<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, 1997
-------------------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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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
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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, 1997: 38,851,464
-----------
<PAGE>
INDEX
<TABLE>
<CAPTION>
Page No.
<S> <C>
PART I - FINANCIAL INFORMATION
Consolidated Balance Sheet - June 30,1997 and
December 31, 1996..................................... 1 - 2
Consolidated Statement of Income - Three Months and Six
Months Ended June 30, 1997 and 1996................... 3 - 4
Consolidated Statement of Cash Flows - Six Months
Ended June 30,1997 and 1996........................... 5
Notes to Financial Statements............................ 6 - 9
Management's Discussion and Analysis of Financial
Condition and Results of Operations................... 10 -19
PART II - OTHER INFORMATION
Legal Proceedings........................................ 19
Exhibits and Reports on Form 8-K......................... 20
Signatures............................................... 20
</TABLE>
<PAGE>
PART I - FINANCIAL INFORMATION
- ------------------------------
ITEM 1. FINANCIAL STATEMENTS
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
June 30, December 31,
Assets 1997 1996
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric $2,427,395 $2,413,881
Gas 398,248 391,231
Common 133,423 129,946
Nuclear fuel 230,715 224,701
---------- ----------
3,189,781 3,159,759
Less: Accumulated depreciation 1,447,440 1,381,908
Nuclear fuel amortization 196,204 187,170
---------- ----------
1,546,137 1,590,681
Construction work in progress 65,327 69,711
---------- ----------
Net Utility Plant 1,611,464 1,660,392
---------- ----------
Current Assets
Cash and cash equivalents 42,515 21,301
Accounts receivable, net of allowance for
doubtful accounts: 1997 - $21,402, 1996 - $17,500 107,965 112,908
Unbilled revenue receivable 32,655 53,261
Materials, supplies and fuels, at average cost 25,015 39,888
Prepayments 25,997 23,103
---------- ----------
Total Current Assets 234,147 250,461
---------- ----------
Deferred Debits
Nuclear generating plant decommissioning fund 113,548 91,195
Nine Mile Two deferred costs 30,834 31,360
Unamortized debt expense 14,027 14,820
Other deferred debits 25,301 28,759
Regulatory assets (Note 2) 251,925 284,489
---------- ----------
Total Deferred Debits 435,635 450,623
---------- ----------
Total Assets $2,281,246 $2,361,476
- --------------------------------------------------------- ---------- ----------
</TABLE>
The accompanying notes are an integral part of the financial statements.
1
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
June 30, December 31,
Capitalization and Liabilities 1997 1996
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization
Long term debt - mortgage bonds $ 525,400 $ 555,054
- promissory notes 91,900 91,900
Preferred stock redeemable at option of Company 47,000 67,000
Preferred stock subject to mandatory redemption 45,000 45,000
Common shareholders' equity:
Common stock
Authorized 50,000,000 shares; 38,851,464
shares outstanding at June 30, 1997
and at December 31, 1996. 696,303 696,019
Retained earnings 111,277 90,540
---------- ----------
Total common shareholders' equity 807,580 786,559
---------- ----------
Total Capitalization 1,516,880 1,545,513
---------- ----------
Long Term Liabilities (Department of Energy)
Nuclear waste disposal 81,154 79,057
Uranium enrichment decommissioning 14,945 14,695
---------- ----------
Total Long Term Liabilities 96,099 93,752
---------- ----------
Current Liabilities
Long term debt due within one year -- 20,000
Preferred stock redeemable within one year 10,000 10,000
Short term debt -- 14,000
Accounts payable 44,421 49,462
Dividends payable 18,974 19,349
Taxes accrued 13,392 4,694
Interest accrued 9,053 10,317
Other 33,122 30,395
---------- ----------
Total Current Liabilities 128,962 158,217
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 351,382 370,028
Pension costs accrued 69,519 69,806
Other 118,404 124,160
---------- ----------
Total Deferred Credits and Other Liabilities 539,305 563,994
---------- ----------
Commitments and Other Matters (Note 2) -- --
---------- ----------
Total Capitalization and Liabilities $2,281,246 $2,361,476
- --------------------------------------------------------- ---------- ----------
</TABLE>
The accompanying notes are an integral part of the financial statements.
2
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
For the Three Months Ended
June 30,
1997 1996
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues
Electric $163,355 $163,127
Gas 61,053 68,380
-------- --------
224,408 231,507
Electric sales to other utilities 5,011 4,070
-------- --------
Total Operating Revenues 229,419 235,577
-------- --------
Fuel Expenses
Fuel for electric generation 11,530 8,746
Purchased electricity 5,556 17,356
Gas purchased for resale 35,727 37,815
-------- --------
Total Fuel Expenses 52,813 63,917
-------- --------
Operating Revenue less Fuel Expenses 176,606 171,660
-------- --------
Other Operating Expenses
Operations excluding fuel expenses 64,771 68,292
Maintenance 10,254 15,506
Depreciation and amortization 29,312 23,867
Taxes - local, state and other 28,090 30,992
Federal income tax 13,054 9,888
-------- --------
Total Other Operating Expenses 145,481 148,545
-------- --------
Operating Income 31,125 23,115
-------- --------
Other Income and Deductions
Allowance for other funds
used during construction 62 283
Federal income tax 1,007 406
Other - net (981) 576
-------- --------
Total Other Income and Deductions 88 1,265
-------- --------
Income before Interest Charges 31,213 24,380
-------- --------
Interest Charges
Long term debt 11,287 11,964
Other - net 1,852 1,138
Allowance for borrowed funds
used during construction (98) (454)
-------- --------
Total Interest Charges 13,041 12,648
-------- --------
Net Income 18,172 11,732
-------- --------
Dividends on Preferred Stock 1,491 1,866
-------- --------
Earnings Applicable to Common Stock $16,681 $9,866
-------- --------
Weighted average number of shares
outstanding in each period (000's) 38,851 38,782
Earnings per Common Share $0.42 $0.25
Cash Dividends Paid per Common Share $0.45 $0.45
</TABLE>
- -----------------------------------------------------------------
The accompanying notes are an integral part of the financial statements.
