<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 June 30, 2000
-------------
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
--------- ---------
<TABLE>
<CAPTION>
Commission Registrant, State of Incorporation I.R.S. Employer
File Number Address and Telephone Number Identification No.
----------- ---------------------------- ------------------
<S> <C> <C>
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
</TABLE>
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 July 31, 2000, (i) RGS Energy Group, Inc.
(RGS) had outstanding 35,060,113 shares of Common Stock ($.01 par value) and,
(ii) all of the outstanding shares of Common Stock ($5 par value) of Rochester
Gas and Electric Corporation (RG&E) were held by RGS.
RG&E meets the conditions set forth in General Instructions (H)(1)(a) and (b)
of Form 10-Q and is therefore, filing this form with the reduced disclosure
format pursuant to General Instructions (H)(2).
<PAGE>
INDEX
<TABLE>
<CAPTION>
Page No.
<S> <C>
PART I - FINANCIAL INFORMATION
RGS Energy Group, Inc.
Consolidated Balance Sheet - June 30, 2000 and
December 31, 1999.................................................................................. 1 - 2
Consolidated Statement of Income - Three Months and Six Months Ended
June 30, 2000 and 1999........................................................................... 3 - 4
Consolidated Statement of Cash Flows - Six Months Ended
June 30, 2000 and 1999........................................................................... 5
Rochester Gas and Electric Corporation
Balance Sheet - June 30, 2000 and December 31, 1999............................................... 6 - 7
Statement of Income - Three Months and Six Months Ended
June 30, 2000 and 1999........................................................................... 8 - 9
Statement of Cash Flows - Six Months Ended
June 30, 2000 and 1999........................................................................... 10
Notes to Financial Statements...................................................................... 11-16
Management's Discussion and Analysis of Financial
Condition and Results of Operations................................................................ 17-28
Quantitative and Qualitative Disclosures About
Market Risk..................................................................................... 28-29
PART II - OTHER INFORMATION
Legal Proceedings.................................................................................. 29
Exhibits and Reports on Form 8-K................................................................... 29-30
Signatures......................................................................................... 31
</TABLE>
____________
Filing Format
This Quarterly report on Form 10-Q is a combined quarterly report being filed by
two different registrants: RGS and RG&E. RGS became the holding company for RG&E
on August 2, 1999. Except where the content clearly indicates otherwise, any
references in this report to "RGS" includes all subsidiaries of RGS including
RG&E. RG&E makes no representation as to the information contained in this
report in relation to RGS and its subsidiaries other than RG&E.
<PAGE>
Abbreviations and Glossary
Company or RGS RGS Energy Group, Inc., a holding company formed August 2,
1999, which is the parent company of Rochester Gas and
Electric Corporation, RGS Development Corporation and
Energetix, Inc.
CWIP Construction work-in progress
RGS Development RGS Development Corporation, a wholly-owned subsidiary of
the Company
EITF Emerging Issues Task Force
Energetix Energetix, Inc., a wholly-owned subsidiary of the Company
Energy Choice A competitive electric retail access program of RG&E
being phased- in over a period ending July, 2001.
FERC Federal Energy Regulatory Commission
Ginna Plant Ginna Nuclear Plant wholly owned by RG&E
Griffith Griffith Oil Company, Inc ., an oil, gasoline and propane
distribution company acquired by Energetix in 1998
LDC Local Distribution Company
Nine Mile Two Nine Mile Point Nuclear Plant Unit No. 2 of which RG&E owns
a 14% share
NOI Notice of Inquiry
NOPR Notice of Proposed Rulemaking
NRC Nuclear Regulatory Commission
NYISO New York Independent System Operator
O&M Operation and Maintenance
PSC New York State Public Service Commission
RG&E Rochester Gas and Electric Corporation, a wholly-owned
subsidiary of RGS
SEC Securities and Exchange Commission
Settlement Competitive Opportunities Case Settlement among RG&E, PSC
and other parties which provides the framework for the
development of competition in the electric energy
marketplace through June 30, 2002
SFAS Statement of Financial Accounting Standards
<PAGE>
1
PART 1 - FINANCIAL INFORMATION
ITEM1. FINANCIAL STATEMENTS
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
Assets (Unaudited)
-------------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric $ 2,440,383 $ 2,399,532
Gas 461,240 453,634
Common 134,580 130,118
Nuclear 281,409 270,447
------------ -----------
3,317,612 3,253,731
Less: Accumulated depreciation 1,708,402 1,636,955
Nuclear fuel amortization 247,534 239,243
------------ -----------
1,361,676 1,377,533
Construction work in progress 108,074 95,862
------------ -----------
Net Utility Plant 1,469,750 1,473,395
------------ -----------
Current Assets
Cash and cash equivalents 19,961 8,288
Accounts receivable, net of allowance for doubtful accounts:
2000 - $34,129; 1999 - $34,026 94,389 90,239
Unbilled revenue receivable 38,938 58,005
Materials, supplies and fuels 37,888 38,206
Prepayments 25,852 24,576
Other current assets 1,958 523
------------ -----------
Total Current Assets 218,986 219,837
------------ -----------
Intangible Assets
Goodwill, net 12,905 13,894
Other Intangible Assets 10,827 7,338
------------ -----------
Total Intangible Assets 23,732 21,232
------------ -----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 238,389 220,815
Nine Mile Two deferred costs 27,681 28,206
Unamortized debt expense 17,353 17,984
Other deferred debits 12,355 13,137
Regulatory assets 437,759 466,231
Other assets 653 2,037
------------ -----------
Total Deferred Debits and Other Assets 734,190 748,410
------------ -----------
Total Assets $ 2,446,658 $ 2,462,874
------------ -----------
</TABLE>
<PAGE>
2
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
Capitalization and Liabilities (Unaudited)
--------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization
Long term debt - mortgage bonds $ 580,104 $ 580,070
- promissory notes 235,531 235,395
Affiliate preferred stock redeemable at option of Company 47,000 47,000
Affiliate preferred stock subject to mandatory redemption 25,000 25,000
Common shareholders' equity
Common stock
Authorized 100,000,000 shares; 38,885,813 shares
issued at June 30, 2000 and at December 31, 1999 700,803 700,268
Retained earnings 177,170 153,186
------------ -----------
877,973 853,454
Less: Treasury stock at cost (3,747,400 shares at June 30, 2000
and 2,942,600 shares at December 31, 1999) 100,905 83,252
------------ -----------
Total Common Shareholders' Equity 777,068 770,202
------------ -----------
Total Capitalization 1,664,703 1,657,667
------------ -----------
Long Term Liabilities
Nuclear waste disposal 94,376 91,743
Uranium enrichment decommissioning 11,158 10,911
Site remediation 23,152 23,698
------------ -----------
128,686 126,352
------------ -----------
Current Liabilities
Long term debt due within one year 7,972 37,643
Short term debt 11,750 10,500
Accounts payable 62,522 54,221
Dividends payable 16,731 17,078
Equal payment plan - 10,529
Other 74,642 39,385
------------ -----------
Total Current Liabilities 173,617 169,356
------------ -----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 282,097 318,694
Pension costs accrued 40,382 48,628
Kamine deferred costs 55,294 58,738
Post employment benefits 52,124 48,653
Other 49,755 34,786
------------ -----------
Total Deferred Credits and Other Liabilities 479,652 509,499
------------ -----------
Commitments and Other Matters - -
------------ -----------
Total Capitalization and Liabilities $ 2,446,658 $ 2,462,874
------------ -----------
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
3
RGS Energy Group Inc.
Consolidated Statement of Income
(Thousands of dollars)
(Unaudited)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
For the Three Months Ended
June 30,
2000 1999
------------ ------------
<S> <C> <C>
Operating Revenues
Electric $174,021 $174,911
Gas 57,253 53,675
Other 79,430 47,219
------------ ------------
Total Operating Revenues 310,704 275,805
Fuel Expenses
Fuel for electric generation 11,073 10,494
Purchased electricity 18,223 15,566
Gas purchased for resale 32,327 26,649
Other fuel expenses 73,225 41,406
------------ ------------
Total Fuel Expenses 134,848 94,115
------------ ------------
Operating Revenues Less Fuel Expenses 175,856 181,690
Other Operating Expenses
Operations and maintenance excluding fuel 67,965 80,931
Unregulated operating and maintenance expenses excluding fuel 6,822 5,647
Depreciation and amortizaton 29,220 31,722
Taxes - state, local & other 19,862 27,522
Income taxes 16,505 8,716
------------ ------------
Total Other Operating Expenses 140,374 154,538
------------ ------------
Operating Income 35,482 27,152
Other (Income) & Deductions
Allowance for other funds used during construction (188) (154)
Income taxes 864 888
Other - net 458 (2,271)
------------ ------------
Total Other (Income) & Deductions 1,134 (1,537)
------------ ------------
Income Before Interest Charges 34,348 28,689
Interest Charges
Long term debt 14,617 13,070
Other - net 1,738 1,044
Allowance for borrowed funds used during construction (302) (247)
------------ ------------
Total Interest Charges 16,053 13,867
------------ ------------
Dividends on Preferred Stock 925 1,116
------------ ------------
Net Income Applicable to Common Stock 17,370 13,706
------------ ------------
Average Number of Common Shares (000's)
Common Stock 35,379 36,769
Common Stock and Equivalents 35,439 36,870
Earnings per Common Share - Basic $ 0.49 $ 0.37
Earnings per Common Share - Diluted $ 0.49 $ 0.37
Cash Dividends Paid per Common Share $ 0.45 $ 0.45
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
4
RGS Energy Group Inc.
