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 March 31, 2000
----------------
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _____________
Commission Registrant, State of Incorporation I.R.S. Employer
File Number Address and Telephone Number Identification No.
- ----------- ---------------------------- ------------------
0-30338 RGS Energy Group, Inc. 16-1558410
(Incorporated in New York)
Rochester, NY 14649
Telephone (716)771-4444
1-672 Rochester Gas and Electric Corporation 16-0612110
(Incorporated in New York)
Rochester, NY 14649
Telephone (716)546-2700
Indicate by check mark whether each registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No ___
-
As of the close of business on April 30, 2000, (i) RGS Energy Group, Inc.
("RGS") had outstanding 35,487,513 shares of Common Stock ($.01 par value) and,
(ii) all of the outstanding shares of Common Stock ($5 par value) of Rochester
Gas and Electric Corporation ("RG&E")were held by RGS.
RG&E meets the conditions set forth in General Instructions (H)(1)(a) and (b)
of Form 10-Q and is therefore, filing this form with the reduced disclosure
format pursuant to General Instructions (H)(2).
2
INDEX
Page No.
PART I - FINANCIAL INFORMATION
RGS Energy Group, Inc.
Consolidated Balance Sheet - March 31, 2000 and
December 31, 1999................................................ 1-2
Consolidated Statement of Income - Three Months Ended
March 31, 2000 and 1999........................................... 3
Consolidated Statement of Cash Flows - Three Months
Ended March 31, 2000 and 1999.................................... 4
Rochester Gas and Electric Corporation
Balance Sheet - March 31, 2000 and December 31, 1999............... 5-6
Statement of Income - Three Months Ended
March 31, 2000 and 1999........................................... 7
Statement of Cash Flows - Three Months Ended
March 31, 2000 and 1999....................................... 8
Notes to Financial Statements....................................... 9-13
Management's Discussion and Analysis of Financial
Condition and Results of Operations.............................. 13-23
Quantitative and Qualitative Disclosures About
Market Risk....................................................... 23-24
PART II - OTHER INFORMATION
Legal Proceedings................................................... 24-26
Submission of Matters to a Vote of Security Holders................. 26
Exhibits and Reports on Form 8-K.................................... 26
Signatures.......................................................... 27
_____________
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.
3
Abbreviations and Glossary
Company or RGS RGS Energy Group, Inc., a holding company formed August 2,
1999, which is the parent company of Rochester Gas and
Electric Corporation, RGS Development Corporation and
Energetix, Inc.
CWIP Construction work-in progress
RGS DEVELOPMENT RGS Development Corporation, a wholly-owned subsidiary of
the Company
EITF Emerging Issues Task Force
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
ISO Independent System Operator
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
NYNOC New York Nuclear Operating Company
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
1
PART 1 - FINANCIAL INFORMATION
- ------------------------------
ITEM1. FINANCIAL STATEMENTS
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
March 31, December 31,
2000 1999
Assets (Unaudited)
- ------------------------------------------------------------------------------------------------------------
Utility Plant
Electric $2,427,860 $2,399,532
Gas 458,734 453,634
Common 133,099 130,118
Nuclear 276,471 270,447
--------- ---------
3,296,164 3,253,731
Less: Accumulated depreciation 1,679,900 1,636,955
Nuclear fuel amortization 243,395 239,243
--------- ---------
1,372,869 1,377,533
Construction work in progress 95,230 95,862
--------- ---------
Net Utility Plant 1,468,099 1,473,395
--------- ---------
Current Assets
Cash and cash equivalents 27,758 8,288
Accounts receivable, net of allowance for doubtful accounts:
2000 - $34,001; 1999 - $34,026 98,307 90,239
Unbilled revenue receivable 56,841 58,005
Materials, supplies and fuels 20,532 38,206
Prepayments 32,458 24,576
Other current assets 645 523
--------- ---------
Total Current Assets 236,541 219,837
--------- ---------
Intangible Assets
Goodwill, net 13,093 13,894
Other Intangible Assets 11,152 7,338
--------- ---------
Total Intangible Assets 24,245 21,232
--------- ---------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 227,189 220,815
Nine Mile Two deferred costs 27,944 28,206
Unamortized debt expense 17,716 17,984
Other deferred debits 12,916 13,137
Regulatory assets 445,869 466,231
Other assets 1,382 2,037
--------- ---------
Total Deferred Debits and Other Assets 733,016 748,410
--------- ---------
Total Assets $2,461,901 $2,462,874
--------- ---------
2
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
March 31, December 31,
2000 1999
Capitalization and Liabilities (Unaudited)
- ----------------------------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $ 580,087 $ 580,070
- promissory notes 236,620 235,395
Preferred stock redeemable at option of Company 47,000 47,000
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 March 31, 2000 and at December 31, 1999 700,803 700,268
Retained earnings 175,602 153,186
---------- ----------
876,405 853,454
Less: Treasury stock at cost (3,320,400 shares at March 31, 2000
and 2,942,600 shares at December 31, 1999) 91,089 83,252
---------- ----------
Total Common Shareholders' Equity 785,316 770,202
---------- ----------
Total Capitalization 1,674,023 1,657,667
---------- ----------
Long Term Liabilities
Nuclear waste disposal 93,011 91,743
Uranium enrichment decommissioning 11,027 10,911
Site remediation 23,884 23,698
---------- ----------
127,922 126,352
---------- ----------
Current Liabilities
Long term debt due within one year 7,972 37,643
Short term debt 10,000 10,500
Accounts payable 55,404 54,221
Dividends payable 16,926 17,078
Equal payment plan - 10,529
Other 73,423 39,385
---------- ----------
Total Current Liabilities 163,725 169,356
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 311,376 318,694
Pension costs accrued 44,164 48,628
Kamine deferred costs 57,008 58,738
Post employment benefits 50,388 48,653
Other 33,295 34,786
---------- ----------
Total Deferred Credits and Other Liabilities 496,231 509,499
---------- ----------
Commitments and Other Matters - -
---------- ----------
Total Capitalization and Liabilities $2,461,901 $2,462,874
---------- ----------
The accompanying notes are an integral part of the financial statements.
3
RGS Energy Group Inc.
