<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 March 31, 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
- -------------------------------------------------------------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) identification No.)
89 East Avenue, Rochester, NY 14649
- -------------------------------------------------------------------------------
(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 April 30, 1999: 36,835,713
----------
<PAGE>
INDEX
<TABLE>
<CAPTION>
Page No.
<S> <C>
PART I - FINANCIAL INFORMATION
Consolidated Balance Sheet - March 31,1999 and
December 31, 1998...................................... 1
Consolidated Statement of Income - Three Months Ended
March 31, 1999 and 1998.................................. 2
Consolidated Statement of Cash Flows - Three Months
Ended March 31, 1999 and 1998.......................... 3
Notes to Financial Statements.............................. 4 - 8
Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 9 -22
Quantitative and Qualitative Disclosures About
Market Risk...................................... 22 -23
PART II - OTHER INFORMATION
Legal Proceedings......................................... 23
Submission of Matters to a Vote of Security Holders....... 23
Other Information......................................... 23
Exhibits and Reports on Form 8-K.......................... 23
Signatures................................................ 24
</TABLE>
<PAGE>
Rochester Gas and Electric Corporation
Abbreviations and Glossary
<TABLE>
<S> <C>
Company or RG&E Rochester Gas and Electric Corporation
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., currently a wholly-owned subsidiary of the
Company which is expected to become the parent company later in 1999.
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
</TABLE>
<PAGE>
PART I - FINANCIAL INFORMATION
Item 1 - FINANCIAL STATEMENTS
Rochester Gas and Electric Corporation
Consolidated Balance Sheet
<TABLE>
<CAPTION>
At March 31, At December 31,
1999 1998
(Thousands of Dollars) (Unaudited)
<S> <C> <C>
Assets
Utility Plant
Electric $2,501,205 $2,477,077
Gas 441,618 435,318
Common 164,054 158,038
Nuclear fuel 269,776 256,562
---------------------------
3,376,653 3,326,995
Less: Accumulated depreciation 1,671,033 1,640,645
Nuclear fuel amortization 226,460 222,830
---------------------------
1,479,160 1,463,520
Construction work in progress 79,384 98,554
---------------------------
Net Utility Plant 1,558,544 1,562,074
---------------------------
Current Assets
Cash and cash equivalents 7,176 6,523
Accounts receivable, net of allowance for doubtful accounts:
3/31/99 - $ 26,577; 12/31/98 - $ 26,554 113,894 89,291
Unbilled revenue receivable 31,222 37,922
Materials, supplies and fuels 20,307 43,024
Prepayments 37,132 25,950
Other current assets 71 253
---------------------------
Total Current Assets 209,802 202,963
---------------------------
Intangible Assets
Goodwill 14,457 14,681
Other Intangible assets 6,697 6,381
---------------------------
Total Intangible Assets 21,154 21,062
---------------------------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 188,619 183,502
Nine Mile Two deferred costs 28,995 29,258
Unamortized debt expense 16,842 17,241
Other deferred debits 24,169 18,531
Regulatory assets 396,893 416,320
Other assets 1,102 1,984
---------------------------
Total Deferred Debits and Other Assets 656,620 666,836
---------------------------
Total Assets $2,446,120 $2,452,935
---------------------------
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds $510,019 $510,002
- promissory notes 244,146 248,224
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 ($5 par, 38,885,813 shares at 3/31/99 and 12/31/98 700,218 699,730
Retained earnings 148,984 129,484
---------------------------
849,202 829,214
Less: Treasury stock at cost (1,895,400 shares at 3/31/99 and 1,507,000
shares at 12/31/98) 56,974 46,433
---------------------------
Total Common Shareholders' Equity 792,228 782,781
---------------------------
Total Capitalization 1,618,393 1,613,007
---------------------------
Long Term Liabilities
Nuclear waste disposal 88,538 87,566
Uranium enrichment decommissioning 12,243 12,197
Site remediation 24,097 24,157
---------------------------
Total Long Term Liabilities 124,878 123,920
---------------------------
Current Liabilities
Long term debt due within one year 3,936 427
Preferred stock redeemable within one year 10,000 10,000
Short term debt 10,040 57,000
Accounts payable 73,132 52,454
Dividends payable 17,762 17,937
Equal payment plan (4,558) 11,025
Other 66,171 34,526
---------------------------
Total Current Liabilities 176,483 183,369
---------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 323,895 326,972
Pension costs accrued 62,676 58,677
Kamine deferred costs 64,021 65,799
Post employment benefits internal reserve 45,209 42,909
Other 30,565 38,282
---------------------------
Total Deferred Credits and Other Liabilities 526,366 532,639
---------------------------
Commitments and Other Matters
---------------------------
Total Capitalization and Liabilities $2,446,120 $2,452,935
---------------------------
</TABLE>
The accompanying notes are an integral part of the financial statements.
