<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 September 30, 1995
------------------------
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
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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 October 31, 1995: 38,423,637
----------
<PAGE>
INDEX
Page No.
PART I - FINANCIAL INFORMATION
Consolidated Balance Sheet - September 30, 1995 and
December 31, 1994....................................... 1 - 2
Consolidated Statements of Income - Three Months and Nine
Months Ended September 30, 1995.......................... 3 - 4
Consolidated Statement of Cash Flows - Nine Months
Ended September 30, 1995 and 1994....................... 5
Notes to Financial Statements.............................. 6-15
Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 16-25
PART II - OTHER INFORMATION
Legal Proceedings.......................................... 25
Other Information.......................................... 26
Exhibits and Reports on Form 8-K........................... 27
Signatures................................................. 28
<PAGE>
PART I-FINANCIAL INFORMATION
- ----------------------------
ROCHESTER GAS AND ELECTRIC CORPORATION
<TABLE>
<CAPTION>
Consolidated Balance Sheet
(Thousands of Dollars) September 30, December 31,
(Unaudited) 1995 1994
- ----------------------------------------------------------------------------
<S> <C> <C>
Assets
Utility Plant
Electric $2,335,358 $2,284,634
Gas 375,319 370,205
Common 146,828 135,975
Nuclear fuel 202,656 190,337
---------- ----------
3,060,161 2,981,151
Less: Accumulated depreciation 1,325,467 1,263,637
Nuclear fuel amortization 168,769 159,461
---------- ----------
1,565,925 1,558,053
Construction work in progress 125,237 128,860
---------- ----------
Net Utility Plant 1,691,162 1,686,913
---------- ----------
Current Assets
Cash and cash equivalents 26,116 2,810
Accounts receivable 111,439 110,417
Unbilled revenue receivable 42,071 54,270
Materials and supplies, at average cost
Fossil fuel 7,033 7,908
Construction and other supplies 12,058 13,264
Gas stored underground 23,320 24,315
Prepayments 30,727 23,535
---------- ----------
Total Current Assets 252,764 236,519
---------- ----------
Investment in Empire 38,879 38,560
Deferred Debits
Unamortized debt expense 17,071 18,343
Nuclear generating plant decommissioning fund 57,319 49,011
Nine Mile Two deferred costs 32,674 33,462
Deferred finance charges - Nine Mile Two 19,242 19,242
Other Deferred Debits 24,799 19,214
Regulatory assets -
Income taxes 181,671 205,794
Uranium enrichment decommissioning deferral 18,954 20,169
Deferred ice storm charges 17,193 19,111
FERC 636 transition costs 44,641 32,479
Demand side management costs 14,783 19,807
Deferred fuel costs - gas 27,840 33,845
Other regulatory assets 35,474 33,727
---------- ----------
Total Deferred Debits 491,661 504,204
---------- ----------
Total Assets $2,474,466 $2,466,196
- --------------------------------------------- ========== ==========
</TABLE>
The accompanying notes are an integral part of the financial statements.
1
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
<TABLE>
<CAPTION>
Consolidated Balance Sheet
(Thousands of Dollars) September 30, December 31,
(Unaudited) 1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C>
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds $ 625,318 $ 643,278
- promissory notes 91,900 91,900
Preferred stock redeemable at option of Company 67,000 67,000
Preferred stock subject to mandatory redemption 55,000 55,000
Common shareholders' equity
Common stock
Authorized 50,000,000 shares; 38,278,153
shares outstanding at September 30, 1995
and 37,669,963 shares outstanding at
December 31, 1994 683,463 670,569
Retained earnings 89,887 74,566
---------- ----------
Total Common Shareholders' Equity 773,350 745,135
---------- ----------
Total Capitalization 1,612,568 1,602,313
---------- ----------
Long Term Liabilities (Department of Energy)
Nuclear waste disposal 74,058 70,895
Uranium enrichment decommissioning 17,326 16,931
---------- ----------
Total Long Term Liabilities 91,384 87,826
---------- ----------
Current Liabilities
Long term debt due within one year 18,000 -
Short Term Debt - 51,600
Note Payable - Empire 29,600 29,600
Accounts payable 59,819 42,934
Dividends payable 19,091 18,818
Taxes accrued 3,531 3,471
Interest accrued 14,968 11,967
Other 25,929 22,937
---------- ----------
Total Current Liabilities 170,938 181,327
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 367,865 402,894
Deferred finance charges - Nine Mile Two 19,242 19,242
Pension costs accrued 76,311 75,912
Other 136,158 96,682
---------- ----------
Total Deferred Credits and Other Liabilities 599,576 594,730
---------- ----------
Commitments and Other Matters (Note 2) - -
---------- ----------
Total Capitalization and Liabilities $2,474,466 $2,466,196
------------------------------------------------ ========== ==========
</TABLE>
The accompanying notes are an integral part of the financial statements.
2
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
<TABLE>
<CAPTION>
Consolidated Statement of Income Three Months Ended
(Thousands of Dollars) September 30, September 30,
(Unaudited) 1995 1994
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues
Electric $194,761 $180,542
Gas 41,976 46,098
-------- --------
236,737 226,640
Electric sales to other utilities 8,408 3,342
-------- --------
Total Operating Revenues 245,145 229,982
Operating Expenses -------- --------
Fuel Expenses
Fuel for electric generation 12,009 10,744
Purchased electricity 18,427 9,534
Gas purchased for resale 27,242 28,629
-------- --------
Total Fuel Expenses 57,678 48,907
-------- --------
Operating Revenues Less Fuel Expenses 187,467 181,075
Other Operating Expenses -------- --------
Operations excluding fuel expenses 61,333 58,257
Maintenance 11,952 11,300
Depreciation and amortization 23,247 22,198
Taxes - local, state and other 30,672 31,014
Federal income tax 18,525 17,299
-------- --------
Total Other Operating Expenses 145,729 140,068
-------- --------
Operating Income 41,738 41,007
Other Income and Deductions -------- --------
Allowance for other funds used during construction 119 111
Federal income tax 1,633 12,615
Pension plan curtailment - (33,679)
Other, net (2,247) (627)
-------- --------
Total Other Income and (Deductions) (495) (21,580)
Interest Charges -------- --------
Long term debt 13,110 13,152
Other, net 1,977 1,841
Allowance for borrowed funds used during construction (778) (478)
-------- --------
Total Interest Charges 14,309 14,515
-------- --------
Net Income 26,934 4,912
Dividends on Preferred Stock 1,866 1,866
-------- --------
Earnings Applicable to Common Stock $ 25,068 $ 3,046
======== ========
Weighted Average Number of Shares for Period (000's) 38,212 37,412
-------- --------
Earnings per Common Share $ 0.65 $ 0.08
-------- --------
Cash Dividends Paid per Common Share $ 0.45 $ 0.44
- ---------------------------------------------------- -------- --------
</TABLE>
The accompanying notes are an integral part of the financial statements.
