<PAGE>
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, 2000
------------------
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, 2000, (i) RGS Energy Group, Inc.
(RGS) had outstanding 34,516,513 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 Instructions (H)(2).
<PAGE>
2
INDEX
<TABLE>
<CAPTION>
Page No.
<S> <C>
PART I - FINANCIAL INFORMATION
RGS Energy Group, Inc.
Consolidated Balance Sheet - September 30, 2000 and
December 31, 1999....................................................................................... 1 - 2
Consolidated Statement of Income - Three Months and Nine Months Ended
September 30, 2000 and 1999............................................................................ 3 - 4
Consolidated Statement of Cash Flows - Nine Months Ended
September 30, 2000 and 1999............................................................................ 5
Rochester Gas and Electric Corporation
Balance Sheet - September 30, 2000 and December 31, 1999................................................ 6 - 7
Statement of Income - Three Months and Nine Months Ended
September 30, 2000 and 1999............................................................................. 8 - 9
Statement of Cash Flows - Nine Months Ended
September 30, 2000 and 1999............................................................................. 10
Notes to Financial Statements.............................................................................. 11 -17
Management's Discussion and Analysis of Financial
Condition and Results of Operations..................................................................... 17 - 29
Quantitative and Qualitative Disclosures About
Market Risk.............................................................................................. 29 - 30
PART II - OTHER INFORMATION
Legal Proceedings.......................................................................................... 30
Exhibits and Reports on Form 8-K........................................................................... 30
Signatures................................................................................................. 31
</TABLE>
-----------------
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" includes 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.
<PAGE>
3
Abbreviations and Glossary
Company or RGS RGS Energy Group, Inc., a holding company formed August 2,
1999, which is the parent company of Rochester Gas and
Electric Corporation, RGS Development Corporation and
Energetix, Inc.
CWIP Construction work-in progress
RGS Development RGS Development Corporation, a wholly-owned subsidiary of
the Company
EITF Emerging Issues Task Force of the Financial Accounting
Standards Board
Energetix Energetix, Inc., a wholly-owned subsidiary of the Company
Energy Choice A competitive electric retail access program of RG&E being
phased-in over a period ending July, 2001.
FERC Federal Energy Regulatory Commission
Ginna Plant Ginna Nuclear Plant wholly owned by RG&E
Griffith Griffith Oil Company, Inc ., an oil, gasoline and propane
distribution company acquired by Energetix in 1998
LDC Local Distribution Company
Nine Mile Two Nine Mile Point Nuclear Plant Unit No. 2 of which RG&E owns
a 14% share
NOI Notice of Inquiry
NOPR Notice of Proposed Rulemaking
NRC Nuclear Regulatory Commission
NYISO New York Independent System Operator
O&M Operation and Maintenance
PSC New York State Public Service Commission
RG&E Rochester Gas and Electric Corporation, a wholly-owned
subsidiary of RGS
SEC Securities and Exchange Commission
Electric Settlement 1997 Competitive Opportunities Case Settlement among RG&E,
PSC and other parties which provides the framework for the
development of competition in the electric energy
marketplace through June 30, 2002
SFAS Statement of Financial Accounting Standards
<PAGE>
1
PART 1 - FINANCIAL INFORMATION
------------------------------
ITEM1. FINANCIAL STATEMENTS
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
Assets Unaudited)
-----------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric $2,448,221 $2,399,532
Gas 461,587 453,634
Common 137,542 130,118
Nuclear 291,640 270,447
---------- ----------
3,338,990 3,253,731
Less: Accumulated depreciation 1,723,253 1,636,955
Nuclear fuel amortization 251,274 239,243
---------- ----------
1,364,463 1,377,533
Construction work in progress 113,234 95,862
---------- ----------
Net Utility Plant 1,477,697 1,473,395
---------- ----------
Current Assets
Cash and cash equivalents 1,685 8,288
Accounts receivable, net of allowance for doubtful accounts:
2000 - $34,236; 1999 - $34,026 90,137 90,239
Unbilled revenue receivable 35,908 58,005
Materials, supplies and fuels 65,254 38,206
Prepayments 34,672 24,576
Other current assets 2,229 523
---------- ----------
Total Current Assets 229,885 219,837
---------- ----------
Intangible Assets
Goodwill, net 12,678 13,894
Other Intangible Assets 13,890 7,338
---------- ----------
Total Intangible Assets 26,568 21,232
---------- ----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 243,571 220,815
Nine Mile Two deferred costs 27,418 28,206
Unamortized debt expense 16,997 17,984
Other deferred debits 7,129 13,137
Regulatory assets 436,692 466,231
Other assets 614 2,037
---------- ----------
Total Deferred Debits and Other Assets 732,421 748,410
---------- ----------
Total Assets $2,466,571 $2,462,874
---------- ----------
</TABLE>
<PAGE>
2
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
Capitalization and Liabilities (Unaudited)
---------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization
Long term debt - mortgage bonds $ 580,117 $ 580,070
- promissory notes 233,158 235,395
Affiliate preferred stock redeemable at option of Company 47,000 47,000
Affiliate preferred stock subject to mandatory redemption 25,000 25,000
Common shareholders' equity
Common stock
Authorized 100,000,000 shares; 38,885,813 shares
issued at September 30, 2000 and at December 31, 1999 700,803 700,268
Retained earnings 174,745 153,186
---------- ----------
875,548 853,454
Less: Treasury stock at cost (4,222,700 shares at September 30, 2000
and 2,942,600 shares at December 31, 1999) 112,811 83,252
---------- ----------
Total Common Shareholders' Equity 762,737 770,202
---------- ----------
Total Capitalization 1,648,012 1,657,667
---------- ----------
Long Term Liabilities
Nuclear waste disposal 95,792 91,743
Uranium enrichment decommissioning 11,279 10,911
Site remediation 22,988 23,698
---------- ----------
130,059 126,352
---------- ----------
Current Liabilities
Long term debt due within one year 8,189 37,643
Short term debt 44,000 10,500
Accounts payable 83,939 54,221
Dividends payable 16,515 17,078
Equal payment plan 4,483 10,529
Other 44,315 39,385
---------- ----------
Total Current Liabilities 201,441 169,356
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 285,821 318,694
Pension costs accrued 35,665 48,628
Kamine deferred costs 53,598 58,738
Post employment benefits 53,860 48,653
Other 58,115 34,786
---------- ----------
Total Deferred Credits and Other Liabilities 487,059 509,499
---------- ----------
Commitments and Other Matters - -
---------- ----------
Total Capitalization and Liabilities $2,466,571 $2,462,874
---------- ----------
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
3
RGS Energy Group Inc.
Consolidated Statement of Income
(Thousands of dollars)
(Unaudited)
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>
For the Three Months Ended
September 30,
2000 1999
---------- -----------
<S> <C> <C>
OPERATING REVENUES
Electric $ 189,569 $ 190,372
Gas 37,428 32,300
Other 87,308 57,181
--------- ---------
Total Operating Revenues 314,305 279,853
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 13,382 15,629
Purchased electricity 27,928 16,166
Gas purchased for resale 24,915 18,160
Unregulated fuel expenses 80,310 51,466
--------- ---------
Total Fuel Expenses 146,535 101,421
--------- ---------
Operating Revenues Less Fuel Expenses 167,770 178,432
Other Operating Expenses
Operations and maintenance excluding fuel 80,053 77,957
Unregulated operating and maintenance expenses excluding fuel 6,974 6,062
Depreciation and amortization 29,200 28,967
Taxes - state, local and other 21,541 26,449
Income taxes 3,040 9,330
--------- ---------
Total Other Operating Expenses 140,808 148,765
--------- ---------
Operating Income 26,962 29,667
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds used during construction (225) (124)
Income taxes 473 677
Other - net (2,963) (1,870)
--------- ---------
Total Other (Income) and Deductions (2,715) (1,317)
INTEREST CHARGES
Long term debt 14,458 12,996
Other - net 1,485 1,297
Allowance for borrowed funds used during construction (361) (199)
--------- ---------
Total Interest Charges 15,582 14,094
--------- ---------
Preferred Stock Dividend Requirements 925 925
--------- ---------
Net Income Applicable to Common Stock 13,170 15,965
--------- ---------
Average Number of Common Shares (000's)
Common Stock 34,928 36,443
Common Stock and Equivalents 35,009 36,535
Earnings per Common Share - Basic $ 0.38 $ 0.44
Earnings per Common Share - Diluted $ 0.38 $ 0.44
Cash Dividends Paid per Common Share $ 0.45 $ 0.45
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
4
RGS Energy Group Inc.
