<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, 1999
-----------------------------------
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, 1999, (i) RGS Energy Group, Inc.
("RGS ENERGY") had outstanding 36,254,313 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 ENERGY.
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>
INDEX
Page No.
PART I - FINANCIAL INFORMATION
RGS Energy Group, Inc.
Consolidated Balance Sheet - September 30,1999 and
December 31, 1998........................................ 1 - 2
Consolidated Statement of Income - Three Months and Nine
Months Ended September 30, 1999 and 1998.................. 3 - 4
Consolidated Statement of Cash Flows - Nine Months
Ended September 30, 1999 and 1998........................ 5
Rochester Gas and Electric Corporation
Consolidated Balance Sheet - September 30,1999 and
December 31, 1998........................................ 6 - 7
Consolidated Statement of Income - Three Months and Nine
Months Ended September 30, 1999 and 1998.................. 8 - 9
Consolidated Statement of Cash Flows - Nine Months
Ended September 30, 1999 and 1998......................... 10
Notes to Financial Statements................................. 11 -16
Management's Discussion and Analysis of Financial
Condition and Results of Operations...................... 17-34
Quantitative and Qualitative Disclosures About
Market Risk............................................... 34
PART II - OTHER INFORMATION
Legal Proceedings........................................... 34-35
Exhibits and Reports on Form 8-K............................ 35
Signatures.................................................. 36
____________
Filing Format
This Quarterly report on Form 10-Q is a combined quarterly report being filed by
two different registrants: RGS ENERGY and RG&E. RGS ENERGY 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 ENERGY" includes all
subsidiaries of RGS ENERGY including RG&E. RG&E makes no representation as to
the information contained in this report in relation to RGS ENERGY and its
subsidiaries other than RG&E.
<PAGE>
Abbreviations and Glossary
Company or RGS RGS Energy Group, Inc., a holding company formed August
ENERGY 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
Energetix Energetix, Inc., a wholly-owned subsidiary of the Company
Energy Choice A competitive electric retail access program of the Company
being phased- in over a period ending July, 2001.
FERC Federal Energy Regulatory Commission
Ginna Plant Ginna Nuclear Plant wholly owned by the Company
Griffith Griffith Oil Company, Inc ., an oil, gasoline and propane
distribution company acquired by Energetix in 1998
ISO Independent System Operator
Kamine Kamine/Besicorp Allegany L.P.
LDC Local Distribution Company
Nine Mile Two Nine Mile Point Nuclear Plant Unit No. 2 of which the
Company owns a 14% share
NOI Notice of Inquiry
NOPR Notice of Proposed Rulemaking
NRC Nuclear Regulatory Commission
NYISO New York Independent System Operator
NYNOC New York Nuclear Operating Company
NYPP New York Power Pool
O&M Operation and Maintenance
PSC New York State Public Service Commission
RG&E Rochester Gas and Electric Corporation, a wholly-owned
subsidiary of the Company
SEC Securities and Exchange Commission
Settlement Competitive Opportunities Case Settlement among the Company,
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>
PART 1 - FINANCIAL INFORMATION
- ------------------------------
ITEM1. FINANCIAL STATEMENTS
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
Assets (Unaudited)
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric $ 2,488,353 $ 2,477,077
Gas 448,852 435,318
Common 171,415 158,038
Nuclear 270,034 256,562
-------------- --------------
3,378,654 3,326,995
Less: Accumulated depreciation 1,691,135 1,640,645
Nuclear fuel amortization 234,755 222,830
-------------- --------------
1,452,764 1,463,520
Construction work in progress 90,507 98,554
-------------- --------------
Net Utility Plant 1,543,271 1,562,074
-------------- --------------
Current Assets
Cash and cash equivalents 4,552 6,523
Accounts receivable, net of allowance for doubtful accounts:
1999 - $33,913; 1998 - $26,554 80,837 89,291
Unbilled revenue receivable 33,217 37,922
Materials, supplies and fuels 44,264 43,024
Prepayments 35,457 25,950
Other current assets 274 253
-------------- --------------
Total Current Assets 198,601 202,963
-------------- --------------
Intangible Assets
Goodwill, net 14,082 14,681
Other Intangible Assets 7,378 6,381
-------------- --------------
Total Intangible Assets 21,460 21,062
-------------- --------------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 202,160 183,502
Nine Mile Two deferred costs 28,469 29,258
Unamortized debt expense 16,023 17,241
Other deferred debits 19,714 18,531
Regulatory assets 403,065 416,320
Other assets 1,143 1,984
-------------- --------------
Total Deferred Debits and Other Assets 670,574 666,836
-------------- --------------
Total Assets $ 2,433,906 $ 2,452,935
-------------- --------------
</TABLE>
1
<PAGE>
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
Capitalization and Liabilities (Unaudited)
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization
Long term debt - mortgage bonds $ 480,053 $ 510,002
- promissory notes 240,024 248,224
Preferred stock redeemable at option of Company 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholder's equity
Common stock
Authorized 50,000,000 shares; 38,885,813 shares
issued at September 30, 1999 and at December 31, 1998 700,300 699,730
Retained earnings 145,523 129,484
-------------- --------------
845,823 829,214
Less: Treasury stock at cost (2,538,600 shares at September 30, 1999
and 1,507,000 shares at December 31, 1998) 74,026 46,433
-------------- --------------
Total Common Shareholders' Equity 771,797 782,781
-------------- --------------
Total Capitalization 1,563,874 1,613,007
-------------- --------------
Long Term Liabilities
Nuclear waste disposal 90,640 87,566
Uranium enrichment decommissioning 12,484 12,197
Site remediation 23,856 24,157
-------------- --------------
126,980 123,920
-------------- --------------
Current Liabilities
Long term debt due within one year 33,936 427
Preferred stock redeemable within one year - 10,000
Short term debt 59,840 57,000
Accounts payable 66,520 52,454
Dividends payable 17,276 17,937
Equal payment plan 10,068 11,025
Other 35,341 34,526
-------------- --------------
Total Current Liabilities 222,981 183,369
-------------- --------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 315,045 326,972
Pension costs accrued 62,264 58,677
Kamine deferred costs 60,486 65,799
Post employment benefits internal reserve 48,809 42,909
Other 33,467 38,282
-------------- --------------
Total Deferred Credits and Other Liabilities 520,071 532,639
-------------- --------------
Commitments and Other Matters
- -
-------------- --------------
Total Capitalization and Liabilities $ 2,433,906 $ 2,452,935
-------------- --------------
</TABLE>
2
<PAGE>
RGS Energy Group Inc.
Consolidated Statement of Income
(Thousands of Dollars)
(Unaudited)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
For the Three Months Ended
September 30,
1999 1998
----------- ----------
<S> <C> <C>
Operating Revenues
Electric $ 190,372 $ 189,644
Gas 32,300 36,529
Other 57,181 27,579
---------- ----------
Total Operating Revenues 279,853 253,752
Fuel Expenses
Fuel for electric generation 15,629 16,535
Purchased electricity 16,166 8,766
Gas purchased for resale 18,160 22,580
Other fuel expenses 51,466 23,644
---------- ----------
Total Fuel Expenses 101,421 71,525
---------- ----------
Operating Revenues Less Fuel Expenses 178,432 182,227
Other Operating Expenses
Operations and maintenance excluding fuel 77,957 71,613
Unregulated operating and maintenance expenses excluding fuel 6,062 4,379
Depreciation and amortizaton 28,967 28,258
Taxes - state, local & other 26,449 27,803
Federal income tax 9,618 15,218
---------- ----------
Total Other Operating Expenses 149,053 147,271
---------- ----------
Operating Income 29,379 34,956
Other (Income) & Deductions
Allowance for other funds used during construction (124) (101)
Federal income tax 389 910
Other - net (1,870) (2,365)
---------- ----------
Total Other (Income) & Deductions (1,605) (1,556)
---------- ----------
Income Before Interest Charges 30,984 36,512
Interest Charges
Long term debt 12,607 10,394
Other - net 1,686 1,067
Allowance for borrowed funds used during construction (199) (162)
---------- ----------
Total Interest Charges 14,094 11,299
---------- ----------
Net Income 16,890 25,213
---------- ----------
Dividends on Preferred Stock 925 1,305
---------- ----------
Earnings Applicable to Common Stock $ 15,965 $ 23,908
---------- ----------
Average Number of Common Shares (000's)
Common Stock 36,443 38,490
Common Stock and Equivalents 36,535 38,623
Earnings per Common Share - Basic $ 0.44 $ 0.62
Earnings per Common Share - Diluted $ 0.44 $ 0.62
Cash Dividends Paid per Common Share $ 0.45 $ 0.45
</TABLE>
3
<PAGE>
RGS Energy Group Inc.