3
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
<TABLE>
<CAPTION>
Consolidated Statement of Income Nine Months Ended
(Thousands of Dollars) September 30 September 30,
(Unaudited) 1995 1994
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues
Electric $527,298 $502,956
Gas 201,267 243,406
-------- --------
728,565 746,362
Electric sales to other utilities 17,140 10,754
-------- --------
Total Operating Revenues 745,705 757,116
Operating Expenses -------- --------
Fuel Expenses
Fuel for electric generation 33,457 33,530
Purchased electricity 43,045 30,134
Gas purchased for resale 116,472 147,127
-------- --------
Total Fuel Expenses 192,974 210,791
-------- --------
Operating Revenues Less Fuel Expenses 552,731 546,325
Other Operating Expenses -------- --------
Operations excluding fuel expenses 178,515 177,876
Maintenance 36,446 43,325
Depreciation and amortization 68,202 65,193
Taxes - local, state and other 98,701 101,829
Federal income tax 53,118 45,339
-------- --------
Total Other Operating Expenses 434,982 433,562
-------- --------
Operating Income 117,749 112,763
Other Income and Deductions -------- --------
Allowance for other funds used during construction 417 282
Federal income tax 2,817 13,532
Pension plan curtailment - (33,679)
Regulatory Disallowances - (600)
Other, net (5,534) 225
-------- --------
Total Other Income and (Deductions) (2,300) (20,240)
Interest Charges -------- --------
Long term debt 39,346 40,444
Other, net 6,041 4,747
Allowance for borrowed funds used during construction (2,253) (1,426)
-------- --------
Total Interest Charges 43,134 43,765
-------- --------
Net Income 72,315 48,758
Dividends on Preferred Stock 5,599 5,502
-------- --------
Earnings Applicable to Common Stock $ 66,716 $ 43,256
======== ========
Weighted Average Number of Shares for Period (000's) 38,015 37,228
-------- --------
Earnings per Common Share $1.75 $1.16
-------- --------
Cash Dividends Paid per Common Share $1.35 $1.32
- ---------------------------------------------------- -------- --------
</TABLE>
The accompanying notes are an integral part of the financial statements.
4
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS Nine Months Ended
(Thousands of Dollars September 30, September 30,
(Unaudited) 1995 1994
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C>
CASH FLOW FROM OPERATIONS
Net income $ 72,315 $ 48,758
Adjustments to reconcile net income to net cash provided
from operating activities
Depreciation and amortization 68,202 65,193
Amortization of nuclear fuel 12,431 12,906
Deferred fuel - electric (5,572) (5,057)
Deferred fuel - gas 6,005 (28,088)
Deferred income taxes 4,995 (2,488)
Allowance for funds used during construction (2,670) (1,707)
Unbilled revenue, net 12,199 22,588
Deferred ice storm costs 1,918 1,870
Nuclear generating plant decommissioning fund (8,308) (7,702)
Pension costs accrued 399 48,404
Post employment benefit internal reserve 3,981 3,763
Research and development amortization 2,225 (106)
Rate settlement amortizations 4,007 6,171
Changes in certain current assets and liabilities:
Accounts receivable (1,022) 11,685
Materials and supplies - gas stored underground 995 7,926
- other, net 2,081 1,033
Taxes accrued 60 16,357
Accounts payable 16,885 (19,182)
Interest accrued 3,001 2,030
Other current assets and liabilities, net (3,047) (15,113)
Other, net 11,304 (5,241)
-------- --------
Total Operating $202,384 $164,000
-------- --------
CASH FLOW FROM INVESTING ACTIVITIES
Utility Plant
Plant additions $(73,145) $(76,471)
Nuclear fuel additions (12,278) (8,515)
Less: Allowance for funds used during construction 2,670 1,707
-------- --------
Additions to Utility Plant (82,753) (83,279)
Investment in Empire - net (320) -
Other, net (21) 1,737
-------- --------
Total Investing $(83,094) $(81,542)
-------- --------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issue of common stock $ 12,941 $ 13,304
Sale of preferred stock - 25,000
Short term borrowings (51,600) (14,300)
Retirement of long term debt - (33,750)
Retirement of preferred stock - (18,000)
Capital stock expense (47) 1,375
Dividends paid on preferred stock (5,599) (5,461)
Dividends paid on common stock (51,122) (48,968)
Other, net (557) (1,184)
-------- --------
Total Financing $(95,984) $(81,984)
-------- --------
Increase in cash and cash equivalents $ 23,306 $ 474
Cash and cash equivalents at beginning of period $ 2,810 $ 2,327
-------- --------
Cash and cash equivalents at end of period $ 26,116 $ 2,801
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Nine Months Ended
September 30, September 30,
1995 1994
- ----------------------------------------------------------------------------------------------------------------
Cash Paid During the period
Interest paid (net of capitalized amount) $ 38,822 $ 27,945
Income taxes paid $ 40,000 $ 28,198
- --------------------------------------------------- ======== ========
</TABLE>
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 accompanying unaudited financial statements reflect all adjustments
which are, in the opinion of management, necessary to a fair presentation of the
Company's results for these interim periods. All such adjustments are of a
normal recurring nature, except for the reduction to reported earnings from a
Public Service Commission (PSC) order as described in Note 2 under Gas Cost
Recovery. 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, 1994.
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, 1994 and should be read in conjunction with the
material contained in that Note.
LITIGATION WITH CO-GENERATOR.
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). With the
exception of one contract which the Company was compelled by regulators to enter
into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts
of capacity, the Company has no long-term obligations to purchase energy from
Qualifying Facilities.
Under State law and regulatory requirements in effect at the time the
contract with Kamine was negotiated, the Company was required to pay Kamine a
price for power that is substantially greater than the Company's own cost of
production and other purchases. Since that time the State law mandating a
minimum price higher than the Company's own costs has been repealed and PSC
estimates of future costs on which the contract was based have declined
dramatically.