Consolidated Statement of Income
(Thousands of dollars)
(Unaudited)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Year To Date
June 30,
2000 1999
------------- ------------
<S> <C> <C>
Operating Revenues
Electric $353,805 $339,583
Gas 176,821 171,048
Other 165,929 91,265
------------- ------------
Total Operating Revenues 696,555 601,896
Fuel Expenses
Fuel for electric generation 22,037 22,013
Purchased electricity 36,438 28,323
Gas purchased for resale 96,264 87,370
Other fuel expenses 149,013 75,721
------------- ------------
Total Fuel Expenses 303,752 213,427
------------- ------------
Operating Revenues Less Fuel Expenses 392,803 388,469
Other Operating Expenses
Operations and maintenance excluding fuel 138,482 146,685
Unregulated operating and maintenance expenses excluding fuel 14,208 12,316
Depreciation and amortization 58,215 60,862
Taxes - state, local & other 49,688 58,877
Income taxes 43,039 32,579
------------- ------------
Total Other Operating Expenses 303,632 311,319
------------- ------------
Operating Income 89,171 77,150
Other (Income) & Deductions
Allowance for other funds used during construction (379) (383)
Income taxes 1,341 1,406
Other - net (717) (3,840)
------------- ------------
Total Other (Income) & Deductions 245 (2,817)
------------- ------------
Income Before Interest Charges 88,926 79,967
Interest Charges
Long term debt 29,082 26,221
Other - net 2,815 2,275
Allowance for borrowed funds used during construction (608) (613)
------------- ------------
Total Interest Charges 31,289 27,883
------------- ------------
Dividends on Preferred Stock 1,850 2,232
------------- ------------
Net Income Applicable to Common Stock 55,787 49,852
------------- ------------
Average Number of Common Shares (000's)
Common Stock 35,583 37,012
Common Stock and Equivalents 35,648 37,118
Earnings per Common Share - Basic $ 1.57 $ 1.35
Earnings per Common Share - Diluted $ 1.56 $ 1.34
Cash Dividends Paid per Common Share $ 0.90 $ 0.90
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
5
RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Six Months Ended
(Thousands of Dollars) June 30,
-----------------------------------------------------------------------------------------------------------
2000 1999 *
---------- ----------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 57,637 $ 52,084
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 67,007 68,178
Deferred recoverable fuel costs 16,532 6,747
Income taxes deferred (29,507) (2,160)
Allowance for funds used during construction (987) (995)
Unbilled revenue 19,067 5,441
Post employment benefit/pension costs 3,055 3,688
Provision for doubtful accounts 103 7,281
Changes in certain current assets and liabilities:
Accounts receivable (4,253) (519)
Materials, supplies and fuels 318 8,057
Taxes accrued 6,645 9,014
Accounts payable 8,301 (5,627)
Other current assets and liabilities, net 15,153 (8,502)
Other, net 10,781 (2,388)
---------- ----------
Total Operating 169,852 140,299
---------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (65,605) (52,464)
Nuclear generating plant decommissioning fund (10,336) (10,336)
Acquisitions, net of cash (2,571) -
Other, net - (30)
---------- ----------
Total Investing (78,512) (62,830)
---------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Proceeds from short term borrowings, net 1,250 (21,960)
Retirement of long term debt (30,000) -
Repayment of promissory notes (1,856) (701)
Dividends paid on preferred stock (1,850) (2,232)
Dividends paid on common stock (32,150) (33,459)
Payment for treasury stock (17,653) (21,758)
Other, net 2,592 (149)
---------- ----------
Total Financing (79,667) (80,259)
---------- ----------
Increase (Decrease) in cash and cash equivalents 11,673 (2,790)
Cash and cash equivalents at beginning of period 8,288 6,523
---------- ----------
Cash and cash equivalents at end of period $ 19,961 $ 3,733
---------- ----------
</TABLE>
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
<PAGE>
6
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
June 30, December 31,
2000 1999
Assets (Unaudited)
--------------------------------------------------------------------------------
Utility Plant
Electric $ 2,440,383 $ 2,399,532
Gas 461,240 453,634
Common 110,476 107,469
Nuclear 281,409 270,447
------------ -----------
3,293,508 3,231,082
Less: Accumulated depreciation 1,704,721 1,634,334
Nuclear fuel amortization 247,534 239,243
------------ -----------
1,341,253 1,357,505
Construction work in progress 108,074 95,862
------------ -----------
Net Utility Plant 1,449,327 1,453,367
------------ -----------
Current Assets
Cash and cash equivalents 17,877 6,443
Accounts receivable, net of allowance
for doubtful accounts:
2000 - $33,482; 1999 - $33,365 71,974 70,388
Affiliate receivable 17,575 13,197
Unbilled revenue receivable 33,257 55,661
Materials, supplies and fuels 33,118 33,378
Prepayments 25,009 23,294
Other current asset 1,545 145
------------ -----------
Total Current Assets 200,355 202,506
------------ -----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 238,389 220,815
Nine Mile Two deferred costs 27,681 28,206
Unamortized debt expense 17,353 17,984
Other deferred debits 12,355 13,760
Regulatory assets 437,759 466,231
------------ -----------
Total Deferred Debits and Other Assets 733,537 746,996
------------ -----------
Total Assets $ 2,383,219 $ 2,402,869
------------ -----------
<PAGE>
7
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
Capitalization and Liabilities (Unaudited)
-----------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization
Long term debt - mortgage bonds $ 580,104 $ 580,070
- promissory notes 214,075 215,930
Preferred stock redeemable at option of Company 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholders' equity
Authorized 50,000,000 shares; 38,885,813 shares
issued at June 30, 2000 and at December 31, 1999 700,803 700,268
Retained earnings 161,886 137,854
------------ -----------
862,689 838,122
Less: Treasury stock at cost (3,747,400 shares at June 30, 2000
and 2,942,600 shares at December 31, 1999) 100,905 83,252
------------ -----------
Total Common Shareholders' Equity 761,784 754,870
------------ -----------
Total Capitalization 1,627,963 1,622,870
------------ -----------
Long Term Liabilities
Nuclear waste disposal 94,376 91,743
Uranium enrichment decommissioning 11,158 10,911
Site remediation 22,357 22,357
------------ -----------
127,891 125,011
------------ -----------
Current Liabilities
Long term debt due within one year 3,781 33,781
Accounts payable 52,852 42,263
Affiliate payable 14,625 12,961
Dividends payable 16,731 17,078
Equal payment plan - 10,529
Other 63,321 33,243
------------ -----------
Total Current Liabilities 151,310 149,855
------------ -----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 279,266 314,683
Pension costs accrued 40,382 48,628
Kamine deferred costs 55,294 58,738
Post employment benefits 52,124 48,653
Other 48,989 34,431
------------ -----------
Total Deferred Credits and Other Liabilities 476,055 505,133
------------ -----------
Commitments and Other Matters - -
------------ -----------
Total Capitalization and Liabilities $ 2,383,219 $ 2,402,869
------------ -----------
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
8
Rochester Gas and Electric Corporation
Statement of Income
(Thousands of dollars)
(Unaudited)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
For the Three Months Ended
June 30,
2000 1999
---------- -----------
<S> <C> <C>
Operating Revenues
Electric $171,272 $174,911
Gas 55,293 53,675
Other -- 47,219
--------- ----------
Total Operating Revenues 226,565 275,805
--------- ----------
Fuel Expenses
Fuel for electric generation 11,073 10,494
Purchased electricity 16,432 15,566
Gas purchased for resale 30,362 26,649
Other fuel expenses -- 41,406
--------- ----------
Total Fuel Expenses 57,867 94,115
--------- ----------
Operating Revenues Less Fuel Expenses 168,698 181,690
Other Operating Expenses
Operations and maintenance excluding fuel 67,965 80,931
Unregulated operating and maintenance expenses excluding fuel -- 5,647
Depreciation and amortization 28,250 31,722
Taxes - state, local and other 18,901 27,522
Income taxes 17,488 8,716
--------- ----------
Total Other Operating Expenses 132,604 154,538
--------- ----------
Operating Income 36,094 27,152
Other (Income) & Deductions
Allowance for other funds used during construction (188) (154)
Income taxes 396 888
Other - net 1,567 (2,271)
--------- ----------
Total Other (Income) & Deductions 1,775 (1,537)
--------- ----------
Income Before Interest Charges 34,319 28,689
Interest Charges
Long term debt 14,249 13,070
Other - net 1,093 1,044
Allowance for borrowed funds used during construction (302) (247)
--------- ----------
Total Interest Charges 15,040 13,867
--------- ----------
Net Income 19,279 14,822
--------- ----------
Dividends on Preferred Stock 925 1,116
--------- ----------
Net Income Applicable to Common Stock 18,354 13,706
--------- ----------
Average Number of Common Shares (000's)
Common Stock 35,379 36,769
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
9
Rochester Gas and Electric Corporation
Statement of Income
(Thousands of dollars)
(Unaudited)
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Year To Date
June 30,
2000 1999
------------ ------------
<S> <C> <C>
Operating Revenues
Electric $347,979 $339,583
Gas 169,436 171,048
Other -- 91,265
------------ ------------
Total Operating Revenues 517,415 601,896
Fuel Expenses
Fuel for electric generation 22,037 22,013
Purchased electricity 32,595 28,323
Gas purchased for resale 89,600 87,370
Other fuel expenses -- 75,721
------------ ------------
Total Fuel Expenses 144,232 213,427
------------ ------------
Operating Revenues Less Fuel Expenses 373,183 388,469
Other Operating Expenses
Operations and maintenance excluding fuel 138,482 146,685
Unregulated operating and maintenance expenses excluding fuel -- 12,316
Depreciation and amortizaton 56,310 60,862
Taxes - state, local & other 47,485 58,877
Income taxes 42,633 32,579
------------ ------------
Total Other Operating Expenses 284,910 311,319
------------ ------------
Operating Income 88,273 77,150
Other (Income) & Deductions
Allowance for other funds used during construction (379) (383)
Income taxes 813 1,406
Other - net 522 (3,840)
------------ ------------
Total Other (Income) & Deductions 956 (2,817)
------------ ------------
Income Before Interest Charges 87,317 79,967
Interest Charges
Long term debt 28,345 26,221
Other - net 1,958 2,275
Allowance for borrowed funds used during construction (608) (613)
------------ ------------
Total Interest Charges 29,695 27,883
------------ ------------
Net Income 57,622 52,084
------------ ------------
Dividends on Preferred Stock 1,850 2,232
------------ ------------
Net Income Applicable to Common Stock 55,772 49,852
------------ ------------
Average Number of Common Shares (000's)
Common Stock 35,583 37,012
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
10
ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Six Months Ended
(Thousands of Dollars) June 30,
---------------------------------------------------------------------------------------------------------
2000 1999 *
---------- ----------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 57,622 52,084
Adjustments to reconcile net income to net cash provided from
operating activities:
Depreciation & amortization 65,129 68,178
Deferred recoverable fuel costs 16,532 6,747
Income taxes deferred (28,328) (2,160)
Allowance for funds used during construction (987) (995)
Unbilled revenue 22,404 5,441
Post employment benefit/pension costs 3,055 3,688
Provision for doubtful accounts 117 7,281
Changes in certain current assets and liabilities:
Accounts receivable (6,081) (519)
Materials, supplies and fuels 260 8,057
Taxes accrued 7,280 9,014
Accounts payable 12,253 (7,217)
Other current assets and liabilities, net 10,397 5,236
Other, net 10,750 (10,827)
---------- ----------
Total Operating 170,403 144,008
---------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (64,618) (52,464)
Nuclear generating plant decommissioning fund (10,336) (10,336)
Other, net (776) (30)
---------- ----------
Total Investing (75,730) (62,830)
---------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Proceeds from short term borrowings, net - (21,960)
Retirement of long term debt (30,000) -
Repayment of promissory notes (1,856) (701)
Dividends paid on preferred stock (1,850) (2,232)
Dividends paid on common stock (32,150) (33,459)
Payment for treasury stock (17,653) (21,758)
Other, net 270 (149)
---------- ----------
Total Financing (83,239) (80,259)
---------- ----------
Increase in cash and cash equivalents 11,434 919
Cash and cash equivalents at beginning of period 6,443 6,523
---------- ----------
Cash and cash equivalents at end of period $ 17,877 $ 7,442
---------- ----------
</TABLE>
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
<PAGE>
11
RGS ENERGY GROUP, INC.