Consolidated Statement of Income
(Thousands of Dollars)
(Unaudited)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Year To Date
September 30,
1999 1998
------------ -------------
<S> <C> <C>
Operating Revenues
Electric $ 529,955 $ 523,341
Gas 203,348 196,062
Other 148,447 27,580
------------ -------------
Total Operating Revenues 881,750 746,983
Fuel Expenses
Fuel for electric generation 37,642 40,994
Purchased electricity 44,489 21,377
Gas purchased for resale 105,530 113,318
Other fuel expenses 127,188 23,644
------------ -------------
Total Fuel Expenses 314,849 199,333
------------ -------------
Operating Revenues Less Fuel Expenses 566,901 547,650
Other Operating Expenses
Operations and maintenance excluding fuel 224,641 214,056
Unregulated operating and maintenance expenses excluding fuel 18,379 6,106
Depreciation and amortizaton 89,830 87,376
Taxes - state, local & other 85,325 88,218
Federal income tax 41,788 46,002
------------ -------------
Total Other Operating Expenses 459,963 441,758
------------ -------------
Operating Income 106,938 105,892
Other (Income) & Deductions
Allowance for other funds used during construction (507) (293)
Federal income tax 2,204 4,459
Other - net (5,710) (11,531)
------------ -------------
Total Other (Income) & Deductions (4,013) (7,365)
------------ -------------
Income Before Interest Charges 110,951 113,257
Interest Charges
Long term debt 37,968 32,107
Other - net 4,820 2,497
Allowance for borrowed funds used during construction (811) (470)
------------ -------------
Total Interest Charges 41,977 34,134
------------ -------------
Net Income 68,974 79,123
------------ -------------
Dividends on Preferred Stock 3,158 3,915
------------ -------------
Earnings Applicable to Common Stock $ 65,816 $ 75,208
------------ -------------
Average Number of Common Shares (000's)
Common Stock 36,828 38,707
Common Stock and Equivalents 36,863 38,845
Earnings per Common Share - Basic $ 1.79 $ 1.94
Earnings per Common Share - Diluted $ 1.79 $ 1.94
Cash Dividends Paid per Common Share $ 1.35 $ 1.35
</TABLE>
4
<PAGE>
RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Nine Months Ended
(Thousands of Dollars) September 30,
- ------------------------------------------------------------------------------------------------------------------------------
1999 1998
---------- ----------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 68,974 $ 79,123
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & Amortization 101,681 101,000
Deferred fuel (1,927) (4,491)
Deferred income taxes (3,554) (19,899)
Allowance for funds used during construction (1,318) (763)
Unbilled revenue 4,705 27,745
Stock option plan, net 485 51
Nuclear generating plant decommissioning fund (15,536) (15,627)
Pension costs accrued (623) (597)
Post employment benefit internal reserve 5,900 9,727
Provision for doubtful accounts 7,359 (1,079)
Changes in certain current assets and liabilities:
Accounts receivable 1,095 24,904
Materials, supplies and fuels (1,240) (4,361)
Taxes accrued (2,933) (2,404)
Payroll accrued 363 1,729
Accounts payable 14,066 10,525
Other current assets and liabilities, net (6,313) 5,251
Other, net 2,698 (10,386)
---------- ----------
Total Operating 173,882 200,448
---------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (78,945) (80,835)
Acquisition, net of cash (3,152) -
Other, net (34) (18,772)
---------- ----------
Total Investing (82,131) (99,607)
---------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issuance of common stock - 586
Issuance of long term debt - 30,386
Short term borrowings, net 2,840 (20,000)
Retirement of long term debt - (30,000)
Retirement of preferred stock (10,000) (10,000)
Repayment of promissory note (5,096) -
Dividends paid on preferred stock (3,349) (3,915)
Dividends paid on common stock (49,911) (52,393)
Payment for treasury stock (27,594) (20,442)
Equal Payment Plan (956) (8,934)
Other, net 344 (210)
---------- ----------
Total Financing (93,722) (114,922)
---------- ----------
Decrease in cash and cash equivalents (1,971) (14,081)
Cash and cash equivalents at beginning of year 6,523 25,405
---------- ----------
Cash and cash equivalents at end of year $ 4,552 $ 11,324
---------- ----------
</TABLE>
<TABLE>
<CAPTION>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Nine Months Ended
(Thousands of Dollars) September 30,
- ------------------------------------------------------------------------------------------------------------------------------
1999 1998
---------- -----------
<S> <C> <C>
Cash Paid During the Period
Interest paid (net of capitalized amount) $ 33,521 $ 22,195
---------- ----------
Income taxes paid $ 43,750 $ 56,660
---------- ----------
</TABLE>
5
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
Assets (Unaudited)
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric $ 2,488,352 $ 2,477,077
Gas 448,852 435,318
Common 149,422 158,038
Nuclear 270,034 256,562
------------ -----------
3,356,660 3,326,995
Less: Accumulated depreciation 1,689,048 1,640,645
Nuclear fuel amortization 234,755 222,830
------------ -----------
1,432,857 1,463,520
Construction work in progress 90,507 98,554
------------ -----------
Net Utility Plant 1,523,364 1,562,074
------------ -----------
Current Assets
Cash and cash equivalents 3,906 6,523
Accounts receivable, net of allowance for doubtful accounts:
1999 - $33,376; 1998 - $26,554 75,175 89,291
Unbilled revenue receivable 32,625 37,922
Materials, supplies and fuels 38,568 43,024
Prepayments 32,356 25,950
Other current assets - 253
------------ -----------
Total Current Assets 182,630 202,963
------------ -----------
Intangible Assets
Goodwill, net - 14,681
Other Intangible Assets - 6,381
------------ -----------
Total Intangible Assets - 21,062
------------ -----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 202,160 183,502
Nine Mile Two deferred costs 28,469 29,258
Unamortized debt expense 16,023 17,241
Other deferred debits 20,700 18,531
Regulatory assets 403,065 416,320
Other assets - 1,984
------------ -----------
Total Deferred Debits and Other Assets 670,417 666,836
------------ -----------
Total Assets $ 2,376,411 $ 2,452,935
------------ -----------
</TABLE>
6
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
Capitalization and Liabilities (Unaudited)
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization
Long term debt - mortgage bonds $ 480,053 $ 510,002
- promissory notes 220,573 248,224
Preferred stock redeemable at option of Company 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholder's equity
Authorized 50,000,000 shares; 38,885,813 shares
issued at September 30, 1999 and at December 31, 1998 700,300 699,730
Retained earnings 128,112 129,484
----------- -----------
828,412 829,214
Less: Treasury stock at cost (2,538,600 shares at September 30, 1999
and 1,507,000 shares at December 31, 1998) 74,026 46,433
----------- -----------
Total Common Shareholders' Equity 754,386 782,781
----------- -----------
Total Capitalization 1,527,012 1,613,007
----------- -----------
Long Term Liabilities
Nuclear waste disposal 90,640 87,566
Uranium enrichment decommissioning 12,484 12,197
Site remediation 22,356 24,157
----------- -----------
125,480 123,920
----------- -----------
Current Liabilities
Long term debt due within one year 30,000 427
Preferred stock redeemable within one year - 10,000
Short term debt 53,345 57,000
Accounts payable 57,613 52,454
Dividends payable 17,276 17,937
Equal payment plan 10,068 11,025
Other 39,074 34,526
----------- -----------
Total Current Liabilities 207,376 183,369
----------- -----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 311,979 326,972
Pension costs accrued 62,264 58,677
Kamine deferred costs 60,486 65,799
Post employment benefits internal reserve 48,809 42,909
Other 33,005 38,282
----------- -----------
Total Deferred Credits and Other Liabilities 516,543 532,639
----------- -----------
Commitments and Other Matters - -
----------- -----------
Total Capitalization and Liabilities $ 2,376,411 $ 2,452,935
----------- -----------
</TABLE>
7
<PAGE>
Rochester Gas and Electric Corporation
Statement of Income
(Thousands of Dollars)
(Unaudited)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
For the Three Months Ended
September 30,
1999 1998
---------- ------------
<S> <C> <C>
Operating Revenues
Electric $ 189,649 $ 189,644
Gas 32,266 36,529
Other 17,433 27,579
---------- -----------
Total Operating Revenues 239,348 253,752
Fuel Expenses
Fuel for electric generation 15,629 16,535
Purchased electricity 15,972 8,766
Gas purchased for resale 18,048 22,580
Other fuel expenses 15,783 23,644
---------- -----------
Total Fuel Expenses 65,432 71,525
---------- -----------
Operating Revenues Less Fuel Expenses 173,916 182,227
Other Operating Expenses
Operations and maintenance excluding fuel 77,956 71,613
Unregulated operating and maintenance expenses excluding fuel 1,919 4,379
Depreciation and amortizaton 28,430 28,258
Taxes - state, local & other 25,669 27,803
Federal income tax 9,694 15,218
---------- -----------
Total Other Operating Expenses 143,668 147,271
---------- -----------
Operating Income 30,248 34,956
Other (Income) & Deductions
Allowance for other funds used during construction (124) (101)
Federal income tax 436 910
Other - net (1,919) (2,365)
---------- -----------
Total Other (Income) & Deductions (1,607) (1,556)
---------- -----------
Income Before Interest Charges 31,855 36,512
Interest Charges
Long term debt 12,607 10,394
Other - net 1,363 1,067
Allowance for borrowed funds used during construction (199) (162)
---------- -----------
Total Interest Charges 13,771 11,299
---------- -----------
Net Income 18,084 25,213
---------- -----------
Dividends on Preferred Stock 925 1,305
---------- -----------
Earnings Applicable to Common Stock $ 17,159 $ 23,908
---------- -----------
Average Number of Common Shares (000's)
Common Stock 36,443 38,490
Common Stock and Equivalents 36,535 38,623
Earnings per Common Share - Basic $ 0.47 $ 0.62
Earnings per Common Share - Diluted $ 0.47 $ 0.62
Cash Dividends Paid per Common Share $ 0.45 $ 0.45
</TABLE>
8
<PAGE>
Rochester Gas and Electric Corporation
Statement of Income
(Thousands of Dollars)
(Unaudited)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Year To Date
September 30,
1999 1998
---------- -----------
<S> <C> <C>
Operating Revenues
Electric $ 529,232 $ 523,341
Gas 203,315 196,062
Other 108,698 27,580
---------- -----------
Total Operating Revenues 841,245 746,983
Fuel Expenses
Fuel for electric generation 37,642 40,994
Purchased electricity 44,295 21,377
Gas purchased for resale 105,418 113,318
Other fuel expenses 91,505 23,644
---------- -----------
Total Fuel Expenses 278,860 199,333
---------- -----------
Operating Revenues Less Fuel Expenses 562,385 547,650
Other Operating Expenses
Operations and maintenance excluding fuel 224,641 214,056
Unregulated operating and maintenance expenses excluding
fuel 14,235 6,106
Depreciation and amortizaton 89,292 87,376
Taxes - state, local & other 84,546 88,218
Federal income tax 42,273 46,002
---------- -----------
Total Other Operating Expenses 454,987 441,758
---------- -----------
Operating Income 107,398 105,892
Other (Income) & Deductions
Allowance for other funds used during construction (507) (293)
Federal income tax 2,218 4,459
Other - net (5,760) (11,531)
---------- -----------
Total Other (Income) & Deductions (4,049) (7,365)
---------- -----------
Income Before Interest Charges 111,447 113,257
Interest Charges
Long term debt 37,968 32,107
Other - net 4,498 2,497
Allowance for borrowed funds used during construction (811) (470)
---------- -----------
Total Interest Charges 41,655 34,134
---------- -----------
Net Income 69,792 79,123
---------- -----------
Dividends on Preferred Stock 3,157 3,915
---------- -----------
Earnings Applicable to Common Stock $ 66,635 $ 75,208
---------- -----------
Average Number of Common Shares (000's)
Common Stock 36,828 38,707
Common Stock and Equivalents 36,863 38,845
Earnings per Common Share - Basic $ 1.81 $ 1.94
Earnings per Common Share - Diluted $ 1.81 $ 1.94
Cash Dividends Paid per Common Share $ 1.35 $ 1.35
</TABLE>
9
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Nine Months Ended
(Thousands of Dollars) September 30,
- --------------------------------------------------------------------------------------------------------------------------------
1999 1998
------------ -------------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 70,094 $ 79,123
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & Amortization 99,356 101,000
Deferred fuel (1,927) (4,491)
Deferred income taxes (6,620) (19,899)
Allowance for funds used during construction (1,318) (763)
Unbilled revenue 5,297 27,745
Stock option plan, net 485 51
Nuclear generating plant decommissioning fund (15,536) (15,627)
Pension costs accrued (623) (597)
Post employment benefit internal reserve 5,900 9,727
Provision for doubtful accounts 7,077 (1,079)
Changes in certain current assets and liabilities:
Accounts receivable (1,850) 24,904
Materials, supplies and fuels 1,974 (4,361)
Taxes accrued (5,030) (2,404)
Payroll accrued (182) 1,729
Accounts payable 11,090 10,525
Other current assets and liabilities, net (1,162) 5,251
Other, net 3,102 (10,386)
------------ -------------
Total Operating 170,127 200,448
------------ -------------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (77,619) (80,835)
Other, net 1,547 (18,772)
------------ -------------
Total Investing (76,072) (99,607)
------------ -------------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issuance of common stock - 586
Issuance of long term debt - 30,386
Short term borrowings, net 2,040 (20,000)
Retirement of long term debt - (30,000)
Retirement of preferred stock (10,000) (10,000)
Repayment of promissory note (1,587) -
Dividends paid on preferred stock (3,349) (3,915)
Dividends paid on common stock (49,911) (52,393)
Payment for treasury stock (27,594) (20,442)
Equal payment plan (956) (8,934)
Corporate restructuring to establish holding company (8,329) -
Other, net 4,171 (210)
------------ -------------
Total Financing (95,515) (114,922)
------------ -------------
Decrease in cash and cash equivalents (1,460) (14,081)
Cash and cash equivalents at beginning of year 5,366 25,405
------------ -------------
Cash and cash equivalents at end of year $ 3,906 $ 11,324
------------ -------------
</TABLE>
<TABLE>
<CAPTION>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Nine Months Ended
(Thousands of Dollars) September 30,
- --------------------------------------------------------------------------------------------------------------------------------
1999 1998
------------ -------------
<S> <C> <C>
Cash Paid During the Period
Interest paid (net of capitalized amount) $ 33,025 $ 22,195
------------ -------------
Income taxes paid $ 43,750 $ 56,660
------------ -------------
</TABLE>
10
<PAGE>
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 ENERGY. RG&E's common stock was exchanged on a share-for-
share basis for RGS ENERGY's common stock. 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 ENERGY's
Consolidated Financial Statements include the accounts of RGS ENERGY and its
wholly owned subsidiaries, including RG&E, and two non-utility subsidiaries, RGS
Development and Energetix. RGS ENERGY'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 ENERGY's
structure. RGS ENERGY 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 1999 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
RG&E Annual Report on Form 10-K for the year ended December 31, 1998.
