<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1999
-------------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
---------------- ----------------
Commission file number 1-672
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Rochester Gas and Electric Corporation
-----------------------------------------------------
(Exact name of registrant as specified in its charter)
New York 16-0612110
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) identification No.)
89 East Avenue, Rochester, NY 14649
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (716) 546-2700
--------------
N/A
- ----------------------------------------------------------------------
Former name, former address and former fiscal year, if changed since
last report.
Indicate by check mark whether the 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
--- ----
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Common Stock, $5 par value, at July 31, 1999: 36,428,113
----------
<PAGE>
INDEX
Page No.
PART I - FINANCIAL INFORMATION
Consolidated Balance Sheet - June 30,1999 and
December 31, 1998..................................... 1 - 2
Consolidated Statement of Income - Three Months and Six
Months Ended June 30, 1999 and 1998.................... 3 - 4
Consolidated Statement of Cash Flows - Six Months
Ended June 30, 1999 and 1998.......................... 5
Notes to Financial Statements.......................... 6 -11
Management's Discussion and Analysis of Financial
Condition and Results of Operations................... 12 -28
Quantitative and Qualitative Disclosures About
Market Risk.......................................... 28
PART II - OTHER INFORMATION
Legal Proceedings...................................... 29
Exhibits and Reports on Form 8-K....................... 29
Signatures............................................. 30
<PAGE>
Rochester Gas and Electric Corporation
Abbreviations and Glossary
Company or RG&E Rochester Gas and Electric Corporation
CWIP Construction work-in progress
EITF Emerging Issues Task Force
Energetix Energetix, Inc., a wholly-owned subsidiary of the Company
Energy Choice A competitive electric retail access program of the Company
being phased-in over a period ending July, 2001.
FERC Federal Energy Regulatory Commission
Ginna Plant Ginna Nuclear Plant wholly owned by the Company
Griffith Griffith Oil Company, Inc., an oil, gasoline and propane
distribution company acquired by Energetix in 1998
ISO Independent System Operator
Kamine Kamine/Besicorp Allegany L.P.
LDC Local Distribution Company
Nine Mile Two Nine Mile Point Nuclear Plant Unit No. 2 of which the
Company owns a 14% share
NOI Notice of Inquiry
NOPR Notice of Proposed Rulemaking
NRC Nuclear Regulatory Commission
NYISO New York Independent System Operator
NYNOC New York Nuclear Operating Company
NYPP New York Power Pool
O&M Operation and Maintenance
PSC New York State Public Service Commission
RGS Development RGS Development Corporation, a wholly-owned subsidiary of
the Company
RGS Energy RGS Energy Group, Inc., a wholly-owned subsidiary of the
Company until August 2, 1999 at which time it became the
parent company of Rochester Gas and Electric Corporation,
RGS Development and Energetix.
SEC Securities and Exchange Commission
Settlement Competitive Opportunities Case Settlement among the Company,
PSC and other parties which provides the framework for the
development of competition in the electric energy
marketplace through June 30, 2002
SFAS Statement of Financial Accounting Standards
<PAGE>
PART I - FINANCIAL INFORMATION
- ------------------------------
ITEM 1. FINANCIAL STATEMENTS
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
Assets (Unaudited)
- ------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric $ 2,472,665 $ 2,477,077
Gas 443,526 435,318
Common 167,046 158,038
Nuclear fuel 269,965 256,562
------------- ----------------
3,353,202 3,326,995
Less: Accumulated depreciation 1,671,726 1,640,645
Nuclear fuel amortization 230,101 222,830
------------- ----------------
1,451,375 1,463,520
Construction work in progress 88,106 98,554
------------- ----------------
Net Utility Plant 1,539,481 1,562,074
------------- ----------------
Current Assets
Cash and cash equivalents 3,733 6,523
Accounts receivable, net of allowance for
doubtful accounts: 1999 - $33,825, 1998 - $26,544 82,529 89,291
Unbilled revenue receivable 32,481 37,922
Materials, supplies and fuels, at average cost 34,967 43,024
Prepayments 30,838 25,950
Other Current Assets 275 253
------------- ----------------
Total Current Assets 184,823 202,963
------------- ----------------
Intangible Assets
Goodwill, net 14,269 14,681
Other Intangible Assets, net 6,644 6,381
------------- ----------------
Total Intangible Assets 20,913 21,062
------------- ----------------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 204,327 183,502
Nine Mile Two deferred costs 28,732 29,258
Unamortized debt expense 16,443 17,241
Other deferred debits 21,001 18,531
Regulatory assets 400,974 416,320
Other Assets 1,072 1,984
------------- ----------------
Total Deferred Debits and Other Assets 672,549 666,836
------------- ----------------
Total Assets $ 2,417,766 $ 2,452,935
- --------------------------------------------------------------------------------------------------------------
</TABLE>
1
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
Capitalization and Liabilities (Unaudited)
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization
Long term debt - mortage bonds $ 480,036 $ 510,002
- promissory notes 243,746 248,224
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 50,000,000 shares; 38,885,813
shares issued at June 30, 1999
and at December 31, 1998. 700,191 699,730
Retained earnings 146,234 129,484
------------ ---------------
846,425 829,214
Less: Treasury stock at cost (2,317,700 shares
at 6/30/99 and 1,507,000 shares at 12/31/98) 68,191 46,433
------------ ---------------
Total common shareholders' equity 778,234 782,781
------------ ---------------
Total Capitalization 1,574,016 1,613,007
------------ ---------------
Long Term Liabilities
Nuclear waste disposal 89,546 87,566
Uranium enrichment decommissioning 12,401 12,197
Site Remediation 24,026 24,157
------------ ---------------
Total Long Term Liabilities 125,973 123,920
------------ ---------------
Current Liabilities
Long term debt due within one year 33,936 427
Preferred stock redeemable within one year 10,000 10,000
Short term debt 35,040 57,000
Accounts payable 46,827 52,454
Dividends payable 17,579 17,937
Equal payment plan 1,482 11,025
Other 49,533 34,526
------------ ---------------
Total Current Liabilities 194,397 183,369
------------ ---------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 318,427 326,972
Pension costs accrued 62,461 58,677
Kamine costs accrued 62,250 65,799
Post employment benefits internal reserve 47,009 42,909
Other 33,233 38,282
------------ ---------------
Total Deferred Credits and Other Liabilities 523,380 532,639
------------ ---------------
Commitments and Other Matters - -
------------ ---------------
Total Capitalization and Liabilities $ 2,417,766 $ 2,452,935
- --------------------------------------------------------------------------------------------------------------
</TABLE>
2
<PAGE>
Rochester Gas and Electric Corporation
Consolidated Statement of Income
(Thousands of dollars)
(Unaudited)
<TABLE>
<CAPTION>
For the Three Months Ended
June 30,
1999 1998
--------- ---------
<S> <C> <C>
Operating Revenues
Electric $ 174,911 $ 164,697
Gas 53,675 46,026
Other 47,219 1
---------- ----------
Total Operating Revenues 275,805 210,724
Fuel Expenses
Fuel for electric generation 10,494 12,661
Purchased electricity 15,566 7,167
Gas purchased for resale 26,649 29,075
Other fuel expenses 41,406 --
---------- ----------
Total Fuel Expenses 94,115 48,903
---------- ----------
Operating Revenues Less Fuel Expenses 181,690 161,821
Other Operating Expenses
Operations and maintenance excluding fuel 80,939 73,135
Unregulated operating and maintenance expenses excluding fuel 5,639 997
Depreciation and amortizaton 31,722 29,936
Taxes - state, local & other 27,522 27,854
Federal income tax 8,649 7,279
---------- ----------
Total Other Operating Expenses 154,471 139,201
---------- ----------
Operating Income 27,219 22,620
Other (Income) & Deductions
Allowance for other funds used during construction (154) (99)
Federal income tax 955 2,926
Other - net (2,271) (7,289)
---------- ----------
Total Other (Income) & Deductions (1,470) (4,462)
---------- ----------
Income Before Interest Charges 28,689 27,082
Interest Charges
Long term debt 12,641 10,929
Other - net 1,473 656
Allowance for borrowed funds used during construction (247) (158)
---------- ----------
Total Interest Charges 13,867 11,427
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Net Income 14,822 15,655
---------- ----------
Dividends on Preferred Stock 1,116 1,305
---------- ----------
Earnings Applicable to Common Stock 13,706 14,350
---------- ----------
Average Number of Common Shares (000's)
Common Stock 36,769 38,807
Common Stock and Equivalents 36,870 38,957
Earnings per Common Share - Basic $ 0.37 $ 0.37
Earnings per Common Share - Diluted $ 0.37 $ 0.37
Cash Dividends Paid per Common Share $ 0.45 $ 0.45
</TABLE>
3
<PAGE>
Rochester Gas and Electric Corporation
Consolidated Statement of Income
(Thousands of dollars)
(Unaudited)
<TABLE>
<CAPTION>
Year To Date
June 30,
1999 1998
-------- --------
<S> <C> <C>
Operating Revenues
Electric $ 339,583 $ 333,697
Gas 171,048 159,532
Other 91,265 1
----------- -----------
Total Operating Revenues 601,896 493,230
Fuel Expenses
Fuel for electric generation 22,013 24,459
Purchased electricity 28,323 12,611
Gas purchased for resale 87,370 90,738
Other fuel expenses 75,721 --
----------- -----------
Total Fuel Expenses 213,427 127,808
----------- -----------
Operating Revenues Less Fuel Expenses 388,469 365,422
Other Operating Expenses
Operations and maintenance excluding fuel 146,700 142,443
Unregulated operating and maintenance expenses excluding fuel 12,291 1,723
Depreciation and amortizaton 60,885 59,118
Taxes - state, local & other 58,865 60,415
Federal income tax 32,320 30,628
----------- -----------
Total Other Operating Expenses 311,061 294,327
----------- -----------
Operating Income 77,408 71,095
Other (Income) & Deductions
Allowance for other funds used during construction (383) (192)
Federal income tax 1,664 3,704
Other - net (3,840) (9,162)
----------- -----------
Total Other (Income) & Deductions (2,559) (5,650)
----------- -----------
Income Before Interest Charges 79,967 76,745
Interest Charges
Long term debt 25,361 21,713
Other - net 3,134 1,430
Allowance for borrowed funds used during construction (612) (308)
----------- -----------
Total Interest Charges 27,883 22,835
----------- -----------
Net Income 52,084 53,910
----------- -----------
Dividends on Preferred Stock 2,232 2,610
----------- -----------
Earnings Applicable to Common Stock 49,852 51,300
----------- -----------
Average Number of Common Shares (000's)
Common Stock 37,012 38,831
Common Stock and Equivalents 37,118 38,981
Earnings per Common Share - Basic $ 1.35 $ 1.32
Earnings per Common Share - Diluted $ 1.34 $ 1.32
Cash Dividends Paid per Common Share $ 0.90 $ 0.90
</TABLE>
4
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Six Months Ended
(Thousands of Dollars) June 30
- -------------------------------------------------------------------------------------------------------------------------
1999 1998
------- --------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net income $ 52,084 $ 53,910
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation and amortization 68,178 68,345
Deferred fuel 6,747 8,423
Deferred income taxes (2,160) (19,002)
Allowance for funds used during construction (995) (500)
Unbilled revenue 5,441 22,427
Stock option plan 485 116
Nuclear generating plant decommissioning fund (10,336) (10,427)
Pension costs accrued (412) (7,133)
Post employment benefit internal reserve 4,100 3,750
Changes in certain current assets and liabilities:
Accounts receivable 6,762 22,183
Materials, supplies and fuels 8,057 7,249
Taxes accrued 9,014 6,345
Accounts payable (5,627) (14,971)
Other current assets and liabilities, net 1,132 6,651
Other, net (2,964) 354
--------- ----------
Total Operating 139,506 147,720
--------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (52,464) (42,024)
Other, net (30) (7)
--------- ----------
Total Investing (52,494) (42,031)
--------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/issuance of common stock - 314
Short term borrowings, net (21,960) (20,000)
Repayment of promissory note (701) -
Dividends paid on preferred stock (2,232) (2,610)
Dividends paid on common stock (33,459) (34,977)
Purchase of treasury stock (21,758) (5,094)
Equal payment plan (9,543) (8,929)
Other, net (149) (159)
--------- ----------
Total Financing (89,802) (71,455)
--------- ----------
(Decrease) increase in cash and cash equivalents (2,790) 34,234
Cash and cash equivalents at beginning of period 6,523 25,405
--------- ----------
Cash and cash equivalents at end of period $ 3,733 $ 59,639
--------- ----------
<CAPTION>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Six Months Ended
(Thousands of Dollars) June 30
- -------------------------------------------------------------------------------------------------------------------------
1999 1998
------ -------
<S> <C> <C>
Cash Paid During the Period
Interest paid (net of capitalized amount) $22,622 $22,195
------- -------
Income taxes paid $28,750 41,160
------- -------
</TABLE>
5
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
NOTES TO FINANCIAL STATEMENTS
Note 1: GENERAL
The Company, in the opinion of management, has included adjustments (which
include normal recurring adjustments) which are necessary for the fair statement
of the results of operations for the interim periods presented. The
consolidated financial statements for 1999 are subject to adjustment at the end
of the year when they will be audited by independent accountants. The
preparation of financial statements requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates. Moreover, the results for these interim periods are not necessarily
indicative of results to be expected for the year, due to seasonal, operating
and other factors. These financial statements should be read in conjunction
with the financial statements and notes thereto contained in the Company's
Annual Report on Form 10-K for the year ended December 31, 1998.
