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, 1996
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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
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(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
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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
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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, 1996: 38,851,464
INDEX
Page No.
PART I - FINANCIAL INFORMATION
Consolidated Balance Sheet - September 30, 1996 and
December 31, 1995................................................... 1 - 2
Consolidated Statement of Income - Three Months and Nine Months
Ended September 30, 1996 and 1995.................................... 3 - 4
Consolidated Statement of Cash Flows - Nine Months
Ended September 30, 1996 and 1995.................................... 5
Notes to Financial Statements.......................................... 6 - 9
Management's Discussion and Analysis of Financial
Condition and Results of Operations................................. 9 -18
PART II - OTHER INFORMATION
Legal Proceedings...................................................... 18
Exhibits and Reports on Form 8-K....................................... 19
Signatures............................................................. 19
PART I - FINANCIAL INFORMATION
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ITEM 1. FINANCIAL STATEMENTS
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
September 30, December 31,
Assets 1996 1995
- ----------------------------------------------------------------------------------------------------------------
Utility Plant
Electric $2,374,657 $2,342,981
Gas 384,261 382,071
Common 138,320 135,526
Nuclear fuel 224,713 207,525
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3,121 ,951 3,068,103
Less: Accumulated depreciation 1,372,940 1,345,552
Nuclear fuel amortization 182,922 173,326
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1,566,089 1,549,225
Construction work in progress 106,721 121,725
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Net Utility Plant 1,672,810 1,670,950
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Current Assets
Cash and cash equivalents 30,855 44,121
Accounts receivable, net of allowance for
doubtful accounts: 1996 - $16,400, 1995 - $11,950 105,257 121,123
Unbilled revenue receivable 40,476 64,169
Materials and supplies, at average cost:
Gas stored underground 22,677 20,326
Construction and other supplies 10,083 10,223
Fossil fuel 6,334 8,101
Prepayments 31,069 24,533
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Total Current Assets 246,751 292,596
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Investment in Empire -- 38,879
Deferred Debits
Nuclear generating plant decommissioning fund 83,027 71,540
Nine Mile Two deferred costs 31,623 32,411
Deferred finance charges - Nine Mile Two -- 19,242
Unamortized debt expense 15,198 16,712
Other deferred debits 26,224 21,857
Regulatory assets:
Income taxes 182,566 188,599
FERC 636 transition costs 34,773 40,965
Uranium enrichment decommissioning deferral 18,184 18,707
Deferred ice storm charges 14,638 16,553
Demand side management costs 8,422 14,759
Other regulatory assets 28,768 31,623
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Total Regulatory assets 287,351 311,206
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Total Deferred Debits 443,423 472,968
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Total Assets $2,362,984 $2,475,393
- --------------------------------------------------------- ---------- ---------
The accompanying notes are an integral part of the financial statements.
1
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
September 30, December 31,
Capitalization and Liabilities 1996 1995
- ----------------------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $ 555,040 $ 624,332
- promissory notes 91,900 91,900
Preferred stock redeemable at option of Company 67,000 67,000
Preferred stock subject to mandatory redemption 45,000 55,000
Common shareholders' equity:
Common stock
Authorized 50,000,000 shares; 38,851,464
shares outstanding at September 30, 1996
and 38,453,163 shares outstanding at
December 31, 1995. 696,086 687,518
Retained earnings 87,662 70,330
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Total common shareholders' equity 783,748 757,848
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Total Capitalization 1,542,688 1,596,080
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Long Term Liabilities (Department of Energy)
Nuclear waste disposal 78,054 75,077
Uranium enrichment decommissioning 17,888 15,810
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Total Long Term Liabilities 95,942 90,887
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Current Liabilities
Long term debt due within one year 20,000 18,000
Preferred stock redeemable within one year 10,000 --
Notes Payable - Empire -- 29,600
Accounts payable 56,909 52,578
Dividends payable 19,349 19,170
Taxes accrued 410 18,638
Interest accrued 14,626 12,844
Other 28,403 31,508
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Total Current Liabilities 149,697 182,338
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Deferred Credits and Other Liabilities
Accumulated deferred income taxes 377,566 377,652
Pension costs accrued 71,775 71,580
Deferred finance charges - Nine Mile Two -- 19,242
Other 125,316 137,614
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Total Deferred Credits and Other Liabilities 574,657 606,088
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Commitments and Other Matters (Note 2) -- --
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Total Capitalization and Liabilities $2,362,984 $2,475,393
- --------------------------------------------------------- ---------- ----------
The accompanying notes are an integral part of the financial statements.
2
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
For the Three Months Ended
September 30
1996 1995
- ----------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $190,507 $194,761
Gas 42,481 41,976
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232,988 236,737
Electric sales to other utilities 1,855 8,408
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Total Operating Revenues 234,843 245,145
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Fuel Expenses
Fuel for electric generation 9,893 12,009
Purchased electricity 9,380 18,427
Gas purchased for resale 29,904 27,242
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Total Fuel Expenses 49,177 57,678
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Operating Revenue less Fuel Expenses 185,666 187,467
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Other Operating Expenses
Operations excluding fuel expenses 65,114 61,333
Maintenance 11,148 11,952
Depreciation and amortization 29,349 23,247
Taxes - local, state and other 29,603 30,672
Federal income tax 14,293 18,525
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Total Other Operating Expenses 149,507 145,729
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Operating Income 36,159 41,738
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Other Income and Deductions
Allowance for other funds
used during construction 72 119
Federal income tax 552 1,633
Other - net (1,440) (2,247)
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Total Other Income and Deductions (816) (495)
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Interest Charges
Long term debt 11,892 13,110
Other - net 2,505 1,977
Allowance for borrowed funds
used during construction (116) (778)
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Total Interest Charges 14,281 14,309
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Net Income 21,062 26,934
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Dividends on Preferred Stock 1,866 1,866
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Earnings Applicable to Common Stock $19,196 $25,068
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Weighted average number of shares
outstanding in each period (000's) 38,851 38,212
Earnings per Common Share $0.49 $0.65
Cash Dividends Paid per Common Share $0.45 $0.45
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The accompanying notes are an integral part of the financial statements.