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, RGS ENERGY identified three operating
segments, driven by the types of products and services offered and regulatory
environment under which RGS ENERGY primarily operates. The three segments of
RGS ENERGY are Regulated Electric, Regulated Gas, and Unregulated. The
Regulated Electric and Regulated Gas Segments are segments of RG&E. The
Regulated segments' financial records are maintained in accordance with
generally accepted accounting principles (GAAP) and PSC accounting policies.
The Unregulated segment's financial records are maintained in accordance with
GAAP.
<TABLE>
<CAPTION>
For the Three Months Ended September 30, 1999
Regulated Electric Regulated Gas Unregulated
------------------- ------------------- ----------------------
(thousands of dollars) 1999 1998 1999 1998 1999 1998
- ---------------------- -------- --------- -------- --------- -------- ------------
<S> <C> <C> <C> <C> <C> <C>
Profit/(Loss) $ 26,610 $ 34,385* $(8,056) $(7,984)* $(1,664) $(1,188)
Revenues - External Customers 189,425 189,553 32,057 36,507 70,969 29,189
Revenues - Intersegment Transactions 12,537 1,361 61 136 -- --
</TABLE>
11
<PAGE>
<TABLE>
<CAPTION>
For the Nine Months Ended September 30, 1999
Regulated Electric Regulated Gas Unregulated
-------------------- --------------------- ------------------------
(thousands of dollars) 1999 1998 1999 1998 1999 1998
- ---------------------- --------- --------- --------- ---------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C>
Profit $ 63,818* $ 83,629* $ 6,277* $ (2,362)* $ (1,121)* $(2,144)*
Revenues - External Customers 527,782 523,232 200,418 196,039 185,630 29,620
Revenues - Intersegment Transactions 31,790 1,696 290 212 -- --
</TABLE>
<TABLE>
<CAPTION>
September December
--------- --------
(thousands of dollars) 1999 1998
- ---------------------- ---- ----
<S> <C> <C>
Total Assets 77,576 59,946
</TABLE>
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 September 30, 1999 Ended September 30, 1999
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Revenues
Regulated Electric $189,425 $189,553 $527,782 $523,232
Regulated Gas 32,057 36,507 200,418 196,039
Unregulated 70,969 29,189 185,630 29,620
-------- -------- -------- --------
Total 292,451 255,249 913,830 748,891
Reported on RGS Consolidated
Income Statement 279,853 253,752 881,750 746,983
Difference to reconcile 12,598 1,497 32,080 1,908
Intersegment Revenue
Regulated Electric from Unregulated 12,537 1,361 31,790 1,696
Regulated Gas from Unregulated 61 136 290 212
-------- -------- -------- --------
Total Intersegment 12,598 1,497 32,080 1,908
</TABLE>
A reconciliation of the regulated electric and regulated gas revenues to the
RG&E Income Statement follows:
<TABLE>
<CAPTION>
For the Three Months For the Nine Months
Ended September 30, 1999 Ended September 30, 1999
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Revenues
Regulated Electric $189,425 $189,553 $527,782 $523,232
Regulated Gas 32,057 36,507 200,418 196,039
Unregulated 21,727 29,189 136,388 29,620
-------- -------- -------- --------
Total 243,209 255,249 864,588 748,891
Reported on RG&E
Income Statement 239,348 253,752 841,245 746,983
Difference to reconcile 3,861 1,497 23,343 1,908
Intersegment Revenue
Regulated Electric from Unregulated 3,840 1,361 23,093 1,696
Regulated Gas from Unregulated 21 136 250 212
-------- -------- -------- --------
Total Intersegment 3,861 1,497 23,343 1,908
</TABLE>
* Some items have been restated for comparative purposes.
Note 3. COMMITMENTS AND OTHER MATTERS
The following matters supplement the information contained in Note 10 to the
financial statements included in the RG&E's Annual Report on Form 10-K for the
year ended December 31, 1998 and should be read in conjunction with the material
contained in that Note.
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<PAGE>
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 these costs under SFAS-71, these assets would be adjusted for any
impairment to recovery (pursuant to SFAS-121). In certain cases, the entire
amount could be written off.
SFAS-121 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 fully recoverable.
Below is a summarization of the Regulatory Assets as of September 30, 1999
and December 31, 1998:
<TABLE>
<CAPTION>
Millions of Dollars
9/30/99 12/31/98
--------- --------
<S> <C> <C>
Income Taxes $ 139.3 $147.6
Kamine Settlement 189.4 192.8
Uranium Enrichment Decommissioning Deferral 14.1 15.1
Deferred Ice Storm Charges 7.0 8.9
Deferred Environmental SIR costs 20.1 20.9
Labor Day 1998 Storm Costs 8.3 7.2
Other, net 24.9 23.8
--------- ------
Total - Regulatory Assets $ 403.1 $416.3
========= ======
</TABLE>
See the RG&E's 1998 Form 10-K, Item 8, Note 10 of the Notes to Financial
Statements, "Regulatory Assets" 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. Examples
include purchase power contracts or high cost generating assets. 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, 1999 depends on market prices and the competitive market in New
York State which is still under development and subject to continuing changes
which are not yet determinable, but the amount could be significant. Strandable
assets, if any, could be written down for impairment of recovery in the same
manner as deferred costs discussed above.
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 Cost Recovery" 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 September 30, 1999 RG&E believes that its regulatory assets are not
13
<PAGE>
impaired and are probable of recovery. The 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 ultimate determination in this proceeding could have an
impact on strandable assets and the recovery of nuclear costs. The initial
meeting in this Inquiry was held in January 1999 and such a determination is
unlikely before year-end (see PSC Proceeding on Nuclear Generation under Item 2,
Management's Discussion and Analysis of Financial Condition and Results of
Operations).
GAS COST RECOVERY. RG&E entered into several agreements to help manage its
pipeline capacity costs and has successfully met targets agreed upon in a PSC
approved 1995 settlement. In July, 1998 RG&E entered into an agreement with
Dynegy Marketing and Trade to provide assistance with respect to the management
of RG&E's gas supply, transportation and storage costs consistent with the goal
of providing reliable service and reducing the cost of gas.
For information in connection with the PSC's Gas Policy Statement to establish
a competitive gas supply market and the status of settlement negotiations with
the PSC pertaining to the transition to a competitive gas market, see Item 2,
Management's Discussion and Analysis of Financial Condition and Results of
Operations under the headings "PSC Gas Restructuring Policy Statement" and "Gas
Proposal and Interim Settlement".
SPENT NUCLEAR FUEL LITIGATION. The federal Nuclear Waste Act obligated
DOE to accept for disposal spent nuclear fuel (SNF) from utilities' powerplants
by January 31, 1998 (statutory deadline). Since the mid-1980s RG&E and other
nuclear plant owners and operators have paid substantial fees to DOE to fund
that obligation (Nuclear Waste Fund). That DOE would not meet its obligation
was evident well prior to 1998; DOE admitted as much as the statutory deadline
approached.
In 1994, Northern States Power Company and other owners of nuclear plants
filed suit against DOE and the federal government in the U.S. Court of Appeals
for the District of Columbia Circuit (Court) seeking a declaration that DOE's
course of action was in violation of its statutory obligation and requesting
other relief. In 1996, the Court upheld the utilities' position that DOE is
obligated to accept and dispose of the utilities' SNF by the statutory deadline.
The Court rejected the DOE contention that it could defer the disposal until the
availability of a suitable SNF repository, but stopped short of providing the
utilities a remedy since DOE had not yet defaulted.
In late 1996, DOE invited nuclear utilities' views on how its anticipated
inability to meet the statutory deadline could "best be accommodated." RG&E and
a number of other parties responded to that invitation.
By a Joint Petition for Review, RG&E and other nuclear utilities petitioned
the Court in January 1997 for a declaration that the Petitioners were relieved
of the obligation to pay fees into the Nuclear Waste Fund, and were authorized
to place those fees into escrow until DOE commenced disposing of SNF. The
petition further requested that DOE be ordered to develop a program that would
enable it to begin acceptance of SNF by the statutory deadline. In November
1997, the Court held that DOE could not delay acceptance on grounds that it
lacked an SNF repository, and that the utilities had a "clear right to relief".
Rather than grant funding relief and order the DOE to move SNF, however, the
Court referred the utilities to their contractual remedies against DOE. State
agencies, municipal governments and DOE sought review of this decision, but the
U.S. Supreme Court declined in November 1998 to hear the case. In July 1998 the
Company, joined by several other nuclear utilities, initiated a further effort
to have the Court provide a suitable remedy under its "original and exclusive"
jurisdiction over matters arising under the Nuclear Waste Act. In April 1999,
the
14
<PAGE>
Court granted a motion to dismiss the utilities' petition. A petition for
rehearing was similarly denied. A petition for certiorari to the U.S. Supreme
Court was filed on November 1, 1999.
DOE's failure to meet its statutory deadline has given rise to numerous other
lawsuits. For example, several plant operators brought suit against DOE in the
U.S. Court of Federal Claims (COFC). In decisions issued in October and
November 1998, COFC judges held that DOE had breached its contractual
obligations. They denied most portions of DOE motions to dismiss the
operators', claims and granted the operators' summary judgment on DOE contract
liability. However, in a recently announced decision, a different COFC judge
directed claimants in that case to the DOE Contract Administrator for the
requested relief. These decisions are being appealed.
It is not possible to predict the outcome of this split in the COFC, the
future course of the DOE obligation or the resolution of the spent nuclear fuel
movement and storage concern that underlies it. Similarly, the ultimate outcome
of nuclear waste legislation in Congress, that could address these and related
concerns, is uncertain. The court rulings on the DOE's default in meeting its
obligation to remove SNF by the statutory deadline, and on its contractual
liability therefor, have been promising. The current court rulings appear to
have prompted greater DOE effort to complete site investigations at its Yucca
Mountain, NV, site for SNF disposal and to focus greater Congressional attention
on the inappropriateness of continuing to house SNF around the nation at short-
term SNF facilities of nuclear powerplants. These developments have not yet
led, however, either to a firm schedule for DOE's movement of SNF from plant
facilities to a permanent repository or to the authorization of plant owners and
operators to withhold their Nuclear Waste Fund payments to DOE until that
schedule is established. RG&E and other nuclear utilities continue to work
toward those objectives in judicial, legislative and administrative initiatives.
EITF ISSUE 97-4 - DEREGULATION OF THE PRICING OF ELECTRICITY. In July
1997, the Financial Accounting Standards Board's 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 cost 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 Settlement provisions. The
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 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 fixed portion of the non-nuclear generation
to-go
15
<PAGE>
costs after July 1, 1999 and the variable portion of the non-nuclear
generation to-go costs after July 1, 1998 are subject to market forces and would
no longer be able to apply SFAS-71. RG&E's net investment at September 30, 1999
in nuclear generating assets is $644.2 million and in non-nuclear generating
assets is $110.2 million. (See Management's Discussion and Analysis of
Financial Condition and Results of Operations, "Proposed Sale of Nuclear Plant"
for information concerning RG&E's options relative to the proposed sale of Nine
Mile Two by two co-owners.)
ENVIRONMENTAL MATTERS. The New York Attorney General 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 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 state Department of
Environmental Conservation (DEC) prior to their occurrence. RG&E and other
letter recipients are involved in discussions with the Attorney General's office
to clarify the scope and timing of the request and establish the role of the
Attorney General and the DEC in the information gathering effort and any
subsequent potential action. RG&E cannot assess the potential impact of this
issue in these early stages of its development.
On October 14, 1999, the Governor of New York publicly proposed
modifications of the state's oxides of nitrogen (NOx) and sulfur dioxide (SO2)
control programs. 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). The
proposal suggests such a change should take effect in October, 2003. In
addition, the Governor is also proposing that there be a targeted reduction of
some 50% in SO2 emissions below the existing Acid Rain Phase II limits. The
proposal suggests a phase-in period from 2003 through 2007. Since this is only
a proposed rule change and subject to review, comment and modification, no
estimate of its economic impact on RG&E can be made at this time.