Consolidated Statement of Income
(Thousands of dollars)
(Unaudited)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Year To Date
September 30,
2000 1999
---------- ---------
<S> <C> <C>
OPERATING REVENUES
Electric $ 543,375 $ 529,955
Gas 214,249 203,348
Other 253,237 148,447
---------- ---------
Total Operating Revenues 1,010,861 881,750
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 35,419 37,642
Purchased electricity 64,366 44,489
Gas purchased for resale 121,180 105,530
Unregulated fuel expenses 229,323 127,188
---------- ---------
Total Fuel Expenses 450,288 314,849
---------- ---------
Operating Revenues Less Fuel Expenses 560,573 566,901
Other Operating Expenses
Operations and maintenance excluding fuel 218,534 224,641
Unregulated operating and maintenance expenses excluding fuel 21,182 18,379
Depreciation and amortization 87,415 89,830
Taxes - state, local and other 71,229 85,325
Income taxes 46,080 41,909
---------- ---------
Total Other Operating Expenses 444,440 460,084
---------- ---------
Operating Income 116,133 106,817
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds used during construction (605) (507)
Income taxes 1,814 2,083
Other - net (3,679) (5,710)
---------- ---------
Total Other (Income) and Deductions (2,470) (4,134)
INTEREST CHARGES
Long term debt 43,540 39,217
Other - net 4,300 3,571
Allowance for borrowed funds used during construction (968) (811)
---------- ---------
Total Interest Charges 46,872 41,977
---------- ---------
Preferred Stock Dividend Requirements 2,775 3,158
---------- ---------
Net Income Applicable to Common Stock 68,956 65,816
---------- ---------
Average Number of Common Shares (000's)
Common Stock $ 35,365 $ 36,828
Common Stock and Equivalents $ 35,436 36,863
Earnings per Common Share - Basic $ 1.95 $ 1.79
Earnings per Common Share - Diluted $ 1.95 $ 1.79
Cash Dividends Paid per Common Share $ 1.35 $ 1.35
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
5
RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
(Thousands of Dollars) September 30,
----------------------------------------------------------------------------------------------------------------
2000 1999*
--------- ---------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 71,731 $ 68,974
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 100,298 101,681
Deferred recoverable fuel costs 10,112 (1,927)
Income taxes deferred (22,643) (3,554)
Allowance for funds used during construction (1,573) (1,318)
Unbilled revenue 22,097 4,705
Post employment benefit/pension costs 4,581 5,277
Provision for doubtful accounts 210 7,359
Changes in certain current assets and liabilities:
Accounts receivable (108) 139
Materials, supplies and fuels (27,048) (1,240)
Taxes accrued (8,570) (2,933)
Accounts payable 29,718 14,066
Other current assets and liabilities, net (4,946) (5,950)
Other, net 23,193 3,183
--------- ---------
Total Operating 197,052 188,462
--------- ---------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (102,605) (78,945)
Nuclear generating plant decommissioning fund (15,536) (15,536)
Acquisitions, net of cash (7,676) (3,152)
Other, net - (34)
--------- ---------
Total Investing (125,817) (97,667)
--------- ---------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Proceeds from short term borrowings, net 33,500 2,840
Retirement of long term debt (30,000) -
Retirement of preferred stock - (10,000)
Repayment of promissory notes (2,810) (5,096)
Dividends paid on preferred stock (2,775) (3,349)
Dividends paid on common stock (47,960) (49,911)
Payment for treasury stock (29,559) (27,594)
Other, net 1,766 344
--------- ---------
Total Financing (77,838) (92,766)
--------- ---------
Decrease in cash and cash equivalents (6,603) (1,971)
Cash and cash equivalents at beginning of period 8,288 6,523
--------- ---------
Cash and cash equivalents at end of period $ 1,685 $ 4,552
--------- ---------
</TABLE>
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
<PAGE>
6
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
Assets (Unaudited)
-----------------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric $2,448,221 $2,399,532
Gas 461,587 453,634
Common 111,252 107,469
Nuclear 291,640 270,447
---------- ----------
3,312,700 3,231,082
Less: Accumulated depreciation 1,719,025 1,634,334
Nuclear fuel amortization 251,274 239,243
---------- ----------
1,342,401 1,357,505
Construction work in progress 113,235 95,862
---------- ----------
Net Utility Plant 1,455,636 1,453,367
---------- ----------
Current Assets
Cash and cash equivalents 3,757 6,443
Accounts receivable, net of allowance for doubtful accounts:
2000 - $33,482; 1999 - $33,365 67,791 70,388
Affiliate receivable 26,352 13,197
Unbilled revenue receivable 29,872 55,661
Materials, supplies and fuels 53,766 33,378
Prepayments 33,688 23,294
Other current assets - 145
---------- ----------
Total Current Assets 215,226 202,506
---------- ----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 243,571 220,815
Nine Mile Two deferred costs 27,418 28,206
Unamortized debt expense 16,997 17,984
Other deferred debits 7,128 13,760
Regulatory assets 436,692 466,231
Other assets - -
---------- ----------
Total Deferred Debits and Other Assets 731,806 746,996
---------- ----------
Total Assets $2,402,668 $2,402,869
---------- ----------
</TABLE>
<PAGE>
7
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
Capitalization and Liabilities (Unaudited)
-----------------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization
Long term debt - mortgage bonds $ 580,117 $ 580,070
- promissory notes 212,904 215,930
Preferred stock redeemable at option of Company 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholders' equity
Authorized 50,000,000 shares; 38,885,813 shares
issued at September 30, 2000 and at December 31, 1999 700,803 700,268
Retained earnings 160,163 137,854
------------- -------------
860,966 838,122
Less: Treasury stock at cost (4,222,700 shares at September 30, 2000
and 2,942,600 shares at December 31, 1999) 112,811 83,252
------------- -------------
Total Common Shareholders' Equity 748,155 754,870
------------- -------------
Total Capitalization 1,613,176 1,622,870
------------- -------------
Long Term Liabilities
Nuclear waste disposal 95,792 91,743
Uranium enrichment decommissioning 11,279 10,911
Site remediation 22,357 22,357
------------- -------------
129,428 125,011
------------- -------------
Current Liabilities
Long term debt due within one year 3,998 33,781
Short term debt 31,500 -
Accounts payable 72,264 42,263
Affiliate payable 14,865 12,961
Dividends payable 16,515 17,078
Equal payment plan 4,483 10,529
Other 33,377 33,243
------------- -------------
Total Current Liabilities 177,002 149,855
------------- -------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 282,991 314,683
Pension costs accrued 35,665 48,628
Kamine deferred costs 53,598 58,738
Post employment benefits 53,860 48,653
Other 56,948 34,431
------------- -------------
Total Deferred Credits and Other Liabilities 483,062 505,133
------------- -------------
Commitments and Other Matters - -
------------- -------------
Total Capitalization and Liabilities $ 2,402,668 $ 2,402,869
------------- -------------
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
8
Rochester Gas and Electric Corporation
Statement of Income
(Thousands of dollars)
(Unaudited)
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
For the Three Months Ended
September 30,
2000 1999
----------------- -----------------
<S> <C> <C>
OPERATING REVENUES
Electric $ 187,472 $ 189,649
Gas 36,214 32,266
Other - 17,433
----------------- -----------------
Total Operating Revenues 223,686 239,348
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 13,382 15,629
Purchased electricity 27,205 15,972
Gas purchased for resale 23,530 18,048
Unregulated fuel expenses - 15,783
----------------- -----------------
Total Fuel Expenses 64,117 65,432
----------------- -----------------
Operating Revenues Less Fuel Expenses 159,569 173,916
Other Operating Expenses
Operations and maintenance excluding fuel 80,053 77,956
Unregulated operating and maintenance expenses excluding fuel - 1,919
Depreciation and amortization 28,239 28,430
Taxes - state, local and other 20,453 25,669
Income taxes 3,685 9,694
----------------- -----------------
Total Other Operating Expenses 132,430 143,668
----------------- -----------------
Operating Income 27,139 30,248
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds used during construction (225) (124)
Income taxes 262 436
Other - net (2,469) (1,919)
----------------- -----------------
Total Other (Income) and Deductions (2,432) (1,607)
INTEREST CHARGES
Long term debt 14,130 12,750
Other - net 1,006 1,220
Allowance for borrowed funds used during construction (361) (199)
----------------- -----------------
Total Interest Charges 14,775 13,771
----------------- -----------------
Net Income 14,796 18,084
----------------- -----------------
Dividends on Preferred Stock 925 925
----------------- -----------------
Net Income Applicable to Common Stock 13,871 17,159
----------------- -----------------
Average Number of Common Shares (000's)
Common Stock 34,928 36,443
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
9
ROCHESTER GAS AND ELECTRIC CORPORATION
Statement of Income
(Thousands of dollars)
(Unaudited)
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
Year To Date
September 30,
2000 1999
----------- ------------
<S> <C> <C>
OPERATING REVENUES
Electric $535,451 $529,232
Gas 205,651 203,315
Other - 108,698
-------- --------
Total Operating Revenues 741,102 841,245
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 35,418 37,642
Purchased electricity 59,800 44,295
Gas purchased for resale 113,129 105,418
Unregulated fuel expenses - 91,505
-------- --------
Total Fuel Expenses 208,347 278,860
-------- --------
Operating Revenues Less Fuel Expenses 532,755 562,385
Other Operating Expenses
Operations and maintenance excluding fuel 218,534 224,641
Unregulated operating and maintenance expenses excluding fuel - 14,235
Depreciation and amortization 84,549 89,292
Taxes - state, local and other 67,938 84,546
Income taxes 46,318 42,273
-------- --------
Total Other Operating Expenses 417,339 454,987
-------- --------
Operating Income 115,416 107,398
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds used during construction (605) (507)
Income taxes 1,075 2,218
Other - net (1,945) (5,760)
-------- --------
Total Other (Income) and Deductions (1,475) (4,049)
INTEREST CHARGES
Long term debt 42,476 38,971
Other - net 2,965 3,495
Allowance for borrowed funds used during construction (968) (811)
-------- --------
Total Interest Charges 44,473 41,655
-------- --------
Net Income 72,418 69,792
-------- --------
Dividends on Preferred Stock 2,775 3,157
-------- --------
Net Income Applicable to Common Stock 69,643 66,635
-------- --------
Average Number of Common Shares (000's)
Common Stock 35,365 36,828
-------- --------
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
10
ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
(Thousands of Dollars) September 30,
----------------------------------------------------------------------------------------------------------------------------
2000 1999*
--------- -----------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 72,418 69,792
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 97,459 99,356
Deferred recoverable fuel costs 10,112 (1,927)
Income taxes deferred (21,461) (6,620)
Allowance for funds used during construction (1,573) (1,318)
Unbilled revenue 25,789 5,297
Post employment benefit/pension costs 4,581 5,277
Provision for doubtful accounts 117 7,077
Changes in certain current assets and liabilities:
Accounts receivable (10,675) (2,806)
Materials, supplies and fuels (20,387) 1,974
Taxes accrued (8,928) (5,030)
Accounts payable 31,905 11,090
Other current assets and liabilities, net (7,912) (1,344)
Other, net 22,774 3,889
--------- -----------
Total Operating 194,219 184,707
--------- -----------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (101,182) (77,619)
Nuclear generating plant decommissioning fund (15,536) (15,536)
Other, net 769 1,547
--------- -----------
Total Investing (115,949) (91,608)
--------- -----------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Proceeds from short term borrowings, net 31,500 2,040
Retirement of long term debt (30,000) -
Retirement of preferred stock - (10,000)
Repayment of promissory notes (2,810) (1,587)
Dividends paid on preferred stock (2,775) (3,349)
Dividends paid on common stock (47,960) (49,911)
Payment for treasury stock (29,559) (27,594)
Corporate restructuring to establish holding company - (8,329)
Other, net 648 4,171
--------- -----------
Total Financing (80,956) (94,559)
--------- -----------
Decrease in cash and cash equivalents (2,686) (1,460)
Cash and cash equivalents at beginning of period 6,443 5,366
--------- -----------
Cash and cash equivalents at end of period $ 3,757 $ 3,906
--------- -----------
</TABLE>
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
<PAGE>
11
RGS ENERGY GROUP, INC.
ROCHESTER GAS AND ELECTRIC CORPORATION
NOTES TO FINANCIAL STATEMENTS
Note 1: GENERAL
Holding Company Formation. On August 2, 1999, RG&E was reorganized into a
holding company structure in accordance with the Agreement and Plan of Exchange
between RG&E and RGS. RG&E's common stock was exchanged on a share-for-share
basis for the common stock of RGS. RG&E's preferred stock was not exchanged as
part of the share exchange and will continue as shares of RG&E.