3
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
For the Six Months Ended
June 30,
1997 1996
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues
Electric $337,417 $333,635
Gas 198,046 200,196
-------- --------
535,463 533,831
Electric sales to other utilities 8,801 10,942
-------- --------
Total Operating Revenues 544,264 544,773
-------- --------
Fuel Expenses
Fuel for electric generation 22,362 19,857
Purchased electricity 10,440 26,308
Gas purchased for resale 115,083 109,574
-------- --------
Total Fuel Expenses 147,885 155,739
-------- --------
Operating Revenue less Fuel Expenses 396,379 389,034
-------- --------
Other Operating Expenses
Operations excluding fuel expenses 128,964 129,894
Maintenance 21,783 25,018
Depreciation and amortization 58,524 47,357
Taxes - local, state and other 63,057 67,499
Federal income tax 37,732 39,285
-------- --------
Total Other Operating Expenses 310,060 309,053
-------- --------
Operating Income 86,319 79,981
-------- --------
Other Income and Deductions
Allowance for other funds
used during construction 133 528
Federal income tax 1,770 1,004
Other - net (2,166) 897
-------- --------
Total Other Income and Deductions (263) 2,429
-------- --------
Income before Interest Charges 86,056 82,410
-------- --------
Interest Charges
Long term debt 23,140 24,841
Other - net 3,524 4,520
Allowance for borrowed funds
used during construction (213) (1,172)
-------- --------
Total Interest Charges 26,451 28,189
-------- --------
Net Income 59,605 54,221
-------- --------
Dividends on Preferred Stock 3,195 3,732
-------- --------
Earnings Applicable to Common Stock $56,410 $50,489
-------- --------
Weighted average number of shares
outstanding in each period (000's) 38,851 38,686
Earnings per Common Share $1.45 $1.30
Cash Dividends Paid per Common Share $0.90 $0.90
</TABLE>
- -----------------------------------------------------------------
The accompanying notes are an integral part of the financial statements.
4
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Six Months Ended
(Thousands of Dollars) June 30,
- ----------------------------------------------------------------------------------------------------------
1997 1996*
------------------------------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES
Net income $ 59,605 $ 54,221
Adjustments to reconcile net income to net cash flow provided
from operating activities:
Depreciation and amortization 68,034 55,763
Deferred fuel 9,613 13,595
Deferred income taxes (10,158) (4,428)
Allowance for funds used during construction (345) (1,701)
Unbilled revenue, net 20,605 28,293
Nuclear generating plant decommissioning fund (9,931) (4,402)
Pension costs accrued (2,198) (2,036)
Post employment benefit internal reserve 3,933 3,197
Changes in certain current assets and liabilities:
Accounts receivable 4,943 (4,015)
Materials, supplies and fuels 14,874 14,670
Taxes accrued 8,698 16,737
Accounts payable (5,041) (10,579)
Other current assets and liabilities, net 144 (9,045)
Other, net 12,149 17,764
---------- ----------
Total Operating $ 174,925 $ 168,034
---------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant $ (29,509) $ (73,142)
Other, net -- (6,920)
---------- ----------
Total Investing $ (29,509) $ (80,062)
---------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/issuance of common stock $ -- $ 8,612
Short term borrowings (14,000) --
Redemption of preferred stock (20,000) --
Redemption of long term debt (49,668) (67,000)
Dividends paid on preferred stock (3,570) (3,733)
Dividends paid on common stock (34,966) (34,690)
Other, net (1,998) 1,204
---------- ----------
Total Financing $ (124,202) $ (95,607)
---------- ----------
Increase (decrease) in cash and cash equivalents $ 21,214 $ (7,635)
Cash and cash equivalents at beginning of period $ 21,301 $ 44,121
---------- ----------
Cash and cash equivalents at end of period $ 42,515 $ 36,486
---------- ----------
</TABLE>
<TABLE>
<CAPTION>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Six Months Ended
June 30,
(Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------
1997 1996
---------- ----------
<S> <C> <C>
Cash Paid During the Period
Interest paid (net of capitalized amount) $ 26,735 $ 27,888
---------- --------
Income taxes paid $ 39,000 $ 33,000
---------- --------
</TABLE>
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
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) necessary for a fair statement of the
results of operations for the interim periods presented. The consolidated
financial statements for 1997 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. 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, 1996.
Note 2. 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, 1996 and should be read in conjunction with the
material contained in that Note.
LITIGATION
Department of Justice Lawsuit. On June 24, 1997, the Antitrust Division of
the United States Department of Justice filed a civil complaint against the
Company in the United States District Court for the Western District of New
York. The complaint follows a Civil Investigative Demand investigation. That
investigation included a broad look at the Company's activities in the electric
power industry including initially, the Company's power purchase agreement with
an independent power producer. The investigation then focused primarily upon the
flexible rate long term contracts entered between the Company and a number of
its large customers under a tariff approved by the New York State Public Service
Commission (PSC). The tariff and the PSC policies it implemented recognized
that if large customers took their electrical load off the system, the rates for
remaining customers would have to increase to cover the fixed costs of
operation.
The Division in its complaint has challenged only certain provisions of one
flexible rate contract, the contract with the University of Rochester. The
Complaint alleges that those provisions in that contract violate Section 1 of
the Sherman Act by restricting the customer's right to compete with the Company
in the sale of electricity and seeks an injunction prohibiting the Company from
enforcing that contract and from entering other agreements that limit
competition in the sale of electricity to other customers.
The Company believes that the investigation and the Complaint reflect the
desire by the Antitrust Division to become involved in the deregulation of
electric utilities, but that the proper way to do that is in the proceedings
before the PSC in the Competitive Opportunities Case. The Company believes that
its contract with the University was subject to the State Action exemption from
the antitrust laws and actually benefited both the University and the remaining
customers of the Company. Accordingly, the Company will defend this action
vigorously.
Litigation with Co-Generator. The Company is engaged in litigation with
Kamine/Besicorp Allegany L.P. (Kamine), the only co-generator operating in its
service territory. The details of the litigation, involving several different
proceedings, are described in Note 10 of the Company's 1996 Annual Report on
Form 10-K. One of the
6
<PAGE>
complaints served by Kamine seeks damages in the amount of $420,000,000.
Significant developments in these proceedings since the filing of the 1996
Annual Report on Form 10-K are described below.
