC CORPORATION
NOTES TO FINANCIAL STATEMENTS
Note 1. SUMMARY OF ACCOUNTING PRINCIPLES
BASIS OF PRESENTATION
This is a combined report of RGS and RG&E. The Notes to Financial
Statements apply to both RGS and RG&E. RGS's Consolidated Financial Statements
include the accounts of RGS and its wholly-owned subsidiaries, including RG&E,
and two non-utility subsidiaries, Energetix and RGS Development. RGS and RG&E,
in the opinion of management, have included adjustments (which include normal
recurring adjustments) which are necessary for the fair statement of the results
of operations for the interim periods presented. The consolidated financial
statements for 2001 are subject to adjustment at the end of the year when they
will be audited by independent accountants.
The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates. Moreover, the results for these interim periods are not
necessarily indicative of results to be expected for the year, due to seasonal,
operating and other factors. These financial statements should be read in
conjunction with the financial statements and notes thereto contained in the RGS
and RG&E combined Annual Report on Form 10-K for the year ended December 31,
2000 ("Annual Report").
RECLASSIFICATIONS
Certain amounts in the prior years' financial statements were reclassified
to conform with current year presentation.
MERGER AGREEMENT
On February 20, 2001, RGS announced that it had entered into an Agreement
and Plan of Merger (the "Merger Agreement"), dated as of February 16, 2001, with
Energy East Corporation ("Energy East"), a New York corporation, and Eagle
Merger Corp., a New York corporation that will be a wholly owned subsidiary of
Energy East ("Merger Sub") at the effective time of the Merger (as defined
below), pursuant to which RGS will be merged with and into Merger Sub (the
"Merger") and RGS will become a wholly owned subsidiary of Energy East. As a
result of the Merger, all of the outstanding common stock of RGS will be
exchanged for a combination of cash and Energy East common stock valued at
approximately $1.4 billion in the aggregate. Energy East will also assume
approximately $1.0 billion of RGS debt.
Under the Merger Agreement, subject to possible adjustments for tax
reasons, 45% of RGS common stock will be converted into a number of shares of
Energy East common stock with a value of $39.50 per RGS share, subject to
restrictions on the maximum and minimum number of shares of Energy East common
stock to be issued, and 55% of RGS common stock will be converted into $39.50 in
cash per RGS share. RGS shareholders will be able to specify the percentage of
the consideration they wish to receive in shares of Energy East common stock and
in cash, subject to proration.
At the 2001 Annual Meetings of RGS and Energy East, the shareholders of
RGS approved and adopted the Merger Agreement and the shareholders of Energy
East approved the issuance of Energy East shares in connection with the Merger.
All regulatory applications required in connection with the Merger have been
filed and all related regulatory approvals have been received, other than the
approvals of the SEC, PSC, Federal Communications Commission, and NRC. RGS and
Energy East anticipate that the Merger will be consummated in the first quarter
of 2002.
10
NEW YORK STATE TAX CHANGES
On May 15, 2000 changes to the New York State tax laws were signed into law
effective January 1, 2000. During June 2000 the Company recorded taxes in
accordance with these changes. The effect of these changes was a reduction in
the gross receipts tax rate, elimination of excess dividends taxes, and the
imposition of a state income tax. As a result, deferred state income taxes were
established in accordance with the transition rules to recognize timing
differences between book and tax deductibility. This transition item results in
a one-time tax benefit of $16.7 million that has been deferred for future rate
treatment in accordance with the Electric Settlement.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In July 2001, the FASB issued SFAS No. 141, "Business Combinations", ("SFAS
141"), SFAS 142, "Goodwill and Other Intangible Assets" ("SFAS 142"), and SFAS
143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 141
requires that all business combinations initiated after June 30, 2001 be
accounted for by the purchase method. It also requires disclosure of the
primary reasons for a business combination and the allocation of the purchase
price paid to the assets acquired and liabilities assumed by major balance sheet
caption. Additional disclosure would be required when goodwill and intangible
assets represent a significant portion of the purchase price paid.
SFAS 142 addresses financial accounting and reporting for acquired goodwill
and other intangible assets. Under this standard, goodwill and intangible
assets that have indefinite useful lives will not be amortized but rather will
be tested at least annually for impairment. Intangible assets that have finite
useful lives will continue to be amortized over their useful lives, but the
amortization period will not be a limited to a certain period of time. SFAS 142
requires the Company to adopt this standard by January 1, 2002. Management is
currently evaluating the provisions of SFAS 142 regarding the impact on the
financial condition and results of operations.
SFAS 143 requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the entity capitalizes a cost by increasing the
carrying amount of the related long-lived asset. Over time, the liability is
adjusted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. When the liability is
settled, the entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. SFAS 143 requires the Company to adopt
this standard by January 1, 2003, with earlier application encouraged.
Management is currently evaluating the provisions of SFAS 143 regarding the
impact on the financial condition and results of operations of the Company and
has not determined when it will adopt SFAS 143.
In August 2001, the FASB issued SFAS 144, "Accounting for Impairment or
Disposal of Long-Lived Assets" ("SFAS 144"), which is effective January 1, 2002.
SFAS 144 supersedes FASB Statement No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", and the
accounting and reporting provisions relating to the disposal of a segment of a
business of Accounting Principles Board Opinion No. 30. The Company does not
expect that the adoption of SFAS 144 will have a significant impact on its
financial statements.
11
The following matters supplement the information contained in Notes 2, 3 & 12 to
the Financial Statements included in Annual Report and should be read in
conjunction with the material contained in those Notes.
Note 2. NUCLEAR-RELATED MATTERS
NINE MILE NUCLEAR PLANTS
On November 7, 2001, RG&E, Niagara Mohawk Power Corporation, Central Hudson
Gas & Electric Corporation and New York State Electric and Gas Corporation
("NYSEG") sold their ownership interests in Nine Mile Two (and in the case of
Niagara Mohawk, Nine Mile One) to Constellation Nuclear, L.L.C. ("Constellation
Nuclear") pursuant to an agreement dated December 11, 2000. The Long Island
Power Authority, an 18 percent owner of Nine Mile Two, did not participate in
the sale.
The purchase price for RG&E's 14 percent ownership interest in Nine Mile
Two was $101.0 million, $50.5 million of which was paid in cash at the closing
and $50.5 million of which will be paid in five equal annual principal
installments plus interest at a rate of 11 percent pursuant to a five year
promissory note. Principal and interest payments under the promissory note will
total approximately $67.1 million unless the note is pre-paid.
At November 7, 2001, the net book value of RG&E's 14 percent interest in
the Nine Mile Two generating facility was approximately $349.0 million. RG&E
also had investments in fuel of approximately $5.5 million, transmission and
distribution facilities of $3.3 million and construction work in progress of
$8.1 million.