In September 1994, the Company filed a lawsuit against Kamine in New York
State Supreme Court seeking to void its contract for the forced purchase of
unneeded electricity at above-market prices which would
6
<PAGE>
result in substantial cost increases for the Company's customers. Under a
contractual provision that requires Kamine to repay certain "overpayments", the
Company estimates that Kamine will owe the Company $400 million by the midpoint
of the contract term and if the contract extends to its full 25 year term, the
total amount of such overpayments (plus interest) could reach approximately $700
million. The Company believes that Kamine will be unable to meet the contract
security requirements for these sums when due. Alternatively, the Company
sought relief to ensure that its customers would pay no more for the Kamine
power than they would pay for power from the Company's other sources of
electricity. Kamine answered the Company's complaint, seeking to force the
Company to take and pay for power at the above-market rates and claiming damages
in an unspecified amount alleged to have been caused by the Company's conduct.
The Company began receiving test generation from the Kamine facility during the
last quarter of 1994. In late December 1994, the Company announced it would no
longer be accepting electric power from this facility, unless charged at the
current avoided cost rate, because it is the Company's position, among other
reasons, that the Kamine facility is no longer a "Qualifying Facility" as
specified under Federal regulations. On February 17, 1995 Kamine petitioned the
Federal Energy Regulatory Commission (FERC) for a "Temporary Waiver of Operating
and Efficiency Standards" seeking to confirm its status as a Qualifying Facility
in 1994 despite the undisputed fact that no thermal host existed when the plant
is claimed to have entered commercial service. The PSC has joined the Company
in opposing Kamine's request for waiver of the Qualifying Facility standards.
By a decision rendered March 16, 1995, the state court denied Kamine's
motion for summary judgement. Kamine has appealed that decision. The Company
intends to vigorously pursue this lawsuit, but is unable to predict the outcome
at this time.
On January 27, 1995, Kamine initiated a lawsuit against the Company in
United States District Court for the Western District of New York for alleged
antitrust violations by the Company that are based on the same issues that are
raised by the Company's New York State Court lawsuit. The Kamine lawsuit seeks
injunctive relief similar to that requested in Kamine's answer to the Company's
lawsuit in New York State Court and damages of $420 million. Kamine also moved
for a preliminary injunction and a temporary restraining order to require the
Company, during the pendency of the lawsuit, to accept and pay for electricity
generated by Kamine's facility. On March 20, 1995, the District Court issued a
decision and order granting Kamine's application for a
7
<PAGE>
temporary restraining order to require the Company, for a period of ten days
from entry of the order, to purchase electricity generated by Kamine at a rate
of at least six cents per kilowatt hour. The Court subsequently extended the
temporary restraining order until a ruling is made on Kamine's motion for
preliminary injunction. On November 2, 1995, the District Court denied Kamine's
motion for a preliminary injunction subject to the condition that the Company
would agree to pay its actual avoided cost for energy as established by the
Company's current Service Class #5 ("SC-5") tariff. The Court found that
Kamine failed to make a showing of irreparable harm if a preliminary injunction
was not available to Kamine. In addition, the Court ruled that Kamine failed to
demonstrate a likelihood of success sufficient to justify issuing a temporary
injunction. The Company has consistently offered to purchase the output of the
Kamine facility at SC-5 rates, which currently average two cents. The Company
intends to continue to vigorously defend against Kamine's lawsuit, but is unable
to predict the outcome at this time.
The United States Department of Justice, Antitrust Division, has issued a
Civil Investigative Demand calling for the production of documents and answers
to interrogatories concerning the electric utility industry. Among documents
requested are ones that relate to the Kamine project. The Company has been
informed that the Antitrust Division has not concluded that there is an
antitrust violation, and that it is not a target of this investigation, since
there are no targets. The Company is cooperating with the investigation.
On May 9, 1995, the Company filed a petition with the PSC which, among
other things, requested that the Commission investigate Kamine's qualification
as a "cogenerator", as defined in the New York State Public Service Law, to
determine if Kamine is in compliance with contract requirements. It is the
Company's position that Kamine is not a cogenerator as defined by such law and,
as a result, is in violation of a crucial contract provision. The Company has
been unable to clearly resolve this issue and the PSC suggested that it would
consider pursuing the matter if the Company requested that it do so. The PSC
issued a Notice of Proposed Rulemaking on June 21, 1995 and Kamine responded
to that Notice on August 4, 1995. There is no formal deadline for PSC action.
8
<PAGE>
ENVIRONMENTAL MATTERS.
Reference is made to the table entitled "Company-Owned Sites" and the
caption "Company-Owned Waste Site Activities" in Part II, Item 8 of the
Company's 1994 Form 10-K Report under Note 10, "Environmental Matters" for a
listing and discussion relating to Company-owned waste sites.
In October 1995 the Company resumed voluntary cleanup activities of
underground coal tar residue in the vicinity of retired facilities at its West
Station manufactured gas property. Site restoration is expected to be completed
by February, 1996.
In mid-1995, the New York State Department of Environmental Conservation
(NYSDEC) developed a listing of sites called "The Hazardous Substance Site
Inventory". Under current New York State law, unless a site, which is determined
to pose a public health or environmental risk, contains hazardous wastes, State
"Superfund" monies cannot be used to assist in the clean-up. The State wanted
to have some sense of the scale of this problem before the legislature
considered other avenues of legal and financial redress than those currently
available. The NYSDEC's "Hazardous Substance Waste Disposal Site Study" was
devised as a means to estimate the number of and cost to remediate lands where
hazardous chemicals, but not hazardous wastes are present. This inventory
includes three sites which are listed in the table of Company-owned sites
reference above. These are East Station, Front Street, and Brooks Avenue. In
addition to these three sites, the inventory includes Ambrose Yard and Lindberg
Heat Treating. The Company does not believe that additional site investigation
or remediation work for which the Company is responsible is required at either
site, however the Company is unable to predict what action will be necessitated
as a result of the listing.
In March 1995, the Company recorded an additional estimated liability of
$10 million which it anticipates spending on Site Investgation and/or
Remediation (SIR) efforts at six Company-owned sites where past waste handling
and disposal may have occurred. Concurrently, the Company recorded a similar
increase in its Regulatory Assets.