In November 1995 Kamine filed in Newark, New Jersey for protection under the
bankruptcy laws and filed a complaint in an adversary proceeding seeking, among
other things, specific performance of the agreement to sell power to the
Company. Kamine filed a motion to compel the Company to pay what would be due
under Kamine's view of the terms of that agreement during the pendency of the
Adversary Proceeding. After hearing, the Bankruptcy Court denied that motion.
The Court also denied various motions made by the Company to change the venue of
the proceeding to New York State and to lift the automatic stay of the pending
New York State action. On appeal, the Bankruptcy Court was reversed and the
case sent back to the Bankruptcy Court to decide where the contract issues in
the Adversary Proceeding should be adjudicated. As of June 16, 1997, the
Company filed a Second Amended Complaint in the State Court action asserting
additional claims based on subsequent occurrences.
On March 19, 1997, the Bankruptcy Court stayed the Adversary Proceeding
pending resolution of the contract issues in the New York State court trial.
Kamine has indicated it will not appeal this action.
Numerous other procedural motions have been presented in the Bankruptcy
Court, some of which may now be considered by the New York State court. While
these proceedings are pending, the Company would pay approximately two cents per
kilowatt hour when the plant operates. It is not operating at the present time.
General Electric Capital Corporation Lawsuit. On July 3, 1997, General
Electric Capital Corporation (GECC) filed a complaint against the Company in the
United States District Court for the Western District of New York in connection
with the Kamine project in Hume, New York, for which GECC provided financing.
The complaint asserts that the Company violated the antitrust laws in its
dealings with Kamine and seeks injunctive relief, treble damages and alleged
actual damages of not less than $100,000,000. The claims made in the complaint
filed are substantially similar to the claims made by Kamine in the same court
under Kamine's version of the terms of the Power Purchase Agreement for the Hume
project. The court denied Kamine's motion for preliminary injunction on grounds
which included Kamine's failure to establish a likelihood of success on the
merits of its claims. Kamine had filed a notice of appeal from a decision
denying Kamine's motion for a preliminary injunction. Kamine subsequently
withdrew the appeal. The Company believes the complaint by GECC is also without
merit and intends to defend the action.
ENVIRONMENTAL MATTERS
Federal Clean Air Act Amendments. The company is developing strategies
responsive to the federal clean air act amendments of 1990 (Amendments) which
will primarily affect air emissions from the Company's fossil-fueled generating
facilities. The strategy being developed is a combination of hardware solutions
which have a capital and operation and maintenance (O&M) component and allowance
trading solutions which have strictly an O&M impact. The most recent strategy
developments still envision this combination of efforts as the most cost
effective means of proceeding although there is some activity in the New York
State Legislature that could impact the Company's ability to rely upon the
emission allowance market as a reliable means of meeting some of its
environmental commitments. At this time, it is impossible to predict the
outcome of these proceedings in the Legislature and, as a result, the Company's
projections are based solely on the combination strategy. A range of capital
costs between $2.9 and $3.5 million has been estimated for the implementation of
several potential alterations for meeting the foreseeable nitrogen oxide and
sulfur
7
<PAGE>
dioxide requirements of the Amendments, as well as $1.0 to $1.5 million per year
in operating expenses. These capital costs would be incurred between 1997 and
2000. The O&M expenses would be for the year 1999. For the year 2000 and
beyond, the Company estimates that the annual operating expenses would rise to
between $2.4 million and $3.7 million. Any additional post-2000 capital costs
and operating expense cannot be predicted until State and federal legislation
stabilizes sufficiently to enable the Company to finalize its compliance
strategy.
Opacity Issue. In May 1997, the Company commenced negotiations with the New
York State Department of Environmental Conservation (NYSDEC) to resolve
allegations of past opacity violations at the Company's Beebee and Russell
Stations. The opacity standard is a regulation which limits the density of the
smoke emitted from the Stations' smokestacks. The Company believes that it will
reach an agreement with NYSDEC on this issue and that the amount of any civil
penalty will likely include both cash and environmental benefit project
components which, in the aggregate, will not be material to the Company's
financial condition or results of operations. This matter has resulted in
operational adjustments which are discussed in Item 2, Management's Discussion
and Analysis of Financial Condition and Results of Operations under the heading
"Fossil Unit Deratings".
FERC 636 TRANSITION COSTS
As a result of the restructuring of the gas transportation industry by the
Federal Energy Regulatory Commission (FERC) pursuant to Order No. 636 and
related decisions, the Company was required to pay a share of certain transition
costs incurred by the interstate pipelines through which it has purchased gas.
The Company, as a customer, estimated total costs of about $50 million which,
for the most part, have been paid to its suppliers. The pipeline with the
largest transition cost liability has reached a negotiated settlement with its
customers, including the Company. This settlement agreement, filed with the
FERC and awaiting FERC approval, would resolve the last transition cost case.
Under the settlement, transition costs will be paid for an additional 24 months,
then cease. A regulatory asset and related deferred credit have been
established on the balance sheet to account for these costs. Approximately $42.0
million of these costs were paid to suppliers, of which about $35.3 million has
been included in purchased gas costs. An amount of $14.7 million remains for
future collection from customers. The Company has a $10 million credit
agreement with a domestic bank to provide funds for the Company's transition
cost liability to CNG Transmission Corporation. At June 30, 1997 the Company
had $6.7 million of borrowings outstanding under the credit agreement. The
Company is collecting those costs through the Gas Cost Adjustment clause in its
rates.
ASSERTION OF TAX LIABILITY
The Company's federal income tax returns have been examined by the Internal
Revenue Service (IRS) through the calendar year 1992. Although the years 1987-
1992 remain open, the Company has reached tentative Agreement with the IRS on
the issues related to the Nine Mile Two in-service date. With this Agreement,
all outstanding issues will have essentially been resolved and the Company has
ultimately prevailed concerning the use of a 1987 in-service date. All
calculations supporting the Company's position are expected to be finalized in
the third quarter of 1997. The Company has reversed some of the tax reserve
established in prior years as a result of the favorable resolution of the in-
service date related issues.
REGULATORY AND STRANDABLE 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
8
<PAGE>
accounting is permitted by Statement of Financial Accounting Standards No. 71
(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 Statement of Financial
Accounting Standards No. 121 (SFAS-121)). In certain cases, the entire amount
could be written off.