1
<PAGE>
Rochester Gas and Electric Corporation
Consolidated Statement of Income
(Thousands of Dollars) (Unaudited)
<TABLE>
<CAPTION>
March 31 March 31
Three months ended 1999 1998*
<S> <C> <C>
Operating Revenues
Electric $164,671 $169,000
Gas 117,373 113,515
Other 44,047 -
-------- ---------
Total Operating Revenues 326,091 282,515
-------- ---------
Operating Expenses
Fuel Expenses
Fuel for electric generation 11,518 11,799
Purchased electricity 12,757 5,444
Gas purchased for resale 60,721 61,670
Other fuel expenses 34,316 -
-------- ---------
Total Fuel Expenses 119,312 78,913
-------- ---------
Operating Revenues Less Fuel Expenses 206,779 203,602
Other Operating Expenses
Operations and maintenance excluding fuel 65,754 69,309
Unregulated operating and maintenance expenses
excluding fuel 6,476 726
Depreciation and amortization 29,141 29,182
Taxes - local, state and other 31,355 32,561
Federal income tax 23,077 23,679
-------- ---------
Total Other Operating Expenses 155,803 155,457
-------- ---------
Operating Income 50,976 48,145
Other (Income) and Deductions
Allowance for other funds used during construction (228) (93)
Federal income tax 1,303 449
Other, net (1,377) (1,873)
-------- ---------
Total Other (Income) and Deductions (302) (1,517)
-------- ---------
Interest Charges
Long term debt 12,721 10,784
Other, net 1,661 773
Allowance for borrowed funds used during construction (366) (150)
-------- ---------
Total Interest Charges 14,016 11,407
-------- ---------
Net Income 37,262 38,255
-------- ---------
Dividends on Preferred Stock 1,116 1,305
-------- ---------
Earnings Applicable to Common Stock $ 36,146 $ 36,950
-------- ---------
Average Number of Common Shares (000's)
Common Stock 37,249 38,863
Common Stock and Equivalents 37,360 39,014
Earnings per Common Share - Basic $ 0.97 $ 0.95
Earnings per Common Share - Diluted $ 0.97 $ 0.95
Cash Dividends Paid per Common Share $ 0.45 $ 0.45
</TABLE>
*Reclassified for comparative purposes
The accompanying notes are an integral part of the financial statements.