RG&E and the Staff of the PSC have entered into a settlement that addresses
the rate-making treatment associated with RG&E's recovery of its remaining
investment in Nine Mile Two and related costs. The settlement was approved by
the PSC in an order issued on October 26, 2001. As a result of the October 26,
2001 PSC approval, the Company's management has determined that the regulatory
treatment of the transaction is a subsequent event that should be included in
the Company's third quarter financial statements. Under the settlement, RG&E is
authorized to establish a regulatory asset calculated in accordance with the
provisions of the settlement that is currently estimated to be approximately
$328.9 million. RG&E has agreed to a one-time accelerated amortization of $20.0
million of this regulatory asset, approximately 5% of RG&E's pre-sale investment
in Nine Mile Two. RG&E has also agreed to amortize during the period from the
closing of the sale of Nine Mile Two until RG&E's base electric rates are re-set
(estimated to be July 1, 2002) an additional amount of this regulatory asset to
reflect the projected reduction in RG&E's expenses of owning and operating Nine
Mile Two prior to the sale compared to the estimated expenses that it will incur
in purchasing the amount of electricity after the sale that is equivalent to
RG&E's pre-sale share of the output. The amortization during this period will
be calculated using an amortization rate of $30.0 million per year. The terms
associated with the recovery of the remaining regulatory asset will be
established in future RG&E rate proceedings. The settlement further provides
that it constitutes a final and irrevocable resolution of all RG&E rate-making
issues associated with the sale of Nine Mile Two and RG&E's ability to recover
costs associated with its investment in Nine Mile Two through its rates. The
other petitioning utilities have also entered into settlements with the Staff of
the PSC to resolve the rate-making issues associated with the sale of Nine Mile
Two and such settlements were approved by the PSC in an order issued October 26,
2001.
In connection with the sale of Nine Mile Two, RG&E informed Niagara Mohawk
that RG&E's rights and obligations under a June 8, 1998 Exit Agreement will
cease as it pertains to transmission service relating to Nine Mile Two. Niagara
Mohawk disputed RG&E's position, asserting instead that RG&E must continue
making payments that decline from approximately $7.0 million per year currently
to approximately $4.0 million per year in 2007 and continue at that level until
2043 (or until the plant is retired, if sooner). After attempting to resolve
that matter informally, RG&E, on August 13, 2001, commenced an action in New
York State Supreme Court, Monroe County, for a judgment declaring that, as a
result of the sale of its interest in Nine Mile Two, RG&E has no further
obligation to make payments under the Exit Agreement and that the Transmission
Congestion Contracts ("TCCs") to which RG&E was entitled under the Exit
Agreement, should
12
be returned to and accepted by Niagara Mohawk (TCCs function as a hedge against
transmission congestion that can result in higher costs). Niagara Mohawk
answered RG&E's complaint, asserting various affirmative defenses and
counterclaims. On October 16, 2001, RG&E moved for summary judgment. The
ultimate outcome of that motion or of the declaratory judgment itself cannot be
predicted.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND
RG&E and others similarly situated utilities have a case pending against the
U.S. Department of Energy ("DOE") in which the utilities maintain that DOE has
no right to assess them for DOE's costs incurred in decontaminating and
decommissioning ("D&D") certain uranium enrichment plants at which DOE performed
enrichment services to fulfill its contracts for such services with RG&E and
others. This case is in the discovery stage in the Federal District Court for
the Southern District of New York.
In June 2001, the Court of Federal Claims decided that the DOE erroneously
sought to overcharge plaintiff utilities during a certain period in 1992 - 1993
for D&D activity by requiring them to pay an assessment for D&D work under an
applicable statute at the same time it was requiring them to pay for the
identical work through contract prices which included costs for D&D. RG&E is
assessing the bearing of this favorable decision on how it will prosecute its
own claim for D&D charges against DOE.
Pending the resolution of its lawsuit, RG&E has been paying a portion of
the DOE assessments and recognizing a liability on its financial statements for
the balance ($11.7 million at September 30, 2001, of which $9.9 million is
recognized as a long-term liability and $1.8 million is recognized as a current
liability) for both the Ginna plant and its 14 percent interest in Nine Mile
Point Two. RG&E is recovering these costs in rates.
Note 3. REGULATORY MATTERS
REGULATORY ASSETS
Below is a summary of RG&E's regulatory assets as of September 30, 2001 and
December 31, 2000:
Millions of Dollars
September 30, 2001 Dec. 31, 2000
------------------- -------------
Kamine Settlement $172.1 $179.1
Nine Mile Two* 398.5 -
Income Taxes 46.2 101.9
Oswego Plant Sale 70.0 74.4
Deferred Environmental SIR costs 13.0 16.6
Uranium Enrichment Decommissioning Deferral 11.6 12.7
Labor Day 1998 Storm Costs 9.9 9.3
Other, net 12.8 18.8
------ ------
Total - Regulatory Assets $734.1 $412.8
*Nine Mile Two: The $398.5 million represents the establishment of the
regulatory asset resulting from the sale of the Nine Mile Two nuclear plant
to Constellation Nuclear. In the fourth quarter the regulatory asset will
be reduced by the cash proceeds from the sale and a note receivable
totaling $101.0 million, net of transaction and other costs of $11.4
million. See Note 2 "Nuclear Related Matters" for more information related
to the sale.
See the Annual Report, Item 8, Note 3 of the Notes to Financial Statements,
"Regulatory Matters" for a description of the other regulatory assets shown
above.
13
GAS RETAIL ACCESS SETTLEMENTS.
On January 25, 2001, RG&E reached agreement with PSC Staff and other
parties on a comprehensive rate and restructuring proposal for its natural gas
business (the "Gas Rates and Restructuring Proposal"), as contemplated in the
PSC's Restructuring Policy Statement issued November 3, 1998. The Gas Rates and
Restructuring Proposal was approved by the PSC, with some modifications, on
February 28, 2001 and became effective on March 1, 2001.
The Gas Rates and Restructuring Proposal contains a number of features that
are intended to extend for different periods. The two most significant periods
are the Rate Term, which applies principally to rate-related provisions and
extends from July 1, 2000 through June 30, 2002, and the Rate and Restructuring
Program Term, which applies to most other provisions and extends from March 1,
2001 through March 31, 2004. The significant features of the Proposal, as
modified and approved by the PSC, are as follows:
(1) For the purpose of setting base, or local delivery, rates for the period
beginning July 1, 2000, natural gas revenues are decreased a total of
$3,000,000 from the levels in effect on June 30, 2000. This rate level is
based on an agreed-upon return on equity of 11.0%.
(2) Base rates are adjusted effective March 1, 2001 to reflect the revenue
requirements decrease. Because the base rates that were in effect through
February 28, 2001 were higher than those agreed to by the parties, RG&E, in
March 2001, passed back to all its retail gas customers a temporary credit
applied to rates, on a volumetric basis, equal to the amount of the
reduction in rates for the period from July 1, 2000 through
February 28, 2001.
(3) In the event that RG&E achieves a return on equity in excess of 12.5% in
any Rate Year covered by the Gas Rates and Restructuring Proposal, 90% of
the excess over that level will be deferred for the benefit of customers.
(4) RG&E is allowed to defer certain prudent and verifiable costs, expenditures
for competition implementation costs that exceed $300 thousand per rate year
and any costs associated with mandates and catastrophic events that exceed
$600 thousand per rate year for recovery after the Rate Term of the Gas
Rates and Restructuring Proposal, subject to PSC approval.
(5) RG&E is authorized to implement a Retail Access Capacity Program, beginning
November 1, 2001, pursuant to which RG&E would release pipeline capacity it
currently holds to marketers serving customers in RG&E's service area. This
Program will help to avoid stranded capacity costs that might otherwise
result from migration of customers to marketers.
(6) RG&E will implement a Capacity Incentive Program ("CIP"), consisting of a
Capacity Cost Incentive and a Capacity Cost Imputation. Both elements are
intended to encourage aggressive management of RG&E's capacity costs. The
Capacity Cost Incentive is designed to share, between RG&E and its
customers, the savings resulting from the difference between a base level of
capacity costs and the actual capacity costs achieved. The Capacity Cost
Imputation is intended to provide customers with a guaranteed level of
short-term savings through the gas cost adjustment provision. "Short-term"
refers to periods of one year or less. "Savings" refers to capacity release
savings, as well as net revenues from off-system sales, if any. The imputed
level of savings will be $1,100,000 per year for the period beginning April
1, 2001 and extending through June 30, 2002. The level will then be $500,000
per year for the period beginning July 1, 2002 and extending through
March 31, 2004.