3
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
For the Nine Months Ended
September 30
1996 1995
- ----------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $524,143 $527,298
Gas 242,676 201,267
-------- --------
766,819 728,565
Electric sales to other utilities 12,797 17,140
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Total Operating Revenues 779,616 745,705
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Fuel Expenses
Fuel for electric generation 29,750 33,457
Purchased electricity 35,688 43,045
Gas purchased for resale 139,478 116,472
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Total Fuel Expenses 204,916 192,974
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Operating Revenue less Fuel Expenses 574,700 552,731
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Other Operating Expenses
Operations excluding fuel expenses 195,008 178,515
Maintenance 36,166 36,446
Depreciation and amortization 76,707 68,202
Taxes - local, state and other 97,101 98,701
Federal income tax 53,578 53,118
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Total Other Operating Expenses 458,560 434,982
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Operating Income 116,140 117,749
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Other Income and Deductions
Allowance for other funds
used during construction 600 417
Federal income tax 1,556 2,817
Other - net (544) (5,534)
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Total Other Income and Deductions 1,612 (2,300)
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Interest Charges
Long term debt 36,733 39,346
Other - net 7,025 6,041
Allowance for borrowed funds
used during construction (1,289) (2,253)
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Total Interest Charges 42,469 43,134
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Net Income 75,283 72,315
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Dividends on Preferred Stock 5,599 5,599
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Earnings Applicable to Common Stock $69,684 $66,716
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Weighted average number of shares
outstanding in each period (000's) 38,735 38,015
Earnings per Common Share $1.79 $1.75
Cash Dividends Paid per Common Share $1.35 $1.35
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The accompanying notes are an integral part of the financial statements.
4
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Nine Months Ended
September 30,
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1996 1995*
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CASH FLOW FROM OPERATING ACTIVITIES
Net income $ 75,283 $ 72,315
Adjustments to reconcile net income to net cash flow
from operating activities:
Depreciation and amortization 76,707 68,202
Amortization of nuclear fuel 11,763 12,431
Deferred fuel costs - electric 1,270 (5,572)
Deferred fuel costs - gas (4,622) 6,005
Deferred income taxes 5,948 4,995
Allowance for funds used during construction (1,890) (2,670)
Unbilled revenue, net 23,693 12,199
Deferred ice storm costs 1,916 1,918
Nuclear generating plant decommissioning fund (6,652) (8,308)
Pension costs accrued (869) 7,571
Post employment benefit internal reserve 4,485 3,981
Research and development amortization 2,049 2,225
Rate settlement amortizations 2,265 6,760
Changes in certain current assets and liabilities:
Accounts receivable 15,865 (1,022)
Materials and supplies - gas stored underground (2,351) 995
- other, net 1,908 2,081
Taxes accrued (18,229) 60
Accounts payable 4,330 16,885
Interest accrued 1,782 3,001
Other current assets and liabilities, net (12,803) (3,047)
Other, net 4,664 1,379
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Net cash flow from operating activities $ 186,512 $ 202,384
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CASH FLOW FROM INVESTING ACTIVITIES
Utility Plant
Plant additions $ (81,133) $ (73,145)
Nuclear fuel additions (16,377) (12,278)
Less: Allowance for funds used during construction 1,890 2,670
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Additions to Utility Plant (95,620) (82,753)
Investment in Empire, net 9,279 (320)
Other, net (63) (21)
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Net cash used in investing activities $ (86,404) $ (83,094)
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CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/issuance of common stock $ 8,612 $ 12,941
Short term borrowings -- (51,600)
Retirement of long term debt (67,332) --
Dividends paid on preferred stock (5,599) (5,599)
Dividends paid on common stock (52,173) (51,122)
Other, net 3,118 (604)
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Net cash used in financing activities $ (113,374) $ (95,984)
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Net(decrease)increase in cash and cash equivalents $ (13,266) $ 23,306
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Cash and cash equivalents at beginning of period $ 44,121 $ 2,810
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Cash and cash equivalents at end of period $ 30,855 $ 26,116
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Nine Months Ended
September 30,
- --------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 1996 1995*
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Cash Paid During the Period
Interest paid (net of capitalized amount) $ 37,573 $ 38,822
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Income taxes paid $ 55,638 $ 40,000
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* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
5
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 1996 are subject to adjustment at the end of the year
when they will be audited by independent accountants. 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, 1995.
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, 1995 and should be read in conjunction with the
material contained in that Note.
LITIGATION WITH CO-GENERATOR
During 1995 Kamine/Besicorp Allegany L.P. (Kamine) filed a petition before
the Federal Energy Regulatory Commission (FERC) to waive certain requirements
for federal Qualified Facility status for 1994. The Company and the New York
State Public Service Commission (PSC) filed in opposition to the request.
Subsequently FERC issued an order granting the waiver request and the Company's
motion for rehearing was denied. The Company has filed a petition for review
with the U.S. Court of Appeals for the District of Columbia Circuit.
In November 1995 Kamine, the only independent power producer which has a
power purchase agreement (Agreement) with the Company based on mandated pricing
provisions consistent with the "six-cent" law, 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.