Basis of Presentation. This Quarterly Report on Form 10-Q is a combined
report of RGS Energy and RG&E, a regulated electric and gas subsidiary. The
Notes to Financial Statements apply to both RGS Energy and RG&E. RGS's
Consolidated Financial Statements include the accounts of RGS and its wholly
owned subsidiaries, primarily RG&E, and two non-utility subsidiaries, RGS
Development and Energetix. RGS's prior period consolidated financial statements
have been prepared from RG&E's prior period consolidated financial statements,
except that accounts have been reclassified to reflect RGS's structure. 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 2000 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, 1999.
New York State Tax Changes. On May 15, 2000 changes to the New York State
tax laws were signed into law retroactively effective January 1, 2000. In 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. In addition
to a year-to-date reduction in gross receipts and excess dividends taxes of $7.3
million, and year-to-date state income tax effects of $8.9 million and year-to-
date federal income tax effects of $(0.9) million, a transition item, deferred
state income taxes, was established using existing federal deferred taxes to
recognize timing differences between book and tax deductibility. The
transition item results in an adjusted one-time tax deduction of $16.7 million.
The net effect of all of these tax changes has been deferred for future rate
treatment in accordance with RG&E's Electric Settlement.
Adoption of SFAS 133 - Accounting for Derivative Instruments and Hedging
Activities. The Company will adopt SFAS 133 - Accounting for Derivative
Instruments and Hedging Activities as of January 1, 2001. This broad and
complex standard requires, with limited exception, derivative transactions to
be recognized and recorded on the Company's balance sheet at fair value. The
standard allows for hedge accounting, provided stringent documentation
requirements are met prior to execution of the hedge transaction. Where
applicable, the Company intends to elect hedge accounting under the Standard.
As of September 30, 2000, the Company substantially completed its inventory
of derivative transactions, including both stand alone derivatives and those
embedded in host contracts. The majority of the Company's identified derivative
transactions are commodity contracts for the purchase of natural gas,
electricity, and other commodities purchased for resale. These contracts result
from the Company's normal business operations, and, as such, are exempt from the
Standard under the Normal Purchase and Sales Exclusion. Substantially all of the
Company's remaining derivative transactions result from corporate hedging
activities and, as such, are expected to qualify for hedge accounting treatment.
Had the Company adopted the Statement as of September 30, 2000, it would have
recognized an estimated $ 2.0 million in Other Comprehensive Income, reflecting
the current market value of its derivative positions. With the majority of
derivative transactions either excluded under the Normal Purchases and Sales
Exclusion or qualifying for
<PAGE>
12
hedge accounting, the adoption of FAS 133 is not expected to have a material
financial statement effect.
Note 2. OPERATING SEGMENT FINANCIAL INFORMATION
Under SFAS-131, Disclosures about Segments of an Enterprise and Related
Information, information pertaining to operating segments is required to be
reported. Upon adoption of SFAS-131, the Company identified three operating
segments, driven by the types of products and services offered and regulatory
environment under which the Company primarily operates. The three segments of
RGS are Regulated Electric, Regulated Gas, and Unregulated. The regulated
segments' financial records are maintained in accordance with generally accepted
accounting principles (GAAP) and Public Service Commission (PSC) accounting
policies. The Unregulated segment's financial records are maintained in
accordance with GAAP.
<TABLE>
<CAPTION>
For the Three Months Ended September 30, 2000
Regulated Regulated
Electric Gas Unregulated
-------- ---------- ------------
(thousands of dollars) 2000 1999 2000 1999 2000 1999
----------------------------------------------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Operating Income/(Loss) $ 30,754 $ 35,877 $ (3,615) $ (5,376) $ (180) $ (943)
Revenues - External Customers 187,472 189,425 36,214 32,057 111,392 70,969
Revenues - Intersegment Transactions 20,773 12,537 - 61 - -
</TABLE>
<TABLE>
<CAPTION>
For the Nine Months Ended September 30, 2000
Regulated Regulated
Electric Gas Unregulated
-------- -------- -----------
(thousands of dollars) 2000 1999 2000 1999 2000 1999
----------------------------------------------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Operating Income $ 98,888 $ 92,094 $ 16,528 $ 14,111 $ 670 $ 114
Revenues - External Customers 535,451 527,782 205,651 200,418 324,835 185,630
Revenues - Intersegment Transactions 55,076 31,790 - 290 - -
</TABLE>
The operations of RGS Development Corporation and Energyline (a previous
subsidiary of RGS now dissolved) are included in Other (Income) and Deductions
in the RGS Energy Group, Inc. Consolidated Statement of Income. The total
amount of the revenues identified by operating segment do not equal the total
Company consolidated amounts as shown in the RGS Consolidated Statement of
Income. This is due to the elimination of certain intersegment revenues during
consolidation. A reconciliation follows:
<TABLE>
<CAPTION>
For the Three Months For the Nine Months
Ended Sept 30 Ended Sept 30
2000 1999 2000 1999
-------- -------- ---------- --------
<S> <C> <C> <C> <C>
Revenues
Regulated Electric $187,472 $189,425 $ 535,451 $527,782
Regulated Gas 36,214 32,057 205,651 200,418
Unregulated 111,392 70,969 324,835 185,630
-------- -------- ---------- --------
Total 335,078 292,451 1,065,937 913,830
Reported on RGS Consolidated
Income Statement 314,305 279,853 1,010,861 881,750
Difference to reconcile 20,773 12,598 55,076 32,080
Intersegment Revenue
Regulated Electric from Unregulated 20,773 12,537 55,076 31,790
Regulated Gas from Unregulated - 61 - 290
-------- -------- ---------- --------
Total Intersegment 20,773 12,598 55,076 32,080
</TABLE>
<PAGE>
13
Note 3. COMMITMENTS AND OTHER MATTERS
The following matters supplement the information contained in Note 10 to the
financial statements included in the RGS and RG&E combined Annual Report on Form
10-K for the year ended December 31, 1999 and should be read in conjunction with
the material contained in that Note.
REGULATORY ASSETS
With PSC approval RG&E has deferred certain costs rather than recognize
them on its books 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 Sheets. Such cost deferral is
appropriate under traditional regulated cost-of-service rate setting, where all
prudently incurred costs are recovered through rates. In a purely competitive
pricing environment, such costs might not have been incurred and could not have
been deferred. Accordingly, if RG&E was no longer allowed to defer some or all
of these costs under SFAS-71, these assets would be adjusted accordingly, up to
and including the entire amount being written off.
Below is a summarization of the Regulatory Assets as of September 30, 2000
and December 31, 1999:
<TABLE>
<CAPTION>
Millions of Dollars
Sept. 30, 2000 Dec. 31, 1999
-------------- -------------
<S> <C> <C>
Kamine Settlement $181.4 $187.5
Income Taxes 119.2 129.5
Oswego Plant Sale 75.4 78.6
Deferred Environmental SIR costs 20.5 20.5
Uranium Enrichment Decommissioning Deferral 13.0 13.9
Storm Costs 9.1 8.5
Other, net 18.1 27.7
------ ------
Total - Regulatory Assets $436.7 $466.2
====== ======
</TABLE>
See the combined 1999 Form 10-K of RGS and RG&E, Item 8, Note 10 of the Notes
to financial Statements, "Regulatory Matters" for a description of the
Regulatory Assets shown above.
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
assumed in the estimation. The amount of potentially strandable assets at
September 30, 2000 depends on market prices and the competitive market in New
York State which is subject to continuing changes that are not yet determinable,
but the amount could be significant. Strandable assets, if any, could be
written down for impairment of recovery based on SFAS-121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,
which requires write-down of long-lived assets whenever events or circumstances
occur which indicate that the carrying amount of a long-lived asset may not be
recoverable.
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. RG&E has been restructuring its transportation, storage and
supply portfolio to reduce its potential exposure to strandable assets.
Regulatory developments referred to under "Gas Retail Access Settlement" below,
may affect this exposure; but whether and to what extent there may be an impact
on the level and recoverability of strandable assets cannot be determined at
this time.
At June 30, 2000 RG&E believes that its regulatory assets are probable of
recovery. The Electric
<PAGE>
14
Settlement in the Competitive Opportunities Proceeding does not impair the
opportunity of RG&E to recover its investment in these assets. However, the PSC
issued an Opinion and Order Instituting Further Inquiry on March 20, 1998 to
address issues surrounding nuclear generation. After an initial meeting in
January 1999, the case has not significantly progressed. However, in an order
issued April 25, 2000 in a case specifically focused on Nine Mile Two, the PSC
urged the utility owners of Nine Mile Two to determine the market value of that
Plant and such owners subsequently announced their intention to offer the Plant
for sale in an auction process. See below under Nuclear-Related matters: Nine
Mile Nuclear Plants. The ultimate determination in the 1998 proceeding or in the
more recent proceedings addressing Nine Mile Two could have an impact on
strandable assets and the recovery of nuclear costs.
NUCLEAR-RELATED MATTERS
NINE MILE NUCLEAR PLANTS. On June 24, 1999, Niagara Mohawk and New York
State Electric and Gas (NYSEG) announced their intention to sell their interests
in the Nine Mile One and Nine Mile Two nuclear plants to AmerGen Energy Company,
L.L.C. (AmerGen), a joint venture of PECO Energy of Philadelphia and British
Energy. Niagara Mohawk owns 41 percent of Nine Mile Two and 100 percent of Nine
Mile One and NYSEG owns 18 percent of Nine Mile Two.
RG&E's 14 percent interest in Nine Mile Two was not included in the
proposal but RG&E has a right of first refusal to buy the interests of the other
owners of Nine Mile Two on terms at least as favorable as those offered. RG&E
exercised its right of first refusal and broadened it to include Nine Mile One
with which Nine Mile Two was paired in the proposal. However, in the ensuing
discussions with the PSC staff it became clear that the transaction on the terms
proposed would not be approved by the PSC.
On April 25, 2000, the PSC issued an order that allows NYSEG and Niagara
Mohawk to withdraw their petition to sell their interests in the Nine Mile
plants to AmerGen. The order concludes that Nine Mile's market value is "greatly
in excess of the original AmerGen purchase price" and that multiple bidders are
now interested in the Nine Mile plants. The order also concludes that
"...failure for the utilities to determine the market value of the Nine Mile
facilities at this time, through an open process, would raise serious prudence
questions." With respect to stranded costs, the PSC order indicates that
stranded costs cannot be finally quantified "until the disposition of the plants
by the utilities is decided." The PSC's order does, however, observe (1) that a
sale would be considered within its policy of separating generation from
transmission and distribution, (2) that a sale at current market values would
constitute appropriate mitigation of stranded costs and (3) that ratemaking
treatment of a sale would be resolved in accordance with each company's
competitive opportunities/restructuring order taking into account reduced risk
and corollary divestiture effects.