(7) RG&E will implement a Service Quality Performance Program to be effective
as of January 1, 2001 through at least June 30, 2002. This Program
establishes performance targets for six specific measures of service and
provides for a maximum overall penalty of 42 basis points of gas return on
equity (approximately $700,000) for failure to meet the minimum levels
specified.
14
The PSC also directed RG&E to work with PSC Staff and others on three
elements of the Gas Rates and Restructuring Proposal: a weatherization program
for low-income customers, a customer education plan, and an aggregation program
for customers who receive assistance from the Monroe County DSS. Discussions
have been held, and work is in process, on all three of the measures.
Note 4. OPERATING SEGMENT FINANCIAL INFORMATION
The Company has identified three operating segments of its business based on
the types of products and services it offers and the regulatory environment
under which it operates. The three segments are regulated electric, regulated
gas and unregulated. The regulated segments' financial records are maintained
in accordance with the accounting principles generally accepted in the United
States of America ("GAAP") and PSC accounting policies. The unregulated
segment's financial records are maintained in accordance with GAAP.
For the Three Months Ended September 30,
Regulated Regulated
Electric Gas Unregulated
-------- --------- -----------
(thousands of dollars) 2001 2000 2001 2000 2001 2000
-------- -------- -------- -------- -------- --------
Operating Income/(Loss) $ 25,560 $ 30,754 $ (2,120) $ (3,615) $ (2,034) $ (330)
Revenues - External Customers 163,428 166,699 32,972 36,214 129,364 111,392
Revenues - Intersegment Transactions 30,773 20,773 1,667 - - -
For the Nine Months Ended September 30,
Regulated Regulated
Electric Gas Unregulated
-------- --------- -----------
(thousands of dollars) 2001 2000 2001 2000 2001 2000
-------- -------- -------- -------- -------- --------
Operating Income $ 97,920 $ 98,888 $ 15,237 $ 16,528 $ 1,583 $ 159
Revenues - External Customers 478,025 480,375 207,813 205,651 496,142 324,835
Revenues - Intersegment Transactions 81,794 55,076 17,791 - - -
The operations of RGS Development are included in Other (Income) and Deductions
in the RGS Consolidated Statement of Income. The total amount of the revenues
identified by operating segment do not equal the consolidated revenues as shown
in the RGS Consolidated Statement of Income. This is due to the elimination of
certain intersegment revenues during consolidation. A reconciliation follows:
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
(thousands of dollars) 2001 2000 2001 2000
-------- -------- ---------- ----------
Revenues
Regulated Electric $194,201 $187,472 $ 559,819 $ 535,451
Regulated Gas 34,639 36,214 225,604 205,651
Unregulated 129,364 111,392 496,142 324,835
-------- -------- ---------- ----------
Total $358,204 $335,078 $1,281,565 $1,065,937
Reported on RGS Consolidated
Income Statement 325,764 314,305 1,181,980 1,010,861
Difference to reconcile 32,440 20,773 99,585 55,076
Intersegment Revenue
Regulated Electric from Unregulated 30,773 20,773 81,794 55,076
Regulated Gas from Unregulated 1,667 - 17,791 -
-------- -------- ---------- ----------
Total Intersegment $ 32,440 $ 20,773 $ 99,585 $ 55,076
15
Note 5. COMMITMENTS AND OTHER MATTERS
ENVIRONMENTAL MATTERS
NEW YORK INITIATIVES
In May 2000, the NYSDEC issued a Notice of Violation ("NOV") to RG&E,
asserting that certain "modifications" to Russell and Beebee Stations during
1983-1987 resulted in a "significant increase in the capacity to emit sulfur
dioxide." The NOV alleges that, as a result, permits required by the federal
Clean Air Act and the New York Environmental Conservation Law should have been
obtained by RG&E prior to beginning the "modifications." The NOV asserts that
RG&E may be liable for civil penalties of up to $10,000 per day, per violation,
as well as subjected to unspecified injunctive relief. The allegations in the
NOV are similar to those being made by the United States Department of Justice,
on behalf of the United States Environmental Protection Agency, in enforcement
cases relating to a number of electric utility coal-fired power plants in the
midwest and southeast. The NOV invited RG&E to request an informal conference
with the NYSDEC. Since July 2000, RG&E has had several such informal meetings
with the NYSDEC and NYS Office of the Attorney General. On the merits of the
allegation, RG&E does not believe it has engaged in prohibited activities at
either station.
In a separate initiative, the Governor of New York directed the NYSDEC to
require electric generators to further reduce acid rain-causing emissions. The
Governor has proposed extending the existing nitrous oxides control program
under which RG&E's Russell Station operates to a year-round program (it is
currently in effect only for the five-month ozone season that runs from May 1 to
October 1). In addition, the Governor has proposed that there be a targeted
reduction of approximately 50% in sulfur dioxide emissions below the existing
Acid Rain Phase II limits. The state emission reductions would be phased-in
beginning in 2004. These are draft regulations subject to review, comment and
modification. RG&E is in the process of estimating their economic impact on the
station.
RG&E-OWNED WASTE SITE ACTIVITIES
RG&E is conducting proactive Site Investigation and/or Remediation ("SIR")
efforts at eight RG&E-owned sites where past waste handling and disposal may
have occurred. Remediation activities at five of these sites are in various
stages of planning or completion and RG&E is investigating the other three
sites. RG&E has recorded a total liability of approximately $21.9 million which
it anticipates spending on SIR efforts at the eight RG&E-owned sites. Through
September 30, 2001, RG&E has incurred aggregate costs of $8.0 million for these
sites.
MANUFACTURED GAS PLANTS
RG&E and its predecessors formerly owned and operated five manufactured gas
plants ("MGPs") and acquired (following cessation of MGP operations) two others
for which SIR costs are estimated to be approximately $20.0 million. RG&E
estimates that SIR costs at one of these sites known as East Station may be as
much as $14.5 million. These properties are in various stages of investigation
and remediation and, in some instances, RG&E is coordinating its activities with
the NYSDEC.
SUPERFUND AND NON-OWNED OTHER SITES
RG&E has been or may be associated as a potentially responsible party for SIR
efforts at nine sites not owned by it. RG&E has signed orders of consent for
five of these sites. RG&E's ultimate exposure will depend on the final
determination of RG&E's contribution to the waste at these sites and the
financial viability of the other potential responsible parties at these sites.
In June, 1999, RG&E was named as a codefendant in a legal action brought by
a party who purchased a portion of its Ambrose Yard property. The party has
claimed that RG&E's historic activities on the property resulted in the presence
of residual contaminants that have adversely impacted the party's use of the
property. RG&E is defending the legal action but cannot predict its eventual
outcome. There is insufficient information available at this time to predict
the economic impact of the claim on RG&E.
16
UNREGULATED FACILITIES
Griffith Energy, Energetix's liquid-fuel subsidiary, has several sites
which are currently undergoing environmental evaluation and/or remediation.
Griffith estimates the present value of future aggregate cleanup costs for all
active sites as of September 30, 2001 to be approximately $2.8 million, and has
recorded an accrual to reflect this liability.