Kamine filed a motion to compel the Company to pay what would be due under
Kamine's view of the terms of the 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
proceedings 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. Numerous other procedural motions
have been presented in the Bankruptcy Court. While these procedural issues are
pending, the Company would pay approximately two cents per kilowatt hour when
the plant operates and it is not operating at the present time.
The existence of mandated, high-priced independent power purchase agreements
is a significant problem throughout the State of New York and there are various
efforts by investor owned utilities and State officials to resolve the problem.
The Company is litigating the Kamine matter vigorously while it continues to
work to resolve this particular dispute in a fashion that is fair and equitable
to all parties. However, it will continue to take aggressive action on behalf of
customers and the Company to assure that their interests are respected in any
resolution. The Company is unable to predict the ultimate outcome of these
legal proceedings. For further information with respect to the Kamine contract
and related litigation, see the Company's 1995 Form 10-K, Item 8, Note 10 of the
Notes to Financial Statements.
6
1995 GAS SETTLEMENT
Under provisions of the 1995 Gas Settlement with the Staff of the PSC and
other parties, the Company faces an economic risk of remarketing $74.2 million
of excess gas transportation and storage capacity through October 1998. The
Company entered into a marketing agreement with CNG Transmission Corporation
(CNG) that resulted in the release of approximately $29 million of this capacity
through the period. CNG is assisting the Company in obtaining permanent
replacement customers for transportation capacity the Company does not require.
The Company also implemented transportation and storage capacity reductions on
the Empire State Pipeline and upstream pipelines which represent approximately
$21 million of release through the period. To help manage the balance of the
excess capacity costs at risk, the Company has retained MidCon Gas Services
Corp. which is working with the Company to identify and implement opportunities
for temporary and permanent release of surplus pipeline capacity and to advise
in the management of the Company's gas supply, transportation and storage assets
consistent with the goals of providing reliable service and reducing the cost of
gas.
The FERC approved a change in rate design for the Great Lakes Gas Transmission
Limited Partnership (Great Lakes) on which the Company holds transportation
capacity. This change resulted in a retroactive surcharge by Great Lakes to the
Company in the amount of approximately $8 million, including interest. Under
the terms of the 1995 Gas Settlement, the Company may recover approximately one-
half of the surcharge in rates charged to customers; but the remainder may not
be passed through and has been previously reserved. The Company, which paid the
Great Lakes assessment under protest, vigorously contested it before the FERC,
but on April 25, 1996, the FERC upheld this determination that the charge to
the Company is proper. The Company has filed a petition for review with the
U.S. Court of Appeals and will also pursue options available at the FERC. The
ultimate outcome of judicial review and those regulatory options cannot be
predicted.
In an order issued March 28, 1996 in the PSC's Proceeding on Restructuring the
Emerging Competitive Natural Gas Market, which was confirmed in a September 13,
1996 Order resolving various petitions for rehearing, the PSC established a
three-year period (ending March 28, 1999) during which 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.
Prior to the beginning of the third year, the utilities would be required to
demonstrate their efforts to dispose of "excess" capacity. Pursuant to the
PSC's Orders, the cost of capacity defined as "excess" that the Company still
holds after March 28, 1999 may not be fully recoverable in rates. Accordingly,
the Company's ability to avoid absorbing this cost will depend on the success of
remarketing efforts, as described above, and, if such efforts do not result in
eliminating all "excess" capacity, on a satisfactory explanation as to why all
such capacity could not be remarketed.
DECOMMISSIONING TRUST
The Nuclear Regulatory Commission (NRC) is currently considering proposals
which may impact financial funding requirements for decommissioning of nuclear
power plants. Under current NRC regulations electric utilities provide for
decommissioning funds annually over the estimated life of a plant. If state
regulatory authorities were to adopt a program to remove electric generation
(including nuclear plants) from cost-based rate regulation, an action which the
New York PSC is currently considering, such plants would be required to compete
in a competitive electric market and would have no assured source of revenue
from energy sales. Under current regulations, the NRC can require the owners of
nuclear plants lacking such assured revenue streams to provide assurance that
the full estimated cost of decommissioning will ultimately be available
7
through some guarantee mechanism.
The NRC sought public comment through late June on a number of questions,
including the likely timetable for utility restructuring and deregulation and to
what degree costs will be recoverable if a large baseload plant is deemed to be
non-competitive because of high construction costs and what funding sources will
be used to shut down a plant prematurely and safely. It also issued an
Administrative Letter in June underscoring the NRC's requirement that its
approval be sought for changes of control that would amount to a license
transfer. In September, the NRC published a draft policy statement covering
several industry restructuring issues and announcing that it would address its
intended procedures in this area in a forthcoming Standard Review Plan for
financial qualifications and decommissioning funding reviews. Further NRC
activity in this area is expected, possibly as early as the fourth quarter of
1996. See the Company's 1995 Form 10-K, Item 8, Note 10 to the Financial
Statements regarding the Company's plan for the eventual decommissioning of the
Ginna Nuclear Plant and its 14% share of Nine Mile Two.
REGULATORY AND STRANDABLE ASSETS
The Company has deferred certain costs rather than recognize them on its books
when incurred. Such deferred costs are then recognized as expenses when they
are included in rates and recovered from customers. Such deferral accounting is
permitted by 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 were to be changed from a cost-of-service approach, and it were no
longer allowed to defer these costs under SFAS-71, these assets would be
adjusted for any impairment to recovery (see discussion under Financial
Accounting Standards No. 121). In certain cases, the entire amount could be
written off.
Below is a summarization of the Regulatory Assets as of September 30, 1996.