2
<PAGE>
Rochester Gas and Electric Corporation
Consolidated Statement of Cash Flows
(Thousands of Dollars) (Unaudited)
<TABLE>
<CAPTION>
Three months ended March 31, 1999 March 31, 1998
<S> <C> <C>
CASH FLOW FROM OPERATIONS
Net income $ 37,262 $ 38,255
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 32,527 33,869
Deferred fuel 13,535 13,443
Deferred income taxes 115 (16,281)
Allowance for funds used during construction (594) (243)
Unbilled revenue, net 6,700 7,761
Stock option plan 485 181
Nuclear generating plant decommissioning fund (2,571) (5,227)
Pension costs accrued 3,999 (3,246)
Post employment benefit internal reserve 2,300 2,125
Changes in certain current assets and liabilities:
Accounts receivable (29,161) (32,153)
Materials, supplies and fuels 22,717 19,782
Taxes accrued 5,736 4,979
Accounts payable 20,678 (7,870)
Other current assets and liabilities, net 14,870 29,180
Other, net (11,159) 75
---------------------------------------------------
Total Operating 117,439 84,630
---------------------------------------------------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (29,924) (15,475)
Other, net 174 (7)
---------------------------------------------------
Total Investing (29,750) (15,482)
---------------------------------------------------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issuance of common stock - 42
Short term borrowings, net (46,960) (20,000)
Repayment of promissory note (347) -
Dividends paid on preferred stock (1,116) (1,305)
Dividends paid on common stock (16,820) (17,488)
Purchase of treasury stock (10,541) -
Equal payment plan (11,025) 12,697
Other, net (227) (34)
---------------------------------------------------
Total Financing (87,036) (26,088)
---------------------------------------------------
Increase in cash and cash equivalents $ 653 $ 43,060
Cash and cash equivalents at beginning of
period $ 6,523 $ 25,405
---------------------------------------------------
Cash and cash equivalents at end of period $ 7,176 $ 68,465
---------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(Thousands of Dollars) (Unaudited)
Three Months ended March 31, 1999 March 31, 1998
Cash Paid During the Period
Interest paid (net of capitalized amount) $ 6,234 $ 6,293
Income taxes paid $ - $ 4,660
---------------------------------------------------
</TABLE>
The accompanying notes are an integral part of the financial statements.
3
<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, 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 Public Service Commission (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
March 31,
Regulated Electric 1999 1998
- ------------------ ---- ----
<S> <C> <C>
Profit 18,189 25,873
Revenues from External Customers 164,088 169,000
Revenues from Intersegment Transactions 9,696 -
Regulated Gas
- -------------
Profit 18,000 12,862
Revenues from External Customers 115,801 113,515
Revenues from Intersegment Transactions 178 -
Unregulated
- -----------
Profit/(Loss) 1,073 (480)
Revenues from External Customers 56,076 -
<CAPTION>
(thousands of dollars)
March 31, December 31,
1999 1998
---- ----
<S> <C> <C>
Total Unregulated Assets 69,305 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:
4
<PAGE>
<TABLE>
<CAPTION>
(thousands of dollars)
For the Three Months Ended
March 31,
Revenues 1999 1998
---- ----
<S> <C> <C>
Regulated Electric 164,088 169,000
Regulated Gas 115,801 113,515
Unregulated 56,076 -
------- --------
Total 335,965 282,515
Reported on Consolidated Income Statement 326,091 282,515
Difference to reconcile 9,874 -
Intersegment Revenue
Regulated Electric from Unregulated 9,696 -
Regulated Gas from Unregulated 178 -
-------
Total Intersegment 9,874 -
</TABLE>
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.
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 March 31, 1999:
<TABLE>
<CAPTION>
Millions of Dollars
<S> <C>
Income Taxes $144.4
Kamine 192.0
Uranium Enrichment Decommissioning Deferral 14.7
Deferred Ice Storm Charges 8.3
Deferred Environmental SIR costs 20.9
Labor Day 1998 Storm Costs 7.6
Other, net 9.0
------
Total - Regulatory Assets $396.9
------
</TABLE>
5
<PAGE>
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 March 31, 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 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
the level and recoverability of strandable assets cannot be determined at this
time.
At March 31, 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.
NUCLEAR DECOMMISSIONING TRUST. The Company is collecting in its electric
rates for the eventual decommissioning of its Ginna Plant and for its 14% share
of the decommissioning of Nine Mile Two. The operating licenses for these
plants expire in 2009 and 2026, respectively.
The NRC requires reactor licensees to submit funding plans that establish
minimum NRC external funding levels for reactor decommissioning. The Company's
plan, filed in 1990, consists of an external decommissioning trust fund covering
both its Ginna plant and its Nine Mile Two share. NRC regulations require
biennial reports on the status of Decommissioning Trust funds with the first
report due on March 31, 1999. The Company reported to the NRC that both the
Ginna and Nine Mile Two decommissioning trusts exceed the NRC minimum funding
amounts required as of December 31, 1998.