On June 1, 2000, RG&E issued a press release announcing an auction process
by RG&E, Central Hudson Gas & Electric Corporation, NYSEG and Niagara Mohawk in
connection with their ownership interests in Nine Mile Two and Niagara Mohawk's
interest in Nine Mile One.
Discussions with the staff of the PSC and Nine Mile Two co-owners regarding
the auction process and the regulatory impact thereof continue but RG&E is
unable to predict the ultimate outcome. At September 30, 2000 the net book value
of RG&E's 14 percent interest in the Nine Mile Two generating facility was
approximately $367 million.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND. On June 12,
1998, 16 electric utilities from across the country, including RG&E, filed
multi-count complaints against the United States government in the United States
District Court for the Southern District of New York. The suits challenge the
constitutionality of a $2.25 billion, industry-wide retroactive assessment
imposed by the federal government on domestic nuclear power companies to pay for
the clean up of the federal government's three uranium enrichment plants. In
separate rulings, the District Court twice denied Government efforts to prevent
the case from being heard in that Court. A subsequent Government motion to
transfer the case to the Federal Court of Claims, where utility suits based on
similar facts have been dismissed, was argued in Federal Court in the spring
2000. A decision has not yet been issued.
The assessments for Ginna and RG&E's share of Nine Mile Two are estimated to
total $22.1 million,
<PAGE>
15
excluding inflation and interest. Installments aggregating approximately $12.9
million have been paid through September 30, 2000. A liability has been
recognized on the financial statements along with a corresponding regulatory
asset. For the two facilities RG&E's liability at September 30, 2000 is $13.0
million ($11.3 million as a long-term liability and $1.7 million as a current
liability). RG&E is recovering these costs in rates.
GAS RETAIL ACCESS SETTLEMENT
On June 14, 2000, in connection with on-going settlement negotiations
pertaining to RG&E's gas rate and restructuring proposal filed with the PSC on
January 28, 2000 (see March 31, 2000 10-Q, "Rates and Regulatory Matters"),
RG&E, the PSC staff, and certain other parties to the negotiations entered into
a Settlement Agreement Pertaining to Certain Elements of Natural Gas Retail
Access Program (Retail Access Settlement). The Retail Access Settlement, which
the PSC approved in an order issued July 31, 2000, addresses the following
issues: (1) establishment of a Backout Credit to be paid to natural gas
marketers serving retail customers as an incentive to migration of those
customers from RG&E sales service to service from participating marketers; (2)
elimination of the Backout Credit in the event of market concentration, in which
case the affected marketer would no longer receive the Backout Credit with
respect to new customers; (3) establishment of a mechanism to keep RG&E whole
for the difference between the Backout Credit and actual reductions in RG&E's
costs resulting from migration; (4) introduction of the single-retailer model
for natural gas retail access in substantially the same form as currently in
effect for electric retail access; (5) management of transportation gas
deliveries into the RG&E system; (6) protocols regarding communications between
RG&E and the marketers operating on RG&E's system; and (7) continuation of
benefits to customers resulting from the release of upstream pipeline capacity
and the expiration and termination of pipeline contracts.
With one notable exception, the Retail Access Settlement is intended to
remain in effect at least through June 30, 2002, subject to being superseded by
a more comprehensive settlement agreement. The exception is the last enumerated
item, pertaining to upstream capacity. Under the Retail Access Settlement,
continuation of the current level of imputed benefits will be for a two-month
period consisting of September and October 2000. The benefits for those two
months will be $.8 million per month, which is approximately the same as their
recent historic level. RG&E and customers will share any capacity release
revenues and credits above the stated amount on a 5 percent/95 percent basis,
respectively. By letter dated October 18, 2000, RG&E agreed to extend the
imputation benefits for the months November 2000 through March 2001 at the level
of $.53 million per month.
Although the Backout Credit applies to customers who migrated to marketers on
or after July 1, 2000, the Retail Access Settlement assumes that RG&E's
opportunities for savings due to migration of customers will be extremely
limited until the implementation of a single-retailer system of gas retail
access in substantially the same form as that currently in place for electric
retail access. Accordingly, the Differential between the Backout Credit paid
marketers ($3.75 per customer per month) and RG&E's actual savings is initially
assumed to equal the Backout Credit, and RG&E is entitled to recover that entire
amount. Upon implementation of the single-retailer system for gas, which is
anticipated to occur on or about December 1, 2000, following approval of a
tariff filing by RG&E, RG&E expects to be able to realize savings from customer
migration. Accordingly, at that point, the Differential will decrease from
$3.75 per customer per month to $2.55 per customer per month. Both the Backout
Credit and the Differential are to remain in effect at these levels for the term
of the Retail Access Settlement, subject to possible further negotiations in the
event of particularly rapid migration.
RG&E, the PSC staff, and other parties are continuing settlement
negotiations aimed at a comprehensive gas rate and restructuring settlement.
RG&E is unable to predict the ultimate outcome of these negotiations or any PSC
decision pertaining thereto.
ENVIRONMENTAL MATTERS
NEW YORK INITIATIVES. The New York Attorney General (NYAG) sent a letter to
certain New York utilities in October, 1999 requesting historic information
regarding certain upgrades, modifications and maintenance activities at coal
fired power plants under their control. RG&E received such a letter requesting
<PAGE>
16
data covering a period back to 1977 for its Russell and (the now closed) Beebee
Stations. The letter suggests that those upgrades, modifications and
improvements may have required permission from the NYSDEC prior to their
occurrence. In order to assume legal control over the issue, the NYSDEC issued
subpoenas on January 13, 2000 to RG&E and the other NYAG letter recipients (with
the exception of one who had already supplied data to the NYAG) commanding
production of documents including, but not limited to, those requested by the
NYAG's October, 1999 information request. RG&E completed its information
collection activities and provided the requisite response by the March 1
deadline. Under cover of letter dated May 25, 2000, NYSDEC issued a Notice of
Violation (NOV) to RG&E, asserting that certain "modifications" to Russell and
Beebee Stations during 1983-87 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 State 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 against 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 NYSDEC. Since
July 2000, RG&E has had several such informal meetings with NYSDEC. If the
matter cannot be resolved through these discussions, RG&E expects to contest
vigorously NYSDEC's allegations.
Also in October 1999, the Governor of New York directed NYSDEC to require
electric generators to further reduce acid rain-causing emissions. The
governor's proposal suggests extending the existing NOx 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). In addition, the governor also
proposed that there be a targeted reduction of some 50% in SO2 emissions below
the existing Acid Rain Phase II limits. The State emission reductions would be
phased-in beginning January 1, 2003 and be complete by January 1, 2007. Since
this is only a proposed change, and subject to review, comment and modification,
no accurate estimate of its economic impact on RG&E can be made at this time.
OTHER MATTERS
EITF ISSUE 97-4 - DEREGULATION OF THE PRICING OF ELECTRICITY. In July
1997, the EITF reached a consensus on accounting rules for utilities' transition
plans for moving to more competitive environments and provided guidance on when
utilities with transition plans will need to discontinue the application of
SFAS-71.
The major EITF consensus was that the application of SFAS-71 to a segment
(e.g. generation) which is subject to a deregulation transition plan should
cease when the legislation or enabling rate order contains sufficient detail for
the utility to reasonably determine what the transition plan will entail. The
EITF also concluded that a decision to continue to carry some or all of the
regulatory assets (including stranded costs) and liabilities of the separable
portion of the business that is discontinuing the application of SFAS-71 should
be determined on the basis of where the regulated cash flows to realize and
settle them will be derived. If a transition plan provides for a non-bypassable
fee for the recovery of stranded costs, there may not be any significant write-
off if SFAS-71 is discontinued for a segment.
RG&E's application of the EITF 97-4 consensus has not affected its
financial position or results of operations because any above-market generation
costs, regulatory assets and regulatory liabilities associated with the
generation portion of its business will be recovered by the regulated portion of
RG&E through its distribution rates, given the Electric Settlement provisions.
The Electric Settlement provides for recovery of all prudently incurred sunk
costs (all investment in electric plant and electric regulatory assets) as of
March 1, 1997 by inclusion in rates charged pursuant to RG&E's distribution
access tariff. The Electric Settlement also states that "the Parties intend
that the provisions of this Settlement will allow RG&E to continue to recover
such costs, during the term of the Settlement, under SFAS-71", and that "such
treatment shall be consistent with the principle that RG&E shall have a
reasonable opportunity beyond July 1, 2002 to recover all such costs". The
Electric Settlement also addresses "to-go" costs, which are all capital costs
incurred after February 1997, operation and maintenance expenses, and property,
payroll and other taxes. The fixed portion of the
<PAGE>
17
non-nuclear generation to-go costs after April 30, 2001 (the date through which
RG&E currently expects to continue full-requirements electric service) and the
variable portion of the non-nuclear generation to-go costs after July 1, 1998
are subject to market forces and thus SFAS-71 would no longer apply. These costs
have been below prevailing market prices. RG&E's net investment at September 30,
2000 in nuclear generating assets is $599.5 million and in non-nuclear
generating assets is $58.5 million. (See "Nine Mile Nuclear Plants" for
information concerning status of the interests in Nine Mile Two owned by two co-
owners and Nine Mile One owned by Niagara Mohawk.)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The discussion presented below contains statements which are not historic
fact and which can be classified as forward looking. These statements can be
identified by the use of certain words which suggest forward looking
information, such as "believes," "will," "expects," "projects," "estimates" and
"anticipates". They can also be identified by the use of words which 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 nuclear generation
facilities including, (1) the PSC's indication that it would prefer that all
of the current owners sell their interests in the Nine Mile Point nuclear
generating facilities and determine market value through an open process,
(2) the exercise of the co-owners' rights of first refusal and (3) any
changes in regulatory status of nuclear generating facilities and their
related costs, including recovery of costs related to spent fuel and
decommissioning.
2. uncertainties related to the costs associated with management of the New
York electrical grid by the New York Independent System Operator and the
competitive electric wholesale market.