The previous owner of Griffith is obligated under the purchase agreement to
pay for environmental claims or remedial action on Griffith properties owned at
the time of Energetix's acquisition of Griffith once the amount of environmental
losses incurred by Energetix exceeds $3.5 million less any reserve reflected on
the balance sheet at the time of acquisition. As of September 30, 2001
approximately $1.5 million has been spent on these facilities and it is
estimated $1.0 million will be spent in the future.
In connection with its Big Flats, New York terminal, Griffith has been
complying with a Unilateral Administrative Order issued by the EPA. Pursuant to
a cost sharing agreement with Sun Pipe Line Company, Griffith continues to bear
one-half of the costs necessary to comply with the order. To date Griffith has
spent $1.8 million on this compliance. Griffith has asserted cross-claims for
contribution and/or indemnification from Sun Pipe Line Company, and compliance
with the order is proceeding on this basis accordingly. For more detail on this
proceeding see Part II - Other Information, Item 1 - Legal Proceedings in this
report under the heading "Griffith Owned Sites".
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
The following is management's assessment of certain significant factors
affecting the financial condition and operating results of RGS and its
subsidiaries over the past three and nine month periods. The Consolidated
Financial Statements and the Notes thereto contain additional data. For the
quarter ended September 30, 2001, 59.6% of the Company's operating revenues were
derived from regulated electric service, 10.6% from regulated natural gas
service, and 29.8% from unregulated businesses.
FORWARD LOOKING STATEMENTS
The discussion presented below contains statements that are not historic
fact and which can be classified as forward looking. These statements can be
identified by the use of certain words that suggest forward looking information,
such as "believes," "will," "expects," "projects," "estimates" and
"anticipates". They can also be identified by the use of words that relate to
future goals or strategies. In addition to the assumptions and other factors
referred to specifically in connection with the forward looking statements, some
of the factors that could have a significant effect on whether the forward
looking statements ultimately prove to be accurate include:
(1) uncertainties related to the regulatory treatment of RG&E's nuclear
generation.
(2) any state or federal legislative or regulatory initiatives (including the
results of negotiations between RG&E and other parties including the PSC
Staff) that affect the cost or recovery of investments necessary to provide
utility service in the electric and natural gas industries. Such
initiatives could include, for example, changes in the regulation of rate
structures or changes in the speed or degree to which competition occurs in
the electric and natural gas industries;
(3) any changes in the ability of RG&E to recover environmental compliance
costs through increased rates;
(4) the determination in the nuclear generation proceeding initiated by the
PSC, including any changes in the regulatory status of nuclear generating
facilities and their related costs, including recovery of costs related to
spent fuel and decommissioning;
17
(5) fluctuations in energy supply and demand and market prices for energy,
capacity and ancillary services;
(6) any changes in the rate of industrial, commercial and residential growth in
RG&E's and RGS's service territories;
(7) the development of any new technologies, as well as regulatory policies,
which allow customers to generate their own energy or produce lower cost
energy;
(8) any unusual or extreme weather or other natural phenomena;
(9) the timing and extent of changes in commodity prices and interest rates;
(10) the ability of RGS to manage profitably new unregulated operations;
(11) certain unknowable risks involved in operating unregulated businesses in
new territories and new industries;
(12) risks associated with the proposed merger of RGS with and into the Merger
Sub, that will be a wholly owned subsidiary of Energy East at the effective
time of the merger, and if the merger is completed, the integration of RGS
and Energy East; and
(13) any other considerations that may be disclosed from time to time in the
publicly disseminated documents and filings of RGS and RG&E.
RGS ENERGY GROUP, INC.
RGS is a holding company and not an operating entity. RGS's operations are
being conducted through its subsidiaries which include RG&E and two unregulated
subsidiaries - RGS Development and Energetix.
RG&E offers regulated electric and natural gas utility service in its
franchise territory. Energetix provides energy products and services throughout
upstate New York. RGS Development offers energy systems development and
management services.
On February 16, 2001, RGS entered into a Merger Agreement with Energy East
pursuant to which RGS will be merged with and into a subsidiary of Energy East
and will become a wholly owned subsidiary of Energy East. See Note 1 to the
Financial Statements under the heading "Merger Agreement" for additional
information about the Merger.
UNREGULATED SUBSIDIARIES
ENERGETIX
As of September 30, 2001, RGS has invested $85.1 million (including loan
guarantees) in Energetix, against a maximum of $100.0 million allowed by the
Electric Settlement. Energetix markets electricity, natural gas, oil, gasoline,
and propane fuel energy services throughout Upstate and Central New York.
Energetix has approximately 82,000 customers for natural gas and electricity
service.
Griffith and Burnwell, Energetix's liquid-fuels subsidiaries, give
Energetix access to over 123,000 customers, approximately 100,000 of whom are
outside of RG&E's regulated franchise territory. In total, Griffith had
approximately 587 employees and operated 27 customer service centers as of
September 30, 2001.
Additional information on Energetix's operations (including Griffith) is
presented under the headings "Operating Revenues and Sales", and "Operating
Expenses".
18
RGS DEVELOPMENT CORPORATION
RGS Development was formed in 1998 to pursue unregulated business
opportunities in the energy marketplace. Through September 30, 2001, RGS
Development's operations have not been material to RGS's results of operations
or its financial condition.
ROCHESTER GAS AND ELECTRIC CORPORATION
- --------------------------------------
REGULATED ELECTRIC
COMPETITION
PSC Electric Settlement
The Annual Report contains a description of an agreement among RG&E, the
PSC Staff and several other parties which was approved by the PSC in November
1997 the ("Electric Settlement") that sets the framework for the introduction
and development of open competition in the electric energy marketplace and lasts
through June 30, 2002. For further discussion, see "PSC Electric Settlement" in
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operation under the heading "Competition", in the Annual Report.
Energy Choice
RG&E's electric retail access program, Energy Choice, was approved by the
PSC as part of the Electric Settlement and went into effect on July 1, 1998.
The Energy Choice program began with an "Energy-Only" stage, during which energy
service companies were responsible only for providing the energy requirements of
the customers they acquired. The program moved to an "Energy and Capacity"
stage on November 1, 1999. From that point, energy service companies were
required to provide for the energy and installed capacity requirements of their
customers.
Energy service companies have had and continue to have the option to serve
a portion or all of their load by buying power directly from RG&E, at a price
equal to the backout credit for energy and capacity. This is the "full
requirements" option. For a detailed explanation of the "full requirements"
option, see Item 7, Management's Discussion and Analysis of Financial Condition
and Results of Operation under the heading "Competition", in the Annual Report.
Throughout the remaining term of the Electric Settlement, through June 30,
2002, the full requirements option will continue to be available to energy
service companies.
From the beginning of the Energy and Capacity stage through the
implementation of the market-based backout credit (described below), RG&E's
distribution rates were set to be equal to rates for standard retail service
less two separate credits. The first was a fixed "backout" credit for energy
and capacity. The second was a fixed "retailing" credit to represent the avoided
costs of retailing services assumed by energy service companies. From November
1, 1998 through June 30, 2000, the energy and capacity backout credit was set at
2.67 cents per kilowatt-hour (an estimate of the wholesale market price of
electric energy and capacity, adjusted for gross receipts taxes). The retailing
credit was set at 0.40 cents per kilowatt-hour. Beginning July 1, 2000, the
energy and capacity backout credit was updated to 2.68 cents per kilowatt-hour
to reflect the implementation of reduced gross receipts taxes. The retailing
credit was unchanged.