Below is a summarization of the Regulatory Assets as of June 30, 1997.
<TABLE>
<CAPTION>
Millions
of Dollars
----------
<S> <C>
Income Taxes $166.1
Uranium Enrichment Decommissioning Deferral 17.0
Deferred Ice Storm Charges 12.7
FERC 636 Transition Costs 27.9
Demand Side Management Costs Deferred 6.1
Other, net 22.1
------
Total - Regulatory Assets $251.9
======
</TABLE>
See the Company's Form 10-K for the fiscal year ended December 31,
1996 Item 8, Note 10 of the Notes to Financial Statements, "Regulatory and
Strandable Assets" for a description of the Regulatory Assets shown above.
SFAS-121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of", 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.
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 (e.g., the Kamine/Besicorp Allegany L.P.
contract), 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, 1997
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, would be
written down for impairment of recovery in the same manner as deferred cost
discussed above.
At June 30, 1997 the Company believes that its Regulatory and
Strandable Assets, if any, are not impaired and are probable of recovery,
although no assurance can be given. The proposed settlement in the Competitive
Opportunities proceeding does not impair the opportunity of the Company to
recover its investment in these assets.
9
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following is Management's assessment of certain significant factors
affecting the financial condition and operating results of the Company. This
assessment contains forward-looking statements which are subject to various
risks and uncertainties. The Company's actual results could differ from those
anticipated in such forward-looking statements as a result of numerous factors
which may be beyond the Company's control by reason of factors such as electric
and gas utility restructuring, future economic conditions and developments in
the legislative, regulatory and competitive environments in which the Company
operates. Shown below is a listing of the principal items discussed.
<TABLE>
<S> <C>
Earnings Summary Page 10
Competition Page 11
PSC Competitive Opportunities Case Settlement
FERC Open Transmission Orders
PSC Gas Restructuring Case
Rates and Regulatory Matters Page 15
1996 Rate Settlement
1995 Gas Settlement
Gas Fixed Price Proposal
Liquidity and Capital Resources Page 16
Projected Capital and Other Requirements
Redemption of Securities
Financing
Results of Operations Page 17
Operating Revenues and Sales
Operating Expenses
Dividend Policy Page 19
</TABLE>
EARNINGS SUMMARY
Earnings per common share for the current and prior year three month periods
ended June 30, are as follows:
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
Three Months $ .42 $ .25
Six Months $1.45 $1.30
</TABLE>
In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128 ("SFAS-128"), "Earnings per
Share," which changes the methodology of calculating earnings per share. The
Company will adopt SFAS No. 128 in the fourth quarter of 1997. Had the Company
adopted SFAS-128 during the first quarter the impact on earnings would not have
been significant.
Second quarter earnings were higher in 1997 due to sustained operation of
the Company's Ginna nuclear power plant throughout the period. This facility
was in a refueling and steam generator replacement outage during most of the
second quarter of 1996. The Ginna Plant will enter a normal refueling outage
later in the year. In
10
<PAGE>
addition, the Company was able to produce operating expense savings partially
offset by an electric rate decrease.
The increase in earnings for the six-month period reflects the same
factors described for the second quarter.
The Company has maintained its earnings while reducing electric rates
on July 1, 1996. The Company further reduced its rates on July 1, 1997.
Additional electric rate reductions in accordance with the Competitive
Opportunities Settlement (see description below) recently filed with the New
York State Public Service Commission (PSC) are scheduled to begin July 1, 1998,
pending approval from the PSC. The Company believes that the Settlement, when
approved by the PSC and implemented, 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 any proposals ultimately adopted by the PSC on the business
of the Company will depend on the specific details of any plan for increased
competition and resolution of the complex issues involved, especially
competition at the retail level.
Future earnings will also be affected, in part, by the Company's degree
of success in remarketing its excess gas capacity as set under the terms of the
1995 Gas Settlement and in controlling its local gas distribution costs. The
Company believes it will be successful in meeting the 1995 Gas Settlement
targets over the remaining two years of the Settlement period, although no
assurance can be given.
COMPETITION
See the Company's Form 10-K for the fiscal year ended December 31, 1996,
Item 7.- "Competition" for a discussion of formation of a joint nuclear
operating company and the Company's business strategy. See Note 2 of the Notes
to Financial Statements for a discussion of regulatory and strandable assets and
related accounting issues.
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. By Opinion No. 96-12
issued May 20, 1996 in the "Competitive Opportunities Proceeding," the PSC
endorsed a fundamental restructuring of the electric utility industry in the
State. Among other elements, the PSC's goals included lower rates for consumers
and increased customer choice in obtaining electricity and other energy
services.
On April 8, 1997, the Company, the PSC Staff ("Staff") and other parties
entered into a Settlement Agreement (the "Settlement") with regard to the
Competitive Opportunities Proceeding.
Summary. The Settlement, which is subject to PSC approval, provides for
a transition to competition during the five-year term of the Settlement (July 1,
1997 through June 30, 2002). The Settlement would establish the Company's
electric rates for each annual period commencing July 1 ("Rate Year") during the
term. A Retail Access Program will be phased in, allowing customers to purchase
electricity, and later electricity and capacity commitments, from sources other
than the Company. During the term, the Company's non-nuclear generating sources
(fossil-fuel, hydro, gas-turbine generation and purchased power contracts,
excluding Kamine) will be required to compete in the market. The Company will
be provided a reasonable opportunity to recover prudently incurred costs,
including those pertaining to generation and purchased power.
The Settlement also requires the Company to functionally separate its
component operations: distribution, generation, and retailing. The Company
would be required to separate, structurally, any unregulated retail operations
from the remainder of the regulated utility functions. In addition, the Company
would have the option to establish a holding company structure and to utilize
certain funds derived
11
<PAGE>
from rendering utility service for unregulated operations. The Settlement
requires neither divestiture of generating or other assets, nor writing off of
"stranded costs" (the above-market costs, presumed to result from competition).
The Settlement is currently the subject of PSC examination to determine
whether it is in the public interest. Hearings before an Administrative Law
Judge (ALJ) were held in early June 1997. On July 16, 1997, the ALJ issued a
Recommended Decision that recommends approval of the Settlement in all material
respects. A PSC decision regarding the Settlement is expected in September
1997.