Note 2. OPERATING SEGMENT FINANCIAL INFORMATION
Under SFAS-131, Disclosures About Segments of an Enterprise and Related
Information, information pertaining to operating segments is required to be
reported. Upon adoption of SFAS-131, 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 are
Regulated Electric, Regulated Gas, and Unregulated. The Regulated segments'
financial records are maintained in accordance with generally accepted
accounting principles (GAAP) and PSC accounting policies. The Unregulated
segment's financial records are maintained in accordance with GAAP.
<TABLE>
<CAPTION>
(thousands of dollars)
For the Three Months Ended
June 30,
-----------------------------
<S> <C> <C>
Regulated Electric 1999 1998
- ------------------ ---- ----
Profit 18,251 22,119*
Revenues from External Customers 174,270 164,679
Revenues from Intersegment Transactions 9,557 334
Regulated Gas
- -----------------------------------------
Loss (2,600) (5,816)*
Revenues from External Customers 52,560 46,017
Revenues from Intersegment Transactions 52 69
Unregulated
- -----------
Loss (829) (648)
Revenues from External Customers 58,584 431
</TABLE>
<TABLE>
(thousands of dollars)
For the Six Months Ended
June 30,
------------------------
<S> <C> <C>
Regulated Electric 1999 1998
- ------------------ ---- ----
Profit 37,693* 49,709*
Revenues from External Customers 338,358 333,680
Revenues from Intersegment Transactions 19,253 335
Regulated Gas
- -----------------------------------------
Profit 14,195* 5,157*
Revenues from External Customers 168,361 159,532
Revenues from Intersegment Transactions 230 78
</TABLE>
6
<PAGE>
<TABLE>
<CAPTION>
(thousands of dollars)
For the Six Months Ended
June 30,
----------------------
<S> <C> <C>
Unregulated
- -----------
Profit/(Loss) 196 (956)
Revenues from External Customers 114,660 431
</TABLE>
<TABLE>
<CAPTION>
(thousands of dollars)
June 30, 1999 Dec. 31, 1998
----------------- --------------
<S> <C> <C>
Total Unregulated Assets 66,930 59,946
</TABLE>
The total amount of the revenues identified by operating segment do not equal
the total Company consolidated amounts as shown in the Consolidated Statement of
Income. This is due to the elimination of certain intersegment revenues during
consolidation. A reconciliation follows:
<TABLE>
<CAPTION>
(thousands of dollars)
For the Three Months Ended
June 30,
---------------------------
<S> <C> <C>
Revenues 1999 1998
---- ----
Regulated Electric 174,270 164,679
Regulated Gas 52,560 46,017
Unregulated 58,584 431
------- -------
Total 285,414 211,127
Reported on Consolidated Income Statement 275,805 210,724
Difference to reconcile 9,609 403
Intersegment Revenue
Regulated Electric from Unregulated 9,557 334
Regulated Gas from Unregulated 52 69
----- ---
Total Intersegment 9,609 403
</TABLE>
<TABLE>
<CAPTION>
(thousands of dollars)
For the Six Months Ended
June 30,
--------------------------
<S> <C> <C>
Revenues 1999 1998
---- ----
Regulated Electric 338,358 333,680
Regulated Gas 168,361 159,532
Unregulated 114,660 431
------- -------
Total 621,379 493,643
Reported on Consolidated Income Statement 601,896 493,230
Difference to reconcile 19,483 413
Intersegment Revenue
Regulated Electric from Unregulated 19,253 335
Regulated Gas from Unregulated 230 78
------ ---
Total Intersegment 19,483 413
</TABLE>
* Some items have been restated for comparative purposes.
7
<PAGE>
Note 3. COMMITMENTS AND OTHER MATTERS
The following matters supplement the information contained in Note 10 to
the financial statements included in the Company's Annual Report on Form 10-K
for the year ended December 31, 1998 and should be read in conjunction with the
material contained in that Note.
Regulatory Assets. With PSC approval the Company 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 Balance Sheet. 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 the Company's rate setting was changed from a
cost-of-service approach, and it was no longer allowed to defer these costs
under SFAS-71, these assets would be adjusted for any impairment to recovery
(pursuant to SFAS-121). In certain cases, the entire amount could be written
off.
SFAS-121 requires write-down of assets whenever events or circumstances
occur which indicate that the carrying amount of a long-lived asset may not be
fully recoverable.
Below is a summarization of the Regulatory Assets as of June 30, 1999:
<TABLE>
<CAPTION>
Millions of Dollars
<S> <C>
Income Taxes $141.3
Kamine 191.3
Uranium Enrichment Decommissioning Deferral 14.5
Deferred Ice Storm Charges 7.6
Deferred Environmental SIR costs 20.9
Labor Day 1998 Storm Costs 8.1
Other, net 17.3
------
Total - Regulatory Assets $401.0
======
</TABLE>
See the Company's 1998 Form 10-K, Item 8, Note 10 of the Notes to Financial
Statements, "Regulatory Assets" for a description of the Regulatory Assets shown
above.
In a competitive electric market, strandable assets would arise when
investments are made in facilities, or costs are incurred to service customers,
and such costs are not fully recoverable in market-based rates. Examples
include purchase power contracts or high cost generating assets. Estimates of
strandable assets are highly sensitive to the competitive wholesale market price
assumed in the estimation. The amount of potentially strandable assets at June
30, 1999 depends on market prices and the competitive market in New York State
which is still under development and subject to continuing changes which are not
yet determinable, but the amount could be significant. Strandable assets, if
any, could be written down for impairment of recovery in the same manner as
deferred costs discussed above.
In a competitive natural gas market, strandable assets would arise where
customers migrate away from dependence on the Company for full service, leaving
the Company with surplus pipeline and storage capacity, as well as natural gas
supplies, under contract. The Company has been restructuring its
transportation, storage and supply portfolio to reduce its potential exposure to
strandable assets. Regulatory developments discussed under "Gas Cost Recovery"
below, may affect this exposure; but whether and to what extent there may be an
impact on
8
<PAGE>
the level and recoverability of strandable assets cannot be determined at this
time.
At June 30, 1999 the Company believes that its regulatory assets are not
impaired and are probable of recovery. The Settlement in the Competitive
Opportunities Proceeding does not impair the opportunity of the Company to
recover its investment in these assets. However, the PSC issued an Opinion and
Order Instituting Further Inquiry on March 20, 1998 to address issues
surrounding nuclear generation. The ultimate determination in this proceeding
could have an impact on strandable assets and the recovery of nuclear costs.
The initial meeting in this Inquiry was held in January 1999 and such a
determination is unlikely before year-end (see PSC Proceeding on Nuclear
Generation under Item 2, Management's Discussion and Analysis of Financial
Condition and Results of Operations).
GAS COST RECOVERY. The Company entered into several agreements to help
manage its pipeline capacity costs and has successfully met targets, agreed upon
in a PSC approved 1995 settlement. In July, 1998 the Company entered into an
agreement with Dynegy Marketing and Trade to provide assistance with respect to
the management of the Company's gas supply, transportation and storage costs
consistent with the goal of providing reliable service and reducing the cost of
gas.
On October 16, 1998, the Company, the staff of the PSC and certain other
parties entered into an interim settlement agreement, designed to address the
period between the October 31, 1998 expiration of the 1995 settlement and the
implementation of a new multi-year settlement to be negotiated. Under the
Interim Settlement, which was approved by the PSC on November 9, 1998, base
rates for gas service remained frozen at their current levels (which were fixed
pursuant to the 1995 Settlement). Additionally, RG&E was required to provide a
guaranteed level of benefits to customers from the re-marketing of unneeded
transportation and storage capacity, and to permit marketers serving up to ten
percent of retail and aggregated customer annual throughput to do so without
mandatory assignment of the corresponding capacity. RG&E was permitted to
recover the costs associated with non-assigned capacity from all customers, with
certain exceptions. With the expiration of the Interim Settlement on June 30,
1999, the Company anticipates that many of the major elements that are part of
the 1995 Settlement (including the freeze on base rates) will continue in their
current form until superseded, ultimately, by the implementation of the multi-
year settlement agreement. Subsequent to June 30, 1999, RG&E is not permitted
to place any limits on customer migration to marketers. The guaranteed level of
benefits to customers will expire as of September 1, 1999 in the absence of a
new agreement with the PSC.
Negotiations with respect to the multi-year settlement and implementation
of the PSC Policy Statement (see PSC Gas Restructuring Policy Statement under
Item 2, Management's Discussion and Analysis of Financial Condition and Results
of Operations) concerning the future of the Natural Gas Industry in New York
have been ongoing.
SPENT NUCLEAR FUEL LITIGATION. The federal Nuclear Waste Act obligated
DOE to accept for disposal spent nuclear fuel (SNF) from utilities' powerplants
by January 31, 1998 (statutory deadline). Since the mid-1980s, the Company and
other nuclear plant owners and operators have paid substantial fees to DOE to
fund that obligation (Nuclear Waste Fund). That DOE would not meet its
obligation was evident well prior to 1998; DOE admitted as much as the statutory
deadline approached.
In 1994, Northern States Power Company and other owners of nuclear plants
filed suit against DOE and the federal government in the U.S. Court of Appeals
for the District of Columbia Circuit (Court) seeking a declaration that DOE's
course of action was in violation of its statutory obligation and requesting
other relief. In 1996, the Court upheld the utilities' position that DOE is
9
<PAGE>
obligated to accept and dispose of the utilities' SNF by the statutory deadline.
The Court rejected the DOE contention that it could defer the disposal until the
availability of a suitable SNF repository, but stopped short of providing the
utilities a remedy since DOE had not yet defaulted.
In late 1996, DOE invited nuclear utilities' views on how its anticipated
inability to meet the statutory deadline could "best be accommodated." The
Company and a number of other parties responded to that invitation.
By a Joint Petition for Review, the Company and other nuclear utilities
petitioned the Court in January 1997 for a declaration that the Petitioners were
relieved of the obligation to pay fees into the Nuclear Waste Fund, and were
authorized to place those fees into escrow until DOE commenced disposing of SNF.
The petition further requested that DOE be ordered to develop a program that
would enable it to begin acceptance of SNF by the statutory deadline. In
November 1997, the Court held that DOE could not delay acceptance on grounds
that it lacked an SNF repository, and that the utilities had a "clear right to
relief". Rather than grant funding relief and order the DOE to move SNF,
however, the Court referred the utilities to their contractual remedies against
DOE. State agencies, municipal governments and DOE sought review of this
decision, but the U.S. Supreme Court declined in November 1998 to hear the case.