Millions
of Dollars
----------
Income Taxes $182.6
Uranium Enrichment Decommissioning Deferral 18.2
Deferred Ice Storm Charges 14.6
FERC 636 Transition Costs 34.8
Demand Side Management Costs Deferred 8.4
Other, net 28.8
------
Total - Regulatory Assets $287.4
======
See the Company's Form 10-K for the fiscal year ended December 31,
1995, Item 8, Note 10 of the Notes to Financial Statements, "Regulatory and
Strandable Assets" for a description of the Regulatory Assets shown above.
In a competitive electric market, strandable assets would arise when
investments are made in facilities, or costs are incurred to service customers,
and such costs are not fully recoverable in market-based rates. Examples
include purchase power contracts (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 September 30, 1996
cannot be determined at this time, but could
8
be significant.
CIVIL INVESTIGATIVE DEMAND
The United States Department of Justice, Antitrust Division has issued
a Civil Investigative Demand calling for depositions, for the production of
documents and answers to interrogatories concerning the electric industry and
competition. For a discussion of the investigative focus with respect to the
Company see Note 2 of the Company's Form 10-Q for the quarter ended June 30,
1996.
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. Shown below is a listing of the
items discussed.
Earnings Summary Page 9
Competition Page 10
PSC Competitive Opportunities Case
Nuclear Operating Company
FERC Open Transmission Tariffs
PSC Gas Restructuring Case
Rates and Regulatory Matters Page 14
1996 Rate Settlement
1995 Gas Settlement
Liquidity and Capital Resources Page 15
Projected Capital and Other Requirements
Redemption of Securities
Financing
Capital Structure
Results of Operations Page 16
Revenues and Sales
Operating and Other Expenses
Dividend Policy
EARNINGS SUMMARY
Earnings per common share for the current and prior year three month
and nine month periods ended September 30, are as follows:
1996 1995
Three months $ .49 $ .65
Nine months $1.79 $1.75
Lower third quarter earnings were due to the summer weather being 43%
cooler than in 1995, resulting in electric sales to customers declining 2.3%.
Earnings in 1996 were higher for the nine month period due to increased
gas sales. The weather during the heating season over this period was 14%
colder than in 1995. Partially offsetting the increase were higher allowances
for doubtful accounts. For a summary of the earnings effect of changes in
revenues and expenses see the table under Results of Operations.
9
COMPETITION
PSC COMPETITIVE OPPORTUNITIES CASE. The following discussion relative to
the PSC Competitve Opportunities Case is based on the position of the Company
documented in its submission to the PSC filed on October 1, 1996. The PSC has
invited the Company and other New York State utilities to participate in
discussions with the PSC Staff with respect to their submissions. These
discussions may result in changes in the ultimate outcome from the material that
was submitted.
PSC's May 1996 Order. The PSC's Opinion No. 96-12 issued May 20, 1996 in
the Competitive Opportunities Proceeding purports to have required the electric
utilities in New York to file, on or before October 1, 1996, plans and other
information to implement competition at the wholesale level by 1997 and at the
retail level by 1998. Specifically, the PSC sought filings by the individual
utilities that would include: (a) a description of the utility's structure in
both the short and long term and, where divesture of generation is not proposed,
how resulting market power concerns would be addressed; (b) a schedule for the
introduction of retail access to all customers and a set of unbundled tariffs
consistent with retail access; (c)a rate plan covering the transitional period
to a competitive market, including mechanisms to reduce rates and address
strandable costs; (d) identification of public policy programs whose funding is
not recoverable in a competitive market and mechanisms for recovery; (e)
examination of "load pockets" (where within-system generation is required for
reliability) and proposals to mitigate resulting market power; and (f) a plan
for providing energy services, including addressing continued customer
protections that are consistent with emerging competition. Opinion No. 96-12
also purports to require utility group responses to related issues regarding
competition.
Pending Litigation. In its May 20, 1996 Order, the PSC announced its
"vision" for the future of the electric industry in New York State. Certain
aspects of the restructuring envisioned by the PSC -- particularly the PSC's
apparent determinations that it can deny a reasonable opportunity to recover
prudent investments made on behalf of the public, order retail wheeling, require
divestiture of generation assets and deregulate certain sectors of the energy
market -- could, if implemented, have a negative impact on the operations of New
York's investor-owned electric utilities, including the Company. The Company
therefore joined in a lawsuit filed by the Energy Association of New York State
and the State's other electric utilities against the PSC on September 18, 1996,
in the New York Supreme Court for Albany County. The utilities have requested
that the Court declare that the May 20 Order is unlawful or, in the alternative,
that the Court clarify that the May 20 Order can be given no binding effect by
the PSC. The litigation is ongoing and the Company is unable at this time to
predict the likelihood of success or the impact of the litigation on the
Company's operations.
Company's October Filing. On October 1, 1996 the Company, without
prejudice to its position in the pending Article 78 proceeding, submitted a
response to Opinion No. 96-12. The Company's submission presents a possible
restructuring proposal but asserts that certain issues, in addition to the
litigation, need to be addressed satisfactorily before the Company can proceed.
These prerequisites to restructuring include: assurance of the recovery of
investment made to provide public service; a consistent Statewide treatment of
nuclear plants that recognizes the need to treat them as must-run units and as
subject to cost-based rate regulation; assurance of recovery of costs associated
with the Kamine project; assurance of recovery of regulatory assets (i.e.,
generally current costs that have been deferred and/or spread over time to
minimize current rate impact); collection of the cost of public policy programs
through a Public Policy Charge; and provision of a fair opportunity for the
Company to participate in the competitive market place.