The Company believes that the Settlement Agreement will not adversely
affect its eligibility to continue to apply SFAS-71. If, contrary to the
Company's view, such eligibility were adversely affected, a material write-down
of assets, the amount of which is not presently determinable, could be required.
Rate Plan. Subject to certain conditions, the Rate Plan contained in the
Settlement continues and augments the rate reductions provided for in the
Company's 1996 settlement ("the 1996 Settlement") approved by the PSC. Over the
five rate years of the term, the cumulative rate reductions will be as follows:
Rate Year 1: $3.5 million; Rate Year 2: $10.5 million; Rate Year 3: $22.6
million; Rate Year 4: $32.2 million; and Rate Year 5: $34.8 million. To the
extent that "Mandates" (i.e., governmentally required and external costs imposed
----
on the Company) are reduced, the foregoing reductions may increase in Rate Years
2 through 5. The reduction for Rate Year 1 is equal to the previously approved
reduction planned as a provision of the Company's 1996 Rate Settlement. It was
implemented on July 1, 1997 pursuant to the earlier agreement. No changes in
rates would be required for this period even if the Settlement is approved.
The Rate Plan permits the Company to offset against the foregoing total
-----
reductions certain amounts related to a Purchase Power Agreement with Kamine
which is the subject of substantial litigation described in Item 1, Financial
Statements under the caption "Litigation with Co-Generator" in Note 2,
Commitments and Other Matters. To provide for possible settlement of the Kamine
litigation, the Rate Plan permits the Company to make the following offsets, by
"Rate Year": Rate Year 2: $3.5 million; Rate Year 3: $8.5 million; Rate Year 4:
and following (until payment is completed): $10.6 million. The Settlement also
would permit the Company to recover the full amount of any difference between
Kamine costs currently included in rates and any increased amount resulting from
enforcement of the purported PPA or judicially required payments. Seven-eighths
of this difference may be added, on a current basis, to the amount already
included in rates. Amounts not currently recovered may be deferred for future
recovery.
The Settlement permits recovery of inflation-based increases to certain
Operation and Maintenance ("O&M") expenses above 4.0 percent, permits the
Company to retain a portion of property tax decreases, and allows the Company to
recover the costs of certain Mandates to be included in a "System Benefits
Charge" and to recover others to the extent they exceed a $2.5 million
threshold. The Company also would be permitted to recover the costs of
Catastrophic Events and Competition Implementation Costs (i.e., the cost of
----
transition) to the extent they exceed the same threshold. Low-income and service
quality programs, established in prior proceedings would continue in much their
same form. The maximum service quality penalty, however, would be reduced to
$1.25 million per year.
In the event that the Company earns a return on common equity in excess
of 11.80 percent, the Company would be entitled to retain 50 percent of the
excess and to use the remaining 50 percent to write down accumulated deferred
costs or investment in electric plant and Regulatory Assets (which are deferred
costs whose classification as an asset on the balance sheet is permitted by
SFAS-71). If the Company's rate of return on common equity falls below 8.5
percent or increases above 14.5 percent, or if the pre-tax interest coverage
falls below 2.5 times, or if certain governmental actions occur which cannot
adequately be addressed by the Settlement as it pertains to Mandates, either the
Company or any party to the Settlement would have the right to
12
<PAGE>
petition the PSC for review of the Settlement and appropriate remedial action.
Retail Access. Over the five-year term of the Settlement, the Company
will phase in a Retail Access Program that will permit customers to purchase
their own electricity and capacity from alternative suppliers. Assuming that
certain operational requirements are met and certain governmental approvals are
in place, on July 1, 1998, customers whose electric loads total 670 Gigawatt
hours ("GWH") (representing approximately 10 percent of the Company's total
annual Retail Sales) will be eligible to purchase electricity (but not capacity
commitments) from alternative suppliers. On July 1, 1999, customers with loads
totaling up to 1,300 GWH (approximately 20 percent of total Sales) will be
eligible to purchase energy and capacity commitments from alternative suppliers.
As of July 1, 2000, aggregate customer load of up to 2,000 GWH (approximately 30
percent of total Sales) will be eligible; and, as of July 1, 2001, up to 3,000
GWH (approximately 46 percent of total Sales) will be eligible. The cited
amounts eligible for retail access would be increased for growth in retail sales
above 6,714 GWH. As of July 1, 2002, all retail customers will be eligible to
purchase energy and capacity from alternative suppliers.
Under the Retail Access Program, delivery of electricity will continue to
be through The Company's distribution system. The schedule for implementation
of the "Energy and Capacity" stage of the Program (commencing July 1, 1999)
assumes that a Statewide Energy and Capacity Market will be in place by July 1,
1998. If the operation of that Market is delayed, the Company may petition the
PSC for a delay in implementation of the Energy and Capacity stage.
During the initial, energy only stage of the Retail Access Program, the
Company delivery rate will generally equal the rate for fully bundled service
less the average non-nuclear fuel and purchased power cost of the electric
commodity. During the energy and capacity stage, the rate will generally equal
the bundled rate less the cost of the electric commodity and the Company's non-
nuclear generating capacity. These commodity and capacity costs, generally
referred to as "contestable costs," are estimated to be $.032 per kilowatt hour
("KWH").
The Company would not be required to divest any of its generation
facilities. Instead, the phasing-in of the Retail Access Program subjects the
Company's generation to competition from the market in increments, as described
above. "Sunk Costs", the investment in electric plant as of March 1, 1997,
would be included in electric distribution tariff rates during the term of the
Settlement. Future rate treatment of such costs is to be consistent with the
principle that the Company is to have a reasonable opportunity to recover such
costs.
"To-Go Costs" of the Company's non-nuclear resources (i.e., capital costs
----
incurred after February 28, 1997, operation and maintenance expenses, and
property, payroll and other taxes) are to be recovered through the distribution
access tariff. The fixed portion of To-Go Costs would be recovered in full
through the distribution access tariff until July 1, 1999 and subject to the
market thereafter in accordance with the phase-in schedule for the Retail Access
program described above. The variable portion of non-nuclear To-Go Costs would
also be subject to the market in accordance with the phase-in Schedule described
above. Upon extension of eligibility for the Retail Access Program to all
retail customers on July 1, 2002, the Company would be authorized to modify its
distribution access rates, so as to hold constant the degree to which its To-Go
Costs are at risk for recovery through the market. Thus, while the recovery of
non-nuclear To-Go Costs would continue to be through the market, recovery of
nuclear costs would remain recoverable through regulated rates. If, during the
operation of the Energy and Capacity Stage of the Retail Access Program, the
market price of energy and capacity exceeds an average of 3.2 cents per KWH, the
pace of the Retail Access Program implementation schedule could, after
discussion among the Settlement parties, be accelerated.