In July 1998 the Company, joined by several other nuclear utilities, initiated a
further effort to have the Court provide a suitable remedy under its "original
and exclusive" jurisdiction over matters arising under the Nuclear Waste Act. In
April 1999, the Court granted a motion to dismiss the utilities' petition. The
utilities are seeking a rehearing.
DOE's failure to meet its statutory deadline has given rise to numerous
other lawsuits. For example, several plant operators brought suit against DOE in
the U.S. Court of Federal Claims (COFC). In decisions issued in October and
November 1998, COFC judges held that DOE had breached its contractual
obligations. They denied most portions of DOE motions to dismiss the operators',
claims and granted the operators' summary judgment on DOE contract liability.
However, in a recently announced decision, a different COFC judge directed
claimants in that case to the DOE Contract Administrator for the requested
relief. It is expected that the claimants in that case will appeal this
decision.
It is not possible to predict the outcome of this split in the COFC, the
future course of the DOE obligation or the resolution of the spent nuclear fuel
movement and storage concern that underlies it. Similarly, the ultimate outcome
of nuclear waste legislation in Congress, that could address these and related
concerns, is uncertain. The court rulings on the DOE's default in meeting its
obligation to remove SNF by the statutory deadline, and on its contractual
liability therefor, have been promising. The current court rulings appear to
have prompted greater DOE effort to complete site investigations at its Yucca
Mountain, NV, site for SNF disposal and to focus greater Congressional attention
on the inappropriateness of continuing to house SNF around the nation at short-
term SNF facilities of nuclear powerplants. These developments have not yet led,
however, either to a firm schedule for DOE's movement of SNF from plant
facilities to a permanent repository or to the authorization of plant owners and
operators to withhold their Nuclear Waste Fund payments to DOE until that
schedule is established. The Company and other nuclear utilities continue to
work toward those objectives in judicial, legislative and administrative
initiatives.
EITF ISSUE 97-4 - DEREGULATION OF THE PRICING OF ELECTRICITY. In July
1997, the Financial Accounting Standards Board's EITF reached a consensus on
accounting rules for utilities' transition plans for moving to more competitive
environments and provided guidance on when utilities with transition plans will
need to discontinue the application of SFAS-71.
The major EITF consensus was that the application of SFAS-71 to a segment
(e.g. generation) which is subject to a deregulation transition plan should
cease
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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.
The Company'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
the Company through its distribution rates, given the Settlement provisions.
The Settlement provides for recovery of all prudently incurred sunk costs (all
investment in electric plant and electric regulatory assets) as of March 1, 1997
by inclusion in rates charged pursuant to the Company's distribution access
tariff. The Settlement also states that "the Parties intend that the provisions
of this Settlement will allow the Company 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 the Company 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 July 1, 1999 and the variable
portion of the non-nuclear generation to-go costs after July 1, 1998 are subject
to market forces and would no longer be able to apply SFAS-71. The Company's
net investment at June 30, 1999 in nuclear generating assets is $653.9 million
and in non-nuclear generating assets is $111.3 million.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The discussion presented below contains statements which are not historic
fact and which can be classified as forward looking. These statements can be
identified by the use of certain words which suggest forward looking
information, such as "believes," "will," "expects," "projects," "estimates" and
"anticipates". They can also be identified by the use of words which relate to
future goals or strategies. In addition to the assumptions and other factors
referred to specifically in connection with the forward looking statements, some
of the factors that could have a significant difference in whether the forward
looking statements ultimately prove to be accurate include:
(1) any state or federal legislative or regulatory initiatives (including the
results of negotiations between the Company and the PSC regarding the Gas
Settlement) that affect the cost or recovery of investments necessary to provide
utility service in the electric and natural gas industries. Such initiatives
could include, for example, changes in the regulation of rate structures or
changes in the speed or degree to which competition occurs in the electric and
natural gas industries;
(2) any changes in the ability of the Company to recover environmental
compliance costs through increased rates;
(3) the determination in the nuclear generation proceeding initiated by the PSC,
including any changes in the regulatory status of nuclear generating facilities
and their related costs, including recovery of costs related to spent fuel and
decommissioning;
(4) any changes in the rate of industrial, commercial and residential growth in
the Company's service territories;
(5) the development of any new technologies which allow customers to
generate their own energy or produce lower cost energy;
(6) any unusual or extreme weather or other natural phenomena;
(7) the ability of the Company to manage profitably new unregulated operations;
(8) certain unknowable risks involved in operating unregulated businesses in new
territories and new industries;
(9) the timing and extent of changes in commodity prices and interest rates;
(10) any unanticipated developments associated with fixing and testing the
modifications necessary to mitigate Year 2000 compliance problems, including the
possible indirect impact of customers, suppliers and other business partners who
do not sufficiently mitigate their Year 2000 compliance problems; and
(11) any other considerations that may be disclosed from time to time in the
Company's publicly disseminated documents and filings.
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Shown below is a listing of the principal items discussed.
Competition Page 13
PSC Competitive Opportunities Case Settlement
Business and Financial Strategy
Energy Choice
RGS Energy Group, Inc.
Fossil Units Status
Proposed Sale of Nuclear Plant
PSC Proceeding on Nuclear Generation
FERC Open Access Transmission Orders and
Company filings
Rates and Regulatory Matters Page 21
PSC Gas Restructuring Policy Statement
Gas Proposal and Interim Settlement
Flexible Pricing Tariff
Liquidity and Capital Resources Page 22
Capital and Other Requirements
Year 2000 Readiness Information
Financing
Earnings Summary Page 25
Results of Operations Page 26
Income Statement Changes
Operating Revenues and Sales
Operating Expenses
Other Statement of Income Items
Dividend Policy Page 28
COMPETITION
See Note 3 and the Company's Form 10-K for the fiscal year ended December
31, 1998, Item 8.- Note 10 of the Notes to Financial Statements for a discussion
of regulatory assets and related accounting issues.
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.
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The Settlement permits RG&E to fund its unregulated operations with up to
$100 million.
In the event that RG&E earns a return on common equity in excess of an
effective rate of 11.50 percent over the entire five-year term of the
Settlement, 50 percent of such excess will be used to write down deferred costs
accumulated during the term. The other 50 percent of the excess will be used to
write down accumulated deferrals or investment in electric plant or Regulatory
Assets (which are deferred costs whose classification as an asset on the balance
sheet is permitted by SFAS-71). If certain extraordinary events occur, including
a rate of return on common equity below 8.5 percent or above 14.5 percent, or a
pretax interest coverage below 2.5 times, then either the Company or any other
party to the Settlement would have the right to petition the PSC for review of
the Settlement and appropriate remedial action.
The Settlement requires RG&E to functionally separate its three regulated
operations: distribution, generation and retailing. Additionally, unregulated
energy retailing operations must be structurally separate from the regulated
utility functions. Although the Settlement provides incentives for the sale of
generating assets, it does not require RG&E to divest generating or other assets
or write-off stranded costs. Additionally, RG&E will be given a reasonable
opportunity to recover substantially all of its prudently incurred costs,
including those pertaining to generation and purchased power.
RG&E believes that the Settlement has not adversely affected its
eligibility to continue to apply certain accounting rules applicable to
regulated industries. In particular, RG&E believes it continues to be eligible
for the treatment provided by SFAS-71 which allows RG&E to include assets on its
balance sheet based on its regulated ability to recoup the cost of those assets.
However, this may not be the case with respect to certain operational costs
associated with non-nuclear generation (see Note 3 of the Notes to Financial
Statements under the heading Other Matters, EITF Issue 97-4, Deregulation of the
Pricing of Electricity).
The Company'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. The Company is unable, at this time, to predict the
outcome of this action.
BUSINESS AND FINANCIAL STRATEGY. Under the terms of the Settlement, the
Company has functionally separated its generation, distribution, and regulated
energy services businesses. Consistent with the Settlement, the Company has
begun to implement a business and financial strategy which consists of the
following: (1) the reorganization of its corporate structure into a holding
company has been completed effective August 2, 1999 in order to more fully
implement the separation of its regulated and unregulated businesses, (2) the
establishment of separate unregulated subsidiaries, Energetix and RGS
Development (see following discussion under "Unregulated Subsidiaries", and (3)
the development of an integrated financial strategy that includes new business
initiatives and a Common Stock share repurchase program of $145 million.
Through June 30, 1999, approximately 2.3 million shares have been repurchased.
ENERGY CHOICE. On July 1, 1998, the Company officially began implementation
of its full-scale electric retail access Energy Choice program. As of July 1,
1999, the Company entered its second year of this program. There are four basic
components of the sale of energy: the sale of electricity which is the amount of
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energy actually used by the consumer, the sale of capacity which is the ability
through generating facilities or otherwise, to provide electricity when it is
needed, the sale of distribution, which is the physical delivery of electricity
to the consumer, and retail services such as billing and metering.
Historically, the Company has sold all four components bundled together for a
fixed rate approved by the PSC. The implementation of the Energy Choice program
included a four year phase-in process to allow the Company 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. This limit,
beginning July 1, 1999, increases from 10 percent up to approximately 20 percent
for the second year of the program and to approximately 30 percent in the third
year. In July, 2001, all retail customers will be eligible to purchase energy
from alternative energy service companies. The phase-in of the Energy Choice
Program over the next few years eventually will give retail electric customers
the opportunity to purchase energy, capacity and retailing services from
competitive energy service companies. They may also continue to purchase fully
bundled electric service from RG&E under existing retail tariffs.
Energy Choice adopted the single-retailer model for the relationship
between the Company 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. With the exception of
primarily emergency services, which remain the Company's responsibility, the
retail customers' primary point of contact is with their chosen energy service
company.
Under the single-retailer model, energy service companies are responsible
for buying or otherwise providing the electricity their retail customers will
use, paying regulated rates for transmission and distribution, and selling
electricity to their retail customers (the price of which would include the cost
of the electricity itself and the cost to transport electricity through RG&E's
distribution system).
Throughout the term of the Settlement, RG&E will continue to provide
regulated and fully bundled electric service under its retail service tariff to
customers who choose to continue with or return to such service, and to
customers to whom no competitive alternative is offered.
During the initial "Energy-Only" stage of the Energy Choice program, which
began on July 1, 1998 and originally was scheduled to conclude on July 1, 1999,
energy service companies were able to choose their own sources of energy supply,
while RG&E continued to provide to them, through its bundled distribution rates,
the generating capacity (installed reserve) needed to serve their retail
customers. In addition, during the "Energy-Only" stage, energy service
companies have the option of purchasing "full-requirements" (i.e. delivery
services plus energy) from RG&E.
The existence of a fully functional and efficient Statewide Energy and
Capacity market is essential before RG&E can implement the "Energy and Capacity"
stage of the program. This Statewide Energy and Capacity market would be in the
form of an independent transmission system operator ("ISO") in conjunction with
a Wholesale Power Exchange. Without this wholesale market for generating
capacity, there can be no suitable mechanism for the reallocation, from the
regulated utility to the energy service company, of responsibility for ensuring
adequate installed reserve capacity. Since a Statewide Energy and Capacity
market was not
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expected to be in place by July 1, 1999, the Company, according to the terms of
the Settlement, had petitioned the PSC and received approval for a delay in the
implementation of the "Energy and Capacity" stage of its retail access program
until November 1, 1999 (see discussion under FERC Open Access Transmission
Orders and Company Filings). Although the "Energy and Capacity" stage is
delayed, the Company will continue to allow up to approximately 20 percent of
its total annualized sales for competitive energy service companies. More
recently, since the Company is uncertain that this Statewide Energy and Capacity
market will be in place by the November 1, 1999 extension date, it has
petitioned the PSC for another conditional extension of this "Energy-Only" stage
of the program. This petition proposes that if the Statewide Energy and Capacity
Market is not operational by November 1, 1999, the "Energy and Capacity" stage
would be delayed until April 30, 2000, the end of the Company's winter
capability period. Alternatively, if by November 1, 1999, there is a fully
functioning and efficient Statewide Energy and Capacity market, including all
necessary approvals by FERC, the Company would on that date initiate the "Energy
and Capacity" stage of the Energy Choice Program. Also, in order to assist
qualified energy service companies during this period of uncertainty in the
wholesale marketplace, RG&E, through this petition, proposes to offer the option
for purchasing "full-requirements" (i.e. delivery services plus energy plus
capacity) from the Company through April 30, 2000.