9
<PAGE>
GAS COST RECOVERY.
As a result of the restructuring of the gas transportation industry by the
FERC pursuant to Order No. 636 and related decisions, there have been and will
be a number of changes in this aspect of the Company's business over the next
several years. For additional information with respect to these transition
costs see Note 10 of the Notes to Financial Statements in the Company's Form
10-K for the fiscal year ended December 31, 1994.
The Company is committed to transportation capacity on the Empire State
Pipeline (Empire) as well as to upstream pipeline transportation and storage
services. The Company also has contractual obligations with CNG Transmission
Corporation (CNG) and upstream pipelines whereby the Company is subject to
charges for transportation and storage services for a period extending to the
year 2001. The combined CNG and Empire transportation capacity exceeds the
Company's current requirements. This temporary excess has occurred largely due
to the Company's initiatives to diversify its supply of gas and the industry
changes and increasing competition resulting from the implementation of FERC
Order 636.
The Company's purchased gas expense charged to customers was higher during
the 1994-95 heating season for the reasons described above, generating
substantial customer concern. The action the Company took to reduce rates
included refunding the weather normalization adjustment charged to customers in
January and discontinuation of those charges through the remainder of the
heating season ending in May. The weather normalization adjustment provides for
recovery of fixed charges by producing higher unit rates when the weather is
warm and usage is low. Conversely, it would produce lower unit rates during
colder periods of high usage.
In December, 1994, the PSC instituted a proceeding to review the Company's
practices regarding acquisition of pipeline capacity, the deferred costs of the
capacity and the Company's recovery of those costs.
In April, 1995, the PSC issued a Department of Public Service (DPS) staff
report on the Company's 1994-1995 billing practices and procedures which
presented recommendations regarding changes in the Company's natural gas
purchasing, billing, meter reading and communication activities.
10
<PAGE>
On August 17, 1995, the Company announced that a negotiated settlement had
been reached with the Staff of the PSC and other parties which would resolve
various PSC proceedings which were commenced to review the factors affecting the
Company's gas costs. On October 18, 1995, the PSC approved, effective November
1, 1995, (1) the settlement discussed below, (2) elimination of the weather
normalization clause and (3) the Company's plan for improving its gas billing
procedures. The settlement affects the rate treatment of various gas costs
through October 31, 1998.
Under the settlement the Company would forego, for three years, gas rate
increases exclusive of the cost of natural gas and certain cost increases
imposed by interstate pipelines. The Company has also agreed to write off
excess gas pipeline capacity and other costs incurred through 1995 and to take
the economic risk of remarketing excess gas capacity for the years 1996 through
1998, the cost of which will be borne by the Company net of resale credits.
The economic effect on the Company of the proposed settlement in 1995
would be approximately $38.4 million, which would represent the following:
- Pre-tax earnings from gas operations were reduced by approximately $5.3
million this year due to a decision to eliminate weather normalization
charges on customer bills for the 1995 heating season which ended in
May.
- $1.9 million in revenue from a gas rate increase scheduled for the
rate year July 1, 1995, which the Company will forego.
- $8 million in gas pipeline capacity costs for 1995, net of capacity
release payments, which the Company will forego recovering in rates.
Of this amount, $6.9 million of costs were reflected in the September
30, 1995 financial statements.
- $23.2 million in gas pipeline capacity and other costs, which was
written off in October 1995.
The Company has also reserved $3.25 million in October 1995 due to
retroactive changes in ratemaking methodology applicable to charges by certain
pipelines, which are now pending before the FERC.
11
<PAGE>
As described above, the Company has agreed not to charge customers for
pipeline capacity costs in 1996, 1997 and 1998 of $22.5 million, $24.5 million,
and $27.2 million, respectively. Under FERC rules, the Company may sell its
excess transportation capacity in the market. The value of those sales can be
used to offset the capacity costs that will not be charged to customers. These
amounts that the Company will not be permitted to charge are subject to increase
in the event of major increases in the overall cost of pipeline capacity during
these years.
The gas base rate increases the Company has agreed to forego subsequent to
1995 during the period of the settlement are approximately $10.4 million in the
aggregate.
The actions taken with respect to the settlement described above will
reduce 1995 earnings by approximately seventy-one cents per share after tax.
Twenty-three cents of this amount has already reduced earnings through September
30, 1995. The Company believes that this settlement, by itself, will not affect
its ability to pay dividends on its Common Stock at the current annual rate of
$1.80 per share.
The Company has entered into a marketing agreement with CNG, pursuant to
which CNG will assist the Company in obtaining permanent replacement customers
for transporation capacity the Company will not require. As a result of this
marketing agreement and FERC approval of the Chambersburg Project, which is
required to facilitate the use of pipeline capacity by the replacement shippers,
a substantial portion of this capacity will be released to replacement shippers
through the contract period described above. The Company is now in the process
of assigning the subject capacity.
The Company has also entered into a Supply Portfolio Management agreement
with MidCon Gas Services Corp. (MGSC). MGSC will work with the Company to
identify and implement opportunities for temporary and permanent release of
surplus pipeline capacity, as well as advise with respect to the management of
the Company's gas supply, transportation and storage assets consistent with the
goal of providing reliable service and reducing the cost of gas.
REGULATORY AND STRANDED ASSETS.
Certain costs are deferred and recognized as expenses when they are
reflected in rates and recovered from customers as permitted by Statement of
Financial Accounting Standard No. 71, "Accounting of the Effects of Certain
Types of Regulation". These costs are shown as
12
<PAGE>
Regulatory Assets. Such costs arise from the traditional cost-of-service rate
setting approach where all prudently incurred costs are recoverable through
rates. Deferral of these costs is appropriate while the Company's rates are
regulated under a cost-of-service approach.
In a purely competitive pricing approach, such costs might not have been
incurred or deferred. Accordingly, if the Company's rate
setting were changed from a cost-of-service approach and it was no longer
allowed to defer these costs under SFAS 71, certain of these assets may not be
fully recoverable.
Below is a summarization of the Regulatory Assets as of September 30,
1995.