3. any state or federal legislative or regulatory initiatives (including the
results of negotiations between RG&E and the PSC regarding certain gas
restructurings) 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;
4. any changes in the ability of RG&E to recover environmental compliance costs
through increased rates;
5. any changes in the rate of industrial, commercial and residential growth in
RG&E's and RGS's service territories;
6. the development of any new technologies which allow customers to generate
their own energy or produce lower cost energy;
7. any unusual or extreme weather or other natural phenomena;
8. the ability of RGS to manage profitably new unregulated operations;
9. certain unknowable risks involved in operating unregulated businesses in new
territories and new industries;
10. the timing and extent of changes in commodity prices and interest rates; and
11. any other considerations that may be disclosed from time to time in the
publicly disseminated documents and filings of RGS and RG&E.
<PAGE>
18
Shown below is a listing of the principal items discussed.
RGS ENERGY GROUP, INC. Page 18
Unregulated Subsidiaries
ROCHESTER GAS AND ELECTRIC CORPORATION
Competition Page 19
Gas Retail Access
PSC Competitive Opportunities Case Settlement
Energy Choice
Nine Mile Nuclear Plants
New York Independent System Operator
Prospective Financial Position
Rates and Regulatory Matters Page 24
PSC Gas Restructuring Policy Statement
Gas Retail Access Settlement
Flexible Pricing Tariff
FERC Gas Market Proposals
FERC Order No. 2000
LIQUIDITY AND CAPITAL RESOURCES Page 25
Capital and Other Requirements
Financing
Redemption of Securities
Stock Repurchase Plan
EARNINGS SUMMARY Page 26
RESULTS OF OPERATIONS Page 27
Operating Revenues and Sales
Operating Expenses
Other Statement of Income Items
DIVIDENDS Page 29
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.
Unregulated Subsidiaries. It is part of RGS's financial strategy to seek
growth by entering into unregulated businesses in which RGS has invested $65
million (including loan guarantees) as of September 30, 2000. The Electric
Settlement allowed RG&E to provide the funding for RGS to invest up to $100
million in unregulated businesses. The first step in this direction was the
formation and operation of Energetix effective
<PAGE>
19
January 1, 1998. Energetix is an unregulated subsidiary that brings energy
products and services to the marketplace both within and outside of RG&E's
regulated franchise territory. Energetix markets electricity, natural gas, oil,
gasoline, and propane fuel energy services in an area extending in approximately
a 150-mile radius around Rochester.
In 1998, Energetix acquired Griffith Oil Company, Inc. (Griffith), the
second largest oil and propane distribution company in New York State. Griffith
has approximately 350 employees and operates 19 customer service centers.
Griffith gives Energetix access to new customers outside of RG&E's regulated
franchise territory. Acquisitions by Griffith in 1999 and 2000 have increased
Griffith's customer base by over 60 percent.
Additional information on Energetix operations (including Griffith) is
presented under the headings Operating Revenues and Sales, Operating Expenses,
and is contained in Note 2 of the Notes to Financial Statements.
In 1998, the Company formed RGS Development to pursue unregulated business
opportunities in the energy marketplace. Through September 30, 2000, RGS
Development's operations have not been material to RGS's results of operations
or its financial condition.
ROCHESTER GAS AND ELECTRIC CORPORATION
COMPETITION
GAS RETAIL ACCESS. In June, 2000 RG&E reached agreement with the PSC Staff
and other parties to encourage and promote customers' opportunities to choose
among competing natural gas suppliers. The PSC issued an order approving this
agreement on July 31, 2000. As of September 30, 2000 nineteen energy service
companies are qualified by RG&E to serve retail gas customers. The companies are
Agway Energy Services, All Energy Marketing Company, Amerada Hess Corp., Crown
Energy Services, ECONnergy Energy Company, Empire Natural Gas, Energetix, Energy
Coop of NY, Enron Energy Services, Iroquois Energy, Mirabito Fuel, National Fuel
Resources, Niagara Mohawk Energy Marketing, North American Energy, Power
Management Co., Select Energy, Texaco Natural Gas, TXU Energy Services and
Monroe County. See following discussion under Rates and Regulatory Matters, "Gas
Retail Access Settlement".
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. During 1996 and 1997, RG&E,
the staff of the PSC and several other parties negotiated an agreement which was
approved by the PSC in November 1997 (Electric Settlement). The Electric
Settlement sets the framework for the introduction and development of open
competition in the electric energy marketplace and lasts through June 30, 2002.
Over this time, the way electricity is provided to customers will fundamentally
change. In phases, RG&E will allow customers to purchase electricity, and later
capacity commitments, from sources other than RG&E through its retail access
program, Energy Choice. These energy service companies will compete to package
and sell energy and related services to customers. The competing energy service
companies will purchase distribution services from RG&E who will remain the sole
provider of distribution services, and will be responsible for maintaining the
distribution system and for responding to emergencies.
The Electric Settlement sets RG&E's electric rates for each year during its
five-year term. Over the five-year term of the Electric Settlement, the
cumulative rate reductions for the bundled service will be as follows: Rate Year
1 (July 1, 1997 to June 30, 1998) $3.5 million; Rate Year 2 $12.8 million; Rate
Year 3 $27.6 million; Rate Year 4 $39.5 million; and Rate Year 5 $64.6 million.
In the event that RG&E earns a return on common equity in its regulated
electric business in excess of an effective rate of 11.50 percent over the
entire five-year term of the Electric Settlement, 50 percent of such excess will
be used to write down deferred costs accumulated during the term. The first $0.8
million of the other 50 percent shall be used to reduce rates for certain
classes of customers and the remainder will be used to write down accumulated
deferrals or investment in electric plant or Regulatory Assets (which are
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). If certain extraordinary events occur, including a rate of return
on common equity below 8.5 percent or above 14.5 percent, or a pretax interest
coverage below 2.5 times, then
<PAGE>
20
either RG&E or any other party to the Electric Settlement would have the right
to petition the PSC for review of the Electric Settlement and appropriate
remedial action. (See following discussion under "Earnings Summary - RGS"
regarding a $12 million reserve established in September.)
The Electric Settlement requires unregulated energy retailing operations to
be structurally separate from the regulated utility functions. Although the
Electric Settlement provides incentives for the sale of generating assets, it
does not require RG&E to divest generating or other assets or write-off stranded
costs. Additionally, RG&E will be given a reasonable opportunity to recover
substantially all of its prudently incurred costs, including those pertaining to
generation and purchased power.
RG&E believes that the Electric Settlement has not adversely affected its
eligibility to continue to apply certain accounting rules applicable to
regulated industries. In particular, RG&E believes it continues to be eligible
for the treatment provided by SFAS-71 which allows RG&E to include assets on its
balance sheet based on its regulated ability to recoup the cost of those assets.
However, this may not be the case with respect to certain operational costs
associated with non-nuclear generation (see Note 3 of the Notes to Financial
Statements under the heading Other Matters, EITF Issue 97-4, Deregulation of the
Pricing of Electricity).
One of the participants in the Electric Settlement negotiations, the Public
Utility Law Project ("PULP"), has in recent years, commenced a series of legal
actions challenging various aspects of the PSC's 1996 and 1997 decisions
pertaining to, respectively, the restructuring of the electric utility industry
("Electric Restructuring Case") and the provision of competitive retail electric
service ("Electric Marketing Case"). PULP and a non-participant also commenced
an action for declaratory and injunctive relief as to certain provisions of the
Settlement and the PSC's approval of it. On June 29, 2000, PULP's challenge to
the decision in the Electric Restructuring Case was dismissed by the Appellate
Division of New York State Supreme Court for lack of standing. On October 24,
2000, the New York Court of Appeals denied PULP's motion for leave to appeal the
Appellate Division decision. Earlier, in 1999, the Appellate Division and the
Court of Appeals had similarly rejected PULP's challenge to the PSC decision in
the Electric Marketing Case. On March 2, 2000, the New York Supreme Court
dismissed PULP's challenge to the Electric Settlement on the ground that the
plaintiffs lacked standing. On March 30, 2000, PULP filed a notice of appeal.
RG&E is unable to predict the outcome of this action.
RG&E's retail access program, Energy Choice, was approved by the PSC as
part of the Electric Settlement and went into effect on July 1, 1998. Details
of the Energy Choice Program are discussed below.
ENERGY CHOICE. The Energy Choice program has been in existence over two
years now in RG&E's service territory. On July 1, 1998, RG&E officially began
implementation of its full-scale electric retail access Energy Choice program.
As of July 1, 1999, RG&E entered its second year of this program. There are five
basic components of the sale of energy: (1) the sale of electricity which is the
amount of energy actually used by the consumer, (2) the sale of capacity which
is the ability, through generating facilities or otherwise, to provide
electricity when it is needed, (3) the sale of transmission services, which is
the physical transportation of electricity to RG&E's distribution system, (4)
the sale of distribution services, which is the physical delivery of electricity
to the consumer, and (5) retail services such as billing and metering.
Historically, RG&E has sold all five components bundled together for a fixed
rate approved by the PSC. The implementation of Energy Choice included a four
year phase-in process to allow RG&E and other parties to manage the transition
to electric competition in an orderly fashion. During the first year of the
program, participation in Energy Choice was limited to no more than 10 percent
of RG&E's total annual retail electric kilowatt-hour sales (670,000 annualized
megawatt-hours). Essentially, until this 10 percent limit was achieved, RG&E's
electric retail customers could seek out or be approached by alternative energy
service companies for electricity to be resold and then delivered over RG&E's
distribution system. By February 1, 1999, only six months into the Energy
Choice program, this 10 percent limit was achieved by qualified competitive
energy service companies in RG&E's service territory. For the second year of the
program, beginning July 1, 1999, this limit increased from 10 percent to
approximately 20 percent. As of July 1, 2000, beginning the third year of the
program, this limit increased to 30 percent. By September 30, 2000,
approximately 19 percent of total RG&E sales had shifted to competitive energy
service companies. Next year, beginning July 1, 2001, all retail customers will
be
<PAGE>
21
eligible to purchase energy, capacity and retailing services from competitive
energy service companies. Existing RG&E customers may also continue to purchase
fully bundled electric service from RG&E.
Energy Choice adopted the single-retailer model for the relationship
between RG&E as the distribution provider, qualified energy service companies,
and retail (end-use) customers. In this model, retail customers have the
opportunity for choice in their energy service company and receive only one
electric bill from the company that serves them. Except for providing emergency
services, satisfying requests for distribution services, and scheduling outages,
which remain RG&E's responsibility, the retail customer's primary point of
contact for billing questions, technical advice and other energy-related needs,
is with their chosen energy service company.