Subject to the Article 78 proceeding and the foregoing prerequisites, the
Company would propose to move toward full competition at the retail level.
Under the Company's approach, in its ultimate form, the Company's participation
in generation would change substantially as discussed below. A regulated
distribution company (DISCO) would receive electricity purchased in the
unregulated wholesale market by
10
unregulated Load Serving Entities (LSEs), which may include an RG&E unregulated
LSE, and deliver that electricity to the customers of the LSEs. Before arriving
at this final stage, two transition phases would be required.
Phase I - Functional Reorganization. First, the Company would create a
wholesale entity (DISCO/GENCO) comprised of the transmission and distribution
functions, together with existing generation and certain contracts (e.g., for
electric power purchases from the New York Power Authority). At the same time,
the Company would establish a regulated LSE which would handle all retail
functions including customer service, metering, billing and energy purchasing.
The DISCO/GENCO would provide electric transmission service to the regulated LSE
under a federally regulated transmission tariff. It might also provide energy
distribution service to the regulated LSE under a state regulated tariff. The
Public Policy Charge would be collected through the LSE.
Instead of identifying a specific value of stranded costs, the Company
would recover through the LSE the difference between traditional revenue
requirements and the revenues received from electric power sales which the
Company is able to make into the wholesale market.
Service provided by the regulated LSE to customers would be provided
under a retail tariff that, at least initially, would generally be similar to
the existing tariff.
Phase II - Retail Access. The second phase, movement to retail access
would begin with a pilot program, followed by full-scale implementation, if
warranted, in manageable steps. A large-scale pilot program would commence as
soon as (1) recovery of strandable costs, potential jurisdictional problems and
other threshold matters are appropriately addressed and (2) an Independent
System Operator (ISO) is functioning in a manner sufficient to enable multiple
LSEs to operate on the system. A specific geographic area of the Company's
service territory including customers of all types would be selected for the
pilot program and participating customers would be permitted to choose an
unregulated LSE which would provide retail services and take distribution
service under the same tariff as the regulated LSE. The Company's own
unregulated LSE, which would take distribution service under the same tariff as
unaffiliated LSEs, would also compete in the market under the pilot program.
The pilot program would continue for a period of two years.
Full-scale retail access would begin as soon as the pilot phase is
complete (i.e., approximately two years after the pilot program begins) --
assuming that no insurmountable legal or practical obstacles make implementation
impracticable or impossible. Full competition might not be implemented
geographically as in the pilot program, but the Company would propose a
mechanism by which an orderly and deliberate conversion can occur. Under the
full-scale access scenario, the Company would, through its unregulated
affiliated LSE, continue to compete for customers.
Treatment of Incumbent Generation. Under the possible proposal in the
October 1 submission, the Company would retire or otherwise remove all of its
wholly-owned fossil generating plants from rate base before the year 2009, when
the license for the Ginna nuclear plant expires. Prior to retirement, the
Company would run those units as needed to support the Company's system and when
the wholesale price exceeds their variable cost of operation. Any revenues
received from those sales would be used to offset the costs associated with
these units.
The cost of the transmission upgrades that would be necessary to
eliminate load pockets and to maintain system reliability without on-system
generation is currently estimated to range from $64 million to $96 million; but
other mitigation measures may be implemented throughout the State that could
reduce the cost of system upgrades.
Until retirement, Ginna would be operated as a must-run, base load unit
and its output would be sold into the wholesale market. As with revenues from
sales from
11
the fossil units, expected revenues for Ginna sales would be used as an offset
to strandable cost recovery. Use of remaining life depreciation (which the
Company would also apply to other-units) would allow Ginna net plant to be
written down by the time of retirement. Pursuant to NRC requirements,
decommissioning funds are already being collected; any additional required funds
would be recovered through charges applicable to all customers, as would the
cost of decommissioning the Company's other generating units.
Nine Mile 2, a nuclear unit which is co-owned with four other utilities,
requires a Statewide solution. At least until that time, costs not otherwise
recovered in the market would need to be recovered in charges to customers.
Any costs or benefits associated with other Company obligations (e.g. the
jointly-owned Oswego Unit 6 and the Kamine contract) will be reflected in the
appropriate charges.
Corporate Structure. Under the Company's possible approach,
implementation of wholesale and retail access would not require divestiture of
generation or formation of separate subsidiaries to own and/or operate the
Company's generating plants. Functional separation among generation,
distribution and retailing elements of the Company's energy business would avoid
the serious impediments that render structural separation unacceptable.
As with generation, there would be no need to form separate legal
subsidiaries to own and/or operate the retailing functions located in the
regulated LSE, which would take service from the DISCO at regulated prices and
terms available to all LSEs. The Company's involvement in the unregulated LSE
market would be through a separate subsidiary.
Although corporate structural changes would not be required, the Company
nevertheless intends to embark on a deliberate course to increase structural
flexibility over time by retiring first mortgage debt and phasing out preferred
stock when these actions are appropriate and financially prudent. These changes
will eliminate a number of restrictions that would otherwise prevent the Company
from engaging in structural changes that may become advantageous at a later
time.
Rate Plan. The Company's current electric rates are governed by a 1996
Settlement that extends through June 1999; gas rates are set pursuant to a 1995
Settlement that remains in effect through June 1998. In the transition period
the Company would anticipate implementing two sets of rates: one for the
regulated LSE and the other for the DISCO. The regulated LSE, which is intended
to fulfill the Company's obligation to serve customers until they switch to
unregulated LSEs, probably would "inherit," perhaps with some minor
modifications, the Company's current electric and gas tariffs (and the current
electric and gas settlements, to the extent either is in effect). After the
expiration of the settlement periods, the regulated LSE would operate under a
multi-year plan based upon cost of service regulation. Cost of service
regulation would be necessary in this instance because the transition to
competition should result in a dramatic decline in the number of customers
taking service from the regulated LSE and, accordingly, will produce an increase
in per-unit costs of service that might not be recoverable under certain
performance-based approaches.