<TABLE>
<CAPTION>
Millions
of dollars
----------
<S> <C>
Income Taxes $181.7
Deferred Ice Storm Charges 17.2
Uranium Enrichment Decommissioning Deferral 19.0
FERC 636 Transition Costs 44.6
Demand Side Management Costs Deferred 14.8
Deferred Fuel Costs - Gas 27.8
Other, net 35.5
------
Total - Regulatory Assets $340.6
======
</TABLE>
The FERC 636 Transition Costs are based on June 1995 estimates. See the
Company's 1994 10-K, Note 10 of the Notes to Financial Statements under the
heading "Regulatory and Stranded Assets" for a description of the Regulatory
Assets shown above.
Stranded assets (or other costs) arise when investments are made in
facilities, or costs are incurred to serve customers, and such costs and
investments may not be fully recoverable in market-based rates. Examples may
include purchased power contracts (e.g., the Kamine contract) or high cost
generating assets.
Excluding the Kamine contract described above, estimates of possible
stranded asset amounts vary as to scope and methodology and are highly sensitive
to the competitive wholesale price for electricity assumed in the estimation.
The amount of potential stranded assets at September 30,1995, cannot be
determined at this time but could be significant.
13
<PAGE>
While the Company currently believes that its regulatory and other assets
potentially classifiable as stranded assets are probable of recovery in rates,
industry trends have moved more toward competition, and in a purely competitive
environment, it is not clear to what extent, if any, writeoffs of such assets
may occur.
NUCLEAR DECOMMISSIONING TRUST
The Company is collecting in its electric rates amounts 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.
Under accounting procedures approved by the PSC, the Company has collected
decommissioning costs of approximately $76.7 million through September 30, 1995.
In connection with the Company's rate settlement completed in August 1993, the
PSC approved the collection during the rate year ending June 30, 1996 of an
aggregate $8.9 million for decommissioning, covering both nuclear units. The
amount allowed in rates is based on estimated ultimate decommissioning costs of
$169.5 million for Ginna and $38.6 million for the Company's 14% share of Nine
Mile Two (January 1995 dollars). This estimate is based principally on the
application of a Nuclear Regulatory Commission (NRC) formula to determine
minimum funding with an additional allowance for removal of non-contaminated
structures. Site specific studies of the anticipated costs of actual
decommissioning are required to be submitted to the NRC at least five years
prior to the expiration of the license.
The Company completed a site specific cost analysis of decommissioning at
Ginna and incorporated the results of this study in its July 1995 rate filing
with the PSC. Based on the site specific study the estimated decommissioning
cost increased to $296.3 million (May 1995 dollars). The Company has received a
draft of Niagara Mohawk's estimate of a site specific cost estimate for Nine
Mile Two which indicates the Company's share of such costs could be as much as
$113 million. This draft estimate is currently under review by the cotenants
and the staff of the PSC. The Company cannot predict the degree to which any
additional estimates will be recognized in rates stemming from its current rate
filing.
The NRC requires reactor licensees to submit funding plans that establish
minimum NRC external funding levels for reactor
14
<PAGE>
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. Since 1990, the Company has contributed $52.2 million to this fund and,
including realized investment returns, the fund has a balance of $57.3 million
as of September 30, 1995. The amount attributed to the allowance for removal of
non-contaminated structures is being held in an internal reserve. The internal
reserve balance as of September 30, 1995 is $24.5 million.
The Company is aware of recent NRC activities related to upward revisions
to the required minimum funding levels. These activities, primarily focused on
disposition of low level radioactive waste, may require the Company to further
increase funding. The Company continues to monitor these activities but cannot
predict what regulatory actions the NRC may ultimately take.
The Staff of the Securities and Exchange Commission and the Financial
Accounting Standards Board are currently studying the recognition, measurement
and classification of decommissioning costs for nuclear generating stations in
the financial statements of electric utilities. If current accounting practices
for such costs were changed, the annual provisions for decommissioning costs
would increase, the estimated cost for decommissioning could be reclassified as
a liability rather than as accumulated depreciation, the liability accounts and
corresponding plan asset carrying accounts would be increased and trust fund
income from the external decommissioning trusts could be reported as investment
income rather than as a reduction to decommissioning expense. If annual
decommissioning costs increased, the Company would expect to defer the effects
of such costs pending disposition by the PSC.
15
<PAGE>
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.
EARNINGS SUMMARY
Earnings per common share (as reported and without nonrecurring items) for
the current and prior year periods ended September 30, are as follows:
<TABLE>
<CAPTION>
Without
As Reported Non Recurring Items
--------------- -------------------
1995 1994 1995 1994
<S> <C> <C> <C> <C>
Three months $ .65 $ .08 $ .69 $ .67
Nine months $1.75 $1.16 $1.95 $1.76
</TABLE>
The wide fluctuation in reported earnings from 1994 to 1995 was caused by
a $33.7 million charge against 1994 earnings for a major corporate downsizing
effort. The charge reduced earnings for each of the 1994 periods by $.59 per
share.
Reported earnings for the 1995 periods include the cost of measures taken
earlier in the year to reduce the price of gas to customers. Pre-tax earnings
were reduced by approximately $5.3 million or $.09 per share net-of-tax, this
year due to a decision to eliminate weather normalization charges on customer
bills for the 1995 heating season which ended in May. Pre-tax earnings were
reduced by an additional $6.9 million or $.11 per share net-of-tax, due to the
effect of removing $16.0 million of annual gas capacity costs, net of capacity
release credits, from rates beginning in February 1995. As a result of the gas
settlement approved by the PSC in October the Company wrote off an additional
$23.2 million or $.40 per share in October 1995. The Gas Settlement may impact
earnings in the next several years depending on how successful the Company is in
selling excess capacity.
Without non-recurring items, a good summer cooling season along with a
modest increase in rates and savings from work force reductions and other cost
controls all had a positive impact on current quarter and year-to-date earnings.
These factors were partially offset by an
16
<PAGE>
increase in the expense accrual for uncollectibles and gas costs, as discussed
above.
COMMON STOCK DIVIDEND
On September 20, 1995, the Board of Directors authorized a common stock
dividend of $.45 per share, which was paid on October 25, 1995 to shareholders
of record on October 3, 1995. 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 and the gas cost settlement discussed under Note 2 of the Notes
to Financial Statements "Gas Cost Recovery" to affect the Company's ability to
pay dividends at the current rate, future dividends may be affected.
COMPETITION
The PSC has been inviting comments on how to proceed with deregulation
of New York State electric utilities in its "Competitive Opportunities" case.