On March 29, 2001 the PSC approved a joint proposal among RG&E and several
other parties, including the Staff of the PSC, which replaces the fixed energy
and capacity backout credit with one that varies based on the market price of
energy, installed capacity, ancillary services, and the NYPA Transmission
Adjustment Charge ("NTAC"). This new "market-based" backout credit became
effective May 1, 2001. The market-based credit is initially based on projected
prices for energy, capacity, ancillary services and NTAC and is trued-up to
actual prices after they are known. The joint proposal called for the retailing
credit to remain at a level of 0.40 cents per kilowatt-hour.
19
In December 1999, two petitions were filed with the PSC, one by an electric
utility operating in New York State and the other jointly by five energy
marketers and consultants, calling upon the PSC to examine RG&E's retail access
program and to order certain changes in the program. For further detail, refer
to Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operation under the heading "Competition" in the Annual Report. In
the opinion of RG&E, the adoption of the market-based backout credit, described
above, and the elimination of the cap on eligibility to participate in the
electric retail access program on July 1, 2001, as provided by the Electric
Settlement, effectively moots most aspects of these petitions. Nevertheless, it
is not possible at this time to predict with assurance whether or not, in
response to the petitions, the PSC might require that the program be changed in
some manner.
The PSC is conducting proceedings that are intended to bring more
administrative consistency among New York State utilities and potentially
offer additional services for energy service companies to provide. These
include an on-going national effort regarding uniform business practices,
and proceedings regarding standardized billing (single billing options),
provider of last resort, electronic data interchange, and competitive
metering. RG&E continues to assess the scope and impact of such potential
changes on its operations as retail access continues to evolve.
Nine Mile Nuclear Plants
On November 7, 2001, RG&E, Niagara Mohawk Power Corporation, Central Hudson
Gas & Electric Corporation and NYSEG sold their ownership interests in Nine Mile
Two (and in the case of Niagara Mohawk, Nine Mile One) to Constellation Nuclear,
L.L.C. ("Constellation Nuclear"). For further discussion and details on this
transaction, see Note 2 to the Financial Statements under the heading "Nine Mile
Nuclear Plants", and the Form 8-K that was filed by the Company on November 9,
2001.
New York Independent System Operator
In November 1999 following FERC approval, the NYISO began to implement a
competitive wholesale market for the sale, purchase and transmission of
electricity and ancillary services in New York State. NYISO tariffs provide
market-based rates for energy, ancillary services, and installed capacity sold
through the NYISO. For further discussion on the NYISO, see Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operation under the heading "Competition" in the Annual Report.
RATES AND REGULATORY MATTERS
FERC Electric Restructuring Order No. 2000.
On December 15, 1999, FERC adopted Order No. 2000 (the "Rule"), a
significant action regarding electric industry restructuring which calls for
transmission owners to join regional transmission organizations ("RTOs"). The
RTOs will serve as umbrella organizations that will place all public utility
transmission facilities in a region under common control.
On July 12, 2001, FERC issued a series of orders addressing the compliance of
the NYISO with the policies embodied in the Rule. FERC also issued an order
calling for the formation of a single RTO for the northeast rather than three
as proposed by the market participants in each region. The Commission ordered
that the Pennsylvania-New Jersey-Maryland ISO was to be the platform upon which
the northeastern RTO would be based, but that best practice rules from the other
ISOs would be used to develop the final design for the consolidated RTO. Under
the supervision of an Administrative Law Judge, parties from New England, New
York, the mid-Atlantic States and Canada met from July 24 through September 7,
2001. The Judge issued his report to the Commission on September 17, 2001.
Comments on the report were filed with the Commission on October 9, 2001.
Commission action on the report, which seeks specific FERC guidance, is expected
in the fourth quarter. The Chairman of FERC also announced public workshops
related to RTO formation were held between October 15 and 19, 2001. RG&E cannot
predict what effect the ultimate action by FERC with respect to the Rule will
have on its future operations or financial.
For further discussion refer to FERC Electric Restructuring Order No. 2000,
see Item 1 of the Annual
20
Report under the heading "Regulatory Matters".
REGULATED GAS
COMPETITION
Gas Retail Access Settlements
On November 3, 1998, the PSC issued a gas restructuring policy statement
announcing its conclusion that, among other things, the most effective way to
establish a competitive gas supply market is for gas distribution utilities to
cease selling gas. On January 25, 2001, RG&E reached agreement with the PSC
Staff and other parties on a comprehensive rate and restructuring proposal for
its natural gas business (the "Gas Rates and Restructuring Proposal"), as
contemplated in the PSC's Restructuring Policy Statement. With modifications,
the Proposal was approved by the PSC on February 28, 2001. For a description
of the Gas Rates and Restructuring Proposal, as approved, see the discussion
under Note 3 of the Notes to Financial Statements under the heading "Gas Retail
Access Settlements" in this report.
Pursuant to the Capacity Incentive Program ("CIP") established by the Gas
Rates and Restructuring Proposal, RG&E, as of April 1, 2001, has released all of
its ANR Pipeline Company ("ANR") and Great Lakes Gas Transmission Limited
Partnership ("Great Lakes") transportation and storage capacity through March
31, 2004. To maintain the necessary level of service that had been provided by
the ANR and Great Lakes facilities, RG&E entered into an agreement with Union
Gas Limited ("Union") for storage service at facilities in southern Ontario,
Canada. Recovery by RG&E of the costs resulting from the new storage contract
with Union, as well as the recovery of the difference between the cost to the
gas marketers of the released service and the amount received from the
replacement shipper, will be subject to the CIP.
Gas Retail Access Program
On December 1, 2000, RG&E implemented the single-retailer system for small
volume gas customers, following the approval of a tariff filing with the PSC.
Under the June 2000 Gas Settlement discussed in the Annual Report in Item 7
Management's Discussion and Analysis of Financial Condition and Results of
Operations under the heading "Gas Retail Access Settlements", RG&E is permitted
to recover the difference between the backout credit paid marketers ($3.75 per
customer per month) and RG&E's short-run avoided costs associated with the
migration of gas sales customers to retail access under the single retailer
system. For purposes of the June 2000 Gas Settlement, this assumed difference
was set at $2.55 per customer per month. Both the backout credit and the assumed
difference are to remain in effect at these levels over the term of the June
2000 Gas Settlement (generally through June 30, 2002), subject to possible
further negotiations in the event of a particularly rapid migration of
customers.
On April 1, 2001, RG&E also implemented the single-retailer model program
for large volume gas customers. With this transition completed, all small and
large volume retail customers are now eligible to participate under the single-
retailer model.
As of September 30, 2001, eighteen energy service companies, including
Energetix, were qualified by RG&E to serve retail gas customers under RG&E's Gas
Retail Access Program.
RG&E attempts to mitigate its risks of energy marketer defaults by
requiring security deposits as permitted by the PSC.
21
RATES AND REGULATORY MATTERS
FERC Gas Market Proposals
On February 9, 2000, FERC issued Order No. 637, its final rule addressing
"Regulation of Short-Term Natural Gas Transportation Services" and "Regulation
of Interstate Natural Gas Transportation Services". Order No. 637 revised FERC's
regulations to improve the efficiency of the gas transportation market and to
provide captive customers with the opportunity to reduce their cost of holding
long-term pipeline capacity.
On March 30, 2001 Dominion Transmission ("DTI") became the first pipeline
upon which RG&E holds capacity to file a FERC Order No. 637 settlement with the
FERC. On May 31, 2001 FERC issued an order accepting DTI's settlement, as filed.
This was the first of the FERC Order No. 637 filings to be accepted. There are
continuing negotiations with the other pipelines upon which RG&E holds capacity.
RG&E cannot predict what effects, if any, FERC's initiatives and the related
pipeline tariff changes will have on future operations or the financial
condition of RG&E.