The DISCO would "inherit" the Company's recently filed FERC transmission
tariff and, subject to resolution of jurisdictional issues, would either create
a new Commission-regulated distribution tariff or extend the FERC tariff to all
of the distribution system. The revenue requirement for distribution service
would be set, preferably, through a performance-based system that would include
price caps subject to an index that would be adjusted downward for presumed
productivity gains.
Stranded costs of generation and other assets that are not mitigated
through wholesale power sales would be collected through charges applicable to
all customers, as would the Public Policy costs. The Public Policy Charge would
be shown separately
12
on bills to customers.
Service to customers who cannot pay their bills for energy services would
be maintained either through voluntary arrangements with unregulated LSEs or
through the regulated LSE. To the extent that such service would require a
subsidy not already reflected in some form in the Public Policy Charge, that
subsidy would be added to that charge.
Because there is a substantial opportunity to gain additional
efficiencies and other benefits if the development of the competitive market
proceeds in tandem for both electricity and gas, the Company would propose that
measures similar to those included in its submission for electricity be applied
to gas service as well. The Company's submission, however, is not intended to
represent a conclusive position with respect to gas issues.
PSC's Proposed Timetable. On October 9, 1996, the PSC issued its Order
Establishing Procedures and Schedule assigning an Administrative Law Judge to
each utility, specifying a 90-day period for settlement negotiations and a March
8, 1997 deadline for closing the case unless hearings to cross-examine are
called. The Order did not address the pending lawsuit brought by the utilities,
which could significantly alter the proposed schedule.
NUCLEAR OPERATING COMPANY. In mid-October the Company and Niagara Mohawk
Power Corporation announced plans to form a joint nuclear operating company to
support and manage the operations of the Company's Ginna nuclear plant and
Niagara's Nine Mile Point One and Two plants. The plan includes the initial
formation of a nuclear services entity to provide support services such as
quality assessment, engineering support, emergency preparedness and fuel
management. Ultimately, the plan calls for the creation of a joint operating
company to manage operations at the three plants. Other New York nuclear plant
operators are encouraged to join. Formation of a statewide nuclear operating
company would allow organizations to work together efficiently to achieve common
objectives and would enhance a single approach to resolution of nuclear issues
in the PSC Competitive Opportunities review.
FERC OPEN TRANSMISSION TARIFFS. In April 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 to be filed by July 9, 1996. The rule defines
the non-discriminatory terms and conditions under which unregulated generators,
utilities, and other suppliers could gain access to a utility's transmission
grid to deliver power to wholesale customers. A supplementary release by FERC
states the principle that utilities are entitled to full recovery of
"legitimate, prudent and verifiable" strandable costs at the state and federal
level. This supplementary release concludes that FERC should be the principal
forum for addressing wholesale strandable costs, while suggesting state
regulatory authorities should address the recovery of strandable costs which may
result from retail competition.
The Company individually filed the required transmission service tariff
on July 9, 1996. This tariff was set for hearing by an Order issued September
25, 1996. A prehearing conference was held in early October at which time a
procedural schedule was established leading to a trial date in September, 1997.
The Company plans to proceed with the case independent of anticipated filings of
the New York Power Pool (NYPP) until such time as they are made and clearly
supersede the Company's filing. The Company is also continuing to participate in
collateral filings requesting clarification of FERC requirements and providing
additional tariffs for power pools similar to the NYPP. A joint NYPP "open
access" tariff is required by December, 1996. FERC has indicated that it
endorses the concept of an Independent System Operator to operate facilities
controlled by the NYPP. The PSC requested that the NYPP filing be made
available to the PSC on October 1, 1996 in the Competitive Opportunities Case
discussed above. However, on that date the filing materials were not complete
and the NYPP members submitted a status report on development of the FERC
filings.
The NYPP is actively evaluating the requirements for implementing
wholesale
13
competition within the framework of the FERC proposals. Significant changes to
NYPP pricing procedures are expected, but their projected effects on the
Company's operations and financial performance are not substantial assuming
continued vertical integration of the utility industry in New York State. At
the present time, the Company cannot predict what effects regulations ultimately
adopted by FERC will have, if any, on future operations or the financial
condition of the Company. The near term impacts of the FERC tariff filed on
July 9, 1996 are not expected to be significant since they apply to new
wholesale customers. Existing wholesale transmission services now provided to
existing municipal customers will continue to be provided under existing service
agreements.
PSC GAS RESTRUCTURING CASE. In March, 1996 the PSC 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. Consistent with the Commission's decision effective
November 1, 1996, the Company has revised its service offerings to include two
new service classifications that will ultimately provide all customers with gas
supply choice by allowing customers to aggregate their loads for the purpose of
purchasing gas from other suppliers. The first new service offering, Service
Classification No. 5 - Comprehensive Transportation Service, provides for the
transportation, storage and balancing of customer-owned gas from the Company's
city gate to the customer's premises. The second offering, Service
Classification No. 6 -Supplier Service allows a qualified supplier to contract
with a customer, or aggregate the loads of a group of customers, to have gas
transported on behalf of the customer(s) to the Company's city gate. The key
elements of the new services are aggregation -- the ability for customers to
join together to make purchases -- and unbundling-- identification of the
individual components of the price of natural gas service. In recognition of
the accelerating movement by customers toward acquisition of their own gas
supply, the Company has sought to restructure its gas supply and transportation
contracts to reflect reduced requirements for Company-furnished gas. The Company
is also making upstream transportation capacity available to its customers
through capacity assignment programs.