Consolidated Statement of Income
(Thousands of dollars)
(Unaudited)
- --------------------------------------------------------------------------------
For the Three Months Ended
March 31,
2000 1999
---------- ---------
Operating Revenues
Electric $179,784 $164,671
Gas 119,568 117,373
Other 86,498 44,047
-------- --------
Total Operating Revenues 385,850 326,091
Fuel Expenses
Fuel for electric generation 10,963 11,518
Purchased electricity 18,215 12,757
Gas purchased for resale 63,937 60,721
Other fuel expenses 75,788 34,316
-------- --------
Total Fuel Expenses 168,903 119,312
-------- --------
Operating Revenues Less Fuel Expenses 216,947 206,779
Other Operating Expenses
Operations and maintenance excluding fuel 70,517 65,754
Unregulated operating and maintenance expenses excluding fuel 7,385 6,669
Depreciation and amortization 28,995 29,141
Taxes - state, local & other 30,167 31,355
Federal income tax 26,202 23,862
-------- --------
Total Other Operating Expenses 163,266 156,781
-------- --------
Operating Income 53,681 49,998
Other (Income) & Deductions
Allowance for other funds used during construction (191) (228)
Federal income tax 470 518
Other - net (1,175) (1,570)
-------- --------
Total Other (Income) & Deductions (896) (1,280)
-------- --------
Income Before Interest Charges 54,577 51,278
Interest Charges
Long term debt 14,465 13,150
Other - net 1,076 1,232
Allowance for borrowed funds used during construction (306) (366)
-------- --------
Total Interest Charges 15,235 14,016
-------- --------
Dividends on Preferred Stock 925 1,116
-------- --------
Net Income Applicable to Common Stock 38,417 36,146
-------- --------
Average Number of Common Shares (000's)
Common Stock 35,783 37,249
Common Stock and Equivalents 35,803 37,360
Earnings per Common Share - Basic $ 1.07 $ 0.97
Earnings per Common Share - Diluted $ 1.07 $ 0.97
Cash Dividends Paid per Common Share $ 0.45 $ 0.45
The accompanying notes are an integral part of the financial statements.
4
RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
Three Months Ended
(Thousands of Dollars) March 31,
- ---------------------------------------------------------------------------------------------------------
2000 1999
--------- ---------
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 39,342 $ 37,262
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 33,380 32,771
Deferred recoverable fuel costs 15,242 13,535
Income taxes deferred (3,348) 115
Allowance for funds used during construction (497) (594)
Unbilled revenue 1,164 6,700
Post employment benefit/pension costs 1,525 6,299
Provision for doubtful accounts (25) 23
Changes in certain current assets and liabilities:
Accounts receivable (8,043) (29,184)
Materials, supplies and fuels 17,674 22,717
Taxes accrued 2,804 5,736
Payroll accrued (907) -
Accounts payable 1,183 20,678
Other current assets and liabilities, net 24,037 14,870
Other, net (6,622) (10,918)
-------- --------
Total Operating 116,909 120,010
-------- --------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (26,771) (29,924)
Nuclear generating plant decommissioning fund (5,136) (2,571)
Acquisitions, net of cash (1,296) -
Other, net 2 174
-------- --------
Total Investing (33,201) (32,321)
-------- --------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from short term borrowings, net (500) (46,960)
Retirement of long term debt (30,000) -
Repayment of promissory notes (919) (347)
Dividends paid on preferred stock (925) (1,116)
Dividends paid on common stock (16,153) (16,820)
Payment for treasury stock (7,837) (10,541)
Equal Payment Plan (10,529) (11,025)
Other, net 2,625 (227)
-------- --------
Total Financing (64,238) (87,036)
-------- --------
Increase in cash and cash equivalents 19,470 653
Cash and cash equivalents at beginning of period 8,288 6,523
-------- --------
Cash and cash equivalents at end of period $ 27,758 $ 7,176
-------- --------
The accompanying notes are an integral part of the financial statements
5
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
March 31, December 31,
2000 1999
Assets (Unaudited)
- -----------------------------------------------------------------------------------------------------------
Utility Plant
Electric $2,427,860 $2,399,532
Gas 458,734 453,634
Common 109,728 107,469
Nuclear 276,471 270,447
---------- ----------
3,272,793 3,231,082
Less: Accumulated depreciation 1,676,764 1,634,334
Nuclear fuel amortization 243,395 239,243
---------- ----------
1,352,634 1,357,505
Construction work in progress 95,230 95,862
---------- ----------
Net Utility Plant 1,447,864 1,453,367
---------- ----------
Current Assets
Cash and cash equivalents 28,663 6,443
Accounts receivable, net of allowance for doubtful accounts:
2000 - $33,378; 1999 - $33,365 76,052 70,388
Affiliate receivable 17,248 13,197
Unbilled revenue receivable 51,301 55,661
Materials, supplies and fuels 15,090 33,378
Prepayments 32,178 23,294
Other current assets 1,245 145
---------- ----------
Total Current Assets 221,777 202,506
---------- ----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 227,189 220,815
Nine Mile Two deferred costs 27,944 28,206
Unamortized debt expense 17,716 17,984
Other deferred debits 12,915 13,760
Regulatory assets 445,869 466,231
---------- ----------
Total Deferred Debits and Other Assets 731,633 746,996
---------- ----------
Total Assets $2,401,274 $2,402,869
========== ==========
6
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
March 31, December 31,
2000 1999
Capitalization and Liabilities (Unaudited)
- -----------------------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $ 580,087 $ 580,070
- promissory notes 215,011 215,930
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 March 31, 2000 and at December 31, 1999 700,803 700,268
Retained earnings 159,334 137,854
---------- ----------
860,137 838,122
Less: Treasury stock at cost (3,320,400 shares at March 31, 2000
and 2,942,600 shares at December 31, 1999) 91,089 83,252
---------- ----------
Total Common Shareholders' Equity 769,048 754,870
---------- ----------
Total Capitalization 1,636,146 1,622,870
---------- ----------
Long Term Liabilities
Nuclear waste disposal 93,011 91,743
Uranium enrichment decommissioning 11,027 10,911
Site remediation 22,357 22,357
---------- ----------
126,395 125,011
---------- ----------
Current Liabilities
Long term debt due within one year 3,781 33,781
Accounts payable 45,740 42,263
Affiliate payable 14,064 12,961
Dividends payable 16,926 17,078
Equal payment plan - 10,529
Other 64,957 33,243
---------- ----------
Total Current Liabilities 145,468 149,855
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 308,742 314,683
Pension costs accrued 44,164 48,628
Kamine deferred costs 57,008 58,738
Post employment benefits 50,388 48,653
Other 32,963 34,431
---------- ----------
Total Deferred Credits and Other Liabilities 493,265 505,133
---------- ----------
Commitments and Other Matters - -
---------- ----------
Total Capitalization and Liabilities $2,401,274 $2,402,869
---------- ----------
The accompanying notes are an integral part of the financial statements.