ROCHESTER GAS AND ELECTRIC CORPORATION
NOTES TO FINANCIAL STATEMENTS
Note 1: GENERAL
Holding Company Formation. On August 2, 1999, RG&E was reorganized into a
holding company structure in accordance with the Agreement and Plan of Exchange
between RG&E and RGS. RG&E's common stock was exchanged on a share-for-share
basis for the common stock of RGS. RG&E's preferred stock was not exchanged as
part of the share exchange and will continue as shares of RG&E.
Basis of Presentation. This Quarterly Report on Form 10-Q is a combined
report of RGS Energy and RG&E, a regulated electric and gas subsidiary. The
Notes to Financial Statements apply to both RGS Energy and RG&E. RGS's
Consolidated Financial Statements include the accounts of RGS and its wholly
owned subsidiaries, including RG&E, and two non-utility subsidiaries, RGS
Development and Energetix. RGS's prior period consolidated financial statements
have been prepared from RG&E's prior period consolidated financial statements,
except that accounts have been reclassified to reflect RGS's structure. RGS
and RG&E, in the opinion of management, have included adjustments (which include
normal recurring adjustments) which are necessary for the fair statement of the
results of operations for the interim periods presented. The consolidated
financial statements for 2000 are subject to adjustment at the end of the year
when they will be audited by independent accountants. The preparation of
financial statements requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Moreover, the results for these interim periods are not necessarily indicative
of results to be expected for the year, due to seasonal, operating and other
factors. These financial statements should be read in conjunction with the
financial statements and notes thereto contained in the RGS and RG&E combined
Annual Report on Form 10-K for the year ended December 31, 1999.
New York State Tax Changes. On May 15, 2000 changes to the New York State
tax laws were signed into law effective January 1, 2000. In June 2000 the
Company recorded taxes in accordance with these changes. The effect of these
changes was a reduction in the gross receipts tax rate, elimination of excess
dividends taxes, and the imposition of a state income tax. In addition to a
year-to-date reduction in gross receipts and excess dividends taxes of $5.2
million and year-to-date state income tax effects of $7.4 million, a transition
item, deferred state income taxes, was established using existing federal
deferred taxes to recognize timing differences between book and tax
deductibility. The transition item results in a one-time tax deduction of
$17.2 million. The net effect of all of these tax changes has been deferred for
future rate treatment in accordance with RG&E's COB2 settlement.
Note 2. OPERATING SEGMENT FINANCIAL INFORMATION
Under SFAS-131, Disclosures about Segments of an Enterprise and Related
Information, information pertaining to operating segments is required to be
reported. Upon adoption of SFAS-131, the Company identified three operating
segments, driven by the types of products and services offered and regulatory
environment under which the Company primarily operates. The three segments of
RGS are Regulated Electric, Regulated Gas, and Unregulated. The regulated
segments' financial records are maintained in accordance with generally accepted
accounting principles (GAAP) and Public Service Commission (PSC) accounting
policies. The Unregulated segment's financial records are maintained in
accordance with GAAP.
<PAGE>
12
<TABLE>
<CAPTION>
For the Three Months Ended June 30, 2000
Regulated Regulated
Electric Gas Unregulated
-------- --- -----------
(thousands of dollars) 2000 1999 2000 1999 2000 1999
---------------------- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Operating Income/(Loss) $ 33,835 $ 28,229 $ 2,259 $(1,022) $ (631) $ (266)
Revenues - External Customers 171,272 174,270 55,293 52,560 101,550 58,584
Revenues - Intersegment Transactions 17,411 9,557 -- 52 -- --
</TABLE>
<TABLE>
<CAPTION>
For the Six Months Ended June 30, 2000
Regulated Regulated
Electric Gas Unregulated
-------- --- -----------
(thousands of dollars) 2000 1999 2000 1999 2000 1999
---------------------- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Operating Income $ 68,132 $ 56,217 $ 20,141 $ 19,488 $ 853 $ 1,056
Revenues - External Customers 347,979 338,358 169,436 168,361 213,442 114,660
Revenues - Intersegment Transactions 34,302 19,253 -- 230 -- --
</TABLE>
The operations of RGS Development and Energyline (a previous subsidiary of RGS
now dissolved) are included in Other (Income) and Deductions in the RGS Energy
Group, Inc. Consolidated Statement of Income. The total amount of the revenues
identified by operating segment do not equal the total Company consolidated
amounts as shown in the RGS Consolidated Statement of Income. This is due to
the elimination of certain intersegment revenues during consolidation. A
reconciliation follows:
<TABLE>
<CAPTION>
For the Three Months For the Six Months
Ended June 30 Ended June 30
Revenues 2000 1999 2000 1999
---- ---- ---- ----
<S> <C> <C> <C> <C>
Regulated Electric $171,272 $174,270 $347,979 $338,358
Regulated Gas 55,293 52,560 169,436 168,361
Unregulated 101,550 58,584 213,442 114,660
-------- -------- -------- --------
Total 328,115 285,414 730,857 621,379
Reported on RGS Consolidated
Income Statement 310,704 275,805 696,555 601,896
Difference to reconcile 17,411 9,609 34,302 19,483
Intersegment Revenue
Regulated Electric from Unregulated 17,411 9557 34,302 19,253
Regulated Gas from Unregulated -- 52 -- 230
-------- -------- -------- --------
Total Intersegment 17,411 9,609 34,302 19,483
</TABLE>
Note 3. COMMITMENTS AND OTHER MATTERS
The following matters supplement the information contained in Note 10 to
the financial statements included in the RGS and RG&E combined Annual Report on
Form 10-K for the year ended December 31, 1999 and should be read in conjunction
with the material contained in that Note.
REGULATORY ASSETS
With PSC approval RG&E has deferred certain costs rather than recognize
them on its books when incurred. Such deferred costs are then recognized as
expenses when they are included in rates and recovered from customers. Such
deferral accounting is permitted by SFAS-71, Accounting for the Effects of
Certain Types of Regulation. These deferred costs are shown as Regulatory
Assets on the Company's and RG&E's Balance Sheets. Such cost deferral is
appropriate under traditional regulated cost-of-service rate setting, where all
prudently incurred costs are recovered through rates. In a purely competitive
pricing
<PAGE>
13
environment, such costs might not have been incurred and could not have been
deferred. Accordingly, if RG&E was no longer allowed to defer some or all of
these costs under SFAS-71, these assets would be adjusted accordingly, up to and
including the entire amount being written off.
Below is a summarization of the Regulatory Assets as of June 30, 2000 and
December 31, 1999:
<TABLE>
<CAPTION>
Millions of Dollars
June 30, 2000 Dec. 31, 1999
------------- -------------
<S> <C> <C>
Kamine Settlement $183.8 $187.5
Income Taxes 122.4 129.5
Oswego Plant Sale 76.7 78.6
Deferred Environmental SIR costs 20.5 20.5
Uranium Enrichment Decommissioning Deferral 13.3 13.9
Storm Costs 8.9 8.5
Other, net 12.2 27.7
------ ------
Total - Regulatory Assets $437.8 $466.2
====== ======
</TABLE>
See the combined 1999 Form 10-K of RGS and RG&E, Item 8, Note 10 of the
Notes to financial Statements, "Regulatory Matters" for a description of the
Regulatory Assets shown above.
In a competitive electric market, strandable assets would arise when
investments are made in facilities, or costs are incurred to service customers,
and such costs are not fully recoverable in market-based rates. An example
includes 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 June 30, 2000 depends on market
prices and the competitive market in New York State which is subject to
continuing changes that are not yet determinable, but the amount could be
significant. Strandable assets, if any, could be written down for impairment of
recovery based on SFAS-121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of, which requires write-down of long-
lived assets whenever events or circumstances occur which indicate that the
carrying amount of a long-lived asset may not be recoverable.
In a competitive natural gas market, strandable assets would arise where
customers migrate away from dependence on RG&E for full service, leaving RG&E
with surplus pipeline and storage capacity, as well as natural gas supplies
under contract. RG&E has been restructuring its transportation, storage and
supply portfolio to reduce its potential exposure to strandable assets.
Regulatory developments referred to under "Gas Retail Access Settlement" below,
may affect this exposure; but whether and to what extent there may be an impact
on the level and recoverability of strandable assets cannot be determined at
this time.
At June 30, 2000 RG&E believes that its regulatory assets are probable of
recovery. The Settlement in the Competitive Opportunities Proceeding does not
impair the opportunity of RG&E to recover its investment in these assets.
However, the PSC issued an Opinion and Order Instituting Further Inquiry on
March 20, 1998 to address issues surrounding nuclear generation. After an
initial meeting in January 1999, the case has not significantly progressed.
However, in an order issued April 25, 2000 in a case specifically focused on
Nine Mile Two, the PSC urged the utility owners of Nine Mile Two to determine
the market value of that Plant and such owners subsequently announced their
intention to offer the Plant for sale in an auction process. See below under
Nuclear-Related matters: Nine Mile Nuclear Plants. The ultimate determination in
the 1998 proceeding or in the more recent proceedings addressing Nine Mile Two
could have an impact on strandable assets and the recovery of nuclear costs.
NUCLEAR-RELATED MATTERS
NINE MILE NUCLEAR PLANTS. On June 24, 1999, Niagara Mohawk and New York
State Electric and Gas (NYSEG) announced their intention to sell their interests
in the Nine Mile One and Nine Mile Two
<PAGE>
14
nuclear plants to AmerGen Energy Company, L.L.C. (AmerGen), a joint venture of
PECO Energy of Philadelphia and British Energy. Niagara Mohawk owns 41 percent
of Nine Mile Two and 100 percent of Nine Mile One and NYSEG owns 18 percent of
Nine Mile Two.
RG&E's 14 percent interest in Nine Mile Two was not included in the
proposal but RG&E has a right of first refusal to buy the plants on terms at
least as favorable as those offered, assuming the transaction were to proceed as
proposed. RG&E exercised its right of first refusal but in the ensuing
discussions with the PSC staff it became clear that the transaction on the terms
proposed would not be approved by the PSC.