For further discussion concerning FERC Gas Market Proposals see Item 1 of
the Annual Report under the heading "Regulatory Matters".
Competition and the Company's Prospective Financial Position
With PSC approval, RG&E has deferred certain costs rather than recognize
them on its statement of income when incurred. Such deferred costs are then
recognized as expenses when they are included in rates and recovered from
customers. Such deferral accounting is permitted by SFAS 71: Accounting for the
Effects of Certain Types of Regulation. These deferred costs are shown as
Regulatory Assets on the Company's and RG&E's Balance Sheet and a discussion and
summary of such Regulatory Assets is presented in Note 3 of the Notes to
Financial Statements.
In a competitive electric market, strandable assets would arise when
investments are made in facilities, or costs are incurred to service customers,
and such costs are not fully recoverable in market-based rates. Estimates of
strandable assets are highly sensitive to the competitive wholesale market price
of electricity assumed in the estimation. In a competitive natural gas market,
strandable assets would arise where customers migrate away from dependence on
RG&E for full service, leaving RG&E with surplus pipeline and storage capacity,
as well as natural gas supplies under contract. For a discussion of strandable
assets, see Note 3 of the Notes to Financial Statements under the heading
"Regulatory Assets".
At September 30, 2001 RG&E believes that its regulatory assets are probable
of recovery except as described below. The Electric Settlement does not impair
the opportunity of RG&E to recover its investment in these assets. In
connection with the joint proposed settlement relating to the sale of RG&E's
interest in Nine Mile Two, RG&E has agreed to a one-time write-off of $20.0
million of its regulatory asset relating to its interest in Nine Mile Two. See
Note 2 to the Financial Statements under the heading "Nine Mile Nuclear Plants".
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 2001, RGS's and RG&E's cash flow from
operations, and the issuance by RG&E of $200.0 million of First Mortgage Bonds
in April 2001 provided the funds for utility plant construction expenditures,
the payment of dividends, repayment of short term borrowings and the redemption
of $100 million of First Mortgage Bonds in the second quarter of 2001 (see
"Financing" and "Redemption of Securities" below). Capital requirements of the
Company for the remaining three months of 2001 are anticipated to be satisfied
from the combination of internally generated funds, short-term credit
arrangements, and cash proceeds the Nine Mile Two sale.
CAPITAL AND OTHER REQUIREMENTS
RGS's and RG&E's capital requirements have related primarily to
expenditures for energy delivery, including electric transmission and
distribution facilities and gas mains and services as well as nuclear fuel,
22
electric production, and the repayment of existing debt. The Company completed
its share repurchase program in the fourth quarter of 2000. RG&E has no current
plans to install additional baseload generation.
Construction requirements for the Company in 2001 are currently estimated
at $157 million. RG&E's portion of total estimated construction requirements is
$154 million. Approximately $96.5 million had been expended for construction as
of September 30, 2001, reflecting primarily RG&E's expenditures for nuclear
fuel, upgrading electric transmission and distribution facilities, gas mains and
information systems.
FINANCING
On April 6, 2001, RG&E issued $200 million principal amount of 6.95% First
Mortgage Bonds, Series TT, due 2011. The net proceeds from this financing were
used to redeem RG&E's Series PP First Mortgage Bonds as described below and to
repay $39 million of outstanding short-term debt.
RG&E generally utilizes its credit agreements and unsecured lines of credit
to meet any interim external financing needs prior to issuing any long-term debt
securities. For information with respect to RGS's and RG&E's short-term
borrowing arrangements and limitations, see Item 8 of the Annual Report under
Note 10 of the Notes to Financial Statements.
REDEMPTION OF SECURITIES
On May 10, 2001, RG&E redeemed $100 million principal amount of its 9 3/8%
First Mortgage Bonds, Series PP, at a price of 104.47 percent of the principal
amount plus accrued interest from April 1, 2001 through the redemption date.
As financial market conditions warrant, RG&E may from time to time, redeem
higher-cost senior securities; however, RG&E does not anticipate redeeming any
other securities for the remainder of 2001.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In July 2001, the FASB issued SFAS No. 141, "Business Combinations", ("SFAS
141"), SFAS 142, "Goodwill and Other Intangible Assets" ("SFAS 142"), and SFAS
143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 141
requires that all business combinations initiated after June 30, 2001 be
accounted for by the purchase method. It also requires disclosure of the
primary reasons for a business combination and the allocation of the purchase
price paid to the assets acquired and liabilities assumed by major balance sheet
caption. Additional disclosure would be required when goodwill and intangible
assets represent a significant portion of the purchase price paid.
SFAS 142 addresses financial accounting and reporting for acquired goodwill
and other intangible assets. Under this standard, goodwill and intangible
assets that have indefinite useful lives will not be amortized but rather will
be tested at least annually for impairment. Intangible assets that have finite
useful lives will continue to be amortized over their useful lives, but the
amortization period will not be a limited to a certain period of time. SFAS 142
requires the Company to adopt this standard by January 1, 2002. Management is
currently evaluating the provisions of SFAS 142 regarding the impact on the
financial condition and results of operations.
SFAS 143 requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the entity capitalizes a cost by increasing the
carrying amount of the related long-lived asset. Over time, the liability is
adjusted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. When the liability is
settled, the entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. SFAS 143 requires the Company to adopt
this standard by January 1, 2003, with earlier application encouraged.
Management is currently evaluating the provisions of SFAS 143 regarding the
impact on the financial condition and results of operations of the Company and
has not determined when it will adopt SFAS 143.
In August 2001, the FASB issued SFAS 144, "Accounting for Impairment or
Disposal of Long-Lived
23
Assets" ("SFAS 144"), which is effective January 1, 2002. SFAS 144 supersedes
FASB Statement No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of", and the accounting and reporting
provisions relating to the disposal of a segment of a business of Accounting
Principles Board Opinion No. 30. The Company does not expect that the adoption
of SFAS 144 will have a significant impact on its financial statements.
EARNINGS SUMMARY
RGS:
RGS reported earnings per common share of $0.08 for the quarter ended
September 30, 2001, down from $0.38 for the same period in 2000. Earnings per
common share for the nine-month period ended September 30, 2001 were $1.64, down
from $1.95 reported for the same period in 2000. These results for the third
quarter and year to date reflect non-recurring pretax expenses of $5.3 million
(or $0.13 per common share) and $13.6 million (or $0.33 per common share),
respectively, related to the pending merger with Energy East, in addition to
other operating issues as discussed below.
RG&E:
As anticipated, RG&E earnings in the third quarter of 2001 were lower
because of rate reductions under the Electric Settlement equivalent to $0.12 per
common share that took effect in July and reduced revenue from lower-priced
wholesale power sales. Year-to-date results reflect a general economic decline
that has caused electric sales to RG&E's industrial customers to be lower than
2000, offset somewhat by warmer summer weather in the third quarter of 2001.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses for RGS and RG&E, comparing the
three-month and nine-month periods ended September 30, 2001 to the three-month
and nine-month periods ended September 30, 2000. The operating results of the
regulated business reflect RG&E's electric and gas sales and services, and the
operating results of the unregulated business reflect Energetix's operations.
Currently, the majority of RGS's operating results reflect the operating results
of RG&E and the factors that affect operating results for RG&E are the
significant factors that affect comparable operating results for RGS, unless
otherwise noted.
THREE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED TO THREE MONTHS ENDED
- ---------------------------------------------------------------------
SEPTEMBER 30, 2000:
- ------------------
OPERATING REVENUES AND SALES
Regulated Electric
Electric revenues from regulated retail and energy service companies were
up $5.1 million from the third quarter of 2000, driven by increased electric
usage due to weather effects. These increased revenues were partially offset by
lower retail electric base rates that became effective in July 2001.