7
Rochester Gas and Electric Corporation
Statement of Income
(Thousands of dollars)
(Unaudited)
- --------------------------------------------------------------------------------
For the Three Months Ended
March 31,
2000 1999
--------- ---------
Operating Revenues
Electric $176,708 $164,671
Gas 114,143 117,373
Other - 44,047
-------- --------
Total Operating Revenues 290,851 326,091
Fuel Expenses
Fuel for electric generation 10,963 11,518
Purchased electricity 16,163 12,757
Gas purchased for resale 59,238 60,721
Other fuel expenses - 34,316
-------- --------
Total Fuel Expenses 86,364 119,312
-------- --------
Operating Revenues Less Fuel Expenses 204,487 206,779
Other Operating Expenses
Operations and maintenance excluding fuel 70,517 65,754
Unregulated operating and maintenance expenses excluding fuel - 6,669
Depreciation and amortization 28,060 29,141
Taxes - state, local & other 28,584 31,355
Federal income tax 25,145 23,862
-------- --------
Total Other Operating Expenses 152,306 156,781
-------- --------
Operating Income 52,181 49,998
Other (Income) & Deductions
Allowance for other funds used during construction (191) (228)
Federal income tax 417 518
Other - net (1,042) (1,570)
-------- --------
Total Other (Income) & Deductions (816) (1,280)
-------- --------
Income Before Interest Charges 52,997 51,278
Interest Charges
Long term debt 14,096 13,150
Other - net 864 1,232
Allowance for borrowed funds used during construction (306) (366)
-------- --------
Total Interest Charges 14,654 14,016
-------- --------
Net Income 38,343 37,262
-------- --------
Dividends on Preferred Stock 925 1,116
-------- --------
Net Income Applicable to Common Stock 37,418 36,146
-------- --------
Average Number of Common Shares (000's)
Common Stock 35,783 37,249
The accompanying notes are an integral part of the financial statements.
8
ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS
(Unaudited)
Three Months Ended
(Thousands of Dollars) March 31,
- -------------------------------------------------------------------------------------------------------
2000 1999
-------- --------
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 38,343 37,262
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 32,428 32,771
Deferred recoverable fuel costs 15,242 13,535
Income taxes deferred (1,970) 115
Allowance for funds used during construction (497) (594)
Unbilled revenue 4,360 6,700
Post employment benefit/pension costs 1,525 6,299
Provision for doubtful accounts 13 23
Changes in certain current assets and liabilities:
Accounts receivable (9,729) (29,184)
Materials, supplies and fuels 18,288 22,717
Taxes accrued 4,028 5,736
Payroll accrued (45) -
Accounts payable 4,580 20,678
Other current assets and liabilities, net 18,809 14,870
Other, net (4,988) (10,918)
-------- --------
Total Operating 120,387 120,010
-------- --------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (26,345) (29,924)
Nuclear generating plant decommissioning fund (5,136) (2,571)
Other, net (475) 174
-------- --------
Total Investing (31,956) (32,321)
-------- --------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from short term borrowings, net - (46,960)
Retirement of long term debt (30,000) -
Repayment of promissory notes (919) (347)
Dividends paid on preferred stock (925) (1,116)
Dividends paid on common stock (16,153) (16,820)
Payment for treasury stock (7,837) (10,541)
Equal payment plan (10,529) (11,025)
Other, net 152 (227)
-------- --------
Total Financing (66,211) (87,036)
-------- --------
Increase in cash and cash equivalents 22,220 653
Cash and cash equivalents at beginning of period 6,443 6,523
-------- --------
Cash and cash equivalents at end of period $ 28,663 $ 7,176
======== ========
The accompanying notes are an integral part of the financial statements.
9
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.
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.
For the Three Months Ended March 31, 2000
Regulated Regulated
Electric Gas Unregulated
-------- --------- -----------
(thousands of dollars) 2000 1999 2000 1999 2000 1999
- ---------------------- -------- -------- -------- -------- -------- --------
Operating Income $ 34,298 $ 27,987 $ 17,883 $ 20,509 $ 1,474 $ 1,517
Revenues - External Customers 176,708 164,088 114,143 115,801 111,892 56,076
Revenues - Intersegment Transactions 16,893 9,696 -- 178 -- --
The operations of RGS Development Corporation and Energyline 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:
10
For the Three Months
Ended March 31
Revenues 2000 1999
-------- --------
Regulated Electric $176,708 $164,088
Regulated Gas 114,143 115,801
Unregulated 111,892 56,076
-------- --------
Total 402,743 335,965
Reported on RGS Consolidated
Income Statement 385,850 326,091
Difference to reconcile 16,893 9,874
Intersegment Revenue
Regulated Electric from Unregulated 16,893 9,696
Regulated Gas from Unregulated - 178
-------- --------
Total Intersegment 16,893 9,874
Note 3. COMMITMENTS AND OTHER MATTERS
The following matters supplement the information contained in Note 10 to
the financial statements included in the RGS and RG&E combined Annual Report on
Form 10-K for the year ended December 31, 1999 and should be read in conjunction
with the material contained in that Note.
REGULATORY ASSETS
With PSC approval RG&E has deferred certain costs rather than recognize
them on its books when incurred. Such deferred costs are then recognized as
expenses when they are included in rates and recovered from customers. Such
deferral accounting is permitted by SFAS-71, Accounting for the Effects of
Certain Types of Regulation. These deferred costs are shown as Regulatory Assets
on the Company's and RG&E's Balance Sheets. Such cost deferral is appropriate
under traditional regulated cost-of-service rate setting, where all prudently
incurred costs are recovered through rates. In a purely competitive pricing
environment, such costs might not have been incurred and could not have been
deferred. Accordingly, if RG&E was no longer allowed to defer some or a portion
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 March 31, 2000 and
December 31, 1999:
Millions of Dollars
Mar. 31, 2000 Dec. 31, 1999
------------- -------------
Kamine Settlement $185.6 $187.5
Income Taxes 125.5 129.5
Oswego Plant Sale 77.7 78.6
Deferred Environmental SIR costs 20.5 20.5
Uranium Enrichment Decommissioning Deferral 13.6 13.9
Storm Costs 8.7 8.5
Other, net 14.3 27.7
------ ------
Total - Regulatory Assets $445.9 $466.2
====== ======
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
11
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 March 31, 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 Cost Recovery" below, may affect
this exposure; but whether and to what extent there may be an impact on the
level and recoverability of strandable assets cannot be determined at this time.