16
<PAGE>
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 difference in whether the forward
looking statements ultimately prove to be accurate include:
1. any changes in the condition or regulatory treatment of nuclear generation
facilities as a result of the proposed sale of the Nine Mile Point nuclear
generating facilities by Niagara Mohawk Power Corporation and New York
State Electric and Gas Corporation.
2. any state or federal legislative or regulatory initiatives (including the
results of negotiations between RG&E and the PSC regarding the Gas
Settlement) that affect the cost or recovery of investments necessary to
provide utility service in the electric and natural gas industries. Such
initiatives could include, for example, changes in the regulation of rate
structures or changes in the speed or degree to which competition occurs in
the electric and natural gas industries;
3. any changes in the ability of RG&E to recover environmental compliance costs
through increased rates;
4. the determination in the nuclear generation proceeding initiated by the PSC,
including any changes in the regulatory status of nuclear generating
facilities and their related costs, including recovery of costs related to
spent fuel and decommissioning;
5. any changes in the rate of industrial, commercial and residential growth in
RG&E's and RGS ENERGY'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 ENERGY 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;
11. any unanticipated developments associated with fixing and testing the
modifications necessary to mitigate Year 2000 compliance problems, including
the possible indirect impact of customers, suppliers and other business
partners who do not sufficiently mitigate their Year 2000 compliance
problems; and
12. any other considerations that may be disclosed from time to time in the
publicly disseminated documents and filings of RGS ENERGY and RG&E.
Shown below is a listing of the principal items discussed.
17
<PAGE>
RGS ENERGY GROUP, INC. Page 18
Business and Financial Strategy
Unregulated Subsidiaries
ROCHESTER GAS AND ELECTRIC CORPORATION
Competition Page 19
PSC Competitive Opportunities Case Settlement
Energy Choice
Fossil Units Status
Proposed Sale of Nuclear Plant
PSC Proceeding on Nuclear Generation
FERC Open Access Transmission Orders and
Company filings
Rates and Regulatory Matters Page 25
PSC Gas Restructuring Policy Statement
Gas Proposal and Interim Settlement
Flexible Pricing Tariff
LIQUIDITY AND CAPITAL RESOURCES Page 27
Capital and Other Requirements
Financing
Redemption of Securities
Stock Repurchase Plan
Year 2000 Readiness Information
EARNINGS SUMMARY Page 30
RESULTS OF OPERATIONS Page 31
Operating Revenues and Sales
Operating Expenses
Other Statement of Income Items
DIVIDEND POLICY Page 33
RGS ENERGY GROUP, INC.
On August 2, 1999, RG&E was reorganized into a holding company structure
pursuant to an Agreement and Plan of Share Exchange (Exchange Agreement) between
RG&E and RGS ENERGY. As part of the reorganization, all of the outstanding
shares of RG&E common stock were exchanged on a share-for-share basis for shares
of RGS ENERGY and RG&E became a subsidiary of RGS ENERGY. Certificates for
shares of RG&E common stock are automatically valid as certificates for RGS
ENERGY and do not have to be replaced. The transfer does not affect the value
of the stock or RGS ENERGY's dividend policy. RGS ENERGY trades on the New York
Stock Exchange under the symbol "RGS". RG&E shareholders approved the Exchange
Agreement on April 29, 1999.
The holding company structure was formed to respond quickly to changes in
the evolving competitive energy utility industry. The new structure permits the
use of financing techniques that are better suited to the particular
requirements, characteristics and risks of non-utility operations without
affecting the capital structure or creditworthiness of RG&E. This increases RGS
ENERGY's financial flexibility by allowing it to establish different debt-to-
equity ratios for each of its individual lines of business.
RGS ENERGY is not an operating entity. RGS ENERGY's operations are being
conducted through its subsidiaries which include RG&E, and two unregulated
subsidiaries - RGS DEVELOPMENT and Energetix, as well as Griffith, a subsidiary
of Energetix.
18
<PAGE>
RG&E will continue to offer 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.
Business and Financial Strategy. Under the terms of the Settlement, RG&E
has functionally separated its generation, distribution, and regulated energy
services businesses. Consistent with the Settlement, RG&E has implemented a
business and financial strategy which consists of the following: (1) the
reorganization of its corporate structure into a holding company effective
August 2, 1999 in order to more fully implement the separation of its regulated
and unregulated businesses, and (2) the development of an integrated financial
strategy that includes new business initiatives and a Common Stock share
repurchase program of $145 million. Through September 30, 1999, approximately
2.5 million shares have been repurchased.
Unregulated Subsidiaries. It is part of RGS ENERGY's financial strategy to
seek growth by entering into unregulated businesses. The Settlement allowed
RG&E to provide the funding for RGS ENERGY to invest up to $100 million in
unregulated businesses. The first step in this direction was the formation and
operation of Energetix effective 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 August 1998, Energetix announced the acquisition of Griffith, the second
largest oil and propane distribution company in New York State. Energetix
accounted for its acquisition of Griffith as a purchase in the amount of
approximately $31.5 million. Purchase accounting adjustments, including
goodwill, are reflected in the consolidated financial statements of RGS ENERGY
at September 30, 1999 and December 31, 1998.
Griffith gives Energetix access to 65,000 new customers, 60,000 of which
are outside of RG&E's regulated franchise territory. In addition to its current
products, Griffith sells electricity, natural gas and other services offered by
Energetix to its existing customers. Griffith has approximately 350 employees
and operates 18 customer service centers.
In September 1999, Griffith announced the acquisition of Bobbett Gas
Service, a provider of propane gas and service in the Central New York area.
The acquisition adds 2,600 customers to the current Griffith customer base.
Additional information on Energetix operations (including Griffith) is
presented under the headings Operating Revenues, Operating Expenses, and is
contained in Note 2 of the Notes to Financial Statements.
During the second quarter of 1998, the Company formed RGS Development to
pursue unregulated business opportunities in the energy marketplace. Through
September 30, 1999, RGS Development operations have not been material to RGS
ENERGY's results of operations or its financial condition.
ROCHESTER GAS AND ELECTRIC CORPORATION
COMPETITION
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 (the "Settlement"). The
Settlement sets the framework for the introduction and development of open
19
<PAGE>
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 Settlement sets RG&E's electric rates for each year during its five-
year term. Over the five-year term of the 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 excess of an
effective rate of 11.50 percent over the entire five-year term of the
Settlement, 50 percent of such excess will be used to write down deferred costs
accumulated during the term. The other 50 percent of the excess 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). 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 either RG&E or any other party to
the Settlement would have the right to petition the PSC for review of the
Settlement and appropriate remedial action.
The Settlement requires RG&E to functionally separate its three regulated
operations: distribution, generation and retailing. Additionally, unregulated
energy retailing operations must be structurally separate from the regulated
utility functions. Although the 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 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).
RG&E's retail access program, Energy Choice, was approved by the PSC as
part of the Settlement and went into effect on July 1, 1998. Details of the
Energy Choice Program are discussed below.
One party to the Settlement negotiations has commenced an action for
declaratory and injunctive relief as to certain provisions of the Settlement and
the PSC's approval of it. RG&E is unable, at this time, to predict the outcome
of this action.
ENERGY CHOICE. 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 four basic components of
the sale of energy: the sale of electricity which is the amount of energy
actually used by the consumer, the sale of capacity which is the ability through
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generating facilities or otherwise, to provide electricity when it is needed,
the sale of distribution, which is the physical delivery of electricity to the
consumer, and retail services such as billing and metering. Historically, RG&E
has sold all four components bundled together for a fixed rate approved by the
PSC. The implementation of the Energy Choice program 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 our
program, beginning July 1, 1999, this limit increased from 10 percent up to
approximately 20 percent. By October 31, 1999, approximately 14 percent of
total RG&E sales had shifted to competitive energy services companies. On July
1, 2001, all retail customers will be eligible to purchase energy from
alternative energy service companies. The phase-in of the Energy Choice Program
over the next few years eventually will give retail electric customers the
opportunity to purchase energy, capacity and retailing services from competitive
energy service companies. They may also continue to purchase fully bundled
electric service from RG&E under existing retail tariffs.
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).
Throughout the term of the 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 or return to such service, and to
customers to whom no competitive alternative is offered.
During the initial "Energy-Only" stage of the Energy Choice program, 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.
The "Energy and Capacity" stage, the second stage of the phase-in was
scheduled to begin this Fall. In this stage, energy service companies may
purchase both energy and capacity in the open market. As a result of a delay in
establishing a NYISO, RG&E, with the consent of the energy service companies
participating in the Retail Access Program, reserved capacity for the 1999-2000
winter capability period and will provide energy and capacity for the energy
service companies through that period. Essentially, energy service companies
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will purchase "full-requirements" (delivery services plus energy and capacity)
from RG&E.
During the 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. During this stage of the program,
RG&E's distribution rates will be set by deducting 3.0712 cents per kilowatt-
hour from its full service ("bundled") 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.
As of October 31, 1999, seven energy service companies, including
Energetix, the Company's unregulated subsidiary, are qualified by RG&E to serve
retail customers under the Energy Choice Program. In addition to Energetix,
these companies are Columbia Energy Power Marketing Corporation, DukeSolutions,
Inc., Northeast Energy Services, Inc.(NORESCO), North American Energy, Select
Energy Inc., and TXU Energy Services, Inc. In addition, the County of Monroe
has been qualified to act as its own energy service company to service its own
facilities. As of October 31, 1999, all energy service companies had opted to
purchase "full-requirements" from RG&E to serve their retail customers.
With the commencement of the "Energy and Capacity" stage on November 1,
1999, implementation of the NYISO, and the end of the winter capability period,
RG&E will also be shifting the responsibility for purchasing not only
electricity, but also capacity, to these energy service companies. As "full-
requirements" customers during the winter capability period of the "Energy and
Capacity" stage, energy service companies will be purchasing electricity and
capacity from RG&E at 2.6712 cent per kilowatt-hour. Similarly, there will be
a slight revenue loss as a result of the increased back-out rate when this shift
occurs. However, RG&E expects to manage this revenue impact with offsetting
savings in costs no longer incurred for the acquisition and maintenance of
capacity and increasing wholesale revenues through the sale of available
capacity.
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 proceedings
include uniform business practices, standardized billing and competitive
metering. RG&E continues to assess the scope and impact of such changes on its
operations.
FOSSIL UNITS STATUS. On April 30, 1999, RG&E ceased operations at its
Beebee Station (80 Megawatt) generating facility. The plant was retired on July
1, 1999. Factors such as the plant's age, lack of a rail/coal delivery system
and more stringent clean air regulations made the plant uneconomical in the
developing competitive generation business. The retirement of Beebee Station
did not have a material effect on the financial position or results of
operations of RGS ENERGY or RG&E. As a result of a one time incremental charge
of $2.1 million, the plant was fully depreciated at the time of retirement. The
Competitive Opportunities Settlement provides that all prudently incurred
incremental costs associated with the retirement and decommissioning of the
plant are recoverable through RG&E's distribution access rates. The electric
capacity and energy previously provided by the plant are expected to be replaced
in the energy markets as needed.
In early June the Allegany Station, a combined-cycle unit fueled by natural
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gas, began generating electricity. The 62 megawatt capacity unit is expected to
generate electricity during the peak demand summer months and when the economics
of producing electricity for sale are favorable. The plant is being operated
and maintained for RG&E by Bell Harbert Energy LLC. Allegany Station, which was
built as a co-generation facility in the early 1990s, was obtained by RG&E as
part of a legal settlement in December 1998 with General Electric Capital
Corporation, Kamine and other Kamine affiliates.