RATES AND REGULATORY MATTERS
1996 Rate Settlement. On September 26, 1996, the PSC issued Opinion 96-27
which reiterated its June, 1996 approval of a Settlement Agreement (1996
Settlement) among the Company, PSC Staff and several other parties, resolving
most issues in the rate proceedings for a three-year period, commencing July 1,
1996 and concluding June 30, 1999. Under the 1996 Settlement base electric
rates (that is, rates excluding the Fuel Cost Adjustment (FCA)) for the first
year (commencing July 1, 1996) are decreased to a level that reduces revenues in
an amount equal to 1.0 percent ($7.1 million) of the revenues that would have
been produced under the rates previously in effect. In each of the second and
third years base rates will be decreased by an additional amount equal to 0.5
percent ($3.5 million) of the revenues that were produced by the rates in effect
in the immediately preceding year. In addition to these base rate reductions,
the 1996 Settlement reduces and holds constant fuel cost recoveries for the
three-year period. The freezing of costs, combined with the foregoing base rate
decreases, is expected to produce effective overall rate decreases of 3.5% for
residential customers and 5.0% to 6.0% for non-residential customers over the
three year period. The PSC failed to approve certain provisions of the 1996
Settlement related to Kamine (which would have permitted immediate flow through
of increases in Kamine costs, subject to subsequent PSC review) and gas costs
(which the Company maintains are not affected by the 1995 Gas Settlement). On
October 28, 1996, the Company commenced an Article 78 proceeding in State
Supreme Court, Albany County, for judicial review of the PSC's decision to
exclude these two items from the 1996 Settlement. See the Company's Form 10-Q
for the quarter ended June 30, 1996, Management's Discussion and Analysis of
Financial Condition and Results of Operations under the heading "1996 Rate
Settlement" for further information regarding the 1996 Settlement, including a
discussion of certain incentives and adjustments.
The 1996 Settlement is expressly made subject to any modification that
may be
14
required by a PSC decision in the Competitive Opportunities Proceeding
(discussed above). The costs of compliance with that decision are to be treated
as a Generic Mandate for purposes of the 1996 Settlement.
1995 Gas Settlement. Under provisions of the 1995 Gas Settlement, the
Company faces an economic risk of remarketing $74.2 million of excess gas
transportation and storage capacity through October 1998. The financial impact
of the 1995 Gas Settlement on the Company's business in 1996 and subsequent
years will be largely determined by the degree of success achieved by the
Company in remarketing its excess gas capacity and in controlling its local gas
distribution costs. The Company has 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 projects that
it will also be successful in meeting the Settlement targets in the remaining
two years of the Settlement period. For further information with respect to the
1995 Gas Settlement see Note 2 of the Notes to Financial Statements and the
Company's 1995 Form 10-K Item 8, Note 10 of the Notes to Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 1996 cash flow primarily from operations
(see Consolidated Statement of Cash Flows), provided the funds for construction
expenditures and the redemption of long-term debt. At September 30, 1996 the
Company had cash and cash equivalents of $30.9 million. Capital requirements
during 1996 are anticipated to be satisfied primarily from the combination of
internally generated funds and temporary cash investments.
PROJECTED CAPITAL AND OTHER REQUIREMENTS. The Company's capital
requirements relate primarily to expenditures for electric generation, including
the 1996 replacement of its Ginna steam generators, transmission and
distribution facilities, and gas mains and services as well as the repayment of
existing debt. The Company has no current plans to install additional baseload
generation.
Total 1996 capital requirements are currently estimated at $168 million,
of which $150 million is for construction, including replacement of the steam
generators at the Ginna Nuclear Plant and $18 million is for securities
maturities, which were paid on May 1, 1996. Approximately $97 million had been
expended for construction as of September 30, 1996, reflecting primarily
expenditures for steam generator replacement and nuclear fuel, upgrading
electric generating, transmission and distribution facilities and gas mains.
Ginna Steam Generator Replacement. Preparation for replacement of the
two steam generators at the Ginna Nuclear Plant began in 1993 and continued
until the 70-day replacement outage ended on June 10, 1996. Improved plant
efficiency will allow the plant to recapture output capacity that had been lost
due to the declining performance of the former generators. Cost of the
replacement is approximately $112 million, about $40 million for the steam
generators, about $50 million for the installation and the remainder for Company
engineering, radiation protection, plant support, other services and finance
charges. In the first nine months, the Company spent $43 million of a planned
$50 million for 1996 on this project. The PSC order approving this project
provides that certain costs over $115 million, and savings under that amount,
will be shared between the Company and its customers but the Company does not
expect to exceed that amount.
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/Besicorp Allegheny L.P. (Kamine) for approximately 55 megawatts of
capacity, the circumstances
15
of which are discussed in Note 2 and in the Company's 1995 Form 10-K under Item
8, Note 10 of the Notes to Financial Statements. The Kamine contract and the
outcome of related litigation will have an important impact on the Company's
electric rates and its ability to function effectively in a competitive
environment. The Company has no other long-term obligations to purchase energy
from Qualifying Facilities.
Sale of Interest in Empire State Pipeline. In September, 1996 the
Company's wholly owned subsidiary, Energyline Corporation, sold its 20%
ownership interest in the Empire State Pipeline to the other co-tenants,
subsidiaries of The Coastal Corporation and Westcoast Energy Inc. The Company
will remain a customer of Empire, which commenced operation in November 1993.