Under the single-retailer model, energy service companies are responsible
for buying or otherwise providing the electricity their retail customers will
use, paying regulated rates for transmission and distribution, and selling
electricity to their retail customers (the price of which would include the cost
of the electricity itself and the cost to transport electricity through RG&E's
distribution system).
As of September 30 , 2000, seven energy service companies, including
Energetix, the Company's unregulated subsidiary, are qualified by RG&E to serve
retail customers under Energy Choice . In addition to Energetix, the companies
are Energy Co-op of NY (ECNY), Monroe County, North American Energy, NYSEG
Solutions, Inc., Select Energy Inc., and TXU Energy Services, Inc. The County
of Monroe is acting as its own energy service company to service its own
facilities, as well as serving other retail customers.
Throughout the term of the Electric Settlement, RG&E will continue to
provide regulated and fully bundled electric service under its retail service
tariff to customers who choose to continue with such service.
During the initial Energy-Only stage of the Energy Choice program, which began
on July, 1998 and eventually concluded on November 18, 1999, energy service
companies were able to choose their own sources of energy supply, while RG&E
continued to provide to them, through its bundled distribution rates, the
generating capacity (installed reserve) needed to serve their retail customers.
In addition, during the Energy-Only stage, energy service companies had the
option of purchasing "full-requirements" (i.e. delivery services plus energy)
from RG&E.
During this initial Energy Only stage of the retail access program, RG&E's
distribution rate was set by deducting 2.305 cents per kilowatt-hour from its
full service (bundled) rates. The 2.305 cents per kilowatt-hour was comprised
of 1.905 cents per kilowatt-hour (an estimate of the wholesale market price of
electricity) plus 0.4 cents per kilowatt-hour for its avoided cost of retailing
services.
During the Energy and Capacity stage, RG&E's distribution rates will equal
the bundled rate less RG&E's cost of the electric commodity and RG&E's non-
nuclear generating capacity. Throughout this stage of the program, up until
June 30, 2000, RG&E's distribution rates were set by deducting 3.0712 cents per
kilowatt-hour from its full service rates. The 3.0712 cents per kilowatt-hour
is comprised of 2.6712 cents per kilowatt-hour (an estimate of the wholesale
market price of electric energy and capacity) plus 0.4 cents per kilowatt-hour
for its avoided cost of retailing services. Beginning July 1, 2000, RG&E's
distribution rates were set by deducting 3.0816 cents per kilowatt hour from its
full service rates. The 3.0816 cents per kilowatt-hour is comprised of 2.6816
cents per kilowatt-hour for energy and capacity plus 0.4 cents per kilowatt-hour
for its avoided cost of retailing services. This change in the distribution
rates set by deducting 3.0712 cents per kilowatt-hour and then 3.0816 cents per
kilowatt-hour, is a result of changes in average gross receipts taxes, as
defined in our Electric Settlement with the PSC.
The commencement of the Energy and Capacity stage, the second stage of the
phase-in, began with the implementation of the New York Independent System
Operator on November 18, 1999 (see following discussion under New York
Independent System Operator). The responsibility for purchasing not only
energy, but also capacity, was to have shifted to the energy service companies.
However, these energy service companies continued to be "full-requirements"
customers of RG&E during the winter capability period (November 1, 1999 through
April 30, 2000) and purchased energy and capacity from RG&E. The PSC and the
FERC had also approved a request by RG&E to extend "full-requirements"
availability to energy service
<PAGE>
22
companies through October 31, 2000 and more recently, through the next winter
capability period, which is through April 30, 2001. As of September 30, 2000,
all energy service companies serving customers under retail access have opted to
continue purchasing "full requirements" through this next winter capability
period. Through April 30, 2001, energy service companies will have the option to
serve a portion or all of their load from the competitive wholesale market, but
once they make this choice, they will not be able to return this load to "full
requirements".
Once RG&E no longer provides "full requirements" to the energy service
companies, they will assume responsibility for obtaining their own supplies.
There will be a revenue decrease when RG&E no longer collects the rates
described above for energy and capacity. This will be offset to some extent by
decreased costs resulting from no longer acquiring energy and capacity for the
energy service companies. The extent of this offset will be determined by
market prices.
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, and to order certain
changes in, RG&E's retail access program. In particular, these petitioners
objected to the single-retailer form of RG&E's program, under which the retail
marketer assumes responsibility for most retail service functions. They claim
that the backout credit (i.e., the amount by which RG&E's rates for retail
----
electric service are reduced to derive the rates charged for the delivery
service provided by RG&E to marketers) is too low, that it affords insufficient
prospect of profitable operation, and that it should be increased. They further
assert that the phased schedule for implementation of the program, under which
increasing percentages of customers in RG&E's service area are eligible to
obtain competitive service during the term of the Electric Settlement, is too
slow and should be significantly accelerated. On February 28, 2000 RG&E filed
with the PSC its reply to both petitions. As set forth in that reply, RG&E
believes that its single-retailer program offers unique opportunities for
marketers, that its retail backout credit (in conjunction with RG&E's rate for
wholesale power sales to marketers) affords a sound basis for competitive
service, and that its implementation schedule is reasonable and appropriate;
moreover, each of these essential elements of the retail access program is
expressly established by the Electric Settlement. RG&E believes that the
program fully and fairly advances the goals of increased competition for energy
services, and is in full compliance with the Electric Settlement. 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
that include standardized billing (single billing options), provider of last
resort (POLR), electronic data interchange (EDI), and competitive metering.
RG&E continues to assess the scope and impact of such changes on its operations
as retail access continues to evolve.
NINE MILE NUCLEAR PLANTS. On June 24, 1999, Niagara Mohawk and New York
State Electric and Gas (NYSEG) announced their intention to sell their interests
in the Nine Mile One and Nine Mile Two nuclear plants to AmerGen Energy Company,
L.L.C. (AmerGen), a joint venture of PECO Energy of Philadelphia and British
Energy. Niagara Mohawk owns 41 percent of Nine Mile Two and 100 percent of Nine
Mile One and NYSEG owns 18 percent of Nine Mile Two.
RG&E's 14 percent interest in Nine Mile Two was not included in the
proposal but RG&E has a right of first refusal to buy the interests of the other
owners of Nine Mile Two on terms at least as favorable as those offered. RG&E
exercised its right of first refusal and broadened it to include Nine Mile One
with which Nine Mile Two was paired in the proposal. However, in the ensuing
discussions with the PSC staff it became clear that the transaction on the terms
proposed would not be approved by the PSC.
On April 25, 2000, the PSC issued an order that allows NYSEG and Niagara
Mohawk to withdraw their petition to sell their interests in the Nine Mile
plants to AmerGen. The order concludes that Nine Mile's market value is "greatly
in excess of the original AmerGen purchase price" and that multiple bidders are
now interested in the Nine Mile plants. The order also concludes that
"...failure for the utilities to determine the market value of the Nine Mile
facilities at this time, through an open process, would raise serious prudence
<PAGE>
23
questions." With respect to stranded costs, the PSC order indicates that
stranded costs cannot be finally quantified "until the disposition of the plants
by the utilities is decided." The PSC's order does, however, observe (1) that a
sale would be considered within its policy of separating generation from
transmission and distribution, (2) that a sale at current market values would
constitute appropriate mitigation of stranded costs and (3) that ratemaking
treatment of a sale would be resolved in accordance with each company's
competitive opportunities/restructuring order taking into account reduced risk
and corollary divestiture effects.
On June 1, 2000, RG&E issued a press release announcing an auction process
by RG&E, Central Hudson Gas & Electric Corporation, NYSEG and Niagara Mohawk in
connection with their ownership interests in Nine Mile Two and Niagara Mohawk's
interest in Nine Mile One.
Discussions with the staff of the PSC and Nine Mile Two co-owners regarding
the auction process and the regulatory impact thereof continue but RG&E is
unable to predict the ultimate outcome. At September 30, 2000 the net book value
of RG&E's 14 percent interest in the Nine Mile Two generating facility was
approximately $367 million.
NEW YORK INDEPENDENT SYSTEM OPERATOR. In November 1999 following FERC
approval, the New York State Independent System Operator (NYISO) implemented a
competitive wholesale market for the sale, purchase and transmission of
electricity and ancillary services in New York State. NYISO tariffs for market-
based rates for energy, ancillary services, and installed capacity sold through
the NYSIO were approved by FERC. The NYISO and the New York State Reliability
Council were formed to restructure the New York Power Pool in response to FERC
Order 888.
Earlier this year, the NYISO's total cost of providing operating reserves on
an hourly basis exceeded the cost that would be expected in a workable
competitive marketplace. During the first quarter, RG&E, in addition to other
New York State public utilities and several load-serving entities, experienced
rising prices to maintain operating reserves within the NYISO system. For
example, in December 1999, on an average monthly basis, RG&E paid $.51/MWH for
operating reserves. In January, 2000, the figure was $1.10/MWH. In February,
2000, RG&E's average monthly cost for operating reserves was $6.01/MWH. As a
result of, among other things, the implementation of bidding restrictions that
limit reserve prices, as discussed in the following two paragraphs, the average
cost per MWH for operating reserves in the second and third quarters decreased
to $.73 and $.65, respectively.
On April 7, 2000 RG&E filed a complaint with FERC against the NYISO. RG&E
sought corrective re-calculation of operating reserve prices for prior periods
and prospective relief from injuries resulting from the NYISO's operating
reserves market. Niagara Mohawk and NYSEG filed similar complaints with FERC
against the NYISO. On March 27, the NYISO filed with FERC for the immediate
authority to suspend the use of market-based bids in the New York markets for
operating reserves.
On May 31, 2000 FERC issued an order accepting the NYISO's request for
bidding restrictions in the 10-minute non-spinning reserve market amounting to
$2.52/MWH. FERC directed the NYISO to address the issue of self-supply and file
a plan to correct the problem by September 1, 2000. However, they denied the
requests from RG&E and Niagara Mohawk for retroactive rate relief. On June 30,
2000, RG&E filed a request for rehearing seeking, in part, retroactive rate
relief for operating reserve overpayments.
At the present time, RG&E cannot predict what effects, if any, action
ultimately taken by FERC on this subject will have on future operations or the
financial condition of RGS or RG&E.
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. 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 the 1999 Form 10-K, Item 8
under Note 10 of the Notes to Financial Statements.
<PAGE>
24
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
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. A discussion of strandable assets is
presented in Note 3 of the Notes to Financial Statements.