During the initial "Energy Only" stage of the Retail Access Program, RG&E's
distribution rate will be set by deducting 2.3 cents per kilowatt-hour from its
full service ("bundled") rates. The 2.3 cents per kilowatt-hour is comprised of
1.9 cents per kilowatt-hour (an estimate of the wholesale market price of
electricity) plus 0.4 cents per kilowatt-hour for its avoided cost of retailing
services. During the "Energy and Capacity" stage, RG&E's distribution rates
will equal the bundled rate less RG&E's cost of the electric commodity and
RG&E's non-nuclear generating capacity. During this stage of the program,
RG&E's distribution rates will be set by deducting 3.2 cents per kilowatt-hour,
inclusive of applicable gross receipts taxes, from its full service ("bundled")
rates. The 3.2 cents per kilowatt-hour is comprised of 2.8 cents per kilowatt-
hour (an estimate of the wholesale market price of electric energy and capacity,
inclusive of gross receipts taxes) plus 0.4 cents per kilowatt-hour for its
avoided cost of retailing services.
Through June 30, 1999, eight energy service companies, including Energetix,
the Company's unregulated subsidiary, have been 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, TXU Energy
Services, Inc., Florida Power & Light (FPL Energy Services), Inc., NEV East,
L.L.C.(New Energy Ventures), Northeast Energy Services, Inc.(NORESCO), North
American Energy, and Select Energy Inc. As of June 30, 1999, all energy service
companies have opted to purchase "full-requirements" from RG&E to serve their
retail customers. As "full-requirements" customers, energy service companies
are able to purchase electricity from RG&E at 1.9 cents per kilowatt-hour. This
impact was not significant because the loss of RG&E retail sales is roughly
offset by the sale of distribution service and electricity to energy service
companies. Although it is too early to quantify at this time, a substantial
part of this revenue loss is expected to be offset by cost reductions resulting
from the shift in retailing responsibilities from RG&E to energy service
companies.
Looking ahead to when implementation of the "Energy and Capacity" phase of
the full-scale program occurs, the Company will also be shifting the
responsibility for purchasing not only electricity, but also capacity, to these
energy service companies. Similarly, there will be a slight revenue loss as a
result of the increased back-out rate when this shift occurs. However, the
Company expects to manage this revenue impact with offsetting savings in costs
no longer incurred for the acquisition and maintenance of capacity and
increasing wholesale revenues through the sale of available capacity.
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The PSC had initiated a Statewide proceeding to recommend "uniform business
practices" dealing with electric retail access programs for each of the
utilities it regulates. Pursuant to a February 16, 1999 PSC order, Uniform
Business Practices became effective on June 1, 1999. The Uniform Business
Practices include items such as creditworthiness, customer information and
dispute resolution in an effort to further enhance standards for competition
across New York State. The Company already has incorporated provisions relative
to Uniform Business Practices into its business operations with minimal
corporate impact. The Company is currently working with other New York State
utilities to develop a single document relative to Uniform Business Practices.
This document will be submitted to the PSC by October 1, 1999. In addition to
this proceeding, there are three other PSC proceedings underway: Electronic Data
Interchange (EDI), Competitive Metering, and the Single Billing Option.
Since last Fall, EDI working groups have been involved in the development
of standardized electronic billing for all utilities across the State. A PSC
order is expected in the third quarter of 1999. An actual implementation date
will most likely occur no earlier than April 2000.
With regard to Competitive Metering, the PSC issued an order on June 16,
1999. This order directs utilities to unbundle electric services and to provide
a back-out credit to participating retail customers (customers who chose a
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qualified energy services company that provides these types of metering
services). Retail customers with electric demands of 50 Kw or greater, will have
the option to procure meters and various metering services, such as meter
installation and meter reading, from competitive entities, instead of only from
utilities. The Company expects to file tariff changes by October 1, 1999.
With regard to the Single Billing Option, the Company and other interested
parties have an opportunity to comment on various billing arrangements including
an ESCO single bill and the single retailer model. These billing arrangements
will provide a retail customer with a single bill. The Company filed comments
with the PSC by the July 1, 1999 deadline and Statewide implementation of these
billing arrangements may occur as early as the first quarter of 2000.
These PSC proceedings are intended to bring more consistency among New York
State utilities and potentially offer additional services for energy service
companies to provide. The Company continues to assess the scope and impact of
such changes on its operations.
RGS ENERGY GROUP, INC. On August 2, 1999, Rochester Gas and Electric
Corporation was reorganized into a holding company structure pursuant to an
Agreement and Plan of Share Exchange (Exchange Agreement) between RG&E and RGS
Energy. As part of the reorganization, all of the outstanding shares of RG&E
common stock were exchanged on a share-for-share basis for shares of RGS Energy
and RG&E became a subsidiary of RGS Energy. Certificates for shares of RG&E
common stock are automatically valid as certificates for RGS and do not have to
be replaced. The transfer does not affect the value of the stock or the
Company's dividend policy. RGS Energy trades on the New York Stock Exchange
under the symbol "RGS". RG&E shareholders approved the Exchange Agreement on
April 29, 1999.
The holding company structure was formed to respond quickly to changes in
the evolving competitive energy utility industry. The new structure permits the
use of financing techniques that are better suited to the particular
requirements, characteristics and risks of non-utility operations without
affecting the capital structure or creditworthiness of RG&E. This increases
RG&E's financial flexibility by allowing it to establish different debt-to-
equity ratios for each of its individual lines of business.
RGS Energy is not an operating entity. The Company's operations are being
conducted through its subsidiaries which include RG&E, and two unregulated
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subsidiaries - RGS Development and Energetix, as well as Griffith, a subsidiary
of Energetix.
RG&E will continue to offer regulated electric and natural gas utility
service in its franchise territory. Energetix provides energy products and
services throughout upstate New York. RGS Development offers energy systems
development and management services.
Unregulated Subsidiaries. It is part of RG&E's financial strategy to seek
growth by entering into unregulated businesses. The Settlement allows RG&E to
invest up to $100 million in unregulated businesses. The first step in this
direction was the formation and operation of Energetix effective January 1,
1998. Energetix is an unregulated subsidiary that brings energy products and
services to the marketplace both within and outside of RG&E's regulated
franchise territory. Energetix markets electricity, natural gas, oil, gasoline,
and propane fuel energy services in an area extending in approximately a 150-
mile radius around Rochester.
In August 1998, Energetix announced the acquisition of Griffith, the second
largest oil and propane distribution company in New York State. Energetix
accounted for its acquisition of Griffith as a purchase in the amount of
approximately $31.5 million. Purchase accounting adjustments, including
goodwill, are reflected in the consolidated financial statements of the Company
at December 31, 1998 and June 30, 1999.
Griffith gives Energetix access to 65,000 new customers, 60,000 of which
are outside of RG&E's regulated franchise territory. In addition to its current
products, Griffith sells electricity, natural gas and other services offered by
Energetix to its existing customers. Griffith has approximately 350 employees
and operates 17 customer service centers.
Additional information on Energetix's operations (including Griffith) is
presented under the headings Operating Revenues, Operating Expenses, and is
contained in Note 2 of the Notes to Financial Statements.
During the second quarter of 1998, the Company formed RGS Development. RGS
Development was formed to pursue unregulated business opportunities in the
energy marketplace. Through June 30, 1999, RGS Development operations have not
been material to the Company's results of operations or its financial condition.
Stock Repurchase Plan. In April 1998, the PSC approved a Stock Repurchase
Plan providing for the repurchase of Common Stock having an aggregate market
value not to exceed $145 million. The Company began the repurchase program in
May 1998 and has repurchased 2,317,700 shares of Common Stock for approximately
$68.2 million through June 30, 1999. The average cost per share purchased
during the first six months of 1999 was $26.84. The Company expects to continue
the share repurchase program through the year 2000.
FOSSIL UNITS STATUS. On April 30, 1999, the Company ceased operations at
its Beebee Station (80 Megawatt) generating facility. The plant was retired on
July 1, 1999. Factors such as the plant's age, lack of a rail/coal delivery
system and more stringent clean air regulations made the plant uneconomical in
the developing competitive generation business. The retirement of Beebee
Station is not expected to have a material effect on the Company's financial
position or results of operations. As a result of a one time incremental charge
of $2.1 million, the plant was fully depreciated at the time of retirement. The
Competitive Opportunities Settlement provides that all prudently incurred
incremental costs associated with the retirement and decommissioning of the
plant are recoverable through the Company's distribution access rates. The
electric capacity and energy previously provided by the plant are expected to be
replaced in the energy markets as needed.
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In early June the Allegany Station, a combined-cycle unit fueled by natural
gas, began generating electricity. The 62 megawatt capacity unit is expected to
generate electricity during the peak demand summer months and when the economics
of producing electricity for sale are favorable. The plant is being operated
and maintained for RG&E by Bell Harbert Energy LLC. Allegany Station, which was
built as a co-generation facility in the early 1990s, was obtained by RG&E as
part of a legal settlement in December 1998 with General Electric Capital
Corporation, Kamine/Besicorp Allegany L.P. and other Kamine affiliates.
Pursuant to an Asset Sales Agreement dated April 1, 1999, the Company and
Niagara Mohawk agreed to sell their respective 12% and 88% interests in the
entire Oswego Generation Facility to NRG Energy, Inc for approximately $91
million. Additionally, the Buyer agreed to assume the Company's obligations
under a transmission services agreement between the Company and Niagara Mohawk
as it pertains to the Oswego facility. This assumption represents a present
value of approximately $25 million. Upon such assumption by NRG, the Company
will bear such present value in the allocation of the sale proceeds. The
purchase price is subject to certain adjustments which will be determined at the
closing. The closing is expected to occur during the third quarter of 1999. On
April 29, 1999 the sale was approved by the Company's Board of Directors. Under
the terms of the Competitive Opportunities Settlement, RG&E is permitted to
recover any losses on a sale by establishment of a Regulatory Asset and recovery
thereof through distribution rates. The Asset Sales Agreement recognizes these
concepts by being conditioned upon the sellers receiving regulatory approvals
which do not impose upon the sellers materially adverse terms or conditions,
including adverse ratemaking determinations with respect to the sellers'
recovery of any losses or costs incurred or stranded as a result of the sale.
The electric capacity and energy currently provided by the plant are expected to
be replaced in the energy markets as needed. At June 30, 1999, the book value
of the Company's interest in Oswego 6 is approximately $54.4 million.
PROPOSED SALE OF NUCLEAR PLANT. On June 24, 1999, Niagara Mohawk and New
York State Electric and Gas (NYSEG) announced their intention to sell their
interests in the Nine Mile Two nuclear plant to AmerGen Energy Co., a joint
venture of PECO Energy of Philadelphia and British Energy. Niagara Mohawk owns
41 percent and NYSEG owns 18 percent of Nine Mile Two. The financial terms of
the transaction include nominal purchase prices to be paid to Niagara Mohawk of
$63.6 million and to NYSEG of $27.9 million. The sale is subject to several
contingencies including various regulatory approvals.
The Company's 14 percent interest in Nine Mile Two is not included in the
current proposal. As part owner, RG&E, along with the other owners, generally
has three options: the first option is to retain its ownership interest on the
same basis that it does now; the second option is to sell its 14 percent
interest in Nine Mile Two to AmerGen on substantially the same terms as Niagara
Mohawk and NYSEG; and the third option is to buy the Niagara Mohawk and/or NYSEG
interests on the same terms as offered by AmerGen. The Company is considering
each of these options including their impact on ratemaking and the future
regulatory treatment of nuclear plants by the PSC (see paragraph below). At
June 30, 1999 the book value, including nuclear fuel, of the Company's 14
percent interest in Nine Mile Two was approximately $393 million.