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 1998 settlement, for capacity remarketing for the twelve
months ending October 31, 1998, thereby avoiding negative financial impacts for
that period. 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 expiration of the 1995 settlement and the implementation of a
6
<PAGE>
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 remain
frozen at their current levels (which were fixed pursuant to a 1995 Settlement
that expired at the end of October 1998). Additionally, RG&E must provide a
guaranteed level of benefits to customers from the re-marketing of unneeded
transportation and storage capacity, and RG&E must 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 is permitted to
recover the costs associated with non-assigned capacity from all customers, with
certain exceptions. The Interim Settlement will expire on June 30, 1999.
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 are
continuing.
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
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 and no
decision has been made on 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.
7
<PAGE>
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 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. 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 Emerging Issues Task Force
(EITF) reached a consensus on accounting rules for utilities' transition plans
for moving to more competitive environments and provided guidance on when
utilities with transition plans will need to discontinue the application of
SFAS-71, "Accounting for the Effects of Certain Types of Regulation".
The major EITF consensus was that the application of SFAS-71 to a segment
(e.g. generation) which is subject to a deregulation transition plan should
cease when the legislation or enabling rate order contains sufficient detail for
the utility to reasonably determine what the transition plan will entail. The
EITF also concluded that a decision to continue to carry some or all of the
regulatory assets (including stranded costs) and liabilities of the separable
portion of the business that is discontinuing the application of SFAS-71 should
be determined on the basis of where the regulated cash flows to realize and
settle them will be derived. If a transition plan provides for a non-bypassable
fee for the recovery of stranded costs, there may not be any significant write-
off if SFAS-71 is discontinued for a segment.
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 March 31, 1999 in nuclear generating assets is $662.2 million and
in non-nuclear generating assets is $115.4 million.
8
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The discussion presented below contains statements which are not historic
fact and which can be classified as forward looking. These statements can be
identified by the use of certain words which suggest forward looking
information, such as "believes," "will," "expects," "projects," "estimates" and
"anticipates". They can also be identified by the use of words which relate to
future goals or strategies. In addition to the assumptions and other factors
referred to specifically in connection with the forward looking statements, some
of the factors that could have a significant difference in whether the forward
looking statements ultimately prove to be accurate include:
(1) any state or federal legislative or regulatory initiatives 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) 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 identifying, assessing,
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.
Earnings Summary Page 10
Competition Page 11
PSC Competitive Opportunities Case Settlement
Business and Financial Strategy
Energy Choice
Holding Company
PSC Proceeding on Nuclear Generation
FERC Open Access Transmission Orders and
Company filings
Rates and Regulatory Matters Page 16
PSC Gas Restructuring Policy Statement
Gas Proposal and Interim Settlement
Flexible Pricing Tariff
Liquidity and Capital Resources Page 18
Capital and Other Requirements
Year 2000 Readiness Information
Financing
Results of Operations Page 20
Income Statement Changes
Operating Revenues and Sales
Fossil Unit Status
Operating Expenses
Other Statement of Income Items
Dividend Policy Page 22
EARNINGS SUMMARY
The Company reported higher consolidated earnings of $0.97 per share for
the first quarter ended March 31, 1999 compared to $0.95 per share for the same
period in 1998. Earnings per share were positively affected by the Company's
share buy-back program that resulted in a reduction in the shares outstanding
for the current quarter. Earnings applicable to common stock were down $0.8
million in the quarter. Common stock earnings for the quarter 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. Offsetting lower regulated electric
profits was an increase in regulated gas segment profits reflecting higher sales
due to colder weather than last year. For further information regarding
operating results see pages 20-22.
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
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.