At September 30, 2000 RG&E believes that its regulatory assets are probable
of recovery. The Electric Settlement in the Competitive Opportunities
Proceeding does not impair the opportunity of RG&E to recover its investment in
these assets. However, the PSC issued an Opinion and Order Instituting Further
Inquiry on March 20, 1998 to address issues surrounding nuclear generation. The
initial meeting in this Inquiry was held in January 1999 (see 1999 Form 10-K,
Item 7 under the heading "PSC Proceeding on Nuclear Generation"). The ultimate
determination in this proceeding or any proceeding to consider RG&E's proposed
sale of Nine Mile Two as discussed under the heading "Nine Mile Nuclear Plants"
could have an impact on strandable assets and the recovery of nuclear costs.
RATES AND REGULATORY MATTERS
PSC GAS RESTRUCTURING POLICY STATEMENT. On November 3, 1998, the PSC issued
a gas restructuring policy statement (Gas 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. The PSC established a transition process in which it plans to address
three groups of issues: (1) individual gas utility plans to implement the PSC's
vision of the market; (2) key generic issues to be dealt with through
collaboration among gas utilities, marketers, pipelines and other stakeholders,
and (3) coordination of issues that are common to both the gas and the electric
industries. The PSC has encouraged settlement negotiations with each gas
utility pertaining to the transition to a fully competitive gas market. RG&E,
the PSC Staff and other interested parties have been participating in settlement
discussions in response to the specific requirements of the Policy Statement.
GAS RETAIL ACCESS SETTLEMENT. On June 14, 2000, in connection with on-
going settlement negotiations pertaining to RG&E's gas rate and restructuring
proposal filed with the PSC on January 28, 2000 RG&E, the PSC staff, and
certain other parties to the negotiations entered into a Settlement Agreement
Pertaining to Certain Elements of Natural Gas Retail Access Program (Retail
Access Settlement). For a description of the Retail Access Settlement see Part
I, Note 3 of the Financial Statements under the heading "Gas Retail Access
Settlement."
RG&E, the PSC staff, and other parties anticipate continuing settlement
negotiations aimed at a comprehensive gas rate and restructuring settlement.
RG&E is unable to predict the ultimate outcome of these negotiations or any PSC
decision pertaining thereto.
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" (RM98-10) and "Regulation of Interstate Natural Gas Transportation
Services" (RM98-12). On June 5, 2000 FERC issued Order No.637-A providing
clarification and additional guidance. On July 26, 2000 the Commission issued
Order 637-B upholding Orders 637 and 637-A. The Order revises 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. The Order: (1) waives the price ceiling for released capacity
of less than one year until September 30, 2002; (2) permits pipelines to propose
peak and off-peak and term differentiated rates providing that they still
satisfy the revenue and cost constraints of traditional rate-making, and excess
revenues are split with firm customers; (3) revises FERC's regulations on
scheduling procedures, capacity segmentation and pipeline penalties; (4) states
that the right of first refusal will apply in the future to contracts for 12
consecutive months or more of service at maximum rates; (5) amends and
supplements reporting requirements to require interstate pipelines to report
additional information on transactions, operationally available capacity, and an
expanded index of customers.
<PAGE>
25
Order 637/637-A/637-B required each pipeline to make a compliance filing.
All of the pipelines' initial compliance filings were submitted to the FERC by
August 15, 2000. The Commission has established technical and settlement
conference procedures for many of the pipelines, including those on which RG&E
holds transportation 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 the Company.
FERC ORDER NO. 2000. (Reference is made to Item 1 of RG&E's 1999 Form 10-K
under the heading "FERC 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, which will
put all public utility transmission facilities in a region under common control.
The Rule requires all public utilities that own, operate or control interstate
transmission facilities to file by October 15, 2000 (or, for public utilities
like RG&E already participating in an ISO, by January 15, 2001), a proposal for
an RTO, or, alternatively, a description of any efforts made by the utility to
participate in an RTO. RG&E is currently participating in a working group under
the auspices of the NYISO Management Committee. The group is attempting to
create a consensus filing for January 15, 2001. RG&E cannot predict whether a
joint filing will be possible, or what the ultimate ruling by FERC will have on
future operations or on the financial condition of the Company
FLEXIBLE PRICING TARIFF. Under its flexible pricing tariff for major
industrial and commercial electric customers, RG&E may negotiate competitive
electric rates at discount prices to compete with alternative power sources,
such as customer-owned generation facilities. For further information with
respect to the flexible pricing tariff see RG&E's 1999 Form 10-K, Item 7 under
Rates and Regulatory Matters.
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 2000, RGS's and RG&E's cash flow from
operations and short-term borrowings (see Statements of Cash Flows) provided the
funds for utility plant construction expenditures, the payment of dividends, the
retirement of long-term debt (see "Redemption of Securities" below) and the
purchase of treasury stock. Capital requirements of the Company during 2000 are
anticipated to be satisfied from the combination of internally generated funds
and short-term credit arrangements.
CAPITAL AND OTHER REQUIREMENTS. RGS's and RG&E's capital requirements
relate primarily to expenditures for energy delivery, including electric
transmission and distribution facilities and gas mains and services as well as
nuclear fuel, electric production, the repayment of existing debt and the
repurchase of outstanding shares of Common Stock. RG&E has no further plans to
install additional baseload generation.
Capital Requirements. Capital requirements for the Company in 2000 are
currently estimated at $184 million of which $154 million is for construction
and $30 million was for the payment of 7% First Mortgage Bonds due 1/14/00.
RG&E's portion of total construction requirements is $151 million.
Approximately $103 million had been expended for construction as of September
30, 2000, reflecting primarily RG&E's expenditures for nuclear fuel and
upgrading electric transmission and distribution facilities and gas mains.
FINANCING. 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 securities. At September 30, 2000, RGS and RG&E had short-term
borrowings of $44 million and $31.5 million, respectively. In September,
Griffith increased its borrowing limit from $15 million to $26 million under an
amended and restated revolving credit agreement terminating July 31, 2003. For
further information with respect to RGS's and RG&E's short-term borrowing
arrangements and limitations, see the 1999 Form 10-K, Item 8 under Note 9 of the
Notes to Financial Statements.
REDEMPTION OF SECURITIES. On January 14, 2000, RG&E redeemed at maturity
$30 million of 7% First Mortgage Bonds, Designated Secured Medium Term Notes,
Series A. RG&E does not anticipate
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26
redeeming any securities for the remainder of the year 2000.
STOCK REPURCHASE PLAN. In April 1998, the PSC approved a Stock Repurchase
Plan for RG&E providing for the repurchase of Common Stock having an aggregate
market value not to exceed $145 million. RG&E began the repurchase program in
May 1998 and 4,222,700 shares of Common Stock have been repurchased for
approximately $112.8 million through September 30, 2000. The average cost per
share purchased during the nine months ended September 30, 2000 was $23.09.
EARNINGS SUMMARY
RGS:
----
RGS reported consolidated earnings of $0.38 per share for the third quarter
ended September 30, 2000, compared to $0.44 per share for the same period in
1999. As anticipated, third quarter 2000 earnings reflect cooler weather,
scheduled rate reductions and increased purchase power expenses arising from
industry restructuring and generation plant availability.
Consolidated earnings for the nine-month period were $1.95 in 2000 compared
to $1.79 in 1999. Increased wholesale electric sales, reduced operating
expenses and the Company's share buyback program, which resulted in a reduction
of shares outstanding, positively affected results for the first nine months of
this year. Assuming normal weather for the fourth quarter of this year, the
Company expects 2000 earnings per share to exceed last year's results.
Total electric revenues for the third quarter were down $0.8 million due to
cooler weather and the scheduled reduction in regulated rates, which were
partially offset by increased electric sales to other utilities (OEU sales).
Purchase power expenses were up $11.8 million, which included hedging activities
for the summer peak electric load and replacement power for the scheduled 2000
Ginna Plant 30-day refueling outage, which started on September 18, 2000.
Electric fuel expenses were down $2.2 million due to lower generation at Ginna
and the fossil units.
Third quarter regulated non-fuel operating expenses were up $2.1 million
compared to last year. The net increase in expenses reflects a charge of $12.0
million to establish a reserve based on Management's estimate of adjustments
that may occur in accordance with the terms of the PSC Competitive Opportunities
Settlement which ends on June 30, 2002. The adjustments are based on an
estimate of the level of the Company's regulatory earnings for electric
operations in excess of the allowed regulatory return on equity of 11.50% over
the five year term of the Electric Settlement. For further information
regarding the Electric Settlement see earlier discussion under "Competition-PSC
Competitive Opportunities Settlement". Offsetting this expense were the
recognition of a NYISO start-up refund, increased pension income and the
elimination of Y2K expenses. Local, State and other taxes were down $4.9
million this quarter compared to 1999, reflecting the reduction in regulated
revenues, a lower Gross Receipts tax and lower property taxes. Partially
offsetting the reduction in these taxes was the imposition of new State income
taxes of $2.8 million in the quarter. Federal income taxes include a $4.1
million credit resulting from recognition of a favorable resolution of
outstanding tax issues.
Energetix, RGS Energy Group's subsidiary continues to grow its unregulated
businesses of providing electric, natural gas and petroleum-based energy
products and services throughout the upstate New York region. Energetix and its
subsidiary, Griffith now serve a combined total of 140,000 customers. Total
revenues for Energetix and Griffith have grown to $324.8 million for the first
nine months of 2000 reflecting customer growth and increases in fuel oil prices
resulting in a modest pre-tax loss.
RG&E:
-----
Earnings for RG&E reflect the same issues discussed above for RGS except
that discussions relating to Energetix and Griffith are not applicable. On
August 2, 1999 the holding company RGS was formed and RG&E, Energetix and RGS
Development then became subsidiaries of RGS. The RG&E Income Statements reflect
the consolidated operations of RG&E and its former subsidiaries, Energetix and
RGS
<PAGE>
27
Development prior to August 2, 1999. Starting August 2, 1999, the RG&E
Income Statements reflect only the operating results of RG&E.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant changes
in the amounts of revenues and expenses for RGS (regulated and unregulated
business) and RG&E (regulated business), comparing the three-month and nine-
month periods ended September 30, 2000 to the three-month and nine-month
periods ended September 30, 1999. 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 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 SEPT. 30, 2000 COMPARED TO THREE MONTHS ENDED SEPT. 30, 1999
-------------------------------------------------------------------------------
OPERATING REVENUES AND SALES. Unconsolidated regulated electric revenues
were $187.5 million for the third quarter of 2000 as compared to $189.4 million
for the same period a year ago. Together, electric revenues from regulated
retail electric sales and electric sales to energy marketers were down $13.6
million reflecting unfavorable weather and decreased rates. Partially
offsetting these lower electric revenues was an $11.6 million increase in
revenues from OEU sales. The increase in OEU sales reflects favorable market
conditions and increased capacity to sell power to other electric utilities due
to the availability of generation from Nine Mile Two and Allegany Station.