At March 31, 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. RG&E is unable to determine
when this proceeding may conclude (see PSC Proceeding on Nuclear Generation
under Item 2, Management's Discussion and Analysis of Financial Condition and
Results of Operations). The ultimate determination in this proceeding or any
proceeding to consider RG&E's proposed purchase of nuclear plants as discussed
under "Nuclear-Related Matters" could have an impact on strandable assets and
the recovery of nuclear costs.
NUCLEAR-RELATED MATTERS
NINE MILE NUCLEAR PLANTS. On June 24, 1999, Niagara Mohawk and New York
State Electric and Gas (NYSEG) announced their intention to sell their interests
in the Nine Mile One and Nine Mile Two nuclear plants to AmerGen Energy Company,
L.L.C. (AmerGen), a joint venture of PECO Energy of Philadelphia and British
Energy. Niagara Mohawk owns 41 percent of Nine Mile Two and 100 percent of Nine
Mile One and NYSEG owns 18 percent of Nine Mile Two.
RG&E's 14 percent interest in Nine Mile Two was not included in the
proposal but RG&E has a right of first refusal to buy the 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, 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.
Discussions with the staff of the PSC and Nine Mile Two co-owners regarding
the process by which their interests might be offered for sale and the
regulatory impact thereof continue but RG&E is unable to predict the ultimate
outcome.
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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. The Government has
moved to dismiss the utilities' complaints. A decision on the Government's
motion is expected soon. Similar cases brought in the Federal Court of Claims
have been dismissed.
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. NYSDEC is continuing its investigation (including reviewing the
documents submitted by the letter recipients) in an effort to determine whether
it believes any violations have occurred. RG&E cannot yet assess the potential
impact of this initiative on company operations.
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 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
13
inclusion in rates charged pursuant to RG&E's distribution access tariff. The
Settlement also states that "the Parties intend that the provisions of this
Settlement will allow RG&E to continue to recover such costs, during the term of
the Settlement, under SFAS-71", and that "such treatment shall be consistent
with the principle that RG&E shall have a reasonable opportunity beyond July 1,
2002 to recover all such costs". The fixed portion of the non-nuclear generation
to-go 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 would no longer be able to apply SFAS-71. These costs have been below
prevailing market prices. RG&E's net investment at March 31, 2000 in nuclear
generating assets is $623.3 million and in non-nuclear generating assets is
$58.7 million. (See "Nine Mile Nuclear Plants" for information concerning status
of the interests in Nine Mile Two owned by two co-owners and Nine Mile One owned
by Niagara Mohawk.)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The discussion presented below contains statements which are not historic
fact and which can be classified as forward looking. These statements can be
identified by the use of certain words which suggest forward looking
information, such as "believes," "will," "expects," "projects," "estimates" and
"anticipates". They can also be identified by the use of words which relate to
future goals or strategies. In addition to the assumptions and other factors
referred to specifically in connection with the forward looking statements, some
of the factors that could have a significant effect on whether the forward
looking statements ultimately prove to be accurate include:
1. uncertainties related to the regulatory treatment of nuclear generation
facilities including, (1) the PSC's indication that it would prefer that all
of the current owners sell their interests in the Nine Mile Point nuclear
generating facilities and determine market value through an open process, (2)
the exercise of the co-owners' rights of first refusal and (3) any changes in
regulatory status of nuclear generating facilities and their related costs,
including recovery of costs related to spent fuel and decommissioning.
2. uncertainties related to the costs associated with management of the New York
electrical grid by the New York Independent System Operator and the
competitive electric wholesale market.
3. any state or federal legislative or regulatory initiatives (including the
results of negotiations between RG&E and the PSC regarding certain gas
restructurings) that affect the cost or recovery of investments necessary to
provide utility service in the electric and natural gas industries. Such
initiatives could include, for example, changes in the regulation of rate
structures or changes in the speed or degree to which competition occurs in
the electric and natural gas industries;
4. any changes in the ability of RG&E to recover environmental compliance costs
through increased rates;
5. any changes in the rate of industrial, commercial and residential growth in
RG&E's and RGS's service territories;
6. the development of any new technologies which allow customers to generate
their own energy or produce lower cost energy;
7. any unusual or extreme weather or other natural phenomena;
8. the ability of RGS to manage profitably new unregulated operations;
9. certain unknowable risks involved in operating unregulated businesses in new
territories and new industries;
14
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.
Shown below is a listing of the principal items discussed.
RGS ENERGY GROUP, INC. Page 14
Unregulated Subsidiaries
ROCHESTER GAS AND ELECTRIC CORPORATION
Competition Page 15
PSC Competitive Opportunities Case Settlement
Energy Choice
Nine Mile Nuclear Plants
New York Independent System Operator
Prospective Financial Position
Rates and Regulatory Matters Page 20
PSC Gas Restructuring Policy Statement
Gas Proposal and Interim Settlement
Flexible Pricing Tariff
LIQUIDITY AND CAPITAL RESOURCES Page 21
Capital and Other Requirements
Financing
Redemption of Securities
Stock Repurchase Plan
EARNINGS SUMMARY Page 21
RESULTS OF OPERATIONS Page 22
Operating Revenues and Sales
Operating Expenses
Other Statement of Income Items
DIVIDENDS Page 23
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 Corporation and Energetix, Inc.
RG&E offers regulated electric and natural gas utility service in its
franchise territory. Energetix, Inc. provides energy products and services
throughout upstate New York. RGS Development Corporation offers energy systems
development and management services.
15
Unregulated Subsidiaries. It is part of RGS's financial strategy to
seek growth by entering into unregulated businesses of which RGS has invested
$60 million (including loan guarantees) as of March 31, 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, Inc. (Energetix) effective January 1, 1998. Energetix is
an unregulated subsidiary that brings energy products and services to the
marketplace both within and outside of RG&E's regulated franchise territory.