In an Opinion issued on June 7, 1995, the PSC provided a revision of the nine
"Principles to Guide the Transition to Competition" initially issued in December
of 1994. Among other things, the PSC endorsed increased emphasis on market-
based approaches to research, environmental protections and energy efficiency,
and it supported the concept that utilities should have a reasonable opportunity
to recover expenditures and commitments made pursuant to historical obligations.
The PSC also indicated that current vertically integrated industry structure
must be thoroughly examined to ensure that it does not impede effective
wholesale or retail competition. A "[recommended] decision or report" was
requested by the PSC by "the end of 1995".
On October 5, 1995, The Energy Association of New York State (an industry
association which is representing the Company and other utilities in the
Competitive Opportunities proceeding) released documents outlining the consensus
position of the utilities. The Energy Association endorsed a significant change
in the existing regulatory structure which would significantly increase
competition at the
17
<PAGE>
wholesale level. The proposed structure would require all generators of power
in New York to either bid into a voluntary power "pool" market or to negotiate
contracts with wholesale purchasers of energy. The proposal calls for formation
of an "independent system operator" to operate the transmission in New York and
assure reliability of the system. The proposal also calls for major regulatory
and taxation reforms as well as a mechanism for generators to recover
investments made pursuant to legal obligations to provide universal service.
The Energy Association proposal stopped short of endorsing increased competition
at the retail level, citing several unresolved issues created by differing
obligations to serve customers when more than one supplier sells energy in a
single area. The Energy Association documents did acknowledge that some of its
members could endorse further changes based on specific utility circumstances.
On October 6, 1995, Niagara Mohawk Power Corporation (an Energy
Association member) announced that it is prepared to conduct phased introduction
of competition at the retail level if certain concessions and arrangements can
be obtained. The Niagara Mohawk proposal is consistent with many of the
features of the Energy Association proposal but further proposes to engage in
competition at the individual customer level and recognizes that a writeoff of a
portion of certain stranded assets may be pursued to obtain concessions from
other parties.
On October 25, 1995, thirty formal submissions were made by parties or
coalitions of parties in the Competitive Opportunities case. These submissions
were made in support of, or opposition to, various aspects of proposals to
restructure the electric industry in the State of New York. The majority of the
submissions support the concept that competition should extend to the level of
individual retail customers. Many submissions, including the document provided
by the staff of the PSC, strongly endorse the idea that existing utility
companies should be required to divest themselves of their existing generating
facilities to foster greater competition. While acknowledging that ".. there
are certain drawbacks to divestiture.." and that there are ".. questions
relating to the initial sale [of generating units], such as the complex cost
allocation and related financial and tax questions, indenture questions, and the
complex nuclear unit issues", the PSC staff has taken the position that
divestiture and retail competition could be completed by 1997. The PSC staff
also indicated that a less desirable but acceptable alternative to divestiture
would be the creation of a holding company structure which functionally
separated generation from the distribution functions of existing utilities.
18
<PAGE>
While the Company agrees with the spirit underlying the PSC's principles
and the proposals made by the Energy Association and Niagara Mohawk, the nature
and magnitude of the potential impact of those proposals on the business of the
Company will depend on the specific details of any plan for increased
competition and resolution of the complex issues related to competition at the
retail level.
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 1995 cash flow from operations, together
with proceeds from external financing activity (see Consolidated Statement of
Cash Flows), provided the funds for construction expenditures and the retirement
of short-term borrowings. The Company has no debt maturity or sinking fund
obligations scheduled in 1995.
PROJECTED CAPITAL AND OTHER REQUIREMENTS
The Company's capital requirements relate primarily to expenditures for
electric generation including replacement of its Ginna steam generators,
transmission and distribution facilities and gas mains and services as well as
the repayment of existing debt. Construction programs of the Company focus on
the need to serve new customers, to provide for the replacement of obsolete or
inefficient utility property and to modify facilities consistent with the most
current environmental and safety regulations. The Company has no current plans
to install additional base load generation.
The Company's most current Integrated Resource Plan (IRP) explores
options for complying with the 1990 Clean Air Act Amendments. The IRP is part of
an ongoing planning process to examine options for the future with regard to
generating resources and alternative methods of meeting electric capacity
requirements. Activities are currently under way to:
- Modify Units 2, 3, and 4 at Russell Station and Unit 12 at Beebee
Station, all coal-fired facilities, to meet Federal Environmental
Protection Agency standards and Clean Air Act requirements,
- Replace the two steam generators at the Ginna Nuclear Plant.
See below.)
19
<PAGE>
Total 1995 capital requirements for construction are currently estimated
at $132 million, including replacement of the steam generators at the Ginna
Nuclear Plant. Approximately $84 million had been expended for construction as
of September 30, 1995, reflecting primarily expenditures for steam generator
replacement, upgrading electric generating, transmission and distribution
facilities and gas mains and expenditures for nuclear fuel.
Preparation for replacement of the two steam generators at the Ginna
Nuclear Plant began in 1993 and will continue until the replacement in 1996.
Steam generator fabrication is nearing completion. All major components for the
steam generators have been delivered and major sub-assemblies have been
fabricated. Manufacturing will be completed in early 1996 and the steam
generators will be shipped to the site. The installation contractor will remain
on site throughout 1995 in preparation for the 1996 replacement outage. Cost of
the replacement is estimated at $115 million; the costs comprise approximately
$40 million for the units, $50 million for installation and the remainder for
engineering, radiation protection, plant support, other services and finance
charges. The Company spent $24 million on this project in the first nine months
of 1995 and expects to spend a total of $30 million this year. Installation
activities during 1995 will include a number of in-containment modifications,
foundations for building and equipment, construction of a temporary building on
site and construction of a storage building for the old steam generators. The
PSC order approving this project provides that certain costs over $115 million
will not be fully recoverable in rates but the Company does not expect to exceed
that amount.
FINANCING
Under provisions of the Company's Charter, the Company may not issue
unsecured debt if immediately after such issuance the total amount of unsecured
debt outstanding would exceed 15 percent of the Company's total secured
indebtedness, capital, and surplus without the approval of at least a majority
of the holders of outstanding Preferred Stock. At September 30, 1995, the
Company was able to issue $67.1 million of additional unsecured debt under this
provision.
The Company is utilizing its credit agreements totaling $140 million
and unsecured lines of credit totaling $72 million to meet any interim external
financing needs prior to issuing any long-term securities. See the Company's
1994 Form 10-K, Management's Discussion
20
<PAGE>
and Analysis of Financial Condition and Results of Operations under the heading
"FINANCING AND CAPITAL STRUCTURE" for information on these credit agreements.