The sale of Empire did not have a material impact on the Company's financial
condition.
The Company invested in Empire in 1992 because it believed there was a
need for access to an alternative supply of natural gas for its customers and
that meeting their need would best be achieved by its direct investment in the
pipeline. The Company's achievement of that goal and its current strategic
business decision to concentrate on delivering energy and energy services
directly to customers are the reasons for Energyline's decision to sell its
equity interest in Empire.
REDEMPTION OF SECURITIES. On March 7, 1996, the Company redeemed $49
million principal amount of its First Mortgage 8 3/8% Bonds, Series CC at
103.18% plus accrued interest from September 15, 1995. On May 1, 1996, the
Company redeemed $332 thousand of its First Mortgage 8% Bonds, Series Y at the
special redemption price of 100.17% plus accrued interest from February 15, 1996
under sinking and improvement fund provisions of its General Mortgage. On May 1,
1996, the Company also redeemed at maturity $18 million principal amount of its
First Mortgage 5.30% Bonds, Series V.
FINANCING. (See Form 10-K for the fiscal year ended December 31, 1995,
Item 8. Note 9. Short-Term Debt, regarding the Company's short-term borrowing
arrangements.)
During the first nine months of 1996, the Company issued 398,301 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 $8.6 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, 1996 the Company had Common Stock
available for issuance of 1,026,840 shares under the ADR Plan and 129,664 shares
under the Savings Plus Plan. In July, the Company began providing for ADR Plan
and Savings Plus Plan requirements through the purchase of shares on the open
market.
CAPITAL STRUCTURE. The Company's retained earnings at September 30, 1996
were $87.7 million, an increase of approximately $17.3 million compared with
December 31, 1995. The amount of long term debt (including due within one year)
decreased $67.3 million at September 30, 1996 as compared with December 31, 1995
due to the redemption of First Mortgage Bonds discussed above. Common equity
increased approximately $25.9 million, reflecting an increase in retained
earnings and the issuance and sale of Common Stock as discussed under
"Financing". Capitalization at September 30, 1996 was comprised of 47.5 percent
common equity, 7.7 percent preferred equity and 45.1 percent long-term debt. 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.
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-month periods
16
ended September 30, 1996 to the three-month and nine-month periods ended
September 30, 1995.
A summary of changes in Electric and Gas Department revenues and
expenses is shown below:
(Millions of Dollars)
Three Months Nine Months
Ended Sept.30 Ended Sept.30
------------- -------------
1995 Earnings $25.1 $66.7
Increase (decrease) in earnings:
Electric margin (revenue less fuel) 0.4 3.6
- Includes effect of 7/1/96 rate decrease
- Consumption changes including weather
- Changes in sales to other electric utilities
- Expense reductions
Gas margin (revenue less fuel) (2.2) 18.4
- Consumption changes including weather
- Expense reductions
Maintenance associated with 1996 Ginna outage -- (1.7)
Reserve for doubtful accounts (0.3) (5.7)
Payroll changes (1.2) (6.5)
- Amortization of early retirement program
- Ongoing outplacement program
- Improved employee performance
Miscellaneous non-fuel O&M (1.5) (2.3)
Depreciation and amortization (6.1) (8.5)
Net federal income tax effects 2.2 (2.6)
Local and state tax effects 1.1 1.6
Other income and deductions effects 0.8 5.2
Interest Savings 0.9 1.5
- Redeemed 8 3/8% series CC bonds 3/7/96
- Matured 5.3% series V bonds 5/1/96
----- -----
1996 Earnings $19.2 $69.7
OPERATING REVENUES AND SALES. Total operating revenues for the first
nine months of 1996 were $33.9 million or 5% above the first nine months of
1995. The higher revenues resulted from the impact of an extended period of
cold weather on electric and gas sales this year, compared to the revenue effect
of unusually warm weather in the first quarter of 1995, as well as higher
revenue stemming from purchased gas costs offset by lower electric fuel and
purchased electricity costs and cooler 1996 summer weather.
Total operating revenues for the third quarter were $10.3 million or
4% below the third quarter last year, reflecting lower electric revenues due to
lower fuel costs, a rate decrease effective July 1, 1996 and the cooler 1996
summer weather.
17
FUEL EXPENSES. Total fuel expenses increased in the nine-month
comparison period reflecting mainly higher gas purchased for resale expense in
1996 driven by higher volumes of purchased gas resulting from colder than normal
weather as well as higher commodity costs offset by lower electric fuel costs
due to less generation and purchases. Additionally, the unit cost for purchased
electricity was lower because the Company stopped purchasing high cost
electricity from Kamine in 1996. Effective July 1, 1996 electric revenues
collected through the fuel cost adjustment have been eliminated.
Total fuel expenses decreased in the third quarter comparison period
reflecting lower electric fuel costs as described above.
OPERATIONS EXCLUDING FUEL EXPENSES. The increases in operations
excluding fuel expenses in both comparison periods reflect mainly the timing for
recording lump sum payroll performance incentives, employee
redeployment/outplacement costs, an increase in the reserve for doubtful
accounts and, for the nine-month comparison period, amortization of additional
early retirement costs. While doubtful accounts have been a problem, the
Company is dealing with this issue in a manner that looks toward a more
competitive environment with limits on the ability to pass those costs along as
rate increases. The Company is also taking more aggressive steps to improve its
collection efforts.
DEPRECIATION AND AMORTIZATION. Depreciation and amortization increased
due mainly to an increase in depreciable plant.
TAXES. The decrease in local, state and other