On April 25, 2000, the PSC issued an order that allows NYSEG and Niagara
Mohawk to withdraw their petition to sell their interests in the Nine Mile
plants to AmerGen. The order concludes that Nine Mile's market value is "greatly
in excess of the original AmerGen purchase price" and that multiple bidders are
now interested in the Nine Mile plants. The order also concludes that
"...failure for the utilities to determine the market value of the Nine Mile
facilities at this time, through an open process, would raise serious prudence
questions." With respect to stranded costs, the PSC order indicates that
stranded costs cannot be finally quantified "until the disposition of the plants
by the utilities is decided." The PSC's order does, however, observe (1) that a
sale would be considered within its policy of separating generation from
transmission and distribution, (2) that a sale at current market values would
constitute appropriate mitigation of stranded costs and (3) that ratemaking
treatment of a sale would be resolved in accordance with each company's
competitive opportunities/restructuring order taking into account reduced risk
and corollary divestiture effects.
On June 1, 2000, RG&E issued a press release announcing an auction process
by RG&E, Central Hudson Gas & Electric Corporation, NYSEG and Niagara Mohawk in
connection with their ownership interests in Nine Mile Two and Niagara Mohawk's
interest in Nine Mile Point Unit 1.
Discussions with the staff of the PSC and Nine Mile Two co-owners regarding
the auction process and the regulatory impact thereof continue but RG&E is
unable to predict the ultimate outcome. At June 30, 2000 the net book value of
RG&E's 14 percent interest in the Nine Mile Two generating facility was
approximately $370 million.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND. On June 12,
1998, 16 electric utilities from across the country, including RG&E, filed
multi-count complaints against the United States government in the United States
District Court for the Southern District of New York. The suits challenge the
constitutionality of a $2.25 billion retroactive assessment imposed by the
federal government on domestic nuclear power companies to pay for the clean up
of the federal government's three uranium enrichment plants. In separate
rulings, the District Court twice denied Government efforts to prevent the case
from being heard in that Court. A subsequent Government motion to transfer the
case to the Federal Court of Claims, where utility suits based on similar facts
have been dismissed, was argued in Federal Court in the spring. A decision is
expected shortly.
The assessments for Ginna and RG&E's share of Nine Mile Two are estimated
to total $22.1 million, excluding inflation and interest. Installments
aggregating approximately $12.9 million have been paid through June 30, 2000. A
liability has been recognized on the financial statements along with a
corresponding regulatory asset. For the two facilities RG&E's liability at June
30, 2000 is $12.9 million ($11.2 million as a long-term liability and $1.7
million as a current liability). RG&E is recovering these costs in rates.
GAS RETAIL ACCESS SETTLEMENT
On June 14, 2000, in connection with on-going settlement negotiations
pertaining to RG&E's gas rate and restructuring proposal filed with the PSC on
January 28, 2000 (see March 31, 2000 10-Q, "Rates and Regulatory Matters"),
RG&E, the PSC staff, and certain other parties to the negotiations entered into
a Settlement Agreement Pertaining to Certain Elements of Natural Gas Retail
Access Program (Retail Access Settlement). The Retail Access Settlement, which
the PSC voted to approve on July 19, 2000, addresses the following issues: (1)
establishment of a Backout Credit to be paid to natural gas marketers serving
retail customers as an incentive to migration of those customers from RG&E sales
service to service from participating marketers; (2) elimination of the Backout
Credit in the event of market concentration, in which
<PAGE>
15
case the affected marketer would no longer receive the Backout Credit with
respect to new customers; (3) establishment of a mechanism to keep RG&E whole
for the difference between the Backout Credit and actual reductions in RG&E's
costs resulting from migration; (4) introduction of the single-retailer model
for natural gas retail access in substantially the same form as currently in
effect for electric retail access; (5) management of transportation gas
deliveries into the RG&E system; (6) protocols regarding communications between
RG&E and the marketers operating on RG&E's system; and (7) continuation of
benefits to customers resulting from the release of upstream pipeline capacity
and the expiration and termination of pipeline contracts.
With one notable exception, the Retail Access Settlement is intended to
remain in effect at least through June 30, 2002, subject to being superseded by
a more comprehensive settlement agreement. The exception is the last enumerated
item, pertaining to upstream capacity. Under the Retail Access Settlement,
continuation of the current level of imputed benefits will be for a two-month
period consisting of September and October 2000. The benefits for those two
months will be $.8 million per month, which is approximately their current
level. RG&E and customers will share any capacity release revenues and credits
above the stated amount on a 5 percent/95 percent basis, respectively.
Although the Backout Credit will apply to customers who migrated to
marketers on or after July 1, 2000, the Retail Access Settlement assumes that
RG&E's opportunities for savings due to migration of customers will be extremely
limited until the implementation of a single-retailer system of gas retail
access in substantially the same form as that currently in place for electric
retail access. Accordingly, the Differential between the Backout Credit paid
marketers ($3.75 per customer per month) and RG&E's actual savings is initially
assumed to equal the Backout Credit, and RG&E is entitled to recover that entire
amount. Upon implementation of the single-retailer system for gas, which is
anticipated to occur on or about November 1, 2000, following approval of a
tariff filing by RG&E, RG&E expects to be able to realize savings from customer
migration. Accordingly, at that point, the Differential will decrease from
$3.75 per customer per month to $2.55 per customer per month. Both the Backout
Credit and the Differential are to remain in effect at these levels for the term
of the Retail Access Settlement, subject to possible further negotiations in the
event of particularly rapid migration.
RG&E, the PSC staff, and other parties anticipate continuing settlement
negotiations aimed at a comprehensive gas rate and restructuring settlement.
RG&E is unable to predict the ultimate outcome of these negotiations or any PSC
decision pertaining thereto.
ENVIRONMENTAL MATTERS
NEW YORK INITIATIVES. The New York Attorney General (NYAG) sent a letter to
certain New York utilities in October, 1999 requesting historic information
regarding certain upgrades, modifications and maintenance activities at coal
fired power plants under their control. RG&E received such a letter requesting
data covering a period back to 1977 for its Russell and (the now closed) Beebee
Stations. The letter suggests that those upgrades, modifications and
improvements may have required permission from the NYSDEC prior to their
occurrence. In order to assume legal control over the issue, the NYSDEC issued
subpoenas on January 13, 2000 to RG&E and the other NYAG letter recipients (with
the exception of one who had already supplied data to the NYAG) commanding
production of documents including, but not limited to, those requested by the
NYAG's October, 1999 information request. RG&E completed its information
collection activities and provided the requisite response by the March 1
deadline. Under cover of letter dated May 25, 2000, NYSDEC issued a Notice of
Violation (NOV) to RG&E, asserting that certain "modifications" to Russell and
Beebee Stations during 1983-87 resulted in a "significant increase in the
capacity to emit sulfur dioxide." The NOV alleges that, as a result, permits
required by the federal Clean Air Act and the State Environmental Conservation
Law should have been obtained by RG&E prior to beginning the "modifications."
The NOV asserts that RG&E may be liable for civil penalties of up to $10,000 per
day per violation, as well as subjected to unspecified injunctive relief. The
allegations in the NOV are similar to those being made by the United States
Department of Justice, on behalf of the United States Environmental Protection
Agency, in enforcement cases against a number of electric utility coal-fired
power plants in the midwest and southeast.
The NOV invited RG&E to request an informal conference with NYSDEC. During
July 2000, RG&E
<PAGE>
16
has had several such informal meetings with NYSDEC. If the matter cannot be
resolved through these discussions, RG&E expects to contest vigorously NYSDEC's
allegations.
Also in October 1999, the Governor of New York directed NYSDEC to require
electric generators to further reduce acid rain-causing emissions. The
governor's proposal suggests extending the existing NOx control program under
which RG&E's Russell Station operates to a year-round program (it is currently
in effect only for the five-month ozone season). In addition, the governor is
also proposing that there be a targeted reduction of some 50% in SO2 emissions
below the existing Acid Rain Phase II limits. The State emission reductions
would be phased-in beginning January 1, 2003 and be complete by January 1, 2007.
Since this is only a proposed change, and subject to review, comment and
modification, no accurate estimate of its economic impact on RG&E can be made at
this time.
OTHER MATTERS
EITF ISSUE 97-4 - DEREGULATION OF THE PRICING OF ELECTRICITY. In July
1997, the Financial Accounting Standards Board's Emerging Issues Task Force
(EITF) reached a consensus on accounting rules for utilities' transition plans
for moving to more competitive environments and provided guidance on when
utilities with transition plans will need to discontinue the application of
SFAS-71.
The major EITF consensus was that the application of SFAS-71 to a segment
(e.g. generation) which is subject to a deregulation transition plan should
cease when the legislation or enabling rate order contains sufficient detail for
the utility to reasonably determine what the transition plan will entail. The
EITF also concluded that a decision to continue to carry some or all of the
regulatory assets (including stranded costs) and liabilities of the separable
portion of the business that is discontinuing the application of SFAS-71 should
be determined on the basis of where the regulated cash flows to realize and
settle them will be derived. If a transition plan provides for a non-bypassable
fee for the recovery of stranded costs, there may not be any significant write-
off if SFAS-71 is discontinued for a segment.
RG&E's application of the EITF 97-4 consensus has not affected its
financial position or results of operations because any above-market generation
costs, regulatory assets and regulatory liabilities associated with the
generation portion of its business will be recovered by the regulated portion of
RG&E through its distribution rates, given the 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 Settlement also addresses "to-go" costs,
which are all capital costs incurred after February 1997, operation and
maintenance expenses, and property, payroll and other taxes. The fixed portion
of the non-nuclear generation to-go costs after November 1, 2000 (the date RG&E
currently expects to discontinue full-requirements electric service) and the
variable portion of the non-nuclear generation to-go costs after July 1, 1998
are subject to market forces and thus SFAS-71 would no longer apply. These costs
have been below prevailing market prices. RG&E's net investment at June 30,
2000 in nuclear generating assets is $611.5 million and in non-nuclear
generating assets is $58.8 million. (See "Nine Mile Nuclear Plants" for
information concerning status of the interests in Nine Mile Two owned by two co-
owners and Nine Mile One owned by Niagara Mohawk.)