At September 30, 1995 the Company had short-term borrowings outstanding of $15
million associated with FERC Order 636 transition costs (recorded on the Balance
Sheet under Deferred Credits).
During the first nine months of 1995, the Company issued 608,190 shares
of Common Stock through its Automatic Dividend Reinvestment and Stock Purchase
Plan (ADR Plan) and the RG&E Savings Plus Plan (Savings Plus Plan) providing
approximately $12.9 million to help finance its capital expenditures program.
The new shares were issued at a market price above the book value per share at
the time of issuance. At September 30, 1995 the Company had Common Stock
available for issuance of 1,520,954 shares under the ADR Plan and 208,861 shares
under the Savings Plus Plan.
CAPITAL STRUCTURE
The Company's retained earnings at September 30, 1995 were $89.9 million,
an increase of approximately $15.3 million compared with December 31, 1994.
There were virtually no changes in the amount of long term debt and preferred
stock at September 30, 1995 as compared with December 31, 1994. Common equity
increased approximately $28.2 million, reflecting the issuance and sale of
Common Stock as discussed under "Financing" and an increase in retained
earnings. Capitalization at September 30, 1995, including $18.0 million of
long-term debt due within one year, was comprised of 45.3 percent common equity,
7.2 percent preferred equity and 47.5 percent long-term debt. To improve its
capital structure, the Company currently anticipates the issuance of new shares
of common stock, primarily through the Company's ADR Plan. As financial market
conditions warrant, the Company may, from time to time, issue securities to
permit early redemption of higher-cost senior securities. The Company is
reviewing its financing strategies as they relate to debt and equity structures
in the context of the new competitive environment and the ability of the Company
to shift from a fully regulated to a more competitive organization.
RATE BASE AND REGULATORY POLICIES
See the Company's 1994 Form 10-K, Management's Discussion and Analysis of
Financial Condition and Results of Operations under the heading "REGULATORY
MATTERS--New York State Public Service Commission" for information on the 1993
Rate Agreement which extends to June 30,
21
<PAGE>
1996, including a discussion of the incentive arrangements and the risks and
rewards available to the Company.
Under the Rate Agreement the PSC approved an electric rate increase of
2.5% ($18.3 million) effective for the rate year beginning July 1, 1995. A gas
rate increase that would have been permitted to take effect as of July 1, has
been eliminted as part of the August Settlement Agreement as discussed in Note 2
of the Notes to Financial Statements under the heading "Gas Cost Recovery".
In July, 1995 the Company filed a request with the PSC to increase its
rates for electricity commencing in August, 1996. The filing asks for electric
rates to be increased by approximately $17.1 million or 2.4 percent annually
based on forecasted retail sales volumes for the twelve month period ending June
30, 1997. As a result of the August Settlement Agreement with various parties
(See Note 2, Gas Cost Recovery) gas rates will be frozen for three years. In its
July filing the Company requested an 11.75% rate of return on equity. The
higher rates have been requested to cover increases in capital and operating
costs projected for the Rate Year that are not provided for in present rates and
are not expected to be offset by increased revenues from sales.
With the current three-year electric and gas rate plan expiring in 1996,
the Company is also working with the PSC and others to develop a competitive
initiative that could lead to settlement of the filing described above, replace
the 1993 Rate Agreement with a new five year agreement and continue to provide
price benefits to customers. The goal of the collaborative effort is to
stabilize customer rates as low as possible and establish guidelines that will
allow the Company to assume more risk to take actions that could create
increased earnings for shareholders. The Company is unable to predict whether
any settlement will be achieved.
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. Under the terms of the 1993 Rate Agreement, the
Company would absorb 30 percent of any net revenues lost as a result of such
discounts through June 1996, while the remaining 70 percent would be recovered
from other customers. The Company has not sought recovery of that 70 percent
from other customers. The portion recoverable after June 1996 is expected to be
determined in the recently commenced Company rate proceeding. Under the flexible
22
<PAGE>
tariff provisions, the Company has negotiated long-term electric supply
contracts with nine of its large industrial and commercial electric customers at
discounted rates. The Company is negotiating long term electric supply contracts
with other large customers as the need and opportunity arise. The Company has
not experienced any customer loss due to competitive alternative arrangements.
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
nine months periods ended September 30, 1995 to the corresponding three-month
and nine months periods ended September 30, 1994.
OPERATING REVENUES AND SALES
Total Company revenues for the first nine months of 1995 were $11.4
million or 1.5% below the first nine months of 1994, resulting from lower gas
revenues due to the mild weather during the heating season, the reduction of gas
revenues representing a portion of the $16 million of costs attributable to
excess capacity removed from rates as described under Note 2, Gas Cost Recovery
and the Company decision in February to discontinue for the balance of the
heating season ending in May the operation of its weather normalization clause
in order to moderate the adverse effects on customer bills. Customer electric
revenue increased reflecting higher kilowatt hour sales.
Total Company revenues for the third quarter of 1995 were $15.2
million or 6.6% above the third quarter of 1994 reflecting higher kilowatt hour
sales of electricity due to a good summer cooling season and a modest increase
in rates partially offset by lower gas revenues due to the factors described
above.
Revenues from other electric utility (OEU) sales increased in both
comparison periods reflecting higher kilowatt hour sales and higher rates. In
addition to sales through the New York Power Pool, tariff changes in late 1994
allowed the Company to participate in two-party sales.
23
<PAGE>
The principal factors causing changes in Electric and Gas Department
revenues are estimated below:
<TABLE>
<CAPTION>
Comparison Comparison
Three months Nine months
Ended Sept. 30, Ended Sept.30,
1995 and 1994 1995 and 1994
----------------------- ----------------------
Increase or (Decrease) Increase or (Decrease)
for comparison period for comparison period
(Millions of Dollars) (Millions of Dollars)
Electric Gas Electric Gas
----------------------- ----------------------
<S> <C> <C> <C> <C>
Rate increases $ 3.6 $ - $11.9 $ 4.3
Fuel Costs 10.2 (1.4) 12.8 (30.5)
Weather effects (Heating
& Cooling) 3.9 - (1.8) (8.7)
Customer consumption/*/ 3.9 .4 8.0 9.3
Other/*/ (7.4) (3.1) (6.6) (16.5)
----- ----- ----- ------
Total change in customer
revenues $14.2 $(4.1) $24.3 $(42.1)
OEU sales 5.1 - 6.4 -
----- ----- ----- ------
Total change in operating
revenues $19.3 $(4.1) $30.7 $(42.1)
===== ===== ===== ======
</TABLE>
* Customer consumption reflects retail and unbilled margins and transportation
gas less rate increases and weather effects. Fluctuations in other customer
revenues shown in the table above are largely the result of deferred fuel
costs, revenue taxes and miscellaneous revenues.