Energetix markets electricity, natural gas, oil, gasoline, and propane fuel
energy services in an area extending in approximately a 150-mile radius around
Rochester.
In 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 March 31, 2000, RGS
Development operations have not been material to RGS's results of operations or
its financial condition.
ROCHESTER GAS AND ELECTRIC CORPORATION
COMPETITION
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. During 1996 and 1997,
RG&E, the staff of the PSC and several other parties negotiated an agreement
which was approved by the PSC in November 1997 (the "Settlement"). The
Settlement sets the framework for the introduction and development of open
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 be
structurally separate from the regulated utility functions. Although the
Settlement provides incentives for the sale of generating assets, it
16
does not require RG&E to divest generating or other assets or write-off stranded
costs. Additionally, RG&E will be given a reasonable opportunity to recover
substantially all of its prudently incurred costs, including those pertaining to
generation and purchased power.
RG&E believes that the Settlement has not adversely affected its
eligibility to continue to apply certain accounting rules applicable to
regulated industries. In particular, RG&E believes it continues to be eligible
for the treatment provided by SFAS-71 which allows RG&E to include assets on its
balance sheet based on its regulated ability to recoup the cost of those assets.
However, this may not be the case with respect to certain operational costs
associated with non-nuclear generation (see Note 3 of the Notes to Financial
Statements under the heading Other Matters, EITF Issue 97-4, Deregulation of the
Pricing of Electricity).
RG&E's retail access program, Energy Choice, was approved by the PSC as
part of the Settlement and went into effect on July 1, 1998. Details of the
Energy Choice Program are discussed below.
One party to the Settlement negotiations has commenced an action for
declaratory and injunctive relief as to certain provisions of the Settlement and
the PSC's approval of it. RG&E is unable, at this time, to predict the outcome
of this action.
ENERGY CHOICE. On July 1, 1998, RG&E officially began implementation of
its full-scale electric retail access Energy Choice program. As of July 1, 1999,
RG&E entered its second year of this program. There are 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 the Energy Choice program included a four year
phase-in process to allow RG&E and other parties to manage the transition to
electric competition in an orderly fashion. During the first year of the
program, participation in Energy Choice was limited to no more than 10 percent
of RG&E's total annual retail electric kilowatt-hour sales (670,000 annualized
megawatt-hours). Essentially, until this 10 percent limit was achieved, RG&E's
electric retail customers could seek out or be approached by alternative energy
service companies for electricity to be resold and then delivered over RG&E's
distribution system. By February 1, 1999, only six months into the Energy Choice
program, this 10 percent limit was achieved by qualified competitive energy
service companies in RG&E's service territory. For the second year of the
program, beginning July 1, 1999, this limit increased from 10 percent to
approximately 20 percent. By March 31, 2000, approximately 16.3 percent of total
RG&E sales had shifted to competitive energy service companies. On July 1, 2000
this limit will increase from 20 percent to 30 percent. On July 1, 2001, all
retail customers will be eligible to purchase energy from alternative energy
service companies. The phase-in of the Energy Choice program over the next few
years eventually will give retail electric customers the opportunity to purchase
energy, capacity and retailing services from competitive energy service
companies. 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).
17
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,
energy service companies were able to choose their own sources of energy supply,
while RG&E continued to provide to them, through its bundled distribution rates,
the generating capacity (installed reserve) needed to serve their retail
customers. In addition, during the "Energy-Only" stage, energy service companies
had the option of purchasing "full-requirements" (i.e. delivery services plus
energy) from RG&E.
The "Energy and Capacity" stage, the second stage of the phase-in, was
scheduled to begin this past Fall. In this stage, energy service companies may
purchase both energy and capacity in the open market. As a result of a delay in
establishing an Independent System Operator entity in New York State, RG&E, with
the consent of the energy service companies participating in the Retail Access
Program, reserved capacity for the 1999-2000 winter capability period and will
provide energy and capacity for the energy service companies through that
period. Essentially, energy service companies will purchase "full-requirements"
(delivery services plus energy and capacity) from RG&E.
During the initial "Energy Only" stage of the retail access program,
RG&E's distribution rate was set by deducting 2.305 cents per kilowatt-hour from
its full service ("bundled") rates. The 2.305 cents per kilowatt-hour was
comprised of 1.905 cents per kilowatt-hour (an estimate of the wholesale market
price of electricity) plus 0.4 cents per kilowatt-hour for its avoided cost of
retailing services.
During the "Energy and Capacity" stage, RG&E's distribution rates will
equal the bundled rate less RG&E's cost of the electric commodity and RG&E's
non-nuclear generating capacity. During this stage of the program, up until June
30, 2000, RG&E's distribution rates will be set by deducting 3.0712 cents per
kilowatt-hour from its full service ("bundled") rates. The 3.0712 cents per
kilowatt-hour is comprised of 2.6712 cents per kilowatt-hour (an estimate of the
wholesale market price of electric energy and capacity) plus 0.4 cents per
kilowatt-hour for its avoided cost of retailing services. Beginning July 1,
2000, RG&E's distribution rates will be set by deducting 3.0816 cents per
kilowatt hour from its full service ("bundled") 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.
As of March 31, 2000, eight energy service companies, including
Energetix, the Company's unregulated subsidiary, are qualified by RG&E to serve
retail customers under the Energy Choice program. In addition to Energetix,
these companies are Columbia Energy Power Marketing Corporation, DukeSolutions,
Inc., Northeast Energy Services, Inc.(NORESCO), North American Energy, NYSEG
Solutions, Inc., Select Energy Inc., and TXU Energy Services, Inc. In addition,
the County of Monroe has been qualified to act as its own energy service company
to service its own facilities, as well as serve other retail customers. As of
March 31, 2000, all energy service companies had opted to purchase
"full-requirements" from RG&E for the winter capability period (November 1, 1999
through April 30, 2000) to serve their retail customers.
With the commencement of the "Energy and Capacity" stage and the
implementation of the New York Independent System Operator on November 18, 1999
(see FERC Open Access Transmission Orders and Company Filings), the
responsibility for purchasing not only energy, but also capacity, shifted to the
energy service companies. However, these energy service companies, as
"full-requirements" customers of RG&E during the winter capability period, will
be purchasing energy and capacity from RG&E at 2.6712 cents per kilowatt-hour.