Additionally, electric sales to other utilities were up $1.6 million, which
reflects higher electric output from the RG&E generation facilities, partially
offset by the effect of lower market prices.
Regulated Gas
Gas revenues were down $1.6 million for RG&E reflecting a decrease in the
usage of natural gas in the third quarter of 2001 due in part to warmer weather.
Unregulated
Energetix's operating revenues were $129.4 million in the third quarter of
2001, compared to $111.4 million for the third quarter of 2000. The increase of
approximately 16% is attributable primarily to an aggressive expansion program
that included the acquisitions by Griffith in November 2000 of Burnwell Gas and
certain assets of the New York Fuels Division of AllEnergy Marketing Company,
L.L.C., as well as increased quantities of electricity and natural gas sold to
an expanding customer base.
24
OPERATING EXPENSES
Regulated
Regulated electric fuel expenses for the third quarter were up $4.5 million
due to the increased fuel consumption resulting primarily from higher
availability of RG&E's Ginna nuclear generation plant which was shut down during
a portion of the third quarter of 2000 for refueling. Purchased electricity
expense for RG&E was up $3.1 million driven by higher wholesale market prices
during the exceptionally warm months of July and August.
The non-fuel regulated operating and maintenance expenses in the third
quarter of 2001 are relatively even with those experienced in the same period in
2000. Last year's expenses included the establishment in the third quarter of
2000 of a $12.0 million reserve for excess earnings pursuant to certain terms of
the Electric Settlement. Compared with 2001, this expense was generally offset
by a $3.0 million Nine Mile Two inventory credit adjustment in 2000, increased
expense of $7.6 million in 2001 for electric transmission and wheeling charges
by the NYISO, and $1.3 million of additional expense in 2001 associated with
next year's outage accrual for the Ginna Plant.
Unregulated
Higher unregulated fuel costs reflect mainly the higher volumes of liquid
fuel sold in the third quarter of 2001 as compared to a year ago when in
November 2000 Griffith acquired Burnwell Gas and certain assets of the New York
Fuels Division of AllEnergy Marketing Company, L.L.C. Also contributing to the
increase was a charge of approximately $1.7 million for the "mark to market"
reporting requirements of Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"),
which became effective in 2001 and which in this case required an acceleration
of expense for the cost of certain call options associated with the Company's
risk management initiatives.
Unregulated non-fuel operating and maintenance expenses increased $4.2
million for the quarter compared to a year ago due to increased operating costs
associated with the business acquisitions referenced above.
Income Taxes
The income tax expense for RGS and RG&E was lower in the third quarter of
2000 due to a favorable tax ruling in that period, partially offset by lower
2001 RG&E pre-tax earnings.
OTHER STATEMENT OF INCOME ITEMS
The change in RGS's Other Income and Deductions is mainly attributable to
the $5.3 million in merger-related expenses incurred by RGS.
As a result of the October 26, 2001 PSC approval of the sale of RG&E's
interest in Nine Mile Two, RG&E recognized a one-time pretax accelerated
amortization of $20.0 million, associated with the Nine Mile Two regulatory
asset. Concurrently with this charge, the PSC allowed RG&E to recognize $13.1
million of investment tax credits.
Interest expense for both RGS and RG&E is driven by the $200 million bond
financing in April 2001 which was partially offset by the $100 million
redemption of bonds in May 2001 as discussed in "Financing" and "Redemption of
Securities" above. Interest expense for RGS also increased due to interest
payments on the promissory note issued in November 2000 in connection with the
acquisition of Burnwell Gas.
25
NINE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED TO NINE MONTHS ENDED
- ------------------------------------------------------------------
SEPTEMBER 30, 2000:
- ------------------
OPERATING REVENUES AND SALES
Regulated Electric
Regulated electric total operating revenues increased $24.4 million in
2001 due to increased wholesale power sales of $20.6 million reflecting
increased availability of generation from RG&E facilities. In addition,
electric revenues from regulated retail and energy service companies were up
$3.8 million due to warmer summer weather in 2001, which were partially offset
by the effect of electric base rate reductions that became effective in July
2000 and July 2001.
Regulated Gas
Gas revenues were up $20.0 million for RG&E for the first nine months of
2001 as compared to the corresponding period in 2000. This was due to the
higher commodity prices for natural gas earlier this year, which were partially
offset by the effects of decreased customer consumption in response to such
higher commodity prices.
Unregulated
Unregulated revenues were $496.1 million for the first nine months of
2001, as compared to $324.8 million last year, an increase of 52.7%. This
increase is attributable primarily to an aggressive expansion program that
included the acquisitions by Griffith in November 2000 of Burnwell Gas and
certain assets of the New York Fuels Division of AllEnergy Marketing Company,
L.L.C., as well as increased quantities of electricity and natural gas sold to
an expanding customer base.
OPERATING EXPENSES
Regulated
Regulated electric fuel expenses were up due to the increased fuel
consumption resulting primarily from higher availability of RG&E's fossil-fueled
and nuclear generation plants. Increased generation from these facilities
allowed RG&E to increase its sales into the wholesale market as discussed above.
Purchased electricity expense for RG&E increased because of higher market prices
per megawatt hour purchased, however, the increase was partially offset by a
decline in units purchased.
The $1.3 million decrease in regulated non-fuel operating and maintenance
expenses primarily reflects similar factors discussed above for the third
quarter, in addition to a $4.0 million decrease in the Company's reserve for
uncollectible accounts in the second quarter of this year due to improved
collection techniques.
Unregulated
Unregulated fuel expense increased $155.7 million or 52% for the first nine
months of 2001 compared to 2000. The increase is primarily attributable to
Griffith acquisitions, as discussed above. Also contributing to the higher fuel
expense is an increase in the volumes of natural gas and electricity sold, and a
year-to-date charge of approximately $1.4 million for the "mark to market"
reporting requirements of SFAS 133 which became effective in 2001 and which in
this case required an acceleration of expense for the cost of certain call
options associated with the Company's risk management initiatives.
The $12.4 million increase in unregulated non-fuel operating expenses
reflects primarily the acquisitions of Burnwell Gas and certain assets of the
New York Fuels Division of AllEnergy Marketing Company, L.L.C. in November 2000
by Griffith.
Income Taxes
The decline in income tax expense for RGS and RG&E is primarily
attributable to lower 2001 pretax earnings, which were partially offset by the
effect of certain non-deductible merger-related costs in 2001.
26
OTHER STATEMENT OF INCOME ITEMS
The factors causing variances in RGS's Other Income and Deductions are
also applicable for the nine-month comparison period. Non-recurring pretax
merger expenses of $13.6 million were partially offset by lower expenses
compared to a year ago due to recognition in June 2000 of certain non-recurring
prior period purchase power expenses.
As a result of the October 26, 2001 PSC approval of the sale of RG&E's
interest in Nine Mile Two, RG&E recognized a one-time pretax accelerated
amortization of $20.0 million, associated with the Nine Mile Two regulatory
asset. Concurrently with this charge, the PSC allowed RG&E to recognize $13.1
million of investment tax credits.
Interest expense for both RGS and RG&E for the nine months was affected by
the same factors discussed for the third quarter, in addition to an increase in
short-term debt interest expense of approximately $1.1 million.