Oswego Unit Sale. In a single-Commissioner order issued October 21, 1999,
the PSC approved the joint petition of RG&E and Niagara Mohawk to sell their
interests in the Oswego Generation Facility (excluding a 345 kilovolt substation
and associated land (Retained Parcel)) and, on October 22, 1999, RG&E and
Niagara Mohawk sold their respective 12% and 88% interests in the Oswego
Generation Facility to Oswego Harbor Power LLC, a wholly-owned affiliate of NRG
Energy, Inc. (collectively, the Buyer) for approximately $91 million.
Additionally, the Buyer agreed to assume RG&E's obligations under a June 8, 1998
transmission services agreement (Exit Agreement) as it pertains to the Oswego
Generation Facility. This assumption represents a net present value of
approximately $25 million, which is deducted from RG&E's approximately $11
million share of the sale proceeds. Accordingly, upon closing, RG&E was
required to make a net payment of approximately $14 million to Niagara Mohawk.
Under the terms of the Competitive Opportunities Settlement, RG&E is permitted
to recover any losses on a sale of generation through distribution rates.
Pursuant to the October 21 order, which must be confirmed by the full PSC, RG&E
is required to file, within 30 days of the closing, a detailed calculation of
its net book loss after tax impacts. Including the impact of the $25 million
relating to the Exit Agreement, RG&E's net loss, before expenses and taxes, is
approximately $66 million. In the required filing, RG&E will identify the
extent to which that figure, as otherwise adjusted, may be offset by items that
are currently recovered in rates.
RG&E and Niagara Mohawk have also entered into a Purchase and Sale
Agreement Dated October 22, 1999, pursuant to which Niagara Mohawk will acquire
RG&E's 12% interest in the Retained Parcel for $1.1 million, subject to
obtaining the requisite approvals for the transfer from the PSC and FERC. The
closing of the sale is not expected to occur until 2000.
PROPOSED SALE OF NUCLEAR PLANT. 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 Two nuclear plant to AmerGen Energy Co.(AmerGen), a
joint venture of PECO Energy of Philadelphia and British Energy. Niagara
Mohawk owns 41 percent and NYSEG owns 18 percent of Nine Mile Two. The
financial terms of the transaction include nominal purchase prices to be paid to
Niagara Mohawk of $63.6 million and to NYSEG of $27.9 million. The sale is
subject to several contingencies including various regulatory approvals.
RG&E's 14 percent interest in Nine Mile Two is not included in the current
proposal. As part owner, RG&E, along with the other owners, generally has three
options: the first option is to retain its ownership interest on the same basis
that it does now; the second option is to sell its 14 percent interest in Nine
Mile Two to AmerGen on substantially the same terms as Niagara Mohawk and NYSEG;
and the third option is to buy the Niagara Mohawk and/or NYSEG interests on the
same terms as offered by AmerGen. Niagara Mohawk has taken the position that an
exercise of the right to buy its interest in Nine Mile Two must necessarily
include matching the current offer to buy the Nine Mile Point One Nuclear Plant.
While RG&E does not necessarily agree with such position, it is considering this
as an additional option. RG&E is considering each of these options including
their impact on ratemaking and the future regulatory treatment of nuclear plants
by the PSC (see paragraph below). RG&E has contracted with Entergy Nuclear,
Inc. to assist in conducting due diligence of the plants and evaluating the
options. At September 30, 1999 the book value, including nuclear fuel, of
RG&E's 14 percent interest in Nine Mile Two was approximately $390 million.
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On August 30, 1999 the PSC began a proceeding to review the proposed sale
by Niagara Mohawk and NYSEG to determine if the sale is in the public interest.
RG&E has intervened in that proceeding.
PSC PROCEEDING ON NUCLEAR GENERATION. On March 20, 1998, the PSC initiated
a proceeding to examine a number of issues raised by a Staff position paper on
nuclear generation and the comments received in response to it. In reviewing
the Staff paper and parties' comments, the PSC:
(1) adopted as a rebuttable presumption the premise that nuclear power should
be priced on a market basis to the same degree as power from other sources,
with parties challenging that premise having to bear a substantial burden
of persuasion;
(2) characterized the proposals in the Staff paper as by and large consistent
in concept with the PSC's goal of a competitive, market-based electricity
industry;
(3) questioned Staff's position that would leave funding and other
decommissioning responsibilities with the sellers of nuclear power
interests and;
(4) indicated interest in the potential for a New York Nuclear Operating
Company (NYNOC) proposal to benefit customers through efficiency gains and
directed pursuit of that matter in this nuclear generating proceeding or
separately upon the filing of a formal NYNOC proposal.
RG&E has worked with other New York nuclear generation operators on the
development of a NYNOC but no substantial further work on its implementation is
anticipated until completion of this proceeding and the outcome of any proposed
sales by current New York nuclear plant owners is determined.
RG&E's potentially strandable assets in nuclear plant could be impacted by
the outcome of this proceeding. The initial collaborative conference for this
proceeding was held on January 20, 1999. The parties in this proceeding
developed a collaborative, non-binding interim report entitled "Nuclear
Generation and the Competitive Electric Market" which was issued in July, 1999.
A copy of the interim report is available on the PSC's website
(http://www.dps.state.ny.us/). The report and the status of the proceeding, in
addition to the proposed sale of the nuclear assets owned by Niagara Mohawk and
NYSEG (see section on Proposed Nuclear Plant Sale above), were discussed at the
July 14, 1999 PSC Session. At that meeting, the Chairman of the PSC recommended
that this nuclear proceeding continue in parallel with the PSC proceeding to
consider the proposed sale of the Nine Mile Two nuclear plant discussed above.
The Chairman also provided direction that the proceeding on the sale of the
nuclear plant has priority and the PSC Staff is to be mindful of resource
conflicts as many parties are involved in both proceedings. RG&E will be
actively involved in both proceedings. A final determination in either
proceeding is unlikely before late in the first quarter of 2000.
FERC OPEN ACCESS TRANSMISSION ORDERS AND COMPANY FILINGS. On January 31,
1997, the New York electric utilities filed a "Comprehensive Proposal To
Restructure the New York Wholesale Electric Market" with the FERC. As proposed,
the existing New York Power Pool (NYPP) will be dissolved and an independent
system operator (NYISO) will administer a Statewide open access tariff and
provide for the short-term reliable operation of the bulk power system in the
State. In addition to proposing a FERC-endorsed NYISO, the proposal calls for
creation of a New York State Reliability Council.
On June 30, 1998, the FERC issued an Order that conditionally authorized
the establishment of the NYISO by the member systems of the NYPP (Member
Systems). The order addresses areas of governance, standards of conduct and
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reliability. On April 30, 1999, the FERC issued an order which addressed
several issues, including its rejection of the Member Systems' settlement on
governance issues, and its acceptance of the section 203 filing to transfer
jurisdictional transmission facilities to the NYISO. On July 2, 1999, the
Member Systems of the NYPP filed a proposed agreement on governance issues and
an explanatory statement of the agreement. On September 15, 1999, the FERC
issued an Order approving the agreement on governance.
On January 27, 1999 the FERC issued an Order conditionally accepting the
proposed NYISO tariff, and the proposed market rules of the NYISO. The Order
also granted the Member Systems' request for market-based rates for energy,
ancillary services and installed capacity sold through the NYISO. Certain
aspects of the proposed transmission rates were set for hearing. On April 30,
1999, the Member Systems made their compliance filing as requested by the
January 27, 1999 Order. On July 29, 1999, the FERC issued an Order on the
Compliance Filing, approving the NYISO Open Access Transmission Tariff, the
NYISO Services Tariff, and each of the related ISO Agreements submitted by the
Member Systems.
On May 28, 1999, in accordance with the procedural schedule then in effect,
the Member Systems filed their Direct Testimony. The Member Systems filed a
response to the comments and protests to the April 30th filing on June 30, 1999.
Settlement talks have been held between the Member Systems, FERC staff and the
other intervenors. A Memorandum of Understanding addressing most of the issues
set for hearing is currently under negotiation. The hearing established to
address rate issues is scheduled to begin on January 6, 2000. Such hearing is
not expected to affect adversely any plans to commence ISO operations.
Additionally, a settlement judge proceeding was established to resolve an
issue involving whether certain transmission arrangements should be
grandfathered as "pre-ISO" arrangements. On June 17, 1999, the Member Systems
filed with the FERC a Settlement Agreement resolving a grandfathering issue.
On July 7, 1999, the FERC Trial Staff filed comments in support of the
Settlement Agreement. The matter is currently pending FERC action.
On November 3, 1999 the NYISO issued notification that it would implement a
competitive wholesale market for the sale, purchase and transmission of
electricity in New York State on November 18, 1999.
Significant changes to pricing procedures now in effect within NYPP are
expected, but it is unclear what effect these changes may have once other
regulatory changes in New York State are implemented. At the present time, RG&E
cannot predict what effects regulations ultimately adopted by FERC will have, if
any, on future operations or the financial condition of RGS ENERGY or RG&E.
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 PROPOSAL AND INTERIM SETTLEMENT. In August 1998, prior to issuance of the
PSC's Gas Policy Statement (see PSC Gas Restructuring Policy Statement
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above), RG&E had commenced negotiations with the PSC staff and other parties to
develop a comprehensive multi-year settlement of various issues, including rates
and the structure of RG&E's gas business. Because the negotiation of a
comprehensive settlement was not anticipated to conclude until mid-1999, the
parties to the negotiations agreed to an Interim Settlement, effective November
1998 through June 1999, that deals with such issues as rates, transportation and
storage capacity costs, assignment of capacity, and retail access. Major
elements of the Interim Settlement include: (1) the term is from December 1,
1998 through the earlier of June 30, 1999 or the effective date of a new multi-
year agreement; (2) base rates, which cover the cost of the local distribution
system, will remain frozen for all customers at their current levels (which were
fixed at the July 1994 level pursuant to the 1995 settlement), while the Gas
Cost Adjustment will continue to vary from month to month; (3) a level of
revenues ($11.9 million on an annual basis) which corresponds to RG&E's
anticipated revenues from capacity remarketing transactions currently in place
is imputed to RG&E; (4) RG&E is entitled to retain 15% of the savings realized
from the reduction of capacity commitments; (5) RG&E will simplify the
transportation gas program and cap the migration of customers at 10% of annual
retail sales and not assign capacity costs to certain migrating customers (see
discussion of March 24, 1999 PSC order below); (6) RG&E will be allowed to
recover the upstream costs that may be stranded by migration; and, (7) certain
issues relating to past gas costs have been resolved whereby RG&E shall set
aside, in a manner to be determined by the PSC for the benefit of customers,
$2.2 million of the total amount recovered through the Gas Cost Adjustment.
RG&E, the PSC Staff and other parties have been engaged in discussions,
based on RG&E's August 1998 comprehensive proposal and the PSC's Gas Policy
Statement, to achieve a comprehensive, multi-year settlement. RG&E's objective
was to have a comprehensive final settlement in place prior to July 1, 1999.
However, negotiations for a comprehensive final settlement have not proceeded as
quickly as originally planned. At this time, RG&E is continuing to pursue
negotiations (which are currently suspended) with the PSC staff and other
interested parties.
On September 14, 1999, RG&E filed a proposal with the PSC to address issues
pertaining to the cost of upstream capacity and other matters pertaining to
restructuring pursuant to the PSC's Policy Statement. The proposal calls for:
(1) a continued reduction in capacity costs of $11.9 million, comprised of $10.2
million relating to upstream capacity release transactions for the period
September 1, 1999 through August 31, 2000 and $1.7 million from the expiration
of a Texas Eastern capacity contract; (2) a report to PSC staff, within 60 days
of approval of the proposal, of the progress RG&E has made to reduce its
upstream capacity costs; (3) a resumption of the multi-year settlement
discussions calling for RG&E to make a public filing of the rate and
restructuring issues addressed in the PSC's Policy Statement within 120 days of
approval of the proposal; and (4) RG&E continuing to work on retail access
program improvements. By a single-Commissioner Order issued September 30, 1999,
the PSC approved the September 14 proposal. On October 27, 1999 that Order was
confirmed by the full PSC. RG&E will proceed with implementation of the
proposal. The deadlines referred to in the proposal run from the September 30th
date.
Settlement negotiations pertaining to RG&E's gas rate and restructuring
proposal will begin as early as 30 days after the filing pursuant to the Policy
Statement.
Under a March 1996 Order, the PSC permitted RG&E and other gas distribution
companies to assign to marketers the pipeline and storage capacity held by RG&E
to serve their customers. In its Gas Policy Statement issued in November 1998,
the PSC ordered that the mandatory assignment of capacity, permitted by the
March 1996 Order, be terminated effective April 1, 1999. According to the Gas
Policy Statement, however, the utilities are to be afforded a reasonable
opportunity to recover resulting strandable costs, if any. RG&E complied with
the PSC's
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directive to remove mandatory assignment of capacity through its compliance
filing made for the Interim Settlement Agreement. However, on March 24, 1999,
the PSC issued an Order Concerning Assignment of Capacity for all gas utilities
in the State of New York, stating that all companies must file tariff revisions
in accordance with the general conclusions stated in the order. In most
instances, RG&E's current tariff is in compliance with the order. The order,
however, states that all LDCs shall remove all restrictions and place no
limitation on the level of migration, except as may be negotiated. For RG&E's
tariff, a modification has been made to remove the ten percent migration cap as
of July 1, 1999. Any further discussion of migration caps will likely be part of
the comprehensive multi-year settlement negotiations.
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 1998 Form 10-K, Item 7 under
Rates and Regulatory Matters.
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 1999, RGS ENERGY's and RG&E's cash flow
from operations (see Consolidated Statement of Cash Flows) provided the funds
for construction expenditures and the payment of dividends and short-term debt.
Operating cash flow was lower in the first nine months largely due to a change
in unbilled revenues receivable and accounts receivable. Because December 1998
was substantially warmer than December 1997, receivables at the end of 1998 were
lower than at year-end 1997. This resulted in a net decrease in working capital
for the 1999 nine-month period when compared to the 1998 nine-month period.
Cash used for investing activities was lower due to the acquisition of Griffith
in August 1998 and there were no acquisitions of comparable size in 1999. Cash
used in financing activities was lower due to redemption of long-term debt in
1998 and by the repurchase of common stock. Capital requirements during the
first nine months of 1999 were satisfied primarily from internally generated
funds. The Company completed a long-term financing in October 1999 (see
"Financing" below).
CAPITAL AND OTHER REQUIREMENTS. RGS ENERGY'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. Currently, RG&E has no
plans to install additional baseload generation.
RGS ENERGY's total 1999 capital requirements are currently estimated at
$124 million, of which $114 million is for construction and $10 million is for
sinking fund obligations. Approximately $79 million had been expended for
construction as of September 30, 1999, reflecting primarily RG&E's expenditures
for nuclear fuel and upgrading electric transmission and distribution facilities
and gas mains. RG&E's portion of the $124 million estimate is $121 million.
FINANCING. On October 27, 1999 RG&E issued $100 million of 7.60% First
Mortgage Bonds, Designated Secured Medium-Term Notes, Series B. The net
proceeds from this financing are being used to repay short-term debt and pay for
capital expenditures and maturing long term debt.
RG&E generally utilizes its credit agreements and unsecured lines of credit
to meet any interim external financing needs prior to issuing any long-term
securities. (See Form 10-K for the fiscal year ended December 31, 1998, Item 8.
Note 9, Short-Term Debt, regarding RGS ENERGY's and RG&E's short-term borrowing
arrangements and limitations.)
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REDEMPTION OF SECURITIES. On September 1, 1999, the Company redeemed,
pursuant to a mandatory sinking fund, 100,000 shares of 7.65% Preferred Stock,
Series U, at $100 per share.
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 has repurchased 2,538,600 shares of Common Stock for approximately
$74.0 million through September 30, 1999. The average cost per share purchased
during the first nine months of 1999 was $26.75. RGS ENERGY expects to continue
the program for the repurchase of RGS ENERGY shares through the year 2000.
YEAR 2000 READINESS INFORMATION. As the year 2000 (Y2K) approaches, RG&E,
like most companies, faced potentially serious information and operational
systems (computer and microprocessor-based devices) problems because many
software applications and embedded systems programs created in the past will not
properly recognize calendar dates beginning with the year 2000 or that the year
2000 is a "leap-year".
RG&E identified the need to address Y2K issues early and in June 1996
established the Y2K Project (Y2K Project). Resources from across the enterprise
were committed to the Y2K Project. RG&E had assigned approximately 40 full-time
equivalent people to work on the Y2K Project as well as retaining certain
outside consultants to assist in the inventory, assessment, and certification of
date-aware devices. RG&E is funding its Y2K Project internally and estimates
it will incur between $10 to $12 million of incremental costs through January 1,
2000, associated with making the necessary modifications identified to date to
applications ($9-11 million) and devices ($1 million). This projection included
replacement systems that may be required and represents 25% of the Corporate
Information Technology (IT) budget. RG&E has not deferred any other major IT
project due to this effort. RG&E has incurred approximately $8.7 million of
its $10-12 million total costs through September 30, 1999. RG&E is also
participating in the Y2K activities of several organizations such as the New
York Power Pool and the North American Electric Reliability Council. In
addition RG&E is a member of the Electric Power Research Institute which has
developed an on-line database inventory that reports Y2K assessment and test
results for devices and software used by other utilities.
The Y2K Project is divided into five primary phases, a detailed discussion of
which is given in the following paragraphs. It should be noted that all five
phases may be occurring at any given time, due to grouping of work. The first
phase is the inventory phase which was the identification of internally
developed applications, devices, vendor applications and critical external
parties including customers, suppliers, business partners, government agencies,
and financial institutions. During the next phase, the assessment phase, the Y2K
Readiness of the items was determined. Year 2000 Readiness is defined as a
computer system, device or application that has been determined to be suitable
for continued use into the Year 2000 even though the computer system or
application is not fully Y2K compliant. The third phase, fix, is when
replacement or remediation of the items is performed. The fourth phase is the
test phase, when the items are functionally verified and date tested. The final
phase is the contingency phase when contingency plans are developed for all
critical applications, devices and systems.
Phase 1, Inventory. The Y2K Project has completed the inventory phase. RG&E
has prioritized external critical parties and is independently verifying the
most critical of these by various methods, such as mandatory written
verification to RG&E of their status or by testing transfer of electronic data.
Phase 2, Assessment. The Y2K Project has completed assessment of
internally developed applications, critical devices, vendor applications,
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suppliers and fiduciaries. Results of these assessments have been given to the
Business Areas for further action.
Phase 3, Fix. The fix phase activities of the Y2K project for mission
critical (i.e. those required to deliver energy and energy services to customers
reliably and safely) internally developed applications is 100% complete and for
critical devices is 100% complete. As part of this phase the customer
information and billing system is Y2K ready, and starting in April 1998 RG&E
has been replacing its PC workstations and software with Y2K-ready equipment and
software. As facility maintenance outages occurred, Y2K critical device
replacement/modifications were performed. This effort was completed by June 30,
1999. Critical devices are those which are important to the safe and continuous
delivery of energy and energy related services to RG&E's customers.
Phase 4, Testing. RG&E successfully completed the testing of mission
critical applications, devices, and systems by June 30, 1999. Testing included
critical systems at RG&E's two major electric power plants, Ginna and Russell
Stations. Both plants performed without any difficulties when setting the
calendar past 2000. In addition, similar work and testing has been performed on
the statewide and on regional power systems so that computer systems important
to energy delivery will be ready.
Phase 5, Contingency Planning. RG&E has in place a Business Recovery
Plan describing alternative processes and procedures to ensure the integrity of
its energy and financial systems. The Business Recovery Plan served as a
starting point for Y2K contingency plans. Contingency planning commenced in
October 1998 and was completed in June 1999. RG&E's most reasonably likely
worst case scenario would be the simultaneous loss of energy system monitoring,
coupled with the failure of a major energy supplier. RG&E's contingency plan
provides for backup of its energy monitoring system in the event that its
primary system is inoperable. RG&E is capable of operating its electric system
in the event of a failure of a major electric supplier. A failure from a major
gas supplier may impact gas service. RG&E has arranged for appropriate staff
coverage to manage potential contingencies, as needed. If necessary, RG&E
would activate established emergency procedures, including procuring additional
supply and/or reapportioning the available supply to assist residential
customers. RG&E has received certificates of compliance from all of its
critical third parties, including its electric and gas suppliers. Contingency
planning efforts have involved participation from all key Company areas. In
1999, two `drills' were held, in conjunction with other New York State
utilities, to test readiness status and procedures for the Year 2000 rollover.
The first drill, which tested the ability to effectively respond to simulated
conditions involving the loss of primary communications, was successfully
completed on April 9, 1999. The second drill occurred on September 9, 1999.
This drill tested equipment that backs up Y2K-related communication tools. The
drill also posed simulated operational problems that could occur any time of the
year, involving electric and gas distribution systems and power plants. It also
included a simulated lightning storm which caused New Year's power outages at
the same time. In all cases, employees responded with timely recovery actions
using established contingency and emergency plans.
All activities in support of mission critical systems were completed by
July 1999, as required by the PSC. Likewise, RG&E has met the July 1999
completion criteria set by the NRC for RG&E's Ginna facility. While no
absolute guarantees of continuous energy delivery can ever be provided, about
200 key personnel will be working a 10-hour shift at RG&E beginning at 10 p.m.
December 31 to monitor the rollover to the year 2000 and deal with any problems
that might occur.
Energetix, RGS ENERGY's wholly owned subsidiary, including its recently
29
<PAGE>
acquired Griffith, estimates the cost of making the necessary modifications
identified to date to be less than $100,000, 50% of which relate to devices and
50% to applications. The cost represents approximately 50% of the Energetix IT
budget, but no major IT projects have been deferred due to Y2K. Most of its
systems, personal computers and operating equipment are less than seven years
old. Energetix identified items that were the most vulnerable to the Y2K
problem and, after assessing, fixing and testing, these items were Y2K-ready as
of November 1, 1999. A Scenario Risk Analysis has also been completed. Energetix
has a Business Recovery Plan, which will serve as the basis for Y2K contingency
plans as required. Energetix has surveyed critical third parties independently
of RG&E, to assess their degree of Y2K readiness and, where appropriate, has
developed contingency plans to ensure the integrity of its operational and
financial systems. Energetix has prioritized these critical parties and
independently evaluated the most critical of these by various methods, such as
mandatory verification of their status or testing transfer of information.
EARNINGS SUMMARY
The impact of developing competition in the energy marketplace may affect
future earnings. The Competitive Opportunities Settlement allows for a phase-in
to open electric markets while lowering customer prices and establishing an
opportunity for competitive returns on shareholder investments. The nature and
magnitude of the potential impact of the Settlement on the business of RG&E will
depend on several factors, including the availability of qualified energy
suppliers in RG&E's service territory, the degree of customer participation and
ultimate selection of an alternative energy supplier, RG&E's ability to be
competitive by controlling its operating expenses, and RG&E's ultimate success
in the development of its unregulated business opportunities as permitted under
the Settlement.
Although under the current regulatory environment RG&E does not earn a
return on the gas commodity it acquires for distribution, future earnings may
also be affected, in part, by the ultimate outcome of implementation of the
November 1998 Gas Policy Statement (see Rates and Regulatory Matters). That
policy statement concludes that the most effective way to establish a robust
competitive gas supply in New York State is for LDCs, such as RG&E, to exit the
merchant function of acquiring gas, as well as transportation and storage
capacity to serve retail customers. LDCs ceased assigning transportation
capacity to customers migrating from sales to transportation service by April 1,
1999. The nature and magnitude of the potential impact of these policies will
depend on individual negotiations that RG&E is undertaking with the PSC Staff
and other interested parties on RG&E specific restructuring, as well as a number
of Statewide collaborative efforts that will deal with such issues as provider
of last resort, reliability, recovery of stranded costs, and market power as the
transition is made to a more competitive gas business.
RGS ENERGY:
- -----------
RGS ENERGY reported earnings for the third quarter of this year that were
lower than the third quarter of 1998 but in-line with internal expectations.
Assuming normal weather for the fourth quarter of this year, the Company expects
1999 earnings to be somewhat better than last year. RGS ENERGY reported
consolidated earnings of $0.44 for the third quarter ended September 30, 1999
compared to $0.62 per share for the same period in 1998. Consolidated earnings
for the nine-month period were $1.79 in 1999 compared to $1.94 in 1998. The per
share decrease in earnings, for both periods, reflect the lower levels of profit
realized in the regulated electric segment (see Note 2 of the Notes to Financial
Statements) due to increased purchased power expenses and decreased sales of
30
<PAGE>
electricity to other utilities.
Third quarter 1999 earnings were anticipated to be lower than last year
due to assumed normal weather, scheduled rate reductions and increased purchase
power costs arising from industry restructuring. Actual third quarter results
reflect warmer summer weather offset by costs associated with an unscheduled
outage at Nine Mile Two.
The fourth quarter of 1998 was negatively affected by warmer weather,
Ginna refueling costs and other non-recurring costs. In December 1998, RG&E
began accruing expenses for the 1999 Ginna plant refueling outage on a monthly
basis. This resulted in a non-recurring $9 million charge in the fourth quarter
of 1998 covering the prior months that will not recur in the fourth quarter of
1999. Future costs are being accrued on a monthly basis over the 18-month
cycle.
Year to date results were effected by the same issues previously
discussed regarding the third quarter. In addition, year-to-date results
reflect a scheduled refueling and ten-year in-service inspection outage at the
Ginna Nuclear Plant from March 1, 1999 to April 26, 1999. There was no outage
at the Ginna Plant in 1998. A one-time accounting adjustment of approximately
$7 million was recorded in the second quarter to increase RGS ENERGY's reserve
for uncollectible accounts. Also, sales and revenues in 1999 reflect a one-time
accounting adjustment during the second quarter of the year in the methodology
for calculating unbilled sales and revenues which increased electric revenues by
$7.1 million and gas revenues by $6.1 million. Earnings per share were
positively affected by the Company's share buy-back program and higher gas
revenue in the first quarter of 1999 due to 19% colder weather as compared to
1998.
RGS ENERGY continues to grow its unregulated business through its
subsidiary, Energetix, which provides electric, natural gas, and petroleum-based
energy products and services throughout the upstate New York region. Energetix
total operating revenues were $186 million for the first nine months of 1999, of
which sales from Griffith's heating oil, gasoline and propane gas contributed
approximately $148 million. Energetix and Griffith, on a consolidated basis,
had a pre-tax loss of $1.9 million for the third quarter and a pre-tax loss of
$0.8 million for the nine-month period ended September 30, 1999. These results
continue to reflect the cyclical effect of the Griffith heating oil business,
and the development expenses related to building a successful unregulated
electric and natural gas business in an open and competitive market.
RG&E:
- -----
Earnings for RG&E in both periods reflect the same issues discussed above
for RGS ENERGY except that discussions relating to Energetix and Griffith and
RGS ENERGY's share buy-back program are not applicable.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses for RGS ENERGY (regulated and
unregulated business) and RG&E (regulated business), comparing the three-month
and nine-month periods ended September 30, 1999 to the respective three-month
and nine-month periods ended September 30, 1998. 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 ENERGY'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 ENERGY.
31
<PAGE>
THREE MONTHS ENDED SEPT. 30, 1999 COMPARED TO THREE MONTHS ENDED SEPT. 30, 1998
- -------------------------------------------------------------------------------
OPERATING REVENUES AND SALES. In the third quarter total regulated
revenues decreased 2.0% reflecting mainly lower gas cost adjustment revenues.
Electric operating revenues were relatively unchanged from a year earlier.
Together, retail electric sales and sales to energy marketers were up 4.2% in
the current quarter reflecting 25% warmer summer weather than a year ago. The
benefit of these higher sales, however, was offset by a drop in sales to other
utilities driven by an unscheduled outage at Nine Mile Two from June 24 to July
24 and the effect of an electric rate decrease effective July 1. Unregulated
sales reflect Griffith's acquisition on August 2, 1998 and the migration of
electric and gas customers from the regulated to the unregulated business.
Beginning on July 1, up to an additional 10% of regulated electric retail load
became eligible to choose competitive suppliers, including Energetix.
Energetix began formal operations in the first quarter of 1998 and
acquired Griffith, as a subsidiary, in August 1998. Griffith's liquid fuels
energy business extends beyond RG&E's regulated distribution service territory
and provides a platform upon which to develop the unregulated electric and
natural gas business. Energetix total operating revenues were $71 million for
the third quarter of 1999, of which approximately $57 million was from the sale
of heating oil, propane and gasoline by Griffith.
OPERATING EXPENSES. Higher regulated fuel expenses reflect increased
purchased electricity costs due to an increase in the cost per unit purchased,
in addition to the effect from lower generation from the Company's hydro plants
and Russell Station, and the closing of Beebee Station on April 30, 1999. Non-
fuel O&M expenses for the regulated business increased $6.3 million, driven by
Ginna refueling expenses, higher payroll and benefit costs and site remediation
costs.
Unregulated non-fuel O&M reflects primarily payroll expenses, fleet
expenses for Griffith, and general and administrative expenses.
Local, State and other taxes for RGS ENERGY and RG&E declined reflecting a
New York State Use tax audit refund, lower tax rates for State and local revenue
taxes and lower property taxes due to decreased assessments partially offset by
higher unbilled revenue taxes resulting from an increase in unbilled revenues.
The difference in Federal income tax is attributable to pre-tax earnings.
OTHER STATEMENT OF INCOME ITEMS. The change in RGS ENERGY's and RG&E's
Other Income and Deductions, Other-net reflect mainly the recognition of income
in 1998 due to the elimination of certain pension deferred credits and Nine Mile
Two operating and maintenance expenses in accordance with the Competitive
Opportunities settlement, partially offset by non-cash carrying charges related
to deferral of Kamine (Allegany Station) facility costs in 1999 for the
regulated business. These carrying charges, which are primarily associated with
the deferred recovery of costs associated with the Kamine settlement (see
following paragraph), were allowed under the Competitive Opportunities and
Kamine settlements.
The increase in RGS Energy's interest charges reflect mainly an increase
of approximately $140 million in long-term debt outstanding, resulting mainly
from the Kamine settlement and the acquisition of Griffith by Energetix. The
increase in RG&E's interest charges reflect mainly an increase in long-term debt
as a result of the Kamine Settlement.
32
<PAGE>
NINE MONTHS ENDED SEPT. 30, 1999 COMPARED TO NINE MONTHS ENDED SEPT. 30, 1998
- -----------------------------------------------------------------------------
OPERATING REVENUES AND SALES. Increased electric revenues for RGS ENERGY
and RG&E reflect the warmer summer weather for the current quarter as discussed
above partially offset by a base rate reduction and lower regulated electric
sales due largely to RG&E's reduced capacity to sell power to other electric
utilities because of a refueling and in-service inspection outage at the Ginna
Plant as discussed above under "RGS Energy" and the unscheduled outage at Nine
Mile Two as previously discussed under "Earnings Summary". Regulated sales and
revenues for this period compared to last year also reflect a one-time
accounting adjustment to reflect a change in the estimating process for unbilled
sales and revenues. This adjustment increased regulated electric revenues by
$7.1 million and increased regulated gas revenues by $6.1 million.
Regulated gas margins (revenues less cost of purchased gas) were up over
$14 million reflecting 17% cooler weather and the change in unbilled sales
methodology discussed above.
Eighty percent of Energetix total operating revenues in 1999 were from the
sale of heating oil, propane and gasoline by Griffith (see discussion under
"Earnings Summary").
OPERATING EXPENSES. The increase in operating expenses for RGS ENERGY and
RG&E includes a June 1999 increase in the uncollectible reserves of
approximately $7 million. In addition, $1.2 million was accrued during the
current quarter for the next Ginna Station refueling outage (late Year 2000).
Payroll expense for RGS ENERGY and RG&E was up due to a wage increase and
severance packages associated, in part, with the closing of Beebee Station. Site
remediation expenses and services in connection with an enhanced customer record
keeping system also increased O&M expense. Depreciation expense for both
companies in 1999 includes an incremental one-time charge in the second quarter
of approximately $2.1 million associated with the closing of Beebee Station in
April 1999.
Local, State and other taxes for RGS ENERGY and RG&E declined for the
reasons discussed earlier for the quarterly comparison. The difference in
federal income tax expense reflects pre-tax earnings and the settlement of
audits in the first quarter of 1998.
OTHER STATEMENT OF INCOME ITEMS. The same factors described in the
quarterly comparison for changes in RGS ENERGY's and RG&E's Other Income and
Deductions, Other-net also affected the nine month results.
RGS ENERGY's and RG&E's interest charges increased for the same reasons
described in the quarterly comparison except, regarding RGS ENERGY, the interest
from unregulated operations increased approximately $1.3 million.
DIVIDEND POLICY
On September 15, 1999, the Board of Directors of both RG&E and RGS ENERGY
authorized a common stock dividend of $.45 per share, which was paid on October
25, 1999 to shareholders of record on October 4, 1999. The ability of RGS ENERGY
to pay common stock dividends is governed by the ability of RGS ENERGY's
subsidiaries to pay dividends to RGS ENERGY. Because RG&E is by far the largest
of the subsidiaries, it is expected that for the foreseeable future the funds
required by RGS ENERGY to enable it to pay dividends will be derived
predominantly from the dividends paid to RGS ENERGY by RG&E. In the future,
dividends from subsidiaries other than RG&E may also be a source of funds for
33
<PAGE>
dividend payments by RGS ENERGY. RG&E's ability to make dividend payments to
RGS ENERGY will depend upon the availability of retained earnings and the needs
of its utility business. The level of future cash dividend payments on Common
Stock will be dependent upon RGS ENERGY's future earnings, its financial
requirements, and other factors.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.
RGS ENERGY is exposed to interest rate and commodity price risks.
The interest rate risk relates to new debt financing needed to fund capital
requirements, including maturing debt securities, and to variable rate debt.
The Company 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 the RGS ENERGY's long-term debt consists of
long-term Promissory Notes, the interest component of which resets on a periodic
basis reflecting current market conditions. RGS ENERGY was not participating in
any derivative financial instruments for managing interest rate risks as of
September 30, 1999 or December 31, 1998.
The commodity price risk relates to natural gas in storage and other
petroleum-related products used for resale to customers. RGS ENERGY primarily
enters into forward contracts for natural gas through its gas broker. In
addition, Griffith enters into various exchange-traded futures and option
contracts and over-the-counter contracts with third parties. The commodity
instruments are designated at the inception as a hedge where there is a direct
relationship to the price risk associated with RGS ENERGY's inventory or future
purchases and sales of commodities used in the RGS ENERGY's operations. At
September 30, 1999 and December 31, 1998 neither the fair value of the contracts
outstanding nor potential, near-term contract losses from reasonably possible
near-term changes in market prices were material to the financial position,
results of operations or liquidity of RGS ENERGY.
For information about RGS ENERGY's primary market risks associated with
activities in derivative financial instruments, other financial instruments and
derivative commodity instruments, see Item 8, of RG&E's 1998 Form 10-K
under "Financial/Commodity Instruments" in Note 1 of the Notes to Financial
Statements.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to "Company-Owned Waste Site Activities" and "Manufactured
Gas Sites" in Part I, Item 3, Legal Proceedings in the RG&E 1998 Form 10-K.
RG&E and its predecessors formerly owned and operated five manufactured
gas facilities. At one site, located in the Rochester area known as East
Station, RG&E previously reported that a supplemental remedial investigation and
feasibility study was expected to be completed in third quarter 1999. Due to
unexpected delays and an expansion of project scope, the work is continuing and
is expected to be completed early in 2000.
It was previously reported that the Company is conducting proactive site
investigation and remediation activities at seven Company-owned sites where past
waste handling and disposal may have occurred. At one of those sites (Pavilion)
the Company has decided to pursue a phase 2 investigation even though a
34
<PAGE>
preliminary phase 1 investigation failed to reveal the presence of hazardous
substances. This decision is due solely to the nature of past activities as
opposed to any present knowledge of evidence of residuals. Remediation
activities at the remaining six sites are in various stages of planning.
For further 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.
A report was filed on Form 8-K dated August 2, 1999 under Item 5 -Other
Events, describing the reorganization of RG&E into a holding company
structure effective August 2, 1999, pursuant to an Agreement and Plan
of Share Exchange.
Rochester Gas and Electric Corporation
No reports of Form 8-K were filed during the quarter.
EXHIBIT INDEX
Exhibit 10* RGS ENERGY GROUP, INC. Executive Incentive Plan Restatement as of
January 1, 1999.
Exhibit 27-A Financial Data Schedule pursuant to Item 601 (c) of
Regulation S-K for RGS Energy Group, Inc.
Exhibit 27-B Financial Data Schedule pursuant to Item 601 (c) of
Regulation S-K for Rochester Gas and Electric Corporation.
* Denotes executive compensation plan and arrangement
35
<PAGE>
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 12, 1999 By /s/ J.B. STOKES
--------------------------------------
J. Burt Stokes
Senior Vice President and
Chief Financial Officer
Date: November 12, 1999 By /s/ WILLIAM J. REDDY
---------------------------------------
William J. Reddy
Vice President and Controller
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: November 12, 1999 By /s/ J.B. STOKES
---------------------------------------
J. Burt Stokes
Senior Vice President, Corporate Services
and Chief Financial Officer
Date: November 12, 1999 By /s/ WILLIAM J. REDDY
---------------------------------------
William J. Reddy
Vice President and Controller
36
<PAGE>
Exhibit 10
RGS ENERGY GROUP, INC.
EXECUTIVE INCENTIVE PLAN
Restatement as of January 1, 1999
---------------------------------
I. Synopsis of Plan
----------------
This Plan seeks to promote and balance the interests of ratepayers,
shareholders and employees by linking compensation to specific corporate and
organizational/individual objectives in such a way that an employee's total
compensation will increase when goals are reached or exceeded and will decrease
when goals are not met. The Plan is an annual cash incentive plan that pays
benefits in any year when the Company achieves or exceeds annual business plan
objectives. Benefits will be paid to each eligible employee based on the
achievement of a combination of corporate and organizational/individual
objectives. Corporate performance is measured on target objectives for the year
that relate to shareholder, customer and employee satisfaction. The weightings
for each of the corporate objectives may vary from year to year.
Organizational/individual objectives for the year will be specific to each
eligible employee. Weightings of the combined corporate and
organizational/individual objectives are based on an employee's position in the
Company.
II. Purpose
-------
The purpose of this Plan is to provide an incentive to key employees to
meet and exceed certain specified goals as part of the RGS cash compensation
program. This restatement of January 1, 1999, amends and continues the Plan
originally adopted as of January 1, 1992, and last restated as of January 1,
1995.
-1-
<PAGE>
III. Definitions
-----------
(a) "Board" means the Board of Directors of the Company or the Committee
on Management of the Board.
(b) "Company" means RGS Energy Group, Inc. or it successor.
(c) "Corporate Objective" means the business plan objectives adopted by
the Board each year in areas that the Board, in it sole discretion, may
determine such as, but not limited to, customer, shareholder and employee
satisfaction.
(d) "Employee" means an individual employed by a Participating Company in
a position other than as an independent contractor.
(e) "Financial Objective" means the Cash Flow Return on Net Assets
objective established by the Company each year.
(f) "Participant" means an Employee who participates in this Plan.
(g) "Participating Company" means the Company and any affiliate of the
Company whose employees are, with the consent of the Board, eligible to
participate in this Plan.
(h) "RONA" means the Company's cash flow return on net assets.
(i) "Target Award" means the amount or percentage payable when 100% of all
objectives have been achieved on average.
IV. Eligibility
-----------
Eligibility for participation in the Plan shall include any Employee
holding a position of CEO, Senior Executive, Vice President or Senior Manager
plus any Manager who is selected at the discretion of the Senior Management
group.
-2-
<PAGE>
V. Corporate Objectives
--------------------
Each year the Board will review the Corporate Objectives recommended for
the upcoming Plan year, including one or more factors that will be used to
measure each of the Corporate Objectives. The weighting of each of the
Corporate Objectives each year shall be established in the Board's sole
discretion.
VI. Organizational/Individual Objectives
------------------------------------
The Board shall determine the individual components, if any, for the
Chairman of the Board, and the Chairman shall review and approve all other
organizational/individual awards.
VII. Awards
------
A Participant's award depends on whether the Plan's annual objectives have
met the Target Award or are above or below such Target Award and on the
weighting of Corporate Objectives and organizational/individual objectives, all
according to the following table:
<TABLE>
<CAPTION>
Incentive Award* Incentive Weighting
---------------- -------------------
Tiers Position Threshold Target Superior Corp. Org./Ind.
----- -------- --------- ------ -------- ----- ---------
<S> <C> <C> <C> <C> <C> <C>
I CEO 15% 30% 60% 80% 20%
II Sr. Executives 12% 25% 45% 60% 40%
III VP 10% 20% 40% 50% 50%
IV Sr. Managers 8% 15% 35% 40% 60%
V Managers 6% 12% 25% 30% 70%
</TABLE>
* Participant's Incentive Awards are calculated based upon the above table and
are applied to the participant's annualized salary at the end of the Plan
year.
-3-
<PAGE>
An Employee who is not a Plan Participant for a full calendar year shall
receive a pro rata portion of a full year's award based on the rate that his/her
full months of service as a Participant bears to 12 if the change in
participation is a result of his/her being a new hire, his/her retirement, death
or promotion. If a Participant voluntarily or involuntarily terminates
employment or is demoted during a year, the Board may, in its sole discretion,
direct payment of any amount from zero to a pro rata award based on his/her
months of service as a Participant prior to termination or demotion.
VIII. Payment of Awards
-----------------
A Participant's award, if any, for a calendar year will be paid in cash
during the first quarter of the following year unless deferred and paid under
the Company's Deferred Compensation Plan of 1993. Participants may elect to
defer up to 100% of any award to be paid. Elections to defer compensation must
be made before the compensation is earned.
IX. Participant's Rights
--------------------
This Plan constitutes a contractual obligation on the part of a
Participating Company, and a Participant acquires the right of an unsecured
general creditor of a Participating Company. No trust or fund of any kind is
created by reason of this Plan. Participation in this Plan shall not be
construed as giving any Participant the right to be retained in a Participating
Company's employ or the right to receive any benefits not specifically provided
by the Plan.
The rights of a Participant to any payment under this Plan shall not be
assigned, transferred, pledged, encumbered or be subject in any manner to
alienation or anticipation.
-4-
<PAGE>
X. Administration
--------------
This Plan shall be administered by the Committee on Management of the Board
which shall possess the authority (i) to determine eligibility to participate in
the Plan and eligibility to receive benefits, (ii) to delegate its authority,
(iii) to adopt rules and regulations for carrying out the Plan and (iv) to
interpret, construe and implement the provisions of the Plan and any decision or
interpretation of any provision of the Plan by such Committee or its delegate
shall be final and conclusive.
XI. Amendment and Termination
-------------------------
The Plan may, at any time and from time to time, be amended, modified or
terminated by the Board. The Board may eliminate or award payments in any year
due to special circumstances and, in its sole discretion, change the time for
payment of any Plan benefit.
XII. General Provisions
------------------
(a) All expenses of administering the Plan shall be borne by the Company.
(b) To the extent required by law, the Company shall withhold taxes from
any payments made under the Plan.
(c) Except to the extent superseded by federal law, the laws of the State
of New York shall be controlling in all matters relating to the Plan.
-5-
<PAGE>
IN WITNESS WHEREOF, RGS Energy Group, Inc. has caused its duly authorized
executive to sign this Plan this 27th day of September 1999, effective as of
January 1, 1999.
RGS ENERGY GROUP, INC.
By /s/ Thomas S Richards
----------------------------------
Title President
--------------------------------
-6-
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from consolidated
balance sheet, consolidated statement of income and consolidated statement of
cash flows and is qualified in its entirety by reference to such financial
statements.
</LEGEND>
<CIK> 0001073353
<NAME> RGS ENERGY GROUP, INC.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,543,271
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 198,601
<TOTAL-DEFERRED-CHARGES> 670,574
<OTHER-ASSETS> 21,460
<TOTAL-ASSETS> 2,433,906
<COMMON> 389
<CAPITAL-SURPLUS-PAID-IN> 625,885
<RETAINED-EARNINGS> 145,523
<TOTAL-COMMON-STOCKHOLDERS-EQ> 771,797
25,000
47,000
<LONG-TERM-DEBT-NET> 480,053
<SHORT-TERM-NOTES> 59,840
<LONG-TERM-NOTES-PAYABLE> 240,024
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 33,936
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 776,256
<TOT-CAPITALIZATION-AND-LIAB> 2,433,906
<GROSS-OPERATING-REVENUE> 881,750
<INCOME-TAX-EXPENSE> 43,992
<OTHER-OPERATING-EXPENSES> 733,024
<TOTAL-OPERATING-EXPENSES> 774,812
<OPERATING-INCOME-LOSS> 106,938
<OTHER-INCOME-NET> 6,217
<INCOME-BEFORE-INTEREST-EXPEN> 110,951
<TOTAL-INTEREST-EXPENSE> 41,977
<NET-INCOME> 68,974
3,158
<EARNINGS-AVAILABLE-FOR-COMM> 65,816
<COMMON-STOCK-DIVIDENDS> 49,442
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 173,882
<EPS-BASIC> 1.79
<EPS-DILUTED> 1.79
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from consolidated
balance sheet, consolidated statement of income and consolidated statement of
cash flows and is qualified in its entirety by reference to such financial
statements.
</LEGEND>
<CIK> 0000084557
<NAME> ROCHESTER GAS AND ELECTRIC CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,523,364
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 182,630
<TOTAL-DEFERRED-CHARGES> 670,417
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,376,411
<COMMON> 194,429
<CAPITAL-SURPLUS-PAID-IN> 431,845
<RETAINED-EARNINGS> 128,112
<TOTAL-COMMON-STOCKHOLDERS-EQ> 754,386
25,000
47,000
<LONG-TERM-DEBT-NET> 480,053
<SHORT-TERM-NOTES> 53,345
<LONG-TERM-NOTES-PAYABLE> 220,573
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 30,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 766,054
<TOT-CAPITALIZATION-AND-LIAB> 2,376,411
<GROSS-OPERATING-REVENUE> 841,245
<INCOME-TAX-EXPENSE> 44,491
<OTHER-OPERATING-EXPENSES> 691,574
<TOTAL-OPERATING-EXPENSES> 733,847
<OPERATING-INCOME-LOSS> 107,398
<OTHER-INCOME-NET> 6,267
<INCOME-BEFORE-INTEREST-EXPEN> 111,447
<TOTAL-INTEREST-EXPENSE> 41,655
<NET-INCOME> 69,792
3,157
<EARNINGS-AVAILABLE-FOR-COMM> 66,635
<COMMON-STOCK-DIVIDENDS> 49,442
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 170,127
<EPS-BASIC> 1.81
<EPS-DILUTED> 1.81
</TABLE>