<PAGE>
17
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The discussion presented below contains statements which are not historic
fact and which can be classified as forward looking. These statements can be
identified by the use of certain words which suggest forward looking
information, such as "believes," "will," "expects," "projects," "estimates" and
"anticipates". They can also be identified by the use of words which relate to
future goals or strategies. In addition to the assumptions and other factors
referred to specifically in connection with the forward looking statements, some
of the factors that could have a significant effect on whether the forward
looking statements ultimately prove to be accurate include:
1. uncertainties related to the regulatory treatment of nuclear generation
facilities including, (1) the PSC's indication that it would prefer that
all of the current owners sell their interests in the Nine Mile Point
nuclear generating facilities and determine market value through an open
process, (2) the exercise of the co-owners' rights of first refusal and (3)
any changes in regulatory status of nuclear generating facilities and their
related costs, including recovery of costs related to spent fuel and
decommissioning.
2. uncertainties related to the costs associated with management of the New
York electrical grid by the New York Independent System Operator and the
competitive electric wholesale market.
3. any state or federal legislative or regulatory initiatives (including the
results of negotiations between RG&E and the PSC regarding certain gas
restructurings) that affect the cost or recovery of investments necessary
to provide utility service in the electric and natural gas industries. Such
initiatives could include, for example, changes in the regulation of rate
structures or changes in the speed or degree to which competition occurs in
t he electric and natural gas industries;
4. any changes in the ability of RG&E to recover environmental compliance costs
through increased rates;
5. any changes in the rate of industrial, commercial and residential growth in
RG&E's and RGS's service territories;
6. the development of any new technologies which allow customers to generate
their own energy or produce lower cost energy;
7. any unusual or extreme weather or other natural phenomena;
8. the ability of RGS to manage profitably new unregulated operations;
9. certain unknowable risks involved in operating unregulated businesses in new
territories and new industries;
10. the timing and extent of changes in commodity prices and interest rates; and
11. any other considerations that may be disclosed from time to time in the
publicly disseminated documents and filings of RGS and RG&E.
<PAGE>
18
Shown below is a listing of the principal items discussed.
RGS ENERGY GROUP, INC. Page 18
Unregulated Subsidiaries
ROCHESTER GAS AND ELECTRIC CORPORATION
Competition Page 19
PSC Competitive Opportunities Case Settlement
Energy Choice
Nine Mile Nuclear Plants
New York Independent System Operator
Prospective Financial Position
Rates and Regulatory Matters Page 23
PSC Gas Restructuring Policy Statement
Gas Retail Access Settlement
Flexible Pricing Tariff
FERC Gas Market Proposals
LIQUIDITY AND CAPITAL RESOURCES Page 24
Capital and Other Requirements
Financing
Redemption of Securities
Stock Repurchase Plan
EARNINGS SUMMARY Page 25
RESULTS OF OPERATIONS Page 26
Operating Revenues and Sales
Operating Expenses
Other Statement of Income Items
DIVIDENDS Page 28
RGS ENERGY GROUP, INC.
RGS is a holding company and not an operating entity. RGS's operations are
being conducted through its subsidiaries which include RG&E, and two unregulated
subsidiaries - RGS Development and Energetix.
RG&E offers regulated electric and natural gas utility service in its
franchise territory. Energetix provides energy products and services
throughout upstate New York. RGS Development offers energy systems development
and management services.
Unregulated Subsidiaries. It is part of RGS's financial strategy to seek
growth by entering into unregulated businesses in which RGS has invested $61
million (including loan guarantees) as of June 30, 2000. The Settlement allowed
RG&E to provide the funding for RGS to invest up to $100 million in unregulated
businesses. The first step in this direction was the formation and operation of
Energetix effective 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
<PAGE>
19
radius around Rochester.
In 1998, Energetix acquired Griffith Oil Company, Inc. (Griffith), the
second largest oil and propane distribution company in New York State. Griffith
has approximately 350 employees and operates 19 customer service centers.
Griffith gives Energetix access to new customers outside of RG&E's regulated
franchise territory. Acquisitions by Griffith in 1999 and 2000 have increased
Griffith's customer base by approximately 10 percent.
Additional information on Energetix operations (including Griffith) is
presented under the headings Operating Revenues and Sales, Operating Expenses,
and is contained in Note 2 of the Notes to Financial Statements.
In 1998, the Company formed RGS Development to pursue unregulated business
opportunities in the energy marketplace. Through June 30, 2000, RGS
Development's operations have not been material to RGS's results of operations
or its financial condition.
ROCHESTER GAS AND ELECTRIC CORPORATION
COMPETITION
GAS RETAIL ACCESS. In June, 2000 RG&E reached agreement with the PSC Staff
and other parties to encourage and promote customers' opportunities to choose
among competing natural gas suppliers. The PSC voted to approve this agreement
on July 19, 2000. See following discussion under Rates and Regulatory Matters,
"Gas Retail Access Settlement".
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. During 1996 and 1997, RG&E,
the staff of the PSC and several other parties negotiated an agreement which was
approved by the PSC in November 1997 (Settlement). The Settlement sets the
framework for the introduction and development of open competition in the
electric energy marketplace and lasts through June 30, 2002. Over this time, the
way electricity is provided to customers will fundamentally change. In phases,
RG&E will allow customers to purchase electricity, and later capacity
commitments, from sources other than RG&E through its retail access program,
Energy Choice. These energy service companies will compete to package and sell
energy and related services to customers. The competing energy service companies
will purchase distribution services from RG&E who will remain the sole provider
of distribution services, and will be responsible for maintaining the
distribution system and for responding to emergencies.
The 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 its regulated
electric business 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,
Accounting for the Effects of Certain Types of Regulation). If certain
extraordinary events occur, including a rate of return on common equity below
8.5 percent or above 14.5 percent, or a pretax interest coverage below 2.5
times, then 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 unregulated energy retailing operations to 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
<PAGE>
20
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 participant in the Settlement negotiations and a non-participant
commenced an action for declaratory and injunctive relief as to certain
provisions of the Settlement and the PSC's approval of it. The trial court found
in favor of the PSC. On June 29, 2000, the Appellate Division of New York State
Supreme Court concluded that these parties lack standing and affirmed the lower
court's judgment. RG&E is unable, at this time, to predict whether there will be
a further appeal and, if so, the outcome of this action.
ENERGY CHOICE. The Energy Choice program has been in existence over two
years now in RG&E's service territory. On July 1, 1998, RG&E officially began
implementation of its full-scale electric retail access Energy Choice program.
As of July 1, 1999, RG&E entered its second year of this program. There are five
basic components of the sale of energy: (1) the sale of electricity which is the
amount of energy actually used by the consumer, (2) the sale of capacity which
is the ability, through generating facilities or otherwise, to provide
electricity when it is needed, (3) the sale of transmission services, which is
the physical transportation of electricity to RG&E's distribution system, (4)
the sale of distribution services, which is the physical delivery of electricity
to the consumer, and (5) retail services such as billing and metering.
Historically, RG&E has sold all five components bundled together for a fixed
rate approved by the PSC. The implementation of Energy Choice included a four
year phase-in process to allow RG&E and other parties to manage the transition
to electric competition in an orderly fashion. During the first year of the
program, participation in Energy Choice was limited to no more than 10 percent
of RG&E's total annual retail electric kilowatt-hour sales (670,000 annualized
megawatt-hours). Essentially, until this 10 percent limit was achieved, RG&E's
electric retail customers could seek out or be approached by alternative energy
service companies for electricity to be resold and then delivered over RG&E's
distribution system. By February 1, 1999, only six months into the Energy
Choice program, this 10 percent limit was achieved by qualified competitive
energy service companies in RG&E's service territory. For the second year of the
program, beginning July 1, 1999, this limit increased from 10 percent to
approximately 20 percent. By June 30, 2000, approximately 18 percent of total
RG&E sales had shifted to competitive energy service companies. As of July 1,
2000 this limit increased from 20 percent to 30 percent. Next year, beginning
July 1, 2001, all retail customers will be eligible to purchase energy, capacity
and retailing services from competitive energy service companies. Existing RG&E
customers may also continue to purchase fully bundled electric service from
RG&E.
Energy Choice adopted the single-retailer model for the relationship
between RG&E as the distribution provider, qualified energy service companies,
and retail (end-use) customers. In this model, retail customers have the
opportunity for choice in their energy service company and receive only one
electric bill from the company that serves them. Except for providing emergency
services, satisfying requests for distribution services, and scheduling outages,
which remain RG&E's responsibility, the retail customer's primary point of
contact for billing questions, technical advice and other energy-related needs,
is with their chosen energy service company.
Under the single-retailer model, energy service companies are responsible
for buying or otherwise providing the electricity their retail customers will
use, paying regulated rates for transmission and distribution, and selling
electricity to their retail customers (the price of which would include the cost
of the electricity itself and the cost to transport electricity through RG&E's
distribution system).
As of June 30 , 2000, eight energy service companies, including Energetix,
the Company's unregulated subsidiary, are qualified by RG&E to serve retail
customers under Energy Choice. In addition to
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21
Energetix, these companies are Energy Co-op of NY (ECNY), Monroe County,
Northeast Energy Services, Inc.(NORESCO), North American Energy, NYSEG
Solutions, Inc., Select Energy Inc., and TXU Energy Services, Inc. The County of
Monroe is acting as its own energy service company to service its own
facilities, as well as serving other retail customers.
Throughout the term of the Settlement, RG&E will continue to provide
regulated and fully bundled electric service under its retail service tariff to
customers who choose to continue with such service.
During the initial Energy-Only stage of the Energy Choice program beginning
July, 1998 and eventually concluding on November 18, 1999, energy service
companies were able to choose their own sources of energy supply, while RG&E
continued to provide to them, through its bundled distribution rates, the
generating capacity (installed reserve) needed to serve their retail customers.
In addition, during the Energy-Only stage, energy service companies had the
option of purchasing "full-requirements" (i.e. delivery services plus energy)
from RG&E.
During this initial Energy Only stage of the retail access program, RG&E's
distribution rate was set by deducting 2.305 cents per kilowatt-hour from its
full service (bundled) rates. The 2.305 cents per kilowatt-hour was comprised
of 1.905 cents per kilowatt-hour (an estimate of the wholesale market price of
electricity) plus 0.4 cents per kilowatt-hour for its avoided cost of retailing
services.
During the Energy and Capacity stage, RG&E's distribution rates will equal
the bundled rate less RG&E's cost of the electric commodity and RG&E's non-
nuclear generating capacity. During this stage of the program, up until June
30, 2000, RG&E's distribution rates were set by deducting 3.0712 cents per
kilowatt-hour from its full service rates. The 3.0712 cents per kilowatt-hour
is comprised of 2.6712 cents per kilowatt-hour (an estimate of the wholesale
market price of electric energy and capacity) plus 0.4 cents per kilowatt-hour
for its avoided cost of retailing services. Beginning July 1, 2000, RG&E's
distribution rates will be set by deducting 3.0816 cents per kilowatt hour from
its full service rates. The 3.0816 cents per kilowatt-hour is comprised of
2.6816 cents per kilowatt-hour for energy and capacity plus 0.4 cents per
kilowatt-hour for its avoided cost of retailing services. This change in the
distribution rates set by deducting 3.0712 cents per kilowatt-hour and then
3.0816 cents per kilowatt-hour, is a result of changes in average gross receipts
taxes, as defined in our Settlement with the PSC.