During at least the first two and one-half years of the Settlement, all
prudently incurred costs associated with the Ginna nuclear plant and the
Company's share of the Nine Mile Point 2 nuclear facility would be recovered
through regulated
13
<PAGE>
retail rates. Future rate treatment of Nine Mile Point 2 would be determined
through good faith negotiations among the Company, Staff and the other co-
tenants of the facility. It is expected that rate treatment of Ginna would be
similar. No change in such treatment of nuclear facilities may be implemented
prior to January 1, 2000. Shutdown and decommissioning costs would be recovered
during the term of the Settlement in a manner consistent with past ratemaking
treatment.
Corporate Structure. The Settlement envisions, and authorizes the
Company to form, a holding company ("HOLDCO") structure and provides standards
of conduct to govern relationships among affiliated entities within that
structure. Formation of the HOLDCO would require a separate petition to the
PSC, a form of which is appended to the Settlement, and approval by
shareholders, the Securities and Exchange Commission, the Federal Energy
Regulatory Commission ("FERC") and the Nuclear Regulatory Commission.
The Settlement would authorize the Company to initially fund its
unregulated activities, whether conducted through a HOLDCO or otherwise, with
$50 million and would not require a separate authorization by the PSC for such
investment.
Miscellaneous. Upon approval of the Settlement by the PSC, the Company
would withdraw from an appeal challenging the PSC's Opinion No. 96-12 and would
terminate its petition seeking judicial review of the PSC's decision regarding
the settlement in the previous electric rate proceeding (the 1996 Rate
Settlement). The present Settlement would, upon approval, supersede the 1996
Rate Settlement. Various incentive and penalty provisions in the 1996 Rate
Settlement would be eliminated.
As a means of compliance with a PSC order issued February 25, 1997 in a
separate proceeding involving establishment of pilot programs for farmers and
food processors, the Settlement provides that the Company's retail access
program will commence on April 1, 1998 for those groups of customers within the
Company's service area. By a subsequent order issued June 23, 1997, the PSC
required that the program commence on February 1, 1998 and that the rates
offered under the pilot program be reduced below the level contemplated in the
Settlement. The ALJ's July 16, 1997 Recommended Decision proposes that approval
of the Settlement be conditioned on compliance with the June 23, 1997 order.
The Company is considering what action, if any, to take in light of the
differences between the provisions of the Settlement and those of the
Commission's June 23, 1997 order.
FERC OPEN TRANSMISSION ORDERS. In early 1996 FERC issued new rules to
facilitate the development of competitive wholesale markets by requiring
electric utilities to offer "open-access" transmission service on a non-
discriminatory basis in tariffs. The Company filed its required transmission
service tariff on July 9, 1996. The new tariff would apply to wholesale
purchases and sales made by the Company and the financial impact will depend on
prevailing energy prices in the wholesale market. The near-term impacts of this
tariff are not expected to be significant. On March 6, 1997, the Company
reached a settlement in principle with the other parties respecting rate issues.
FERC approval of the settlement was granted on June 25, 1997.
In December 1996 the Company and other New York utilities submitted a
compliance filing with FERC in accordance with the requirements of the FERC's
"open-access" order. In order to support the FERC's "open access" order, the
utilities also established a centralized transmission service information
network, which went on-line in early January 1997. This "open access same-time
information system" (OASIS) enables wholesale customers of New York State's bulk
power system to obtain timely information regarding transmission service
availability and pricing via the Internet.
On January 31, 1997, the 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 the independent
system operator (ISO) will administer a state-wide 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 ISO, the proposal calls for
creation of a New York Power
14
<PAGE>
Exchange ("NYPEx") and a New York State Reliability Council ("NYSRC"). On May
2, 1997 the utilities made a supplemental filing with FERC that provided
additional details of the proposed NYSRC.
The NYPEx is a voluntary organization intended to facilitate development
of an active wholesale market by providing facilities and procedures to offer
energy for sale and to make energy purchases. As proposed, generators of
electricity could submit bids to sell energy to, and load serving entities could
submit bids to buy energy from, the NYPEx or any other power exchange. Each
power exchange would then submit its delivery schedules to the ISO which would
review them for feasibility and reliability. The energy market would use a
"locational-based marginal pricing" mechanism that takes into account
transmission limitations. Generators would also have the opportunity to enter
into bilateral contracts for electricity. The NYSRC is an organization formed by
the existing eight transmission providers in New York plus three representatives
of other market participants (buyers, sellers, and consumer/environmental
groups). The role of the NYSRC would be to establish general reliability
standards that the ISO would use to establish day-to-day operating procedures.
The proposed NYSRC is viewed by the transmission providers as an
essential prerequisite to transferring control of their transmission facilities
to the ISO. The NYPP member systems believe that the combination of an ISO with
day-to-day operational responsibility and the NYSRC with limited authority to
establish basic reliability standards on a long-term basis provides a balanced
structure to resolve the inherent tension between maintaining current system
reliability and maximizing the commercial use of transmission facilities by an
increased number of market participants.
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 of the financial condition of the Company.
PSC GAS RESTRUCTURING CASE. In March 1996 the PSC issued an Order and
approved utility restructuring plans designed to open up the local natural gas
market to competition and thereby allow residential, small business and
commercial/industrial users the same ability to purchase their gas supplies from
a variety of sources, other than the local utility, that larger industrial
customers already have. During a three-year phase-in period the State's gas
utilities would be permitted to require customers converting from sales service
to take associated pipeline capacity for which the utilities had originally
contracted. The PSC has indicated that it will address the issue of how the
costs of such capacity would be recovered after the three-year period during the
third year of the phase-in period. Under two new gas transportation tariffs,
gas customers have a choice of suppliers beginning November 1, 1996. The
Company will distribute the gas and charge for the distribution as well as
associated services. The Company believes its position in the market is such
that it will maintain its distribution system margins. Under a phase-in
limitation, loss of gas commodity sales may be limited to five percent of the
Company's annual gas volume the first year, and then five additional percent for
each of the following two years. The phase-in will be reviewed as experience is
gained with the program. The Company anticipates that the use of transportation
gas service will increase; however, through June 30, 1997 no customers were
being served under this new service.