The cost impact on RG&E of providing "full requirements" energy and capacity for
this time period will be determined by prices in the New York State wholesale
market. The PSC has approved a request by RG&E to extend "full-requirements"
availability through October 31, 2000. As of March 31, 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 transfer
load into the competitive wholesale market, but once they make this choice, they
will not be able to return this load to "full requirements".
18
Once RG&E no longer provides "full requirements" to the energy service
companies, they will assume responsibility for obtaining their own supplies.
There will be a revenue decrease when RG&E no longer collects the rates
described above for energy and capacity. This will be offset to some extent by
decreased costs resulting from no longer acquiring energy and capacity for the
energy service companies. The extent of this offset will be determined by market
prices.
In December 1999, two petitions were filed with the PSC, one by an
electric utility operating in New York State, and the other jointly by five
energy marketers and consultants, calling upon the PSC to examine, and to order
certain changes in, RG&E's retail access program. In particular, these
petitioners 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 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, 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.
19
Discussions with the staff of the PSC and Nine Mile Two co-owners
regarding the process by which their interests might be offered for sale and the
regulatory impact thereof continue but RG&E is unable to predict the ultimate
outcome.
NEW YORK INDEPENDENT SYSTEM OPERATOR. In November 1999 following FERC
approval, the New York State Independent System Operator (NYISO) implemented a
competitive wholesale market for the sale, purchase and transmission of
electricity and ancillary services in New York State. NYISO tariffs for
market-based rates for energy, ancillary services, and installed capacity sold
through the NYSIO were approved by FERC. The NYISO and the New York State
Reliability Council were formed to restructure the New York Power Pool in
response to FERC Order 888.
During the first quarter of 2000, the NYISO's total cost of providing
operating reserves on an hourly basis has exceeded the cost that would be
expected in a workable competitive marketplace. Since the beginning of the year,
RG&E, in addition to other New York State public utilities and several
load-serving entities, has been experiencing 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. For comparison purposes, the rate charged by
RG&E under its Open Access Transmission Tariff (OATT) was $.31/MWH.
On April 7, RG&E filed a complaint with FERC against the NYISO. RG&E
seeks corrective re-calculation of operating reserve prices for prior periods
and prospective relief from injuries resulting from the NYISO's operating
reserves market. RG&E contends that not only are the current costs of operating
reserves not consistent with RG&E's pre-NYISO tariff rates as described above,
these costs are excessive in comparison to the operating reserves paid in
neighboring ISOs. RG&E further contends that market forces are not driving the
prices of operating reserves given the fact that energy flowing on the system
has not reached peak levels and there has been available generation that is
unscheduled and ready to provide operating reserves at costs lower than those
collected. Niagara Mohawk and NYSEG have filed similar complaints with FERC
against the NYISO.
Finally, 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. Specifically, the NYISO requested that all bids for
operating reserves be cost-based until the operating reserves markets are
modified so as to be workably competitive. The NYISO has requested that a
settlement process involving all the buyers and sellers in the New York
operating reserve market be concluded within 90 days.
RG&E cannot predict the outcome of any of the FERC proceedings as
discussed above, or what effects regulations and/or financial relief ultimately
adopted or granted by FERC will have, if any, 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
20
Note 3 of the Notes to Financial Statements.
At March 31, 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 PSC Proceeding on Nuclear
Generation). The ultimate determination in this proceeding or any proceeding to
consider RG&E's proposed purchase of nuclear plants as discussed under Proposed
Transfer of Nuclear Plants could have an impact on strandable assets and the
recovery of nuclear costs.
RATES AND REGULATORY MATTERS
PSC GAS RESTRUCTURING POLICY STATEMENT. On November 3, 1998, the PSC
issued a gas restructuring policy statement ("Gas Policy Statement") announcing
its conclusion that, among other things, the most effective way to establish a
competitive gas supply market is for gas distribution utilities to cease selling
gas. The PSC established a transition process in which it plans to address three
groups of issues: (1) individual gas utility plans to implement the PSC's vision
of the market; (2) key generic issues to be dealt with through collaboration
among gas utilities, marketers, pipelines and other stakeholders, and (3)
coordination of issues that are common to both the gas and the electric
industries. The PSC has encouraged settlement negotiations with each gas utility
pertaining to the transition to a fully competitive gas market. RG&E, the PSC
Staff and other interested parties have been participating in settlement
discussions in response to the specific requirements of the Policy Statement.
GAS PROPOSAL AND INTERIM SETTLEMENT. In August 1998, prior to issuance
of the PSC's Gas Policy Statement (see PSC Gas Restructuring Policy Statement
above), RG&E had commenced negotiations with the PSC staff and other parties to
develop a comprehensive multi-year settlement of various issues, including rates
and the structure of RG&E's gas business. Because the negotiation of a
comprehensive settlement was not anticipated to conclude until mid-1999, the
parties to the negotiations agreed to an Interim Settlement, effective November
1998 through June 1999, that dealt with such issues as rates, transportation and
storage capacity costs, assignment of capacity, and retail access. Significant
features of the Interim Settlement include a freeze on base rates at the current
levels (which were fixed at July 1994 levels), the imputation of $11.9 million
in revenues from the remarketing of capacity and a limit on RG&E's exposure to
costs associated with the migration of customers from RG&E to marketers for
sales and service.
Discussions following the expiration of the Interim Settlement resulted
in a September 14, 1999 filing to address issues pertaining to the cost of
upstream capacity and other matters pertaining to restructuring pursuant to the
PSC's Policy Statement. The proposal calls for: (1) a continued reduction in
capacity costs of $11.9 million, comprised of $10.2 million relating to upstream
capacity release transactions for the period September 1, 1999 through August
31, 2000 and $1.7 million from the expiration of a Texas Eastern capacity
contract; (2) a report to PSC staff, within 60 days of approval of the proposal,
of the plans and progress RG&E has made to reduce its upstream capacity costs;
(3) a resumption of the multi-year settlement discussions calling for RG&E to
make a public filing addressing the rate and restructuring issues addressed in
the PSC's Policy Statement within 120 days of approval of the proposal; and (4)
RG&E continuing to work on retail access program improvements. The proposal was
subsequently approved by the PSC and RG&E began implementation of its proposal
in the fourth quarter of 1999. As required, the report on upstream capacity
costs was submitted on November 29, 1999, under trade secret status. The public
filing addressing the rate and restructuring issues was made on January 28,
2000. This filing is intended to provide the basis for negotiations with the PSC
and other interested parties on RG&E's proposal to implement a fully competitive
marketplace for natural gas. Settlement negotiations pertaining to RG&E's gas
rate and restructuring proposal began on February 29, 2000. 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
21
to the flexible pricing tariff see RG&E's 1999 Form 10-K, Item 7 under Rates and
Regulatory Matters.