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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 for distribution. In addition, LDCs
must cease assigning capacity to customers migrating sales to transportation
service no later than April 1, 1999. The nature and magnitude of the potential
impact of these policies will depend on individual negotiations the Company will
undertake 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.
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.
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, Accounting for the Effects of Certain Types of
Regulation). If certain extraordinary events occur, including a rate of return
on common equity below 8.5 percent or above 14.5 percent, or a pretax interest
coverage below 2.5 times, then either 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
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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 will not adversely affect its eligibility
to continue to apply certain accounting rules applicable to regulated
industries. In particular, RG&E believes it will continue 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 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.
ENERGY CHOICE. On July 1, 1998, the Company launched its full-scale retail
Energy Choice Program. There are four basic components of the sale of energy:
the sale of electricity which is the amount of energy actually used by the
consumer, the sale of capacity which is the ability through 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.
Up to ten percent of RG&E's retail electric customers can now seek out or be
approached by alternative energy service companies for electricity to be
delivered over RG&E's distribution system. Participation in Energy Choice is
limited to no more than 10 percent of RG&E's total annual retail electric
kilowatt-hour sales during the first year of the program. This limit increases
to 20 percent the second year and 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 adopts 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
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from the company that serves them. With the exception of 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.
Until the development of a wholesale market for generating capacity, there
will be no suitable mechanism for the reallocation, from the regulated utility
to the energy service company, of responsibility for ensuring adequate installed
reserve capacity. Accordingly, during the initial "Energy Only" stage of the
Energy Choice Program (July 1, 1998 to July 1, 1999), energy service companies
will be able to choose their own sources of energy supply, while RG&E will
continue to provide to them, through its bundled distribution rates, the
generating capacity (installed reserve) needed to serve their retail customers
reliably.
During the "Energy Only" stage, energy service companies have the option of
purchasing "full-requirements" (i.e., delivery services and energy) from RG&E.
During the "Energy and Capacity" stage, scheduled to commence July 1, 1999,
energy service companies will no longer have the option of purchasing "full-
requirements" from RG&E and will be responsible for procuring generating
capacity, as well as energy, to serve the loads of their retail customers.
Distribution charges will be accordingly reduced as described below.
Since a Statewide energy and capacity market does not currently exist and
is not expected to be implemented by July 1, 1999, the Company, according to the
terms of the Settlement, has petitioned the PSC 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). If a functioning Statewide energy and capacity
market is still not functioning prior to November 1, the Company will need to
seek an additional delay of the scheduled commencement of the "Energy and
Capacity" stage.
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 March 31, 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
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Energetix, these companies are Columbia Energy Power Marketing Corporation,
Enserch Energy Services (New York), 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
March 31, 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. RG&E has distributed approximately 670,000
(annualized) megawatt-hours to retail customers of energy service companies,
thereby reaching 100 percent of the first-year cap of 10% for the full-scale
program. 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 the latter part of 1999, up to 20% of the total annual
electric sales will be eligible for retail access. With implementation of the
Energy and Capacity phase of the full-scale program, 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. 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.
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. It issued an Order on February 16, 1999 and
implementation of Uniform Business Practices is expected on June 1, 1999. In
addition to this proceeding, there are three other proceedings underway:
Electronic Data Interchange, Competitive Metering, and the Single Billing
Option. These proceedings are intended to bring more consistency among New York
State utilities and potentially offer additional services for energy service
companies to provide. The outcome of these proceedings may ultimately result in
changes to the Company's business, but at this time the Company cannot predict
the scope of such changes.
HOLDING COMPANY. During the second half of 1998, the Company filed
applications with various regulatory agencies requesting approval of a corporate
restructuring including the creation of a holding company. The Company received
regulatory approvals from FERC, NRC, PSC and SEC during the November 1998 -
February 1999 period. RGS Energy, a New York corporation, was organized in
November 1998 for the purpose of carrying out the restructuring.