Despite an increase in heating-degree days, regulated gas revenues, net of fuel,
were down slightly for the third quarter of 2000 compared to a year ago.
Unregulated operations are reflected on RG&E's financial statements only on
or before August 1, 1999, the day preceding the formation of the holding
company, RGS Energy Group, Inc. Subsequent to that date, only regulated RG&E
operations are reflected on the RG&E financials.
Unconsolidated unregulated revenues were $111.4 million for the third
quarter of 2000 as compared to $71.0 million for the same period a year ago.
This increase reflects mainly the recovery of higher purchased fuel prices for
gasoline and fuel oil, a growth in electric and gas customers, and a growth in
customer base through acquisitions made by Griffith. Revenues from Griffith are
included under "Other Revenues" on RGS's Income Statements and RG&E's 1999
Income Statement on or before August 1, 1999. For heating oil and propane,
Griffith experiences seasonal fluctuations due to the dependence on spaceheating
sales during the heating season. Unregulated sales also reflect the migration
of electric and gas customers from the regulated to the unregulated business.
OPERATING EXPENSES. Higher regulated fuel expenses reflect increased
purchased electricity costs due to an increase in the cost per unit purchased,
electric generation insurance and hedging activities ($4.5 million ), the effect
from lower generation from the Ginna nuclear plant refueling shutdown and the
closing of the Oswego 6 generating station which occurred in August 1999. The
increase in non-fuel operation and maintenance expenses (O&M) for both RGS and
RG&E reflects mainly a reserve ($12 million) based on Management's estimate of
adjustments that may occur in accordance with the terms of the Electric
Settlement, which was previously described under "Earnings Summary" and higher
transmission and wheeling charges ($4.6 million) from the NYISO. Offsetting
these increases in non-fuel O&M adjustment were a one-time refund of NYISO
startup costs ($4.5 million) and the recognition of pension income ($4.9
million), which is now being recognized monthly. Regulated State, local and
other taxes declined reflecting mainly lower revenues and a lower gross receipts
tax rate. The difference in income tax is attributable mainly to differences in
pre-tax earnings and a one-time adjustment in the form of a credit totaling $4.1
million due to a favorable tax ruling.
Higher unregulated fuel costs reflect the increase in Griffith's costs of
fuel oil and gasoline in the third quarter of 2000 as compared to a year ago.
The increase in unregulated non-fuel O&M for RGS reflects primarily operating
expenses for Griffith, payroll expenses and general and administrative expenses.
These unregulated expenses were not included for RG&E after the August 1999
reorganization described above.
<PAGE>
28
OTHER STATEMENT OF INCOME ITEMS. The increase in regulated interest
expense reflects mainly the interest on $100 million of first mortgage bonds
issued by RG&E in October 1999.
NINE MONTHS ENDED SEPT. 30, 2000 COMPARED TO NINE MONTHS ENDED SEPT. 30, 1999
-----------------------------------------------------------------------------
OPERATING REVENUES AND SALES. In the first nine months of 2000,
unconsolidated regulated electric revenues were $535.5 million as compared to
$527.8 million for the same period a year ago. Compared to last year, revenues
from the sale of energy to other electric utilities were up $33.5 million due to
favorable market conditions (over 50% of the increase reflects higher revenues
per unit sold) and increased generation available from RG&E's facilities.
Partially offsetting these favorable results was a drop of $25.9 million from a
combination of electric revenues from regulated retail electric sales and
electric sales to energy marketers reflecting a June 1999 unbilled electric
revenue adjustment of $7.1 million, unfavorable weather conditions and decreased
rates. Regulated gas revenues, net of fuel expenses, were down slightly due to
2.7% warmer weather on a heating degree day basis and a June 1999 unbilled gas
revenue adjustment of $6.1 million.
As discussed above, unregulated operations are reflected on RG&E's
financial statements only on or before August 1, 1999.
Unconsolidated unregulated revenues were $324.8 million for the first nine
months of 2000 as compared to $185.6 million last year for the same reasons
discussed for the third quarter.
OPERATING EXPENSES. Higher regulated fuel expenses and higher other fuel
costs increased for the same reasons discussed for the third quarter. Also,
purchased electricity increased due to the effect of lower generation from the
Nine Mile Two refueling shutdown in the first half of 2000 and the 1999 closing
of Beebee station and sale of Oswego station.
The decrease in non-fuel O&M for both RGS and RG&E reflects recognition of
pension income ($13.2 million), the absence of Y2K expenses ($4.2 million), a
refund of NYISO start-up costs ($4.5 million) and an increase in 1999 ($7.1
million ) of the RG&E reserve for uncollectible accounts. The non-fuel O&M
decrease was partially offset by the reserve ($12 million) representing
Management's estimate of certain adjustments in accordance with the Electric
Settlement as described under "Earnings Summary" and an increase ($7.9 million)
for electric transmission and wheeling charges related to implementation of the
NYISO (see discussion under "New York Independent System Operator") which mainly
impacted first quarter results. The NYISO assumed control and operation of the
New York State electric transmission system from the New York Power Pool during
the fourth quarter of 1999 pursuant to orders from the FERC. The decrease in
regulated depreciation reflects mainly the retirement of RG&E generating plant
facilities in 1999. The factors affecting variances in regulated State, local
and other taxes for the quarterly period are also applicable for the nine-month
comparison period. The difference in income tax was affected by the same factors
discussed above for the quarter. The difference in income tax also reflects a
reclassification of the state gross receipts tax to state income tax and a true-
up of both federal and state income tax for a new state income tax effective
January 1, 2000 (see Part I, Note 1, "New York State Tax Changes").
The increase in unregulated non-fuel O&M for RGS reflects primarily
operating expenses for Griffith, payroll expenses and general and administrative
expenses.
OTHER STATEMENT OF INCOME ITEMS. The change in regulated Other Income and
Deductions, Other-net reflects mainly a charge ($3.4 million) for reconciliation
of RG&E's 1999 purchased power expense. The factors affecting variances in
interest charges for the quarterly period are also applicable for the nine-month
comparison period. Preferred stock dividends decreased due to the redemption of
an RG&E Preferred Stock issue on September 1, 1999 pursuant to a mandatory
sinking fund.
<PAGE>
29
DIVIDENDS
On September 20, 2000, the Board of Directors of RGS authorized a common
stock dividend of $.45 per share, which was paid on October 25, 2000 to
shareholders of record on October 3, 2000. Also on September 20, 2000, The Board
of Directors of RG&E declared dividends on its Preferred Stocks at the regular
rates per share payable on December 1, 2000 to stockholders of record on
November 1, 2000.
The ability of RGS to pay common stock dividends is governed by the ability
of RGS's subsidiaries to pay dividends to RGS. Because RG&E is by far the
largest of the subsidiaries, 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 be a source of funds for dividend
payments by RGS. 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. 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 (about $35 million at September 30, 2000). The level of
future cash dividend payments on Common Stock will be dependent upon RGS's
future earnings.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.
RG&E is exposed to interest rate and commodity price risks.
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. RG&E was not participating in any
derivative financial instruments for managing interest rate risks as of
September 30, 2000 or December 31, 1999.
Commodity price risk relates to market fluctuations in the price of natural
gas, electricity, and other petroleum-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 petroleum
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.
Under the Electric Settlement, RG&E's electric rates are capped at specified
levels through June 30, 2002. Long-term fixed supply contracts and owned
electric generation significantly reduce RG&E's exposure to market fluctuations
for procurement of its electric supply. Owned generation subjects the Company
to operating risk. Operating risk is managed through a combination of strict
operating and maintenance practices and the use of financial instruments. In
the event RG&E's generation assets fail to perform as planned, generation
insurance and purchased call options reduce the Company's exposure to electric
price spikes in the summer months.
RG&E's exposure to market price fluctuations of the cost of natural gas is
further limited as the result of the Gas Cost Adjustment (GCA), a regulatory
mechanism that transfers substantially all gas commodity price risk to the
customer. Nonetheless, RG&E does hedge approximately 70% of its gas supply price
through the purchase of futures 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.
RG&E does not hold open speculative positions in any commodity for trading
purposes.
Energetix has entered into electric and natural gas purchase commitments with
numerous suppliers. These commitments support fixed price offerings to retail
electric and gas customers and, starting in October,
<PAGE>
30
variable price offerings for gas customers who choose that option. Griffith is
in the business of purchasing various petroleum-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. All hedge contracts are accounted for under the
deferral method with gains and losses from the hedging activity included in the
cost of sales as inventories are sold or as the hedge transaction occurs.
Commodity instruments not designated as effective hedges are marked to market at
the end of the reporting period, with the resulting gains or losses recognized
in cost of sales. These contracts are closely monitored on a daily basis to
manage the price risk associated with inventory and future sales commitments. At
September 30, 2000 Griffith's net deferred gains on open hedge contracts were
$1.6 million.
RGS and RG&E will adopt SFAS 133 - Accounting for Derivative Instruments
and Hedging Activities as of January 1, 2001. See preceding discussion under
Note 1 of the Notes to Financial Statements.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to Part I, Item 3, Legal proceedings in the RGS and
RG&E combined 1999 Form 10-K and Part II, Item 1, Legal Proceedings in the RGS
and RG&E combined Form 10-Q for the quarter ended March 31, 2000.
For additional information on Legal Proceedings reference is made to
Note 3 of the Notes to Financial Statements.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K:
RGS Energy Group, Inc. - None
Rochester Gas and Electric Corporation - None
EXHIBIT INDEX
Exhibit 27-1 Financial Data Schedule pursuant to Item 601(c) of
Regulation S-K for RGS.
Exhibit 27-2 Financial Data Schedule pursuant to Item 601(c) of
Regulation S-K for RG&E.
<PAGE>
31
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrants have duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
RGS ENERGY GROUP, INC.
----------------------
(Registrant)
Date: November 13, 2000 By /s/ J.B. STOKES
-------------------------
J. Burt Stokes
Senior Vice President and
Chief Financial Officer
Date: November 13, 2000 By /s/ WILLIAM J. REDDY
-------------------------
William J. Reddy
Controller
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: November 13, 2000 By /s/ J.B. STOKES
-------------------------
J. Burt Stokes
Senior Vice President,
Corporate Services
and Chief Financial Officer
Date: November 13, 2000 By /s/ WILLIAM J. REDDY
-------------------------
William J. Reddy
Vice President and Controller