RATES AND REGULATORY MATTERS
1996 ELECTRIC RATE SETTLEMENT. The PSC approved a Settlement Agreement
(1996 Rate Settlement) among the Company, PSC Staff and several other parties
which set rates for a three-year period, ending June 30, 1999. If the PSC
approves the
15
<PAGE>
Competitive Opportunities Settlement (Settlement) discussed earlier, the
Settlement would supersede the 1996 Rate Settlement and the Company would
terminate its petition seeking judicial review of the 1996 Rate Settlement. For
a description of the 1996 Rate Settlement see the Company's 1996 Form 10-K, Item
7, under the heading "Rates and Regulatory Matters".
1995 GAS SETTLEMENT. The Company entered into several agreements to help
manage its pipeline capacity costs and successfully met settlement targets for
capacity remarketing for the twelve months ending October 31, 1996, thereby
avoiding negative financial impacts for that period. The Company believes that
it will also be successful in meeting the Settlement targets in the remaining
two years of the Settlement period, although no assurance may be given. For
further information with respect to the 1995 Gas Settlement see the Company's
1996 Form 10-K Item 8, Note 10 of the Notes to Financial Statements.
GAS FIXED PRICE PROPOSAL. On August 4, 1997, the Company submitted a
proposal which offers a fixed price option to retail gas customers for the
coming heating season. The Company is planning to use financial instruments to
manage price risk. The proposal was submitted in response to a PSC order issued
in June requesting that New York Gas utilities offer the fixed price option to
help customers manage the price volatility exhibited in recent years.
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 1997 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 June 30, 1997
the Company had cash and cash equivalents of $42.5 million. Capital requirements
during 1997 are anticipated to be satisfied primarily from the combination of
internally generated funds and the use of short-term credit arrangements.
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 and the repayment of existing debt. The
Company has no plans to install additional baseload generation.
Total 1997 capital requirements are currently estimated at $132 million,
of which $102 million is for construction and $30 million is for the redemption
of maturing securities and sinking fund obligations. Approximately $30 million
had been expended for construction as of June 30, 1997, reflecting primarily
expenditures for upgrading electric generating, transmission and distribution
facilities and gas mains.
Purchased Power Requirement. Under federal and New York State laws and
regulations, the Company is required to purchase the electrical output of
unregulated cogeneration facilities which meet certain criteria (Qualifying
Facilities). The Company was compelled by regulators to enter into a contract
with Kamine for approximately 55 megawatts of capacity, the circumstances of
which are discussed in this report under Note 2 of the Notes to Financial
Statements and in the Company's 1996 Form 10-K under Item 8, Note 10 of the
Notes to Financial Statements. The Kamine contract and the outcome of related
litigation may have an important impact on the Company's electric rates and its
ability to function effectively in a competitive environment. In the event the
Settlement (described above) is approved by the PSC, recovery of costs
pertaining to Kamine will be governed by its terms. The Company has no other
long-term obligations to purchase energy from Qualifying Facilities.
REDEMPTION OF SECURITIES. On April 22, 1997, the Company redeemed
200,000 shares of 7.50% Preferred Stock, Series N at $102 per share plus accrued
dividends
16
<PAGE>
from March 1, 1997. On May 1, 1997, the Company redeemed $20,000,000 principal
amount of its First Mortgage 6 1/4% Bonds, Series W at 100.00% plus accrued
interest from March 15, 1997. On May 1, 1997, the Company redeemed $29,335,000
principal amount of its First Mortgage 8% Bonds, Series Y at 100.59% plus
accrued interest from February 15, 1997. On May 1, 1997, the Company also
redeemed $333,000 of its First Mortgage 8% Bonds, Series Y at the special
redemption price of 100.14% plus accrued interest from February 15, 1997 under
sinking and improvement fund provisions of its General Mortgage. On September
1, 1997, the Company will redeem, pursuant to a mandatory sinking fund, 100,000
shares of 7.45% Preferred Stock, Series S, at $100 per share.
FINANCING. (See Form 10-K for the fiscal year ended December 31, 1996,
Item 8. Note 9. Short-Term Debt, regarding the Company's short-term borrowing
arrangements.)
During the second half of 1997, the Company expects to complete
arrangements for refinancing up to $127.4 million of tax-exempt debt.
At June 30, 1997 the Company had Common Stock available for issuance of
1,026,840 shares under the Automatic Dividend Reinvestment and Stock Purchase
Plan (ADR Plan)and 129,664 shares under the Savings Plus Plan. Since July, 1996
the Company has provided for ADR Plan and Savings Plus Plan requirements through
the purchase of shares on the open market.
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, 1997 to the three-month and six-month periods
ended June 30, 1996. A summary of changes in Electric and Gas department
revenues and expenses is presented in the Operating Revenues and Expenses table.
17
<PAGE>
Operating Revenues and Expenses
<TABLE>
<CAPTION>
(Millions of Dollars)
Three Months Six Months
Ended June 30 Ended June 30
--------------- ---------------
<S> <C> <C>
1996 Earnings $ 9.9 $ 50.5
Increase (decrease) in earnings:
Electric revenue changes 1.2 1.6
- Includes effect of rate change
- Consumption changes including weather
- Changes in sales to other electric utilities
Electric fuel cost changes 9.0 13.4
Gas margin (revenue less fuel) (5.2) (7.7)
- Consumption changes including weather
Miscellaneous non-fuel operating and maintenance 8.8 4.2
- Reflects operating cost associated with 1996
replacement of nuclear steam generators
- Expense reductions for payroll, R&D and
demand side management programs
Depreciation and amortization (5.5) (11.2)
Net federal income tax effects (2.6) 2.3
Local and state tax effects 2.9 4.5
Other income and deductions effects (1.8) (3.4)
Interest expense (0.4) 1.7
- Redeemed 8 3/8% series CC bonds 3/7/96
- Redeemed 8.00% series Y bonds 5/1/97
- Write off of unamortized debt expense
Dividends on preferred stock 0.4 0.5
- Redeemed 7.50% series N 4/22/97
______ _____
1997 Earnings $16.7 $ 56.4
</TABLE>
OPERATING REVENUES AND SALES. Total Company revenues for the first
six months of 1997 were $0.5 million or 0.1% below the first six months of 1996
with decreases in electric sales to other utilities and lower therm sales of gas
due to warmer weather than last year offset by higher customer electric
kilowatt-hour sales. For the second quarter, total Company revenues were $6.2
million or 2.6% below last year reflecting mainly lower gas consumption.