DIVIDENDS
On September 12, 2001, the Board of Directors of RGS authorized a common
stock dividend of $.45 per share, which was paid on October 25, 2001 to
shareholders of record on October 1, 2001. Also on September 12, 2001, the Board
of Directors of RG&E declared dividends on its Preferred Stock at the regular
rates per share payable on December 1, 2001 to shareholders of record on
November 1, 2001.
The ability of RGS to pay common stock dividends is governed by the ability
of RGS's subsidiaries to pay dividends to RGS. RG&E is the largest of RGS's
subsidiaries, therefore it is expected that for the foreseeable future the funds
required by RGS to enable it to pay dividends will be derived predominantly from
the dividends paid to RGS by RG&E. In the future, dividends from subsidiaries
other than RG&E may also contribute to RGS's ability to pay dividends. RG&E's
ability to make dividend payments to RGS will depend upon the availability of
retained earnings and the needs of its utility business. RG&E's Certificate of
Incorporation provides for the payment of dividends on its common stock out of
the surplus net profits (retained earnings) of RG&E. In addition, pursuant to
the PSC order approving the formation of RGS, RG&E may pay dividends to RGS of
no more than 100% of RG&E's net income calculated on a two-year rolling basis.
The calculation of net income for this purpose excludes non-cash charges to
income resulting from accounting changes or certain PSC required charges as well
as charges that may arise from significant unanticipated events. This condition
does not apply to dividends that would be used to fund the remaining portion of
RG&E's $100 million authorization for unregulated operations (approximately
$14.9 million at September 30, 2001).
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
RG&E is exposed to interest rate and commodity price risks.
The interest rate risk relates to new debt financing needed to fund capital
requirements, including maturing debt securities, and to variable rate debt.
RG&E manages its interest rate risk through the issuance of fixed rate debt with
varying maturities and through economic refundings of debt through optional
redemptions. A portion of RG&E's long-term debt consists of long-term
Promissory Notes, the interest component of which resets on a periodic basis
reflecting current market conditions. See the Annual Report "Note 6 - Long Term
Debt". RG&E was not participating in any derivative financial instruments to
manage interest rate risk as of September 30, 2001.
The commodity price risk relates to market fluctuations in the price of
natural gas, electricity, and other liquid-fuel-related products used for
resale. Commodity purchases and electric generation are based on projected
demand for power generation and customer delivery of electricity, natural gas
and liquid-fuel products. RG&E enters into forward contracts for natural gas to
hedge the effect of price increases and reduce volatility on gas purchased for
resale. Owned electric generation significantly reduces RG&E's
27
exposure to market fluctuations in electric prices. RG&E does not hold open
speculative positions in any commodity for trading purposes.
RG&E's exposure to market price fluctuations in the cost of natural gas is
further limited as the result of the Gas Cost Adjustment, a regulatory mechanism
that transfers substantially all gas commodity price risk to the customer.
Nonetheless, RG&E hedges approximately 70% of its gas supply price through the
purchase of derivative contracts and the use of storage assets. The balance of
RG&E's natural gas requirements is procured through spot market purchases and is
subject to market price fluctuations.
Under the Electric Settlement, RG&E's electric rates are capped at
specified levels through June 30, 2002. As a result of owned generation and
long-term fixed rate supply contracts, RG&E is largely insulated from market
price fluctuations for procurement of its electric supply. In the event that
RG&E's generation assets fail to perform as planned, RG&E is exposed to market
price fluctuations. RG&E mitigates this risk through the use of hedging
contracts and generation insurance on a significant percentage of its owned
generation during its peak summer months.
Energetix has entered into electric and natural gas purchase commitments
with numerous suppliers. These commitments support fixed and variable price
offerings to retail electric and gas customers. Additionally, Energetix enters
into exchange-traded option contracts for natural gas. These contracts are
closely monitored on a daily basis to manage the price risk associated with
future commodity purchases.
Energetix, through its subsidiary Griffith, is in the business of
purchasing liquid-fuel-related commodities for resale to its customers. To
manage the resulting market price risk, Griffith enters into various exchange-
traded futures and option contracts and over-the-counter contracts with third
parties. These contracts are closely monitored on a daily basis to manage the
price risk associated with inventory and future commodity purchases.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to Notes 2, 3 and 5 of the Notes to Financial
Statements.
GRIFFITH OWNED SITES
In connection with its Big Flats, New York terminal, Griffith has been
complying with the Unilateral Administrative Order issued by the EPA. Pursuant
to a cost sharing agreement with Sun Pipe Line Company, Griffith continues to
bear one-half of the costs necessary to comply with the order. To date Griffith
has spent $1.8 million on this compliance. Griffith has asserted cross-claims
for contribution and/or indemnification from Sun Pipe Line Company, and
compliance with the order is proceeding on this basis accordingly.
Since February 1996, Griffith has been involved in a legal proceeding in
New York State Supreme Court for Steuben County, related to the environmental
matter in the above paragraph. In Steuben Contracting v. Sun Pipe Line Company,
Griffith Oil Co., Inc. and Chevron, USA, the plaintiff is seeking compensation
for property damage associated with petroleum discharge at Big Flats. In a
decision entered June 28, 2000, the trial court (i) granted summary judgment
against the defendant Sun Pipe Line, (ii) dismissed the complaint against
Chevron, USA, (iii) determined that a question of fact existed as to the
liability of Griffith as an operator of the failed spur, and (iv) denied Sun's
motion for indemnification pursuant to an Access Agreement signed by Griffith
upon discovery of the incident. The Court also determined in its decision that
Griffith did not own the failed spur. This Order was appealed by all
defendants, including Griffith. In April 2001, the Appellate Division for the
Fourth Department of Supreme Court determined that both Griffith Oil and Sun
Pipe Line were dischargers within the meaning of the New York State Navigation
Law, and responsible for the property damages which may be proved by Steuben
Contracting, the owner of lands
28
adjoining Griffith's Big Flats Petroleum Bulk Storage Terminal. Certain causes
of action against Chevron, USA, successor by merger to Gulf Oil, were
reinstated. The plaintiff's damages, as well as the respective claims among the
defendants for contribution and indemnification, have yet to be tried. With the
exception of amounts for which Griffith has assumed responsibility under the
cost-sharing agreement with Sun Pipe Line, an estimate of the possible cost to
Griffith cannot be made at this time.
The State of New York has separately commenced an action for statutory
penalties in connection with this discharge. The company has answered the
complaint and denied the allegations, asserting that it was not responsible for
the discharge. Griffith is unable to estimate the possible cost of any
penalties at this time.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: None
(b) Reports on Form 8-K:
RGS Energy Group, Inc.
Rochester Gas and Electric Corporation
A report was filed August 10, 2001, including under Item 5, Other Events, that
RG&E has reached an agreement with the Staff of the PSC on a joint settlement
proposal with respect to the regulatory and ratemaking aspects of the sale of
RG&E's interest in the Nine Mile Two generating facility.
A report was filed November 9, 2001, including under Item 2, Acquisition or
Disposition of Assets, that RG&E has sold its 14% interest in the Nine Mile Two
generating facility.
29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each of
the Registrants have duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
RGS ENERGY GROUP, INC.
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(Registrant)
Date: November 12, 2001 By /s/ Mark Keogh
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Mark Keogh
Treasurer
Date: November 12, 2001 By /s/ William J. Reddy
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William J. Reddy
Controller
ROCHESTER GAS AND ELECTRIC CORPORATION
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(Registrant)
Date: November 12, 2001 By /s/ Mark Keogh
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Mark Keogh
Vice President and Treasurer
Date: November 12, 2001 By /s/ William J. Reddy
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William J. Reddy
Vice President and Controller