Once RG&E no longer provides "full requirements" to the energy service
companies, they will assume responsibility for obtaining their own supplies.
There will be a revenue decrease when RG&E no longer collects the rates
described above for energy and capacity. This will be offset to some extent by
decreased costs resulting from no longer acquiring energy and capacity for the
energy service companies. The extent of this offset will be determined by
market prices.
The commencement of the Energy and Capacity stage, the second stage of the
phase-in, began with the implementation of the New York Independent System
Operator on November 18, 1999 (see following discussion under New York
Independent System Operator). During this stage, the responsibility for
purchasing not only energy, but also capacity, was to have shifted to the energy
service companies. However, these energy service companies continued to be
"full-requirements" customers of RG&E during the winter capability period and
purchased energy and capacity from RG&E. The PSC had also approved a request by
RG&E to extend "full-requirements" availability to energy service companies
through October 31, 2000. As of June 30, 2000, all energy service companies had
opted to continue purchasing "full requirements" during the summer capability
period (May 1, 2000 through October 31, 2000). Through this summer capability
period, energy service companies will have the option to serve their load from
the competitive wholesale market, but once they make this choice, they will not
be able to return this load to "full requirements".
In December 1999, two petitions were filed with the PSC, one by an electric
utility operating in New York State, and the other jointly by five energy
marketers and consultants, calling upon the PSC to examine, and to order certain
changes in, RG&E's retail access program. In particular, these petitioners
object to the single-retailer form of RG&E's program, under which the retail
marketer assumes responsibility for most retail service functions. They claim
that the backout credit (i.e., the amount by which RG&E's rates for retail
----
electric service are reduced to derive the rates charged for the delivery
service provided by RG&E to marketers) is too
<PAGE>
22
low, that it affords insufficient prospect of profitable operation, and that it
should be increased. They further assert that the phased schedule for
implementation of the program, under which increasing percentages of customers
in RG&E's service area are eligible to obtain competitive service during the
term of the Settlement, is too slow and should be significantly accelerated. On
February 28, 2000 RG&E filed with the PSC its reply to both petitions. As set
forth in that reply, RG&E believes that its single-retailer program offers
unique opportunities for marketers, that its retail backout credit (in
conjunction with RG&E's rate for wholesale power sales to marketers) affords a
sound basis for competitive service, and that its implementation schedule is
reasonable and appropriate; moreover, each of these essential elements of the
retail access program is expressly established by the rate and restructuring
Settlement. RG&E believes that the program fully and fairly advances the goals
of increased competition for energy services, and is in full compliance with the
Settlement. Nevertheless, it is not possible at this time to predict with
assurance whether or not, in response to the petitions, the PSC might require
that the program be changed in some manner.
The PSC is conducting proceedings that are intended to bring more
administrative consistency among New York State utilities and potentially offer
additional services for energy service companies to provide. These include an
on-going national effort regarding uniform business practices, and proceedings
that include standardized billing (single billing options), provider of last
resort (POLR), electronic data interchange (EDI), and competitive metering.
RG&E continues to assess the scope and impact of such changes on its operations
as retail access continues to evolve.
NINE MILE NUCLEAR PLANTS. On June 24, 1999, Niagara Mohawk and New York
State Electric and Gas (NYSEG) announced their intention to sell their interests
in the Nine Mile One and Nine Mile Two nuclear plants to AmerGen Energy Company,
L.L.C. (AmerGen), a joint venture of PECO Energy of Philadelphia and British
Energy. Niagara Mohawk owns 41 percent of Nine Mile Two and 100 percent of Nine
Mile One and NYSEG owns 18 percent of Nine Mile Two.
RG&E's 14 percent interest in Nine Mile Two was not included in the
proposal but RG&E has a right of first refusal to buy the plants on terms at
least as favorable as those offered, assuming the transaction were to proceed as
proposed. RG&E exercised its right of first refusal but in the ensuing
discussions with the PSC staff it became clear that the transaction on the terms
proposed would not be approved by the PSC.
On April 25, 2000, the PSC issued an order that allows NYSEG and Niagara
Mohawk to withdraw their petition to sell their interests in the Nine Mile
plants to AmerGen. The order concludes that Nine Mile's market value is "greatly
in excess of the original AmerGen purchase price" and that multiple bidders are
now interested in the Nine Mile plants. The order also concludes that
"...failure for the utilities to determine the market value of the Nine Mile
facilities at this time, through an open process, would raise serious prudence
questions". With respect to stranded costs, the PSC order indicates that
stranded costs cannot be finally quantified "until the disposition of the plants
by the utilities is decided." The PSC's order does, however, observe (1) that a
sale would be considered within its policy of separating generation from
transmission and distribution, (2) that a sale at current market values would
constitute appropriate mitigation of stranded costs and (3) that ratemaking
treatment of a sale would be resolved in accordance with each company's
competitive opportunities/restructuring order taking into account reduced risk
and corollary divestiture effects.
On June 1, 2000, RG&E issued a press release announcing an auction process
by RG&E, Central Hudson Gas & Electric Corporation, NYSEG and Niagara Mohawk in
connection with their ownership interests in Nine Mile Two and Niagara Mohawk's
interest in Nine Mile Point Unit 1.
Discussions with the staff of the PSC and Nine Mile Two co-owners regarding
the auction process and the regulatory impact thereof continue but RG&E is
unable to predict the ultimate outcome. At June 30, 2000 the net book value of
RG&E's 14 percent interest in the Nine Mile Two generating facility was
approximately $370 million.
NEW YORK INDEPENDENT SYSTEM OPERATOR. In November 1999 following FERC
approval, the New York State Independent System Operator (NYISO) implemented a
competitive wholesale market for the sale, purchase and transmission of
electricity and ancillary services in New York State. NYISO tariffs for market-
based rates for energy, ancillary services, and installed capacity sold through
the NYSIO were
<PAGE>
23
approved by FERC. The NYISO and the New York State Reliability Council were
formed to restructure the New York Power Pool in response to FERC Order 888.
Earlier this year, the NYISO's total cost of providing operating reserves
on an hourly basis exceeded the cost that would be expected in a workable
competitive marketplace. During the first quarter, RG&E, in addition to other
New York State public utilities and several load-serving entities, experienced
rising prices to maintain operating reserves within the NYISO system. For
example, in December 1999, on an average monthly basis, RG&E paid $.51/MWH for
operating reserves. In January, 2000, the figure was $1.10/MWH. In February,
2000, RG&E's average monthly cost for operating reserves was $6.01/MWH. During
the second quarter RG&E did not experience such high prices as it did in the
first quarter and the average cost for operating reserves decreased to $.92/MWH.
For comparison purposes, the rate charged by RG&E under its Open Access
Transmission Tariff (OATT) was $.31/MWH.
On April 7, 2000 RG&E filed a complaint with FERC against the NYISO. RG&E
sought corrective re-calculation of operating reserve prices for prior periods
and prospective relief from injuries resulting from the NYISO's operating
reserves market. Niagara Mohawk and NYSEG filed similar complaints with FERC
against the NYISO. On March 27, the NYISO filed with FERC for the immediate
authority to suspend the use of market-based bids in the New York markets for
operating reserves.
On May 31, 2000 FERC issued an order accepting the NYISO's request for
bidding restrictions in the 10-minute non-spinning reserve market amounting to
$2.52/MWH. FERC directed the NYISO to address the issue of self-supply and file
a plan to correct the problem by September 1, 2000. However, they denied the
requests from RG&E and Niagara Mohawk for retrospective rate relief. On June
30, 2000, RG&E filed a request for rehearing related to retrospective rate
relief and the issue of self-supply.
At the present time, RG&E cannot predict what effects, if any, regulations
ultimately adopted by FERC will have on future operations or the financial
condition of RGS or RG&E.
COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION. With PSC
approval, RG&E has deferred certain costs rather than recognize them on its
statement of income when incurred. Such deferred costs are then recognized as
expenses when they are included in rates and recovered from customers. Such
deferral accounting is permitted by SFAS-71. These deferred costs are shown as
Regulatory Assets on the Company's and RG&E's Balance Sheet and a discussion and
summary of such Regulatory Assets is presented in the 1999 Form 10-K, Item 8
under Note 10 of the Notes to Financial Statements.
In a competitive electric market, strandable assets would arise when
investments are made in facilities, or costs are incurred to service customers,
and such costs are not fully recoverable in market-based rates. Estimates of
strandable assets are highly sensitive to the competitive wholesale market price
assumed in the estimation. In a competitive natural gas market, strandable
assets would arise where customers migrate away from dependence on RG&E for full
service, leaving RG&E with surplus pipeline and storage capacity, as well as
natural gas supplies under contract. A discussion of strandable assets is
presented in Note 3 of the Notes to Financial Statements.
At June 30, 2000 RG&E believes that its regulatory assets 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 initial
meeting in this Inquiry was held in January 1999 (see 1999 Form 10-K, Item 7
under the heading "PSC Proceeding on Nuclear Generation"). The ultimate
determination in this proceeding or any proceeding to consider RG&E's proposed
sale of Nine Mile Two as discussed under the heading "Nine Mile Nuclear Plants"
could have an impact on strandable assets and the recovery of nuclear costs.
RATES AND REGULATORY MATTERS
PSC GAS RESTRUCTURING POLICY STATEMENT. On November 3, 1998, the PSC issued
a gas
<PAGE>
24
restructuring policy statement (Gas Policy Statement) announcing its conclusion
that, among other things, the most effective way to establish a competitive gas
supply market is for gas distribution utilities to cease selling gas. The PSC
established a transition process in which it plans to address three groups of
issues: (1) individual gas utility plans to implement the PSC's vision of the
market; (2) key generic issues to be dealt with through collaboration among gas
utilities, marketers, pipelines and other stakeholders, and (3) coordination of
issues that are common to both the gas and the electric industries. The PSC has
encouraged settlement negotiations with each gas utility pertaining to the
transition to a fully competitive gas market. RG&E, the PSC Staff and other
interested parties have been participating in settlement discussions in response
to the specific requirements of the Policy Statement.