PSC PROCEEDING ON NUCLEAR GENERATION. On March 20, 1998, the PSC initiated
a proceeding to examine a number of issues raised by a Staff position paper on
nuclear generation and the comments received in response to it. In reviewing
the Staff paper and parties' comments, the PSC:
(1) adopted as a rebuttable presumption the premise that nuclear power should
be priced on a market basis to the same degree as power from other sources,
with parties challenging that premise having to bear a substantial burden
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of persuasion;
(2) characterized the proposals in the Staff paper as by and large consistent
in concept with the PSC's goal of a competitive, market-based electricity
industry;
(3) questioned Staff's position that would leave funding and other
decommissioning responsibilities with the sellers of nuclear power
interests and;
(4) indicated interest in the potential for a New York Nuclear Operating
Company (NYNOC) proposal to benefit customers through efficiency gains and
directed pursuit of that matter in this nuclear generating proceeding or
separately upon the filing of a formal NYNOC proposal.
The Company has worked with other New York nuclear generation operators on
the development of a NYNOC but no substantial further work on its implementation
is anticipated until completion of this proceeding and the outcome of any
proposed sales by current New York nuclear plant owners is determined.
The Company's potentially strandable assets in nuclear plant could be
impacted by the outcome of this proceeding. The initial collaborative
conference for this proceeding was held on January 20, 1999. The parties in this
proceeding developed a collaborative, non-binding interim report entitled
"Nuclear Generation and the Competitive Electric Market" which was issued in
July, 1999. A copy of the interim report is available on the PSC's website
(http://www.dps.state.ny.us/). The report and the status of the proceeding, in
addition to the proposed sale of the nuclear assets owned by Niagara Mohawk
and NYSEG (see section on Proposed Nuclear Plant Sale above), were discussed at
the July 14, 1999 PSC Session. At that meeting, the Chairman of the PSC
recommended that this nuclear proceeding continue in parallel with the upcoming
PSC proceeding to consider the proposed sale of the Nine Mile Two nuclear plant
discussed above. The Chairman also provided direction that the proceeding on
the sale of the nuclear plant has priority and the PSC Staff is to be mindful of
resource conflicts as many parties are involved in both proceedings. The
Company will be actively involved in both proceedings. A final determination in
either proceeding is unlikely before December 31, 1999.
FERC OPEN ACCESS TRANSMISSION ORDERS AND COMPANY FILINGS. On January 31,
1997, the New York electric utilities filed a "Comprehensive Proposal To
Restructure the New York Wholesale Electric Market" with the FERC. As proposed,
the existing New York Power Pool (NYPP) will be dissolved and an independent
system operator (NYISO) will administer a Statewide open access tariff and
provide for the short-term reliable operation of the bulk power system in the
State. In addition to proposing a FERC-endorsed NYISO, the proposal calls for
creation of a New York Power Exchange and a New York State Reliability Council.
On June 30, 1998, the FERC issued an Order that conditionally authorizes
the establishment of the NYISO by the member systems of the NYPP (Member
Systems). The order addresses areas of governance, standards of conduct and
reliability. A NYISO Board of Directors has been formed. In that same order the
FERC recommended that concerned parties revisit the independent system operator
weighted voting distribution relative to governance. On April 30, 1999, the FERC
issued an order which addressed several issues, including its rejection of the
Member Systems' settlement on governance issues, and its acceptance of the
section 203 filing to transfer jurisdictional transmission facilities to the
NYISO. On July 2, 1999, the Member Systems of the NYPP filed a proposed
agreement on governance issues and an explanatory statement of the agreement.
The explanatory statement represents the agreement to be in compliance with the
FERC's pronouncements.
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On January 27, 1999 the FERC issued an Order conditionally accepting the
proposed ISO tariff, and the proposed market rules of the ISO. The Order also
granted the Member Systems' request for market-based rates for energy, ancillary
services and installed capacity sold through the ISO. Additionally, certain
aspects of the proposed transmission rates were set for hearing, and a
settlement judge proceeding was established to resolve an issue involving
whether certain transmission arrangements should be grandfathered as "pre-ISO"
arrangements. On April 30, 1999, the Member Systems made their compliance
filing as requested by the January 27, 1999 Order. On May 28, 1999, in
accordance with the procedural schedule then in effect, the Member Systems filed
their Direct Testimony. The Member Systems filed a response to the comments and
protests to the April 30th filing on June 30, 1999. On June 17, 1999, the
Member Systems filed with the FERC a Settlement Agreement resolving the
grandfathering issue. On July 7, 1999, the FERC Trial Staff filed comments in
support of the Settlement Agreement. The matter is currently pending FERC
action. Finally, the hearing established to address rate issues is scheduled
for November, 1999. Such hearing is not expected to affect adversely any plans
to commence ISO operations.
Significant changes to pricing procedures now in effect within NYPP are
expected, but it is unclear what effect these changes may have once other
regulatory changes in New York State are implemented. At the present time, the
Company cannot predict what effects regulations ultimately adopted by FERC will
have, if any, on future operations or the financial condition of the Company.
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. The
Company, 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 deals with such issues as rates, transportation and
storage capacity costs, assignment of capacity, and retail access. Major
elements of the Interim Settlement include: (1) the term is from December 1,
1998 through the earlier of June 30, 1999 or the effective date of a new multi-
year agreement; (2) base rates, which cover the cost of the local distribution
system, will remain frozen for all customers at their current levels (which were
fixed at the July 1994 level pursuant to the 1995 settlement), while the Gas
Cost Adjustment will continue to vary from month to month; (3) a level of
revenues ($11.9 million on an annual basis) which corresponds to the Company's
anticipated revenues from capacity remarketing transactions currently in place
is imputed to the Company; (4) the Company is entitled to retain 15% of the
savings realized from the reduction of capacity commitments; (5) the Company
will simplify the transportation gas program and cap the migration of customers
at 10% of annual retail sales and not assign capacity costs to certain migrating
customers (see
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discussion of March 24, 1999 PSC order below); (6) the Company will be allowed
to recover the upstream costs that may be stranded by migration; and, (7)
certain issues relating to past gas costs have been resolved whereby the Company
shall set aside, in a manner to be determined by the PSC for the benefit of
customers, $2.2 million of the total amount recovered through the Gas Cost
Adjustment.
RG&E, the PSC Staff and other parties have been engaged in discussions,
based on the Company's August 1998 comprehensive proposal and the PSC's Gas
Policy Statement, to achieve a comprehensive, multi-year settlement. RG&E's
objective was to have a comprehensive final settlement in place prior to July 1,
1999. However, negotiations for a comprehensive final settlement have not
proceeded as quickly as originally planned. At this time, the Company is
continuing to pursue negotiations (which are currently suspended) with the PSC
staff and other interested parties.
Under a March 1996 Order, the PSC permitted RG&E and other gas distribution
companies to assign to marketers the pipeline and storage capacity held by RG&E
to serve their customers. In its Gas Policy Statement issued in November 1998,
the PSC ordered that the mandatory assignment of capacity, permitted by the
March 1996 Order, be terminated effective April 1, 1999. According to the Gas
Policy Statement, however, the utilities are to be afforded a reasonable
opportunity to recover resulting strandable costs, if any. The Company complied
with the PSC's directive to remove mandatory assignment of capacity through its
compliance filing made for the Interim Settlement Agreement. However, on March
24, 1999, the PSC issued an Order Concerning Assignment of Capacity for all gas
utilities in the State of New York, stating that all companies must file tariff
revisions in accordance with the general conclusions stated in the order. In
most instances, the Company's current tariff is in compliance with the order.
The order, however, states that all LDCs shall remove all restrictions and place
no limitation on the level of migration, except as may be negotiated. For the
Company's tariff, a modification has been made to remove the ten percent
migration cap as of July 1, 1999. Any further discussion of migration caps will
likely be part of the comprehensive multi-year settlement negotiations.
FLEXIBLE PRICING TARIFF. Under its flexible pricing tariff for major
industrial and commercial electric customers, the Company may negotiate
competitive electric rates at discount prices to compete with alternative power
sources, such as customer-owned generation facilities. For further information
with respect to the flexible pricing tariff see the Company's 1998 Form 10-K,
Item 7 under Rates and Regulatory Matters.
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 1999, cash flow from operations (see
Consolidated Statement of Cash Flows) provided the funds for construction
expenditures and the payment of dividends and short-term debt. Operating cash
flow was lower in the first six months largely due to a change in unbilled
revenues receivable and accounts receivable. Because December 1998 was
substantially warmer than December 1997, receivables at the end of 1998 were
lower than at year-end 1997. This resulted in a net decrease in working capital
for the 1999 six-month period when compared to the 1998 six-month period.
Higher net utility additions reflect $7 million of CWIP additions and $3 million
of nuclear fuel additions. Cash used in financing activities was higher due to
redemption of short-term debt and the repurchase of common stock. Capital
requirements during 1999 are anticipated to be satisfied primarily from the
combination of internally generated funds, short-term credit arrangements and
possibly some external long-term financing.
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CAPITAL AND OTHER REQUIREMENTS. The Company'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. The Company has no plans to
install additional baseload generation.
Total 1999 capital requirements are currently estimated at $124 million,
of which $114 million is for construction and $10 million is for sinking fund
obligations. Approximately $40 million had been expended for construction as of
June 30, 1999, reflecting primarily expenditures for nuclear fuel and upgrading
electric transmission and distribution facilities and gas mains.
Year 2000 Readiness Information. As the year 2000 (Y2K) approaches, the
Company, like most companies, faced potentially serious information and
operational systems (computer and microprocessor-based devices) problems because
many software applications and embedded systems programs created in the past
will not properly recognize calendar dates beginning with the year 2000 or that
the year 2000 is a "leap-year".
The Company identified the need to address Y2K issues early and in June
1996 established the Y2K Project (Y2K Project). Resources from across the
enterprise have been committed to the Y2K Project. The Company has assigned
approximately 40 full-time equivalent people to work on the Y2K Project as well
as retaining certain outside consultants to assist in the inventory, assessment,
and certification of date-aware devices. The Company is funding its Y2K Project
internally and estimates it will incur between $10 to $12 million of incremental
costs through January 1, 2000, associated with making the necessary
modifications identified to date to applications ($9-11 million) and devices ($1
million). This projection included replacement systems that may be required and
represents 25% of the Corporate Information Technology (IT) budget. The Company
has not deferred any other major IT project due to this effort. The Company has
incurred approximately $7.8 million of its $10-12 million total costs through
June 30, 1999. The Company is also participating in the Y2K activities of
several organizations such as the New York Power Pool and the North American
Electric Reliability Council. In addition the Company is a member of the
Electric Power Research Institute which has developed an on-line database
inventory that reports Y2K assessment and test results for devices and software
used by other utilities.
The Y2K Project is divided into five primary phases, a detailed discussion
of which is given in the following paragraphs. It should be noted that all five
phases may be occurring at any given time, due to grouping of work. The first
phase is the inventory phase which was the identification of internally
developed applications, devices, vendor applications and critical external
parties including customers, suppliers, business partners, government agencies,
and financial institutions. During the next phase, the assessment phase, the Y2K
Readiness of the items was determined. Year 2000 Readiness is defined as a
computer system, device or application that has been determined to be suitable
for continued use into the Year 2000 even though the computer system or
application is not fully Y2K compliant. The third phase, fix, is when
replacement or remediation of the items is performed. The fourth phase is the
test phase, when the items are functionally verified and date tested. The final
phase is the contingency phase when contingency plans are developed for all
critical applications, devices and systems.
Phase 1, Inventory. To date, the Y2K Project has completed the inventory
phase. The Company has prioritized external critical parties and is
independently verifying the most critical of these by various methods, such as
mandatory written verification to the Company of their status or by testing
transfer of electronic data.
Phase 2, Assessment. The Y2K Project has completed assessment of
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internally developed applications, critical devices, vendor applications,
suppliers and fiduciaries. Results of these assessments have been given to the
Business Areas for further action.
Phase 3, Fix. The fix phase activities of the Y2K project for mission
critical (i.e. those required to deliver energy and energy services to customers
reliably and safely) internally developed applications is 100% complete and for
critical devices is 100% complete. As part of this phase the customer
information and billing system is Y2K ready, and starting in April 1998 the
Company has been replacing its PC workstations and software with Y2K-ready
equipment and software. As facility maintenance outages occurred, Y2K critical
device replacement/modifications were performed. This effort was completed by
June 30, 1999. Critical devices are those which are important to the safe and
continuous delivery of energy and energy related services to the Company's
customers.