At the Company's 1999 Annual Meeting of Shareholders held April 29, 1999,
shareholders approved an Agreement and Plan of Share Exchange which provides
that all of the outstanding shares of RG&E common stock will be exchanged on a
share-for-share basis for RGS Energy common stock. Upon consummation of the
exchange, RGS Energy will become the parent company of RG&E. Moreover, RG&E
intends to transfer its unregulated subsidiaries, Energetix and RGS Development,
to RGS Energy immediately prior to the exchange so that RGS Energy will become
the parent company of RG&E and such subsidiaries. The Company anticipates
forming the holding company structure during the second half of 1999.
The holding company structure is consistent with provisions of the
Competitive Opportunities Settlement.
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
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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 Oil Co.,
Inc. ("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 and purchase accounting
adjustments, including goodwill, are reflected in the consolidated financial
statements of the Company at December 31, 1998 and March 31, 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 16 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 March 31, 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 1,895,400 shares of Common Stock for approximately
$56.5 million through March 31, 1999. The average cost per share purchased
during the first quarter of 1998 was $27.14. The Company expects to continue the
share repurchase program through the year 2000.
PSC PROCEEDING ON NUCLEAR GENERATION. On March 20, 1998, the PSC initiated
a proceeding to examine a number of issues raised by a Staff position paper on
nuclear generation and the comments received in response to it. In reviewing
the Staff paper and parties' comments, the PSC:
(1) adopted as a rebuttable presumption the premise that nuclear power should
be priced on a market basis to the same degree as power from other sources,
with parties challenging that premise having to bear a substantial burden
of persuasion;
(2) characterized the proposals in the Staff paper as by and large consistent
in concept with the PSC's goal of a competitive, market-based electricity
industry;
(3) questioned Staff's position that would leave funding and other
decommissioning responsibilities with the sellers of nuclear power
interests and;
(4) indicated interest in the potential for a New York Nuclear Operating
Company (NYNOC) proposal to benefit customers through efficiency gains and
directed pursuit of that matter in this nuclear generating proceeding or
separately upon the filing of a formal NYNOC proposal.
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
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proposed sales by current New York nuclear plant owners is determined. In
January 1999 Niagara Mohawk Power Corporation (Niagara Mohawk) announced plans
to pursue the sale of its nuclear assets, including Nine Mile Two of which RG&E
is a 14% owner. The Company is not a party to any proposed sale of Nine Mile
Two and is unable to predict if a sale will occur or the timing of any sale by
Niagara Mohawk.
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. A determination in
this proceeding is unlikely before year-end.
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, FERC issued an Order that conditionally authorizes the
establishment of the NYISO by the member systems of the NYPP. The order
addresses areas of governance, standards of conduct and reliability. A NYISO
Board of Directors has been formed. At that time, FERC deferred consideration
of the unexecuted tariff and agreements filed under Section 205 of the Federal
Power Act for a future order which was issued on January 27, 1999 (see below).
FERC has also recommended that concerned parties revisit the independent system
operator weighted voting distribution relative to governance. On October 23,
1998, the member systems of the NYPP filed a proposed settlement agreement for a
comprehensive settlement of governance issues and an explanatory statement of
the settlement agreement. The explanatory statement represents the settlement
agreement to be in compliance with the Commission's June 30, 1998 Order.
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.
The Member Systems must make a compliance filing by April 27, 1999. A
major issue that will be addressed in that filing involves separating the filed
tariff into two separate tariffs; an ISO Open Access Transmission Tariff,
limited to the provision of transmission service, and an ISO Market Operations
Tariff for all other services provided by the ISO.
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
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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 begun 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 is 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 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.
An Interim Gas Settlement having been reached and the PSC having issued its
Gas Policy Statement, RG&E and other parties have been engaged in discussions
with PSC Staff based on the Company's August 1998 comprehensive proposal and the
PSC's Gas Policy Statement. RG&E's objective is to have a comprehensive final
settlement in place prior to July 1, 1999, although no assurance can be given.
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 must be made to state that the current ten
percent migration cap expires on July 1, 1999, which is the expiration of the
Interim Settlement Agreement. Any further discussion of migration caps will be
part of the comprehensive multi-year settlement negotiations.