GAS RETAIL ACCESS SETTLEMENT. On June 14, 2000, in connection with on-going
settlement negotiations pertaining to RG&E's gas rate and restructuring proposal
filed with the PSC on January 28, 2000 RG&E, the PSC staff, and certain other
parties to the negotiations entered into a Settlement Agreement Pertaining to
Certain Elements of Natural Gas Retail Access Program (Retail Access
Settlement). For a description of the Retail Access Settlement see Part I, Note
3 of the Financial Statements under the heading "Gas Retail Access Settlement."
RG&E, the PSC staff, and other parties anticipate continuing settlement
negotiations aimed at a comprehensive gas rate and restructuring settlement.
RG&E is unable to predict the ultimate outcome of these negotiations or any PSC
decision pertaining thereto.
FLEXIBLE PRICING TARIFF. Under its flexible pricing tariff for major
industrial and commercial electric customers, RG&E may negotiate competitive
electric rates at discount prices to compete with alternative power sources,
such as customer-owned generation facilities. For further information with
respect to the flexible pricing tariff see RG&E's 1999 Form 10-K, Item 7 under
Rates and Regulatory Matters.
FERC GAS MARKET PROPOSALS. On February 9, 2000, FERC issued Order No. 637,
its final rule addressing "Regulation of Short-Term Natural Gas Transportation
Services" (RM98-10) and "Regulation of Interstate Natural Gas Transportation
Services" (RM98-12). On June 5, 2000 FERC issued Order No.637-A providing
clarification and additional guidance. The Order revises FERC's regulations to
improve the efficiency of the gas transportation market and to provide captive
customers with the opportunity to reduce their cost of holding long-term
pipeline capacity. The Order: (1) waives the price ceiling for released capacity
of less than one year until September 30, 2002; (2) permits pipelines to propose
peak and off-peak and term differentiated rates providing that they still
satisfy the revenue and cost constraints of traditional rate-making, and excess
revenues are split with firm customers; (3) revises FERC's regulations on
scheduling procedures, capacity segmentation and pipeline penalties; (4) states
that the right of first refusal will apply in the future to contracts for 12
consecutive months or more of service at maximum rates; (5) amends and
supplements reporting requirements to require interstate pipelines to report
additional information on transactions, operationally available capacity, and an
expanded index of customers.
Order 637/637-A requires each pipeline to make a compliance filing. The
filing schedule has one-third of the pipelines filing on June 15, 2000, the next
group on July 15, 2000 and the last group on August 15, 2000. The first group of
pipelines included major suppliers of RG&E. RG&E filed comments in response on
July 17, 2000. At the present time there is no timetable for FERC action on the
proposals. Therefore, RG&E cannot predict what effects, if any, regulations
ultimately adopted by FERC will have on future operations or the financial
condition of the Company.
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 2000, RGS's and RG&E's cash flow from
operations (see Statements of Cash Flows) provided the funds for construction
expenditures, the payment of dividends, the retirement of long-term debt (see
"Redemption of Securities" below) and the purchase of treasury stock. Cash used
for investing activities in the first six months was higher reflecting mainly
higher net additions to utility plant. Cash used in financing activities in
the first six months was slightly higher reflecting mainly the redemption of
long term debt as described below under "Redemption of Securities" partially
offset by an increase in short term borrowings. Capital requirements of the
Company during 2000 are anticipated to be satisfied from the
<PAGE>
25
combination of internally generated funds and short-term credit arrangements.
CAPITAL AND OTHER REQUIREMENTS. RGS's and RG&E's capital requirements
relate primarily to expenditures for energy delivery, including electric
transmission and distribution facilities and gas mains and services as well as
nuclear fuel, electric production, the repayment of existing debt and the
repurchase of outstanding shares of Common Stock. RG&E has no further plans to
install additional baseload generation.
Capital Requirements. Capital requirements for the Company in 2000 are
currently estimated at $184 million of which $154 million is for construction
and $30 million was for the payment of 7% First Mortgage Bonds due 1/14/00.
RG&E's portion of total construction requirements is $151 million. Approximately
$66 million had been expended for construction as of June 30, 2000, reflecting
primarily RG&E's expenditures for nuclear fuel and upgrading electric
transmission and distribution facilities and gas mains.
FINANCING. RG&E generally utilizes its credit agreements and unsecured
lines of credit to meet any interim external financing needs prior to issuing
any long-term securities. For information with respect to RGS's and RG&E's
short-term borrowing arrangements and limitations, see the 1999 Form 10-K, Item
8 under Note 9 of the Notes to Financial Statements.
REDEMPTION OF SECURITIES. On January 14, 2000, RG&E redeemed at maturity
$30 million of 7% First Mortgage Bonds, Designated Secured Medium Term Notes,
Series A. RG&E does not anticipate redeeming any securities for the remainder of
the year 2000.
STOCK REPURCHASE PLAN. In April 1998, the PSC approved a Stock Repurchase
Plan for RG&E providing for the repurchase of Common Stock having an aggregate
market value not to exceed $145 million. RG&E began the repurchase program in
May 1998 and 3,747,400 shares of Common Stock have been repurchased for
approximately $100.1 million through June 30, 2000. The average cost per share
purchased during the six months ended June 30, 2000 was $21.94.
EARNINGS SUMMARY
RGS:
----
RGS reported higher earnings of $0.49 per share for the second quarter
ended June 30, 2000, higher than the $0.37 per share for the same period in
1999. Earnings for the six-month period ended June 30, 2000 were $1.57 per
share compared to $1.35 per share for 1999. Increased wholesale electric sales,
reduced expenses and the Company's share buyback program, which resulted in a
reduction in shares outstanding, positively affected results in the current
quarter and first six months of this year.
Total operating revenues reflect a $13.0 million revenue increase from
wholesale electric sales, offset by the effects of a decline in electric retail
base rates effective July 1, 1999. The Company had more power available to sell
to the wholesale market in the second quarter of 2000 than was available in 1999
when the R. E. Ginna Nuclear Power Plant was in a scheduled refueling outage.
In addition, higher wholesale market prices were realized this year compared to
1999. Gas revenues, net of gas expenses, for the second quarter excluding a
1999 adjustment for unbilled gas revenues were up $4.0 million due to an
increase in gas sales as a result of cooler weather. Year-to-date results were
affected by the same factors regarding the second quarter except temperatures
for the first six months of the year were 5.7% warmer compared to 1999, which
had an unfavorable effect on therm sales of gas. The market for purchased
electricity did not materially affect quarterly and year-to-date results, as
weather conditions in the Company's service area were moderate and the Company
was able to substantially supply its customers from existing resources.
Non-fuel operating expenses for the second quarter were down $11.8 million
compared to the same period in 1999 when the Company increased its reserve for
uncollectible accounts by $7.0 million. Other reductions this quarter in non-
fuel operating expenses included the absence of Y2K expenses and the recognition
of pension income, which is now being recognized monthly. Year-to-date non-fuel
operating
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26
expenses were affected by the same items as the second quarter, partially offset
by increased fees associated with the NYISO, which began operation on November
18, 1999. The NYISO replaced the New York Power Pool and now manages the bulk
transmission system in New York State.
RGS continues to grow its unregulated electric, natural gas and petroleum-
based energy products and services businesses through its subsidiary, Energetix.
Combined with its subsidiary, Griffith, Energetix now serves a total of 115,000
customers. For the first six months of 2000, Energetix and Griffith realized a
modest profit on combined operating revenues of $213.4 million. Revenues were
affected by significant customer growth for Energetix and increased commodity
prices for Griffith.
RG&E:
-----
Earnings for RG&E reflect the same issues discussed above for RGS except
that discussions relating to Energetix and Griffith are not applicable. The
RG&E Income Statements for the three month and six month periods ended June 30,
1999, reflect the consolidated operations of RG&E and its former subsidiaries,
Energetix and RGS Development. On August 2, 1999 the holding company RGS was
formed and RG&E, Energetix and RGS Development then became subsidiaries of RGS.
The RG&E Income Statements for the three month and six month periods ended June
30, 2000, reflect only the operating results of RG&E.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant changes
in the amounts of revenues and expenses for RGS (regulated and unregulated
business) and RG&E (regulated business), comparing the three-month and six-month
periods ended June 30, 2000 to the three-month and six -month periods ended June
30, 1999. The operating results of the regulated business reflect RG&E's
electric and gas sales and services and the operating results of the unregulated
business reflect Energetix operations. Currently, the majority of RGS's
operating results reflect the operating results of RG&E and the factors that
affect operating results for RG&E are the significant factors that affect
comparable operating results for RGS, unless otherwise noted.
THREE MONTHS ENDED JUNE 30, 2000 COMPARED TO THREE MONTHS ENDED JUNE 30, 1999
-----------------------------------------------------------------------------
OPERATING REVENUES AND SALES. Unconsolidated regulated electric revenues
were $171.3 million for the second quarter of 2000 as compared to $174.3 million
for the same period a year ago. Together, electric revenues from regulated
retail electric sales and electric sales to energy marketers were down $16
million reflecting a 1999 unbilled revenue adjustment of $7.1 million,
unfavorable weather and decreased rates. Partially offsetting these lower
electric revenues was a $13.0 million increase in revenues from the sale of
energy to other electric utilities (OEU sales). The increase in OEU sales
reflects favorable market conditions and increased capacity to sell power to
other electric utilities due to the availability of generation from RG&E's Ginna
nuclear plant for the entire quarter offset somewhat by a Nine Mile Two 48-day
refueling outage which began on March 4, 2000. Ginna is expected to be
undergoing a refueling outage later this year. Despite 5.2% colder weather on
a heating-degree day basis, regulated gas revenues, net of fuel, were down
slightly for the second quarter of 2000 compared to a year ago mainly due to a
1999 unbilled revenue adjustment of $6.1 million.
Unregulated operations are reflected on RG&E's financial statements only
prior to August 1, 1999, the day preceding the formation of the holding company,
RGS Energy Group, Inc. Subsequent to that date, only regulated RG&E operations
are reflected on the RG&E financials.
Unconsolidated unregulated revenues were $101.6 million for the second
quarter of 2000 as compared to $58.6 million for the same period a year ago.
This increase reflects mainly the recovery of higher purchased fuel prices for
gasoline and fuel oil, a growth in electric and gas customers, and a growth in
customer base through acquisitions made by Griffith. Revenues from Griffith are
included under "Other Revenues" on RGS's Income Statements and RG&E's 1999
Income Statement. For heating oil and propane, Griffith experiences seasonal
fluctuations due to the dependence on spaceheating sales during the heating
<PAGE>
27
season. Unregulated sales also reflect the migration of electric and gas
customers from the regulated to the unregulated business.