Phase 4, Testing. The Company successfully completed the testing of
mission critical applications, devices, and systems by June 30, 1999. Testing
included critical systems at RG&E's two major electric power plants, Ginna and
Russell Stations. Both plants performed without any difficulties when setting
the calendar past 2000. In addition, similar work and testing has been
performed on the statewide and on regional power systems so that computer
systems important to energy delivery will be ready.
Phase 5, Contingency Planning. The Company has in place a Business
Recovery Plan describing alternative processes and procedures to ensure the
integrity of its energy and financial systems. The Business Recovery Plan
served as a starting point for Y2K contingency plans. Contingency planning
commenced in October 1998 and was completed in June 1999. The Company's most
reasonably likely worst case scenario would be the simultaneous loss of energy
system monitoring, coupled with the failure of a major energy supplier. The
Company's contingency plan provides for backup of its energy monitoring system
in the event that its primary system is inoperable. The Company is capable of
operating its electric system in the event of a failure of a major electric
supplier. A failure from a major gas supplier may impact gas service. The
Company will arrange for appropriate staff coverage to manage potential
contingencies, as needed. If necessary, the Company would activate established
emergency procedures, including procuring additional supply and/or
reapportioning the available supply to assist residential customers. The
Company has received certificates of compliance from 131 of its 133 critical
third parties, including its electric and gas suppliers. Contingency planning
efforts have involved participation from all key Company areas. In 1999, two
`drills' will be held, in conjunction with other New York State utilities, to
test readiness status and procedures for the Year 2000 rollover. The first
drill, which tested the ability to effectively respond to simulated conditions
involving the loss of primary communications, was successfully completed on
April 9, 1999. The second drill is scheduled for September 9, 1999.
All activities in support of mission critical systems were completed by
July 1999, as required by the PSC. Likewise, the Company has met the July 1999
completion criteria set by the NRC for the Company's Ginna facility. While no
absolute guarantees of continuous energy delivery can ever be provided, about
200 key personnel will be working a 10-hour shift at RG&E beginning at 10 p.m.
December 31 to monitor the rollover to the year 2000 and deal with any problems
that might occur.
Energetix, the Company's wholly owned subsidiary, including its recently
acquired Griffith, estimates the cost of making the necessary modifications
identified to date to be less than $100,000, 50% of which relate to devices and
50% to applications. The cost represents approximately 50% of the Energetix IT
budget, but no major IT projects have been deferred due to Y2K. Most of its
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systems, personal computers and operating equipment are less than seven years
old. Energetix has identified items that are the most vulnerable to the Y2K
problem and is in various stages of assessing, fixing and testing those items.
These items are expected to be Y2K-ready by the third quarter of 1999, at which
time a Scenario Risk Analysis will be completed. Energetix has a Business
Recovery Plan, which will serve as the basis for Y2K contingency planning to be
completed by the third quarter of 1999. Energetix is surveying critical third
parties, independently of the Company, to assess their degree of Y2K readiness
and develop contingency plans to ensure the integrity of its operational and
financial systems. Energetix will prioritize these critical parties and
independently evaluate the most critical of these by various methods, such as
mandatory verification of their status or testing transfer of information.
FINANCING. The Company had no long-term financing during the first half of
1999. Capital requirements during 1999 are anticipated to be satisfied
primarily from the combination of internally generated funds and the use of
short-term credit arrangements with some external long-term financing possible
during the year. The Company may refinance long-term securities obligations
depending on prevailing financial market conditions.
The Company anticipates utilizing its credit agreements and unsecured lines
of credit to meet any interim external financing needs prior to issuing any
long-term securities. (See Form 10-K for the fiscal year ended December 31,
1998, Item 8. Note 9, Short-Term Debt, regarding the Company's short-term
borrowing arrangements and limitations.)
EARNINGS SUMMARY
The Company reported consolidated earnings of $0.37 per share for the
second quarter ended June 30, 1999, unchanged from the earnings per share
reported for the same period in 1998. Consolidated earnings for the six-month
period ended June 30, 1999 were $1.35 per share compared to $1.32 per share for
1998. Earnings per share results for both periods were positively affected by
the Company's share buy-back program that resulted in a reduction in the shares
outstanding for the quarter and first six months of this year. Despite favorable
revenues, overall earnings were down $.6 million in the second quarter due to
the Ginna Plant refueling outage, which resulted in significantly more purchased
power costs than last year, and due to the Company's increased reserve for
uncollectible accounts by approximately $7.0 million. The external auditors
concurred with the decision. To a lesser extent, electric rate reductions and
the migration of customers to competitive suppliers further impacted these
earnings.
Year to date results were affected by the same issues previously
discussed regarding the second quarter, although the effect of the Ginna Plant
refueling outage is greater because it is reflected in both the first and second
quarters. Common stock earnings for the six-month comparison period were
affected by the lower level of profit realized in the regulated electric segment
(see Note 2 of the Notes to Financial Statements) due primarily to the effects
of the Ginna Plant refueling shutdown resulting in increased purchased power
costs and reduced sales to other electric utilities. For further information
regarding operating results see Results of Operations below.
The impact of developing competition in the energy marketplace may affect
future earnings. The Competitive Opportunities Settlement allows for a phase-in
to open electric markets while lowering customer prices and establishing an
opportunity for competitive returns on shareholder investments. The nature and
magnitude of the potential impact of the Settlement on the business of the
Company will depend on several factors, including the availability of qualified
energy suppliers in the Company's service territory, the degree of customer
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participation and ultimate selection of an alternative energy supplier, the
Company's ability to be competitive by controlling its operating expenses, and
the Company's ultimate success in the development of its unregulated business
opportunities as permitted under the Settlement.
Although under the current regulatory environment the Company does not
earn a return on the gas commodity it acquires for distribution, future earnings
may also be affected, in part, by the ultimate outcome of implementation of the
November 1998 Gas Policy Statement (see Rates and Regulatory Matters). That
policy statement concludes that the most effective way to establish a robust
competitive gas supply in New York State is for LDCs, such as the Company, to
exit the merchant function of acquiring gas, as well as transportation and
storage capacity to serve retail customers. LDCs ceased assigning
transportation capacity to customers migrating from sales to transportation
service by April 1, 1999. The nature and magnitude of the potential impact of
these policies will depend on individual negotiations that the Company is
undertaking with the PSC Staff and other interested parties on RG&E specific
restructuring, as well as a number of Statewide collaborative efforts that will
deal with such issues as provider of last resort, reliability, recovery of
stranded costs, and market power as the transition is made to a more competitive
gas business.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses, comparing the three-month and
six-month periods ended June 30, 1999 to the respective three-month and six-
month periods ended June 30, 1998.
INCOME STATEMENT CHANGES. Operating revenues have been reclassified into
three components. Two of them, electric operating revenues and gas operating
revenues, include all regulated and unregulated sales of electricity and gas,
respectively. The third, other operating revenues, includes mainly sales from
Griffith, as well as other energy products. Other fuel expenses and unregulated
operating and maintenance expenses excluding fuel reflect certain operating
expenses of Energetix.
OPERATING REVENUES AND SALES. In the second quarter total electric sales
and related revenues from the Company's regulated electric business were up 1.6%
and $10.2 million, respectively. In addition, the Company's gas business also
experienced an 18.8% increase in sales and $7.6 million increase in revenues.
Sales and revenues for this period compared to last year reflect a one-time
accounting adjustment that was recommended by the Company's external auditor to
reflect a change in the estimating process for unbilled sales and revenues.
This adjustment increased electric revenues by $7.1 million and increased gas
revenues by $6.1 million. In addition, colder weather at the end of this heating
season and warmer weather in June contributed to higher sales and revenues when
compared to the second quarter of 1998.
The decline in total electric sales for the first six months of 1999 is
primarily due to a reduced capacity to sell power to other electric utilities
because of the refueling and in-service inspection outage at the Ginna Plant
that began on March 1, 1999 with the plant returning to service on April 26.
Electric revenue increased $10.2 million in the second quarter of 1999 and was
up $5.9 million for the first six months of 1999 due primarily to increased
sales in the second quarter and the accounting adjustment for unbilled revenues
discussed above, partially offset by an electric rate decrease and the effect of
customer migration to competitive suppliers. At June 30, 1999 competitive
electric suppliers, including Energetix, were serving 10% of RG&E's retail load.
Beginning on July 1, up to an additional 10% of the Company's regulated electric
retail load became eligible to choose competitive suppliers.
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Gas sales from the regulated business during the quarter were up 18.8%
from the second quarter of 1998. Likewise, such sales were up 15.8% for the
first six months of 1999 compared to the same period a year ago. These
increases are primarily due to the effect of 18.6% cooler temperatures during
the spaceheating season in the first six months of 1999. The higher gas sales
increased gas revenue net of fuel by $10.1 million in the quarter comparison and
by $14.9 million in the year-to-date comparison.
Energetix, the Company's unregulated subsidiary, began formal operations
in the first quarter of 1998 and acquired Griffith, as a subsidiary, in August
1998. Griffith's liquid fuels energy business extends beyond RG&E's regulated
distribution service territory and provides a platform upon which to develop the
unregulated electric and natural gas business. Energetix's total operating
revenues were $114.7 million for the first six months of 1999, of which
approximately $91 million was from the sale of heating oil, propane and gasoline
by Griffith. Energetix and Griffith, on a consolidated basis, had a pre-tax
loss of $0.8 million for the second quarter and had pre-tax income of $1.1
million for the six-month period ended June 30, 1999. These results reflect the
cyclical effect of the Griffith heating oil business, and the marketing expenses
incurred to build a successful unregulated electric and natural gas business in
an open and competitive market.
OPERATING EXPENSES. Higher fuel expenses reflect primarily the effect of a
maintenance shutdown of the Ginna Plant, lower generation at Russell Station due
to a derating, low water-flow rates that limited production at hydro facilities
and the shutdown of Beebee Station, requiring higher cost purchases of
electricity. Purchased electricity expenses were higher than 1998 by $8.4
million in the second quarter and $15.7 million for the first six months of the
year. Non-fuel O&M expenses for the regulated businesses increased $7.8 million
in the second quarter, driven by the increase in the Company's reserve for
uncollectible accounts discussed above and a one-time charge of $1.6 million for
the recognition of certain Year 2000 costs associated with the regulated gas
business. For the first six months of 1999, non-fuel O&M expense was up $4.3
million largely for the reasons discussed above.
Unregulated non-fuel O&M reflects primarily payroll expenses, fleet
expenses for Griffith, and general and administrative expenses in both periods.
Depreciation expense in both comparison periods was affected by a planned
one-time incremental charge of $2.1 million associated with the closing of
Beebee Station on April 30.
Local, State and other taxes declined in both comparison periods reflecting
the impact of lower revenues and lower tax rates for State and local revenue
taxes and lower property taxes due to decreased assessments partially offset by
higher unbilled revenue taxes resulting from an increase in unbilled revenues.
The differences in Federal income tax reflect differences in pre-tax earnings in
both comparison periods and, for the six-month comparison period, the settlement
of audits in the first quarter of 1998.
OTHER STATEMENT OF INCOME ITEMS. The changes in Other Income and
Deductions, Other-net (about $5 million in both comparison periods) reflect
mainly the recognition of income in 1998 due to the elimination of certain
pension deferred credits and Nine Mile Two operating and maintenance expenses in
accordance with the Competitive Opportunities settlement, partially offset by
carrying charges related to deferral of Kamine facility costs in 1999.
The increases in interest charges reflect mainly an increase, in both
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comparison periods, of approximately $140 million in long-term debt outstanding,
resulting mainly from the Kamine settlement and the acquisition of Griffith by
Energetix. Interest from unregulated operations increased $0.5 million for the
quarter and $1.1 million for the year-to-date comparison periods.
DIVIDEND POLICY
On June 16, 1999, the Board of Directors authorized a common stock dividend
of $.45 per share, which was paid on July 24, 1999 to shareholders of record on
July 2, 1999. The level of future cash dividend payments on Common Stock will
be dependent upon the Company's future earnings, its financial requirements, and
other factors. The Company's Certificate of Incorporation provides for the
payment of dividends on Common Stock out of the surplus net profits (retained
earnings) of the Company.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.
The Company is exposed to interest rate and commodity price risks.
The interest rate risk relates to new debt financing needed to fund capital
requirements, including maturing debt securities, and to variable rate debt.
The Company manages its interest rate risk through the issuance of fixed-rate
debt with varying maturities and through economic refundings of debt through
optional redemptions. A portion of the Company's long-term debt consists of
long-term Promissory Notes, the interest component of which resets on a periodic
basis reflecting current market conditions. The Company was not participating
in any derivative financial instruments for managing interest rate risks as of
June 30, 1999 or December 31, 1998.
The commodity price risk relates to natural gas in storage and other
petroleum-related products used for resale to customers. The Company primarily
enters into forward contracts for natural gas through its gas broker. In
addition, Griffith enters into various exchange-traded futures and option
contracts and over-the-counter contracts with third parties. The commodity
instruments are designated at the inception as a hedge where there is a direct
relationship to the price risk associated with the Company's inventory or future
purchases and sales of commodities used in the Company's operations. At June
30, 1999 and December 31, 1998 neither the fair value of the contracts
outstanding nor potential, near-term contract losses from reasonably possible
near-term changes in market prices were material to the financial position,
results of operations or liquidity of the Company.
For information about the Company's primary market risks associated with
activities in derivative financial instruments, other financial instruments and
derivative commodity instruments, see Item 8, of the 1998 Form 10-K
under "Financial/Commodity Instruments" in Note 1 of the Notes to Financial
Statements.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to "Company-Owned Waste Site Activities" and "Manufactured
Gas Sites" in Part I, Item 3, Legal Proceedings in the 1998 Form 10-K.
In June, 1999, the Company was named as a codefendant in a legal action
brought by a party who purchased a portion of its Ambrose Yard property. The
party has claimed that the Company's historic activities on the property
resulted in the presence of residual contaminants that have adversely impacted
the party's use of the property. The Company is just beginning to investigate
the claim and does not know whether the claim has any merit. There is
insufficient information available at this time to predict the economic impact
of the claim on the Company.
The Company and its predecessors formerly owned and operated five
manufactured gas facilities. At one site, located in the Rochester area known
as East Station, the Company previously reported that a supplemental remedial
investigation and feasibility study was expected to be completed in early 1999.
The study is now expected to be completed in the third quarter of 1999.
For further information on Legal Proceedings reference is made to Note 3
of the Notes to Financial Statements.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K:
No reports of Form 8-K were filed during the quarter.
EXHIBIT INDEX
Exhibit 10 Supplemental Executive Retirement Plan dated as of July 1, 1999
Exhibit 27 Financial Data Schedule pursuant to Item 601 (c) of
Regulation S-K.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: August 16, 1999 By /s/ J.B. STOKES
--------------------------------------
J. Burt Stokes
Senior Vice President, Corporate Services
and Chief Financial Officer
Date: August 16, 1999 By /s/ WILLIAM J. REDDY
--------------------------------------
William J. Reddy
Vice President and Controller
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Exhibit 10
ROCHESTER GAS AND ELECTRIC CORPORATION
SUPPLEMENTAL EXECUTIVE RETIREMENT PROGRAM
Effective January 1, 1999, ROCHESTER GAS AND ELECTRIC CORPORATION (the
"Company") hereby establishes the ROCHESTER GAS AND ELECTRIC CORPORATION
SUPPLEMENTAL EXECUTIVE RETIREMENT PROGRAM (the "Plan") for the benefit of
eligible Employees.
ARTICLE ONE
Definitions
-----------
1.1 "Board" means the Board of Directors of Rochester Gas and Electric
Corporation.
1.2 "Change in Control" means one of the following circumstances:
(i) any "person," including a "group" as determined in accordance
with Section 13(d)(3) of the Securities Exchange Act of 1934 (the
"Exchange Act"), is or becomes the beneficial owner, directly or
indirectly, of securities of the Company representing 20 percent or
more of the combined voting power of the Company's then outstanding
securities;
(ii) as a result of, or in connection with, any tender offer or
exchange offer, merger or other business combination, sale of assets
or contested election, or any combination of the foregoing
transactions (a "Transaction"), the persons who were directors of the
Company before the Transaction shall cease to constitute a majority of
the Board of Directors of the Company or any successor to the Company;
(iii) the Company is merged or consolidated with another corporation
and as a result of the merger or consolidation less than 70 percent of
the outstanding voting securities of the surviving or resulting
corporation shall then be owned in the aggregate by the former
stockholders of the Company, other than (x) affiliates within the
meaning of the Exchange Act or (y) any party to the merger or
consolidation;
(iv) a tender offer or exchange offer is made and consummated for the
ownership of securities of the Company representing 20 percent or more
of the combined voting power of the Company's then outstanding voting
securities; or
(v) the Company transfers substantially all of its assets to another
corporation which is not a wholly-owned subsidiary of the Company.
<PAGE>
-2-
1.3 "Code" means the Internal Revenue Code of 1986 as amended from time to
time.
1.4 "Committee" means the Committee on Management of the Company's Board
of Directors.
1.5 "Company" means Rochester Gas and Electric Corporation.
1.6 "Compensation" means an Employee's base salary and annual incentive
bonus, including salary reduction contributions to a Participating
Company's 401(k) or 125 cafeteria plan, for a Plan Year. Annual limits on
compensation under the Qualified Plan shall be disregarded for purposes of
determining an Employee's Compensation under this Plan.
1.7 "Effective Date" means January 1, 1999.
1.8 "Employee" means any employee of a Participating Company who (i)
participates in the Qualified Plan (ii) is a management or highly
compensated employee as such employees are defined in Title I of ERISA and
(iii) is designated by the Committee, in its sole discretion, as eligible
to participate in this Plan.
1.9 "Final Average Compensation" means an Employee's average Compensation
determined over any consecutive 36 months of SERP Service out of the last
10 years of SERP Service that produce the highest average. If an Employee
has less than 36 months of SERP Service, his Final Average Compensation
shall be the average of his Compensation for all months of SERP Service.
1.10 "Normal Retirement Date" and "Early Retirement Date" shall have the
same meanings given these terms in the Qualified Plan.
1.11 "Participating Company" means the Company and any related entity that
meets the definition of "Affiliated Company" in the Qualified Plan and
which is approved by the Committee as a Participating Company under this
Plan. Participating Companies are listed in Appendix A.
1.12 "Participating Company Service" means all Years of Service with a
Participating Company determined in accordance with the service-crediting
rules of the Qualified Plan, plus any additional service the Committee, in
its sole discretion, may determine appropriate in individual circumstances.
1.13 "Plan" means this Rochester Gas and Electric Corporation Supplemental
Executive Retirement Program.
1.14 "Plan Year" means the calendar year.
1.15 "Qualified Plan" means the Rochester Gas and Electric Corporation
Retirement Plan.
<PAGE>
-3-
1.16 "SERP Service" means the number of years of service an Employee is
deemed to participate in this Plan. It is anticipated that Employees will
be assigned positions within a Participating Company that may bring them
into and out of participation in this Plan. The Committee shall have the
discretion to designate those periods of actual service with a
Participating Company that constitute SERP Service. SERP Service may
include, in the Committee's sole discretion, service with a Participating
Company prior to the Effective Date of this Plan and other service the
Committee may deem appropriate in individual circumstances. Once credited
to an Employee, the Committee does not have the discretion to reduce such
service.
ARTICLE TWO
Purpose and Intent of Plan
--------------------------
The purpose of this Plan is to attract and retain a highly-motivated
executive workforce by providing to eligible Employees a targeted overall
level of retirement benefits to consist of (i) benefits under the Qualified
Plan and other pension plans maintained by a Participating Company, (ii)
one half of Social Security benefits and (iii) benefits paid from this Plan
equal to the difference between the aggregate benefits under (i) and (ii)
and the targeted amount to be paid from this Plan. The Plan is intended to
constitute an unfunded plan of deferred compensation for a select group of
management or highly-compensated employees as provided for in Title I of
ERISA.
ARTICLE THREE
Eligible Employee
-----------------
The Committee in its sole discretion shall designate those Employees
who shall be eligible to participate in this Plan. All eligible Employees
shall be identified in such records as the Committee deems appropriate to
establish and maintain.
An otherwise eligible Employee shall be ineligible to participate and
shall forfeit all rights to receive any future benefit payment under this
Plan if such Employee:
. is terminated for cause, which determination shall be in the sole
discretion of the Committee and this determination shall be final and
binding on all persons;
. voluntarily terminates employment, without the consent of the
Committee, prior to reaching age 55;
. terminates employment for any reason prior to completing five full
years of service measured from the eligible Employee's date of hire;
or
. without the prior consent of the Committee, engages in any activity
inimical to the interests of any Participating Company at any time
until the lapse of 36 months following the Employee's retirement.
<PAGE>
-4-
ARTICLE FOUR
Benefits
--------
4.1 Benefit Amount. The benefit payable to an eligible Employee under
--------------
this Plan on the Employee's Normal Retirement Date shall be a straight life
annuity equal to the greater of (a) or (b) offset by (c) where (a), (b) and
(c) are determined as follows:
(a) equals the "target SERP benefit" determined by multiplying the
percentage determined below times an Employee's Final Average
Compensation:
Accrual Percentage Per
Years of SERP Service Year of SERP Service
--------------------- --------------------
0-5 4.0%
6-10 3.5%
11-15 3.0%
16-20 2.5%
21 or more 0.0%
Example: if an Employee has 12 years of SERP Service, his target
-------
SERP benefit will be 43.5% of his Final Average Compensation
determined as follows:
5 x 4.0% + 5 x 3.5% + 2 x 3.0% =
20% + 17.5% + 6% = 43.5%
(b) equals the "minimum SERP benefit" determined by multiplying the
percentage determined below times an Employee's Final Average
Compensation:
Years of Participating Annual Percentage Per Year of
Company Service Participating Company Service
--------------- -----------------------------
0-30 2.166%
31 or more 0%
Example: if the Employee with 12 years of SERP Service has a
-------
total of 25 years of service with a Participating Company, his
minimum SERP benefit will be 54.15% (25 x 2.166%) of his Final
Average Compensation. Since this figure is greater than the
Employee's target SERP benefit, it becomes the accrual percentage
on which the Employee's target benefit will be based.
(c) equals the annual aggregate total of an Employee's Qualified Plan
benefit, a benefit from any other pension plan maintained by a
Participating Company and
<PAGE>
-5-
one-half his Primary Insurance Amount under the Social Security Act
determined as of the date the Employee retires from a Participating
Company.
Example: Assume the Employee is entitled to receive $130,000 per
-------
year for the Company's Retirement Plan, $30,000 from the
Company's Unfunded Retirement Income Plan and $20,000 from Social
Security. The Employee's offset, therefore is $170,000 ($130,000
+ $30,000 + 1/2 of $20,000).
If this Employee has Final Average Compensation of $500,000,
his target benefit is $216,600 (54.15% x $400,000).
The Employee's benefit payable from this Plan, then, is
$46,600 ($216,600 -$170,000 = $46,600). This benefit is the
annual life annuity amount payable at the Employee's Normal
Retirement Date. If the benefit is payable at another date or in
a form other than a life annuity, the amount shall be adjusted as
described in Section 4.3 and in the Qualified Plan.
4.2 Commencement of Benefits. A Participating Company shall pay the
------------------------
benefits due under this Plan commencing within 30 days of retirement,
disability, death or any other event that entitles an eligible Employee or
his beneficiary to receive benefits under the Qualified Plan.