FOSSIL UNIT DERATINGS. Several of the Company's fossil-fueled generating
units have been temporarily derated since February 1997 to maintain acceptable
opacity levels while the Company investigates additional engineering solutions
to address the opacity of the Units' emissions ( see Note 2 of the Notes to
Financial Statements under the heading "Environmental Matters, Opacity Issue").
The financial impact of the deratings includes the lost opportunity associated
with energy sales and, at times, the need to make additional purchases to meet
system requirements. While the deratings have decreased earnings, and will
continue to do so, the amount is not expected to be material.
18
<PAGE>
The NYPP is in the process of evaluating new rules for its system load
regulation. Opacity limitations are expected to reduce the ability of the
Company to react to changes in load and provide regulation services when called
upon by the NYPP, resulting in additional costs. Depending on the new NYPP
requirements, the revised rules could result in the Company having to purchase
additional regulation services which may cost between $500,000 and $2,500,000
annually.
FUEL EXPENSES. Fuel expenses decreased in both comparison periods
reflecting mainly lower kwh purchases of electricity due to efficiencies derived
from the new steam generators installed last year at the Ginna nuclear plant.
While the Ginna Plant operated throughout the first six months of 1997, it was
in a refueling and steam generator replacement outage during most of the second
quarter of 1996. Purchased electricity is expected to increase when the Ginna
plant enters its normal refueling outage later this year.
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES. The
decreases in operations excluding fuel and maintenance expenses in both
comparison periods reflect mainly lower payroll due to workforce reductions,
lower research and development and outside services expenses and lower
maintenance expenses following the Ginna steam generator replacement outage last
year.
DEPRECIATION AND AMORTIZATION. Depreciation and amortization increased
in both comparison periods due mainly to an increase in nuclear decommissioning
expense allowed in rates effective July 1, 1996 and completion of the steam
generator replacement at the Ginna nuclear plant in the summer of 1996.
TAXES. The decreases in local, state and other taxes in both
comparison periods is due reflect mainly lower property taxes due to decreases
in assessments and lower revenue taxes due to a decrease in the New York State
revenue tax surcharge rate.
The decrease in Federal income tax in the first half of 1997 reflects
mainly the reversal of a prior provision for the in-service date of Nine Mile
Two as a result of an agreement reached with the Internal Revenue Service. The
increase in Federal income tax for the second quarter is a result of increased
pre-tax earnings for the period.
OTHER STATEMENT OF INCOME ITEMS. Other Income and Deductions, Other-net
decreased in both comparison periods mainly due to higher accrual for obsolete
materials and supplies and a decline in subsidiary earnings resulting from the
sale of its interest in the Empire State Pipeline in 1996. Variations in
interest charges reflect decreases due to the early redemption of long-term debt
offset by the write-off of unamortized debt expense in the second quarter
relating to the redemption. Preferred stock dividends decreased due to the
redemption of an issue in April, 1997.
DIVIDEND POLICY
On June 18, 1997, the Board of Directors authorized a common stock
dividend of $.45 per share, which was paid on July 25, 1997 to shareholders of
record on July 2, 1997. The Company believes that future dividend payments will
need to be evaluated in the context of maintaining the financial strength
necessary to operate in a more competitive and uncertain business environment.
This will require consideration, among other things, of a dividend payout ratio
that is lower over time, reevaluating assets and managing greater fluctuation in
revenues. While the Company does not presently expect the impact of these
factors to affect the Company's ability to pay dividends at the current rate,
future dividends may be affected.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information on Legal Proceedings reference is made to Note 2 of the
Notes to Financial Statements.
19
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K:
The Company filed a Form 8-K dated April 9, 1997, reporting under Item 5,
Other Events a settlement with the staff of the PSC and other parties in the
"Competitive Opportunities" proceeding with respect to the restructuring of the
electric utility industry in New York State, based on competition in the
generation and energy services sections of the industry.
EXHIBIT INDEX
Exhibit 27 Financial Data Schedule pursuant to Item 601 (c) of
Regulation S-K.
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 5, 1997 By /s/ J.B. STOKES
------------------------------------
J. Burt Stokes
Senior Vice President, Corporate Services
and Chief Financial Officer
Date: August 5, 1997 By /s/ WM. J. REDDY
--------------------------------------
William J. Reddy
Controller
20
<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-31-1996
<PERIOD-START> JAN-01-1997
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,611,464
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 234,147
<TOTAL-DEFERRED-CHARGES> 435,635
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,281,246
<COMMON> 194,257
<CAPITAL-SURPLUS-PAID-IN> 502,046
<RETAINED-EARNINGS> 111,277
<TOTAL-COMMON-STOCKHOLDERS-EQ> 807,580
45,000
47,000
<LONG-TERM-DEBT-NET> 525,400
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 91,900
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
10,000
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 754,366
<TOT-CAPITALIZATION-AND-LIAB> 2,281,246
<GROSS-OPERATING-REVENUE> 544,264
<INCOME-TAX-EXPENSE> 35,962
<OTHER-OPERATING-EXPENSES> 420,213
<TOTAL-OPERATING-EXPENSES> 457,945
<OPERATING-INCOME-LOSS> 86,319
<OTHER-INCOME-NET> (2,033)
<INCOME-BEFORE-INTEREST-EXPEN> 86,056
<TOTAL-INTEREST-EXPENSE> 26,451
<NET-INCOME> 59,605
3,195
<EARNINGS-AVAILABLE-FOR-COMM> 56,410
<COMMON-STOCK-DIVIDENDS> 34,966
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 174,925
<EPS-PRIMARY> 1.45
<EPS-DILUTED> 1.45
</TABLE>