LIQUIDITY AND CAPITAL RESOURCES
During the first quarter 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 quarter was slightly higher reflecting the
timing of nuclear decommissioning fund payments somewhat offset by lower net
additions to utility plant . Cash used in financing activities in the first
quarter was lower reflecting mainly lower levels of short term debt. Capital
requirements of the Company during 2000 are anticipated to be satisfied from the
combination of internally generated funds and short-term credit arrangements.
RG&E may also refinance long-term securities obligations during 2000 depending
on prevailing financial market conditions.
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
$28 million had been expended for construction as of March 31, 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. As financial market
conditions warrant, RG&E may also, from time to time, redeem higher-cost senior
securities.
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
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 3,320,400 shares of Common Stock have been repurchased
for approximately $91.1 million through March 31, 2000. The average cost per
share purchased during the three months ended March 31, 2000 was $20.74.
EARNINGS SUMMARY
RGS :
RGS reported higher common stock earnings of $38.4 million for
the first quarter ended March 31, 2000, as compared to $36.1 million for the
same period in 1999. First quarter 2000 results were better than last year due
primarily to increased wholesale electric sales, offset somewhat by weather that
was warmer than last year. Earnings per share increased to $1.07 for the
quarter, as compared to $0.97 last year, reflecting increased earnings and the
positive effect of the Company's share buy-back program that resulted in a
reduction in the shares outstanding for the current period.
The Company's unregulated subsidiary, Energetix, continues to show
progress as the electric and gas utility business evolves to an open and
competitive market. Griffith, a subsidiary of Energetix, has grown its base to
over 70,000 customers for propane and oil based products throughout upstate New
York. Griffith
22
has provided an excellent foundation to develop its unregulated electric and gas
businesses. Energetix and Griffith, on a consolidated basis, had operating
income of $1.5 million for the first quarter, approximately equal to the 1999
results in spite of 8.4% warmer temperatures that was experienced in 2000. First
quarter income is driven by the seasonal nature of its heating oil business,
partially offset by expenses incurred in the development of its unregulated
electric and gas businesses. Energetix's revenues for 2000 from electric and gas
operations are expected to increase over 1999 levels as Energetix expands its
customer base, although no assurance may be given that Energetix will achieve a
net operating income for the year 2000.
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 Statement for the first quarter of 1999 reflects 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
Statement for the first quarter of 2000 reflects 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
period ended March 31, 2000 to the three-month period ended March 31, 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 MARCH 31, 2000 COMPARED TO THREE MONTHS ENDED MARCH 31, 1999
- -------------------------------------------------------------------------------
OPERATING REVENUES AND SALES. In the first quarter total revenues for
RGS increased 18.3% reflecting higher electric sales to other utilities (OEU
sales) and higher other revenues from Griffith due to the higher costs of
heating oil and gasoline. The increase in OEU sales reflects favorable market
conditions and increased capacity to sell power to other electric utilities due
to the availability of RG&E's Ginna Nuclear plant for the entire quarter offset
somewhat by the Nine Mile two refueling outage which began on March 4th. Ginna
was not in service in March of 1999 due to a refueling and in-service inspection
outage. Together revenues from regulated retail sales and sales to energy
marketers were up $3.7 million reflecting higher consumption levels and an
increase in customers. Gas revenues, net of fuel expenses, were down for RGS and
RG&E due to 8.4% warmer weather on a heating degree day basis. The decrease in
total revenues for RG&E reflects mainly the discontinuing of recording Energetix
revenues as a result of the corporate reorganization on August 2, 1999.
Energetix revenues were included in the RG&E income statement prior to that
date.
Energetix's unconsolidated operating revenues were $112 million for
the first three months of 2000 as compared to $56 million for the same period a
year ago due mainly to growth in electric and gas customers and, for Griffith,
an increase in the customer base through acquisitions and the higher price of
gasoline and fuel oil. 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 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 mainly
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. Higher
other fuel costs for RGS reflect the increase in Griffith's costs of fuel oil
and gasoline in the first quarter of 2000 as compared to a year ago. Those other
fuel costs were not included for RG&E after the August 1999
23
reorganization described above.
The increase in non-fuel operating and maintenance expense for both RGS
and RG&E in the first quarter of 2000 reflects mainly an increase of $ 8.8
million for electric transmission and wheeling charges related to implementation
the NYISO (see discussion under "New York Independent System Operator"). 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 increase in non-fuel O&M was partially offset by a
$4.3 million drop in RG&E welfare expense due mainly to the performance of
assets invested in the Company's pension plan and $2.5 million from insurance
dividends.
The increase in unregulated non-fuel O&M reflects primarily operating
expenses for Griffith, payroll expenses and general and administrative expenses.
Local, State and other taxes for RGS and RG&E declined reflecting
mainly a drop in regulated revenues and a lower gross receipts tax rate. The
difference in Federal income tax is attributable to pre-tax earnings.
OTHER STATEMENT OF INCOME ITEMS. The changes in RGS's and RG&E's
Other Income and Deductions, Other-net reflect the effect of credits taken in
1999 primarily for gain on the disposal of property partially offset by reduced
expenses associated with RG&E management performance awards.
The increase in interest expense for both of RGS and RG&E reflects
mainly the interest on $100 million of first mortgage bonds issued by RG&E in
October 1999.
DIVIDENDS
On March 15, 2000, the Board of Directors of RGS authorized a common
stock dividend of $.45 per share, which was paid on April 25, 2000 to
shareholders of record on April 4, 2000. Also on March 15, 2000, The Board of
Directors of RG&E declared dividends on its Preferred Stocks at the regular
rates per share payable on June 1, 2000 to stockholders of record on May 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 $40 million at March 31, 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
24
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 March 31, 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 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 March 31,
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.