4.3 Form of Payment. The form of benefit payable under this Plan shall be
---------------
a life annuity for unmarried Employees and a joint and 50 percent survivor
annuity for married Employees. Notwithstanding the foregoing, the
Committee in its sole discretion may elect to pay the benefit in any
alternative form of payment permitted under the Qualified Plan or, in the
event of the Employee's or his beneficiary's financial need, to pay the
entire benefit, or the present value of the remaining installments, in a
lump sum payment. The amount of the actual benefit paid from this Plan
shall be the straight life annuity calculated under Section 4.1 adjusted as
appropriate by the actuarial assumptions used in the Qualified Plan if a
different form of benefit is paid or if it is paid other than at Normal
Retirement Age.
4.4 Death Benefits During Employment. If an eligible Employee dies while
--------------------------------
still employed by a Participating Company but after becoming entitled to
receive a vested benefit, the eligible Employee's spouse, if surviving,
shall be entitled to a monthly lifetime benefit equal to 50 percent of the
benefit the eligible Employee would have received under Section 4.1. This
benefit shall be payable at such time as in-service death benefits are
payable under the Qualified Plan and pursuant to such other terms and
conditions as may apply to benefits payable under the Qualified Plan. In
the discretion of the Committee, the value of this benefit may be paid out
in a lump sum or in another alternative form of benefit the Committee may
prescribe.
4.5 Unfunded Plan. All benefits payable to an eligible Employee under this
-------------
Plan shall be paid by the Participating Company that employs the eligible
Employee out of its general assets and the Plan shall not otherwise be
funded. However, the Company may,
<PAGE>
-6-
in its discretion, set aside assets for meeting its obligations, including,
but not limited to, the establishment of a rabbi or other grantor trust. In
the event such fund or trust is established, each Participating Company
shall be responsible for making contributions to provide for the benefits
of its own eligible Employees.
In the event of a Change in Control, the Company's Chief Executive
Officer shall inform the trustee of any rabbi trust that has been
established to provide Plan benefits of the Change in Control and shall
arrange for the Participating Companies to fully fund, to the extent
practicable, the present value of all Plan benefits.
No Employee shall have any property rights in any such fund or trust
or in any other assets held by a Participating Company. The right of an
eligible Employee or his or her spouse or beneficiary to receive any of the
benefits provided by this Plan shall be an unsecured claim against the
general assets of a Participating Company.
4.6 Coordination with Qualified Plan Benefits. If an eligible Employee is
-----------------------------------------
receiving benefits under this Plan and his annual benefits under the
Qualified Plan are increased due to cost of living adjustments to the
Qualified Plan limits under Section 415 of the Internal Revenue Code, his
annual benefit under this Plan shall be correspondingly reduced in order to
maintain the same aggregate level of benefits. If the Qualified Plan is
amended to improve the benefits paid to retirees or their beneficiaries,
the benefits payable under this Plan to a retiree or beneficiary shall
automatically be increased by the same percentage increase that the
retiree's or beneficiary's Qualified Plan benefit is increased.
4.7 Change in Control. In the event of a Change in Control, all Plan
-----------------
benefits of eligible Employees shall become fully vested, and upon
termination of employment, or by action of the Committee in anticipation of
termination of employment, eligible Employees shall be paid such vested
benefits in a single lump sum payment. For this purpose, termination of
employment shall mean termination of the Employee's employment with a
Participating Company within four years following a Change in Control. A
termination shall be deemed to occur if during such period the Employee
determines in good faith that the position, duties, responsibilities and
status assigned to the Employee are inconsistent with the position, duties,
responsibilities and status of the Employee with the Participating Company
immediately prior to the Change in Control. Such determination shall be
evidenced by the Employee in a writing delivered to the Secretary of the
Company promptly but in no event later than 180 days after such
determination.
In the case of a Change in Control and a termination of employment as
above described, an eligible Employee who has not at such time attained the
age of 55 and whose Qualified Plan benefits are therefore deferred shall
nevertheless be entitled to an immediate lump sum payment under this Plan
equal to the then present value of the benefit that would have been payable
at the time the Employee reached age 55 had he remained in employment but
determined on the basis of Compensation and service figures in effect on
the date of the Employee's termination of employment.
<PAGE>
-7-
4.8 Other Benefits. An eligible Employee who is entitled to receive
--------------
benefits under Sections 4.1 and 4.2 of this Plan shall also be entitled to
receive welfare benefit provided generally to retirees of a Participating
Company. Such benefits shall be subject to the same terms and conditions
as apply to retirees generally except that the usual age and service
requirements for such welfare benefits shall not apply. In place of the
usual age and service requirements, an eligible Employee shall receive
retiree welfare benefits provided that he has commenced receiving benefits
under this Plan and that none of the forfeiture conditions of Article Three
apply to the eligible Employee. If welfare benefits are provided to
beneficiaries of deceased employees or retirees generally by a
Participating Company, beneficiaries of a deceased eligible Employee shall
be entitled to receive such benefits under the same terms and conditions as
apply to beneficiaries of deceased employees or retirees generally except
that the Article Three conditions, including the forfeiture conditions,
shall apply for entitlement purposes in lieu of any age and service
conditions applicable to beneficiary benefits generally.
ARTICLE FIVE
Administration
--------------
5.1 Committee as Administrator. This Plan shall be administered by the
--------------------------
Committee in accordance with the Plan's terms.
The Committee shall determine the benefits due each Employee from this
Plan and the Qualified Plan and shall cause them to be paid by the
Qualified Plan or by a Participating Company under this Plan accordingly.
The Committee shall inform each Employee of any elections which the
Employee may possess and shall record such choices along with such other
information as may be necessary to administer the Plan.
5.2 Coordination with Qualified Plan. Since this Plan is intended to
--------------------------------
operate in conjunction with the Qualified Plan, any questions concerning
plan administration or the calculation of benefits that arise but are not
specifically addressed by this Plan shall be considered in light of the
Qualified Plan. In addition, unless the context requires otherwise, the
terms used in this Plan shall have the same meaning as the same terms used
in the Qualified Plan.
5.3 Committee Action Final. The Committee has sole discretion to
----------------------
determine eligibility to participate in this Plan, to determine the
eligibility for and the amount of benefits, to interpret the Plan and to
take any other action it deems appropriate to administer this Plan. The
decisions made by and the actions taken by the Committee shall be final and
conclusive on all persons.
Members of the Committee shall not be subject to individual liability
with respect to their actions under this Plan. Notwithstanding the
foregoing, the Company shall
<PAGE>
-8-
indemnify each member of the Committee who may incur financial liability
for actions or failures to act with respect to the member's Committee
responsibilities.
ARTICLE SIX
Amendment and Termination
-------------------------
While the Company intends to maintain this Plan in conjunction with
the Qualified Plan indefinitely, the Board reserves the right to amend or
terminate it at any time for whatever reasons it may deem appropriate.
Notwithstanding the preceding paragraph, however, the Company hereby
makes a contractual commitment on behalf of itself, the other Participating
Companies and their successors to pay, or to require the other
Participating Companies to pay, the benefits accrued under this Plan prior
to its amendment or termination to the extent it or the other Participating
Companies are financially capable of meeting such obligation.
ARTICLE SEVEN
Miscellaneous
-------------
7.1 No Contract of Employment. Nothing contained in this Plan shall be
-------------------------
construed as a contract of employment between a Participating Company and
an Employee, or as a right of any Employee to be continued in the
employment of a Participating Company, or as a limitation of the right of a
Participating Company to discharge any of its Employees, with or without
cause.
7.2 No Transferability. The rights of an Employee under this Plan shall
------------------
not be transferable, voluntarily or involuntarily, other than by will or
the laws of descent and distribution and are exercisable during the
Employee's lifetime only by the Employee or the Employee's guardian or
legal representative.
7.3 Taxation. The benefits payable under this Plan shall be subject to
--------
all federal, state and local income and employment taxes to which benefits
of this type are normally subject.
7.4 Indemnification. To the fullest extent authorized or permitted by
---------------
law, the Company shall indemnify any eligible Employee who brings an action
or proceeding, whether civil or criminal, or who is made, or threatened to
be made, a party to an action or proceeding, whether civil or criminal, by
reason of the fact that he, his testator or intestate, is or shall be
entitled to benefits under this Plan and the Company has failed to make
payments hereunder when due or has otherwise failed to follow the terms of
the Plan or such eligible Employee has reasonable cause to believe the
Company shall fail or intends to fail to perform its future obligations
hereunder arising within a reasonable time thereof, or with respect to any
other matter directly or indirectly related to this Plan, unless a judgment
or other final adjudication adverse to such eligible Employee
<PAGE>
-9-
establishes that the Company was or is legally entitled to fail to so
perform its obligations hereunder. Without limitation of the foregoing,
such indemnification shall include indemnification against all costs of
whatever nature or kind, including attorneys' fees and costs of
investigation or defense, incurred by any eligible Employee with respect to
any such action or proceeding and any appeal therein, and which judgments,
fines, amounts and expenses have not been recouped by him in any other
manner. All expenses incurred by a person in connection with an actual or
threatened action or proceeding with respect to which such person is or may
be entitled to indemnification under this Section, shall, in the absence of
a final adjudication adverse to such person as described above, be promptly
paid by the Company to him, upon receipt of an undertaking by him to repay
the portion of such advances, if any, to which he may finally be determined
not to be entitled. The Company's obligations under this Section 7.4 may be
paid from any rabbi trust or other fund established by the Company for the
purpose of paying such expenses. This Section may not without the consent
of a eligible Employee be amended or changed in any manner adverse to such
eligible Employee. The indemnification provided by this Section shall not
be deemed exclusive of any other rights to which an eligible Employee may
be entitled other than pursuant to this Section.
Notwithstanding the foregoing, there shall be no indemnification for
persons who cease Plan participation and forfeit all benefits on account of
termination for cause as described in Section 3.1.
7.5 Successors. This Plan shall be binding on the Company's successors
----------
and assigns.
7.6 Governing Law. This Plan shall be interpreted and enforced in
-------------
accordance with the laws of the State of New York.
IN WITNESS WHEREOF, the Company has caused this Plan document to be
executed by its duly authorized officer this 1st day of July, 1999.
--- ----
ROCHESTER GAS AND ELECTRIC
CORPORATION
By /s/ Thomas S. Richards
---------------------------------
Title Chairman of the Board, President
--------------------------------
and Chief Executive Officer
---------------------------
<PAGE>
APPENDIX A
Participating Companies
Name of Company Effective Date of Participation
- --------------- -------------------------------
Rochester Gas and Electric Corporation July 1, 1999
RGS Energy Group, Inc. July 1, 1999
RGS Development Corporation July 1, 1999
Energetix, Inc. July 1, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CONSOLIDATED
BALANCE SHEET, CONSOLIDATED STATEMENT OF INCOME AND CONSOLIDATED STATEMENT OF
CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,539,481
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 184,823
<TOTAL-DEFERRED-CHARGES> 672,549
<OTHER-ASSETS> 20,913
<TOTAL-ASSETS> 2,417,766
<COMMON> 194,429
<CAPITAL-SURPLUS-PAID-IN> 437,571
<RETAINED-EARNINGS> 146,234
<TOTAL-COMMON-STOCKHOLDERS-EQ> 778,234
25,000
47,000
<LONG-TERM-DEBT-NET> 480,036
<SHORT-TERM-NOTES> 35,040
<LONG-TERM-NOTES-PAYABLE> 243,746
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 33,936
10,000
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 764,774
<TOT-CAPITALIZATION-AND-LIAB> 2,417,766
<GROSS-OPERATING-REVENUE> 601,896
<INCOME-TAX-EXPENSE> 33,984
<OTHER-OPERATING-EXPENSES> 492,168
<TOTAL-OPERATING-EXPENSES> 524,488
<OPERATING-INCOME-LOSS> 77,408
<OTHER-INCOME-NET> 4,223
<INCOME-BEFORE-INTEREST-EXPEN> 79,967
<TOTAL-INTEREST-EXPENSE> 27,883
<NET-INCOME> 52,084
2,232
<EARNINGS-AVAILABLE-FOR-COMM> 49,852
<COMMON-STOCK-DIVIDENDS> 33,101
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 139,506
<EPS-BASIC> 1.35
<EPS-DILUTED> 1.34
</TABLE>