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Negotiations with respect to the multi-year settlement and implementation
of the PSC Policy Statement concerning the future of the Natural Gas Industry in
New York are continuing.
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 three 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. At March 31, 1999
the Company had cash and cash equivalents of $7.2 million. 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.
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 $31 million had been expended for construction as of
March 31, 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, faces 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 expects to fund 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 ($11 million) and devices ($1
million). This projection includes contingencies and 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 $6.5 million of its $12 million
total costs through March 31, 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
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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 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, fixing, is when replacement or
remediation of the items is performed. The fourth phase is the testing phase,
when the items are functionally verified and date tested. The final phase is
the contingency phase when contingency plans will be 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
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 internally
developed applications is 90% complete and for critical devices is 85% complete.
This phase is expected to be completed by the end of the first half of 1999. As
part of this phase, a recently implemented customer information and billing
system is Y2K ready, and starting in April 1998 and continuing through the first
half of 1999, the Company is replacing its PC workstations and software with
Y2K-ready equipment and software. As facility maintenance outages are occurring,
Y2K critical device replacement/modifications are being performed. This effort
will be complete 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. Testing of internal applications for Y2K readiness has
begun and is 42% complete. Testing of critical applications, devices, and
systems is underway, with completion expected by June 30, 1999.
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 will
serve as the basis for Y2K contingency plans. Contingency planning commenced in
October 1998 and is expected to be completed by June 1999. 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. The Company's
initial most reasonably likely worst case scenario would be the simultaneous
loss of energy system monitoring, coupled with the failure of a major energy
supplier. Failure to address Y2K business issues properly could cause the
Company to issue inaccurate bills, or report inaccurate data.
All activities in support of mission critical systems are expected to be
completed by July 1999, as required by the PSC. Likewise, the Company fully
expects to meet the July 1999 completion criteria set by the NRC for the
Company's Ginna facility.
19
<PAGE>
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 their IT budget,
but no major IT projects have been deferred due to Y2K. Most of its systems,
personal computers and operating equipment are less than seven years old.
Energetix 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 by the third
quarter of 1999 also. Energetix has begun to survey critical third parties
including customers, suppliers, business partners and financial institutions 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 quarter
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.)
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant changes
in the amounts of revenues and expenses, comparing the three-month period ended
March 31, 1999 to the three-month period ended March 31, 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. Total electric sales from the Company's
regulated electric business were down 3.5% in the first quarter when compared to
the same period last year. The decline in total electric sales 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 March
1, 1999 and was completed by April 23, 1999. Electric revenue declined $4.3
million due primarily to lower total sales discussed above, an electric rate
decrease and the effect of customer migration to competitive suppliers,
partially offset by wholesale sales to other electric suppliers. Competitive
electric suppliers, including Energetix, are now serving 10% of RG&E's retail
load. This did not have a material effect on the Company's total electric sales
since the impact was offset by the wholesale sale of distribution services and
electricity to competitive suppliers.
20
<PAGE>
Gas sales from the regulated business during the quarter were up 14.7% from
the first quarter of 1998. This increase is primarily due to the effect of 19.4%
cooler temperatures in the quarter. The higher gas sales increased gas revenue
net of fuel by $4.8 million in the quarter comparison.
Prior year comparisons for the Company's unregulated subsidiary, Energetix,
are not relevant because formal operations began in the first quarter of 1998
and Griffith was acquired in August, 1998. Operating revenues from Energetix for
the quarter were primarily due to heating oil and propane gas sales by Griffith
totaling $44.0 million. Energitix, including Griffith on a consolidated basis
had pre-tax income of $2 million for the first quarter, which was due in large
part to the very seasonal nature of the Griffith business. The Company believes
the Energetix with its subsidiary, Griffith, provide the Company a platform upon
which to develop its unregulated electric and natural gas business as these
competitive markets develop. Griffith's liquid fuels energy business extends
beyond the Company's regulated distribution service territory.