FUEL EXPENSES
Fuel expenses decreased in the first nine months of 1995 reflecting
mainly lower unit gas customer sales due to mild weather and lower commodity
costs partially offset by the cost of higher kilowatt hour sales of electricity
including forced purchases from the Kamine cogenerating facility costing
approximately $12.8 million, $3.0 million of which is reflected as fuel expense
and charged to customers in rates and $9.8 million of which remains in the Fuel
Cost Adjustment (FCA) deferral. This amount will be phased into customer
billings and collected over the next year through the FCA.
Fuel expenses increased in the third quarter of 1995 due mainly to the
cost of higher kilowatt hour sales of electricity and an electric
purchase/generation mix which included a higher proportion of relatively
expensive purchased power.
24
<PAGE>
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES
Variations in these line items in both comparison periods reflect
mainly an increase in the accrual for uncollectibles in the third quarter and
lower cost for payroll, employee welfare, contractor and consultant services and
materials and supplies due to Company cost control efforts and the workforce
reduction program undertaken in the second and third quarters of 1994.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased due mainly to an increase in
depreciable plant.
TAXES
The decreases in local, state and other taxes in both periods reflect
mainly lower payroll taxes due to fewer employees and a five percent decrease in
the surcharge on the New York State Gross Revenue Tax in 1995 partially offset
by higher service revenues.
The changes in Federal income tax in both comparison periods reflect
mainly changes in estimates in the effective tax rate used in the Company's
interim tax provision.
OTHER STATEMENT OF INCOME ITEMS
The increases in allowance for funds used during construction (AFUDC)
reflect mainly increases in the amount of utility plant under construction and a
one-half percent increase in the effective rate in September 1994. The changes
in pension plan curtailment and regulatory disallowances reflect write-offs in
connection with workforce reduction programs and unrecoverable gas costs in
1994.
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.
25
<PAGE>
ITEM 5. OTHER INFORMATION
CORPORATE REORGANIZATION
In August, the Company restructured its internal organization to
improve its ability to serve the customer in the emerging competitive
environment. The new organization structure includes four functional areas.
- ENERGY OPERATIONS. This area is responsible for operation of the
physical system, including power plants, systems and engineering
support. Robert E. Smith is the Senior Vice President in charge of
Energy Operations.
- ENERGY SERVICES. Consolidates all customer related activities,
including customer service, strategic development, gas supply,
information services and public affairs under one area headed by
Senior Vice President Thomas S. Richards.
- CORPORATE SERVICES. Includes accounting, finance, auditing, risk
management and human and legal resources. The Corporate Services
function will be headed by a new Chief Financial Officer, who will
be recruited through an external search. Until this position is
filled, Corporate Services will report to David C. Heiligman, Vice
President, Finance and Corporate Secretary.
- NEW BUSINESS DEVELOPMENT. Separates responsibility for new
business development from operations, reflecting its importance to
the Company's future success as the industry moves towards an era
of greater competition. In the short term, Roger W. Kober,
Chairman of the Board, President and Chief Executive Officer, will
take responsibility for this area.
MANAGEMENT CHANGES
David K. Laniak, Executive Vice President, retired on November 1, 1995
to accept a position as Chief Executive Officer of ACC Corporation, a long
distance and telecommunications company based in Rochester. In accordance with
corporate policy, Mr. Laniak will also retire from the Company's Board of
Directors.
26
<PAGE>
Jessica S. Raines was elected Auditor of the Company, effective
September 11, 1995, replacing Jack M. Kuebel, who retired on October 1. Ms.
Raines comes to RG&E from Chase Manhattan Bank, where she was a Vice President
and Client Service Partner.
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 August 17, 1995 reporting under Item
5, Other Events, a settlement with the staff of the PSC and other parties which
affects the rate treatment of various gas costs through October 31, 1998.
EXHIBIT INDEX
Exhibit 27 - Financial Data Schedule pursuant to Item 601 (c) of
Regulation S-K.
27
<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: November 13, 1995 By DAVID C. HEILIGMAN
-------------------------------------
David C. Heiligman
Vice President, Finance and
Corporate Secretary
Date: November 13, 1995 By DANIEL J. BAIER
--------------------------------------
Daniel J. Baier
Controller
(Principal Accounting Officer)
28
<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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1995
<PERIOD-END> SEP-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,691,162
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 252,764
<TOTAL-DEFERRED-CHARGES> 491,661
<OTHER-ASSETS> 38,879
<TOTAL-ASSETS> 2,474,466
<COMMON> 191,391
<CAPITAL-SURPLUS-PAID-IN> 492,072
<RETAINED-EARNINGS> 89,887
<TOTAL-COMMON-STOCKHOLDERS-EQ> 773,350
55,000
67,000
<LONG-TERM-DEBT-NET> 625,318
<SHORT-TERM-NOTES> 29,600
<LONG-TERM-NOTES-PAYABLE> 91,900
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 18,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 814,298
<TOT-CAPITALIZATION-AND-LIAB> 2,474,466
<GROSS-OPERATING-REVENUE> 745,705
<INCOME-TAX-EXPENSE> 50,301
<OTHER-OPERATING-EXPENSES> 574,838
<TOTAL-OPERATING-EXPENSES> 627,956
<OPERATING-INCOME-LOSS> 117,749
<OTHER-INCOME-NET> (5,117)
<INCOME-BEFORE-INTEREST-EXPEN> 115,449
<TOTAL-INTEREST-EXPENSE> 43,134
<NET-INCOME> 72,315
5,599
<EARNINGS-AVAILABLE-FOR-COMM> 66,716
<COMMON-STOCK-DIVIDENDS> 51,395
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 202,384
<EPS-PRIMARY> 1.75
<EPS-DILUTED> 1.75
</TABLE>