RG&E-OWNED WASTE SITE ACTIVITIES. It was previously reported that RG&E
is conducting proactive site investigation and remediation activities at certain
of its sites where past waste handling and disposal may have occurred. At one of
those sites in Pavilion, NY, where gas manufacturing took place, RG&E is
planning a Phase I investigation, including examination of sub-surface soil
samples, even though an earlier, less detailed study did not indicate there was
any environmental problem with the site.
At East Station in Rochester, NY it was previously reported that a
supplemental remedial investigation and feasibility study was undertaken. A
draft report was sent to the New York State Department of Environmental
Conservation (NYSDEC) in April, 2000.
At another property owned by RG&E where gas manufacturing took place
located in Canandaigua,
25
NY, RG&E is developing a proposed supplemental remedial investigation plan to be
submitted to the NYSDEC for approval.
SUPERFUND AND OTHER NON-OWNED SITES. RG&E's obligations have been met
at the PAS, Oswego Federal Superfund site in Oswego, NY. It is not anticipated
that additional resources will be required.
GRIFFITH OWNED SITES. In connection with its Big Flats, New York
terminal, Griffith has been complying with the Unilateral Administrative Order
issued by the EPA. Pursuant to a cost sharing agreement with Sun Pipe Line
Company, Griffith continues to undertake one-half of the costs necessary to
comply with the order. As of March 31, 2000 Griffith has spent $1.8 million on
this compliance. On January 24, 2000, the State of New York issued a demand for
$206,875, representing reimbursement of $123,428 and penalties in the amount of
$75,000. This demand is technically not embraced by the Cost Sharing Agreement.
The State has been asked to elaborate on the demand and whether it is the same
claim for penalties asserted in the action below. A similar demand has been made
of Sun Pipe Line Company. Griffith continues to disclaim that it is either the
owner or operator of a failed spur where petroleum was discharged, and
compliance is proceeding on this basis accordingly.
Since February 1996, Griffith has been involved in a legal proceeding
in New York State Supreme Court for Steuben County, related to the environmental
matter in the above paragraph. In Steuben Contracting v. Sun Pipe Line Company,
Griffith Oil Co., Inc. and Chevron, USA, the plaintiff is seeking compensation
for property damage associated with petroleum discharge at Big Flats. The
parties have engaged in depositions and disclosure activities. Such disclosure
has not revealed any facts that have altered Griffith's position that the other
parties reimburse Griffith for costs, expenses and damages associated with site
remediation at Big Flats. Recently, the Court rendered a bench decision on the
various motions for summary judgement. Summary judgement was granted as against
Sun Pipe Line and Griffith was determined not to be the owner of the failed
line. The question of whether Griffith is the operator of the failed pipeline
spur has been reserved as an issue of fact to be determined at trial.
In May 1998, the State of New York (State of New York v. Griffith Oil Co., Inc.)
commenced an action against Griffith in New York State Supreme Court for Albany
County, for statutory penalties in connection with the discharge of petroleum at
Big Flats, New York. The complaint alleges Griffith failed to report the
discharge within two hours of discovery, and further alleges a violation of
Griffith's Major Oil Storage Facility License for failure to report such
discharge. Griffith has answered the complaint and denied the allegations.
Griffith's position is that it complied with established practice with DEC, and
promptly reported the discharge upon confirmation of the presence of subsurface
petroleum. An action in New York State Supreme Court , removed to Federal
District Court by ARCO, was commenced by Griffith against ARCO essentially to
preserve the statute of limitations in the event it is determined that ARCO is
the owner of the failed pipeline spur. In a deposition in the Federal District
Court action, ARCO's representative acknowledged that the pipeline was abandoned
to it, and ultimately sold to the Sun Pipeline. If the Court sustains this
position, the company will essentially have established that neither the
company, nor its landlord, purchased any interest in the failed pipeline spur.
Griffith continues to deny responsibility for this matter and will defend this
matter in the usual course.
In April 1998, the State of New York commenced an action against
Griffith and other parties (State of New York v. Griffith Oil Co., Inc., Sugar
Creek Stores, Inc. and Mahl Bros. Oil Co., Inc. [Springville Bulk Plant]) in New
York State Supreme Court for Erie County, for reimbursement of the sum of
$180,962 to the New York Environmental Protection and Spill Compensation Fund in
connection with subsurface petroleum contamination in the vicinity of
Springville, New York. Until December 1997, Griffith leased a petroleum bulk
storage facility at the location. Cross-claims also exist among the defendants
related to causes of action associated with the contamination and lease of the
property. While the presence of subsurface contamination is evident, an analysis
of the contamination is substantially associated with a parent product produced
no later than 1985. This date precedes the interest of Griffith. The Company's
exposure in this action should be limited, however, to $100,000, representing
the self-insured retention limit under its underground storage tank pollution
policy in effect at the time the discharge was reported. Griffith will continue
to vigorously defend this matter.
26
For additional information on Legal Proceedings reference is made to
Note 3 of the Notes to Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's Annual Meeting of Shareholders was held on April 26, 2000. The
following matters were voted upon:
(a) The election of the following Directors for three year terms expiring
at the Annual Meeting of Shareholders in 2003:
Shares Shares
Nominees For Withheld
-------- ------- --------
Allan E. Dugan 29,878,213 771,871
Susan R. Holliday 29,859,835 790,249
Charles I. Plosser 29,841,186 808,897
Thomas S. Richards 29,886,470 763,613
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
No reports of Form 8-K were filed during the quarter.
EXHIBIT INDEX
Exhibit 10-1 The RG&E Supplemental Executive Retirement Program effective January 1, 1999.
Exhibit 10-2 The RG&E Supplemental Retirement Benefit Program effective July 1, 1999.
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.
27
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: May 11, 2000 By /s/ J.B. STOKES
----------------------------------
J. Burt Stokes
Senior Vice President and
Financial Officer
Date: May 11, 2000 By /s/ WILLIAM J. REDDY
----------------------------------
William J. Reddy
Vice President and Controller
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: May 11, 2000 By /s/ J.B. STOKES
----------------------------------
J. Burt Stokes
Senior Vice President, Corporate
Financial Officer
Date: May 11, 2000 By /s/ WILLIAM J. REDDY
----------------------------------
William J. Reddy
Vice President and Controller