FOSSIL UNIT STATUS. On April 30, 1999, the Company ceased operations at its
Beebee Station (80 Megawatt) generating facility. As previously announced, the
plant will be retired. 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. The plant will be 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 currently
provided by the plant are expected to be replaced in the energy markets as
needed.
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 $66
million, which includes the buyer's agreement to assume the Company's
obligations under a transmission services agreement between the Company and
Niagara Mohawk which represents a present value of approximately $25 million.
The transaction is subject to certain adjustments to be determined at closing.
In the event of the assumption of the transmission services agreement by NRG,
the Company will bear such present value in the allocation of the sale proceeds.
On April 29, 1999 the sale was approved by the Company's Board of Directors.
Under the terms of the Competitive Opportunities Settlement, the Settlement
acknowledges an intent that RG&E will be 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. The book value of the Company's interest in Oswego 6 is
approximately $54.4 million.
OPERATING EXPENSES. Higher fuel expenses reflect primarily the effect of a
maintenance shutdown of the Ginna Plant requiring higher cost purchases of
electricity. Other fuel expenses reflect mainly the cost of purchased fuel for
Griffith.
The $3.6 million decrease in regulated non-fuel O&M expenses for the
quarter reflects mainly dividends on insurance policies and the elimination of
property insurance and storm reserves.
Unregulated non-fuel O&M reflects primarily payroll expenses, fleet
21
<PAGE>
expenses for Griffith, and general and administrative expenses.
Local, State and other taxes declined in the first quarter reflecting
mainly variations in tax rates and tax credits on State revenue tax. The
difference in Federal income tax between the first quarters of 1999 and 1998 is
mainly the result of the settlement of audits in the first quarter of 1998.
OTHER STATEMENT OF INCOME ITEMS. The $.5 million increase in Other Income
and Deductions, Other-net for the quarter reflects mainly elimination of a
pension deferred credit consistent with the terms of the Competitive
Opportunities Settlement partially offset by carrying charges related to
deferral of Kamine facility costs and an accrual for certain incentive plans.
The increase in interest charges reflects mainly an increase of
approximately $140 million in long-term debt outstanding, resulting mainly from
the Kamine settlement and the acquisition of Griffith by Energetix, and $.5
million of interest from unregulated operations.
DIVIDEND POLICY
On March 17, 1999, the Board of Directors authorized a common stock
dividend of $.45 per share, which was paid on April 24, 1999 to shareholders of
record on April 5, 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
March 31, 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 March
31, 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.
22
<PAGE>
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information on Legal Proceedings reference is made to Note 3 of the
Notes to Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's Annual Meeting of Shareholders was held on April 29, 1999.
The following matters were voted upon:
(a) Approval of an Agreement and Plan of Share Exchange under which RG&E will
reorganize into a holding company structure:
Shares For: 26,987,404
Shares Against: 2,205,342
Shares Abstain: 620,418
Broker "Non Voted": 4,118,326
(b) The election of the following Directors for three year terms expiring at
the Annual Meeting of Shareholders in 2002:
Shares Shares
Nominees For Withheld
--------- ---------- --------
G. Jean Howard 33,135,361 796,129
Samuel T. Hubbard, Jr. 33,245,837 685,653
Cleve L. Killingsworth, Jr. 33,221,192 710,298
Roger W. Kober 33,063,919 867,571
ITEM 5. OTHER INFORMATION
BOARD OF DIRECTORS CHANGE. On May 11, 1999, the Company announced that G.
Jean Howard, executive director of Wilson Commencement Park, has been elected to
the Company's Board of Directors.
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 27 Financial Data Schedule pursuant to Item 601 (c) of
Regulation S-K.
23
<PAGE>
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: May 14, 1999 By /s/ J.B. STOKES
------------------------------------
J. Burt Stokes
Senior Vice President, Corporate Services
and Chief Financial Officer
Date: May 14, 1999 By /s/ WILLIAM J. REDDY
--------------------------------------
William J. Reddy
Controller
24
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