OPERATING EXPENSES. Higher regulated fuel expenses reflect increased
purchased electricity costs due to an increase in the cost per unit purchased
and the effect from lower generation from the Nine Mile Two refueling shutdown
and the closing of Beebee Station which occurred in April 1999. The decrease in
non-fuel operation and maintenance expenses (O&M) for both RGS and RG&E reflects
a $7 million increase in 1999 of the RG&E reserve for uncollectible accounts.
Other reductions this quarter in non-fuel O&M include the recognition of pension
income ($4.0 million), which is now being recognized monthly and the absence of
Y2K expenses ($2.6 million). The decrease in regulated depreciation expense
reflects mainly the retirement of RG&E generating plant facilities in 1999.
Regulated State, local and other taxes declined reflecting mainly lower revenues
and a lower gross receipts tax rate. The difference in income tax is
attributable to pre-tax earnings, a reclassification of the state gross receipts
tax to state income tax and a true-up of both federal and state income tax for a
new state income tax effective January 1, 2000 (see Part I, Note 1, "New York
State Tax Changes").
Higher unregulated fuel costs reflect the increase in Griffith's costs of
fuel oil and gasoline in the second quarter of 2000 as compared to a year ago.
The increase in unregulated non-fuel O&M for RGS reflects primarily operating
expenses for Griffith, payroll expenses and general and administrative expenses.
These unregulated expenses were not included for RG&E after the August 1999
reorganization described above.
OTHER STATEMENT OF INCOME ITEMS. The changes in regulated Other Income and
Deductions, Other-net reflect mainly a charge for reconciliation of RGE's 1999
purchased power expense ($3.3 million). The increase in regulated interest
expense reflects mainly the interest on $100 million of first mortgage bonds
issued by RG&E in October 1999. Preferred stock dividends decreased due to the
redemption of an RG&E Preferred stock issue on September 1, 1999 pursuant to a
mandatory sinking fund.
SIX MONTHS ENDED JUNE 30, 2000 COMPARED TO SIX MONTHS ENDED JUNE 30, 1999
-------------------------------------------------------------------------
OPERATING REVENUES AND SALES. In the first six months of 2000,
unconsolidated regulated electric revenues were $348.0 million as compared to
$338.4 million for the same period a year ago. Compared to last year, revenues
from the sale of energy to other electric utilities were up $21.9 million driven
by the same factors as discussed above for the second quarter. Partially
offsetting these favorable results was a drop of $12.3 million from a
combination of electric revenues from regulated retail electric sales and
electric sales to energy marketers reflecting the 1999 unbilled revenue
adjustment described above, unfavorable weather and decreased rates. Regulated
gas revenues, net of fuel expenses, were down slightly due mainly to the 1999
unbilled gas revenue adjustment described above.
As discussed above, unregulated operations are reflected on RG&E's
financial statements only prior to August 1, 1999.
Unconsolidated unregulated revenues were $213.4 million for the first six
months of 2000 as compared to $114.7 million last year for the same reasons
discussed for the second quarter.
OPERATING EXPENSES. Higher regulated fuel expenses and higher other fuel
costs increased for the same reasons discussed for the second quarter.
The decrease in regulated non-fuel O&M was affected by the same factors
previously discussed for the quarter. The decrease was partially offset by an
increase of $ 7.7 million for electric transmission and wheeling charges
related to implementation of the NYISO (see discussion under "New York
Independent System Operator") which mainly impacted first quarter results. The
NYISO assumed control and operation of the New York State electric transmission
system from the New York Power Pool during the fourth quarter of 1999 pursuant
to orders from the FERC. The decrease in regulated depreciation reflects mainly
the retirement of RG&E generating plant facilities in 1999. The factors
affecting variances in regulated State, local and other taxes and income taxes
for the quarterly period are also applicable for the six-month comparison
period.
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The increase in unregulated non-fuel O&M for RGS reflects primarily
operating expenses for Griffith, payroll expenses and general and administrative
expenses.
OTHER STATEMENT OF INCOME ITEMS. The factors affecting variances in
regulated other (income) and deductions-net, interest charges and dividends on
preferred stock for the quarterly period are also applicable for the six-month
comparison period.
DIVIDENDS
On June 21, 2000, the Board of Directors of RGS authorized a common stock
dividend of $.45 per share, which was paid on July 25, 2000 to shareholders of
record on July 3, 2000. Also on June 21, 2000, The Board of Directors of RG&E
declared dividends on its Preferred Stocks at the regular rates per share
payable on September 1, 2000 to stockholders of record on August 1, 2000.
The ability of RGS to pay common stock dividends is governed by the ability
of RGS's subsidiaries to pay dividends to RGS. Because RG&E is by far the
largest of the subsidiaries, it is expected that for the foreseeable future the
funds required by RGS to enable it to pay dividends will be derived
predominantly from the dividends paid to RGS by RG&E. In the future, dividends
from subsidiaries other than RG&E may also be a source of funds for dividend
payments by RGS. RG&E's ability to make dividend payments to RGS will depend
upon the availability of retained earnings and the needs of its utility
business. In addition, pursuant to the PSC order approving the formation of
RGS, RG&E may pay dividends to RGS of no more than 100% of RG&E's net income
calculated on a two-year rolling basis. The calculation of net income for this
purpose excludes non-cash charges to income resulting from accounting changes or
certain PSC required charges as well as charges that may arise from significant
unanticipated events. This condition does not apply to dividends that would be
used to fund the remaining portion of RG&E's $100 million authorization for
unregulated operations (about $39 million at June 30, 2000). The level of
future cash dividend payments on Common Stock will be dependent upon RGS's
future earnings.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.
RG&E is exposed to interest rate and commodity price risks.
The interest rate risk relates to new debt financing needed to fund capital
requirements, including maturing debt securities, and to variable rate debt.
RG&E manages its interest rate risk through the issuance of fixed -rate debt
with varying maturities and through economic refundings of debt through optional
redemptions. A portion of RG&E's long-term debt consists of long-term
Promissory Notes, the interest component of which resets on a periodic basis
reflecting current market conditions. RG&E was not participating in any
derivative financial instruments for managing interest rate risks as of June 30,
2000 or December 31, 1999.
The commodity price risk relates to market fluctuations in the price of
natural gas, electricity, and other petroleum-related products used for resale.
Commodity purchases and electric generation are based on projected demand for
power generation and customer delivery of electricity, natural gas and petroleum
products. RG&E enters into forward contracts for natural gas to hedge the
effect of price increases and reduce volatility on gas purchased for resale.
Under the Competitive Opportunities Settlement, RG&E's electric rates are capped
at specified levels through June 30, 2002. Long-term fixed supply contracts and
owned electric generation significantly reduce RG&E's exposure to market
fluctuations for procurement of its electric supply. Owned generation subjects
the Company to operating risk. Operating risk is managed through a combination
of strict operating and maintenance practices and the use of financial
instruments. In the event RG&E's generation assets fail to perform as planned,
generation insurance and purchased call options reduce the Company's exposure to
electric price spikes in the summer months.
RG&E's exposure to market price fluctuations of the cost of natural gas is
further limited as the result
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29
of the Gas Cost Adjustment (GCA), a regulatory mechanism that transfers
substantially all gas commodity price risk to the customer. Nonetheless, RG&E
does hedge approximately 70% of its gas supply price through the purchase of
futures contracts and the use of storage assets. The balance of RG&E's natural
gas requirements is procured through spot market purchases and is subject to
market price fluctuations.
RG&E does not hold open speculative positions in any commodity for trading
purposes.
Energetix has entered into electric and natural gas purchase commitments
with numerous suppliers. These commitments support fixed price offerings to
retail electric and gas customers. Griffith is in the business of purchasing
various petroleum-related commodities for resale to its customers. To manage
the resulting market price risk, Griffith enters into various exchange-traded
futures and option contracts and over-the-counter contracts with third parties.
All hedge contracts are accounted for under the deferral method with gains and
losses from the hedging activity included in the cost of sales as inventories
are sold or as the hedge transaction occurs. Commodity instruments not
designated as effective hedges are marked to market at the end of the reporting
period, with the resulting gains or losses recognized in cost of sales. These
contracts are closely monitored on a daily basis to manage the price risk
associated with inventory and future sales commitments. At June 30, 2000 and
December 31, 1999 Griffith's net deferred gains on open hedge contracts were
immaterial.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to Part I, Item 3, Legal proceedings in the RGS and RG&E
combined 1999 Form 10-K and Part II, Item 1, Legal Proceedings in the RGS and
RG&E combined Form 10-Q for the quarter ended March 31, 2000.
For additional information on Legal Proceedings reference is made to Note
3 of the Notes to Financial Statements.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K:
RGS Energy Group, Inc.
Rochester Gas and Electric Corporation
A report was filed on Form 8-K dated May 25, 2000 reporting under Item
5, Other Events, (a) NYSDEC issued an air pollution notice of violation to RG&E
regarding operation of its Beebee and Russell coal-fired generation plants and
(b) filing as an exhibit a Press Release of RG&E announcing an auction process
by RG&E, NYSEG and Niagara Mohawk in connection with their ownership interests
in Nine Mile Two and Niagara Mohawk's interest in Nine Mile One.
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30
EXHIBIT INDEX
Exhibit 10-1* Change of Control Agreement effective April 26, 2000 between
RGS, Energetix and Michael J. Bovalino.
Exhibit 10-2* Change of Control Agreement effective April 26, 2000 between
RGS, RG&E and Thomas S. Richards.
Exhibit 10-3* Change of Control Agreement effective April 26, 2000 between
RGS, RG&E and J. Burt Stokes.
Exhibit 10-4* Change of Control Agreement effective April 26, 2000 between
RGS, RG&E and Michael T. Tomaino.
Exhibit 10-5* Change of Control Agreement effective April 26, 2000 between
RGS, RG&E and Paul C. Wilkens.
Exhibit 27-1 Financial Data Schedule pursuant to Item 601(c) of Regulation
S-K for RGS.
Exhibit 27-2 Financial Data Schedule pursuant to Item 601(c) of Regulation
S-K for RG&E.
* Denotes executive compensation plans and arrangements.
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31
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrants have duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
RGS ENERGY GROUP, INC.
----------------------
(Registrant)
Date: August 11, 2000 By /s/ J.B. STOKES
--------------------------
J.Burt Stokes
Senior Vice President and
Chief Financial Officer
Date: August 11, 2000 By /s/ WILLIAM J. REDDY
----------------------
William J. Reddy
Controller
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: August 11, 2000 By /s/ J.B. STOKES
--------------------------
J.Burt Stokes
Senior Vice President and
Chief Financial Officer
Date: August 11, 2000 By /s/ WILLIAM J. REDDY
----------------------
William J. Reddy
Vice President and
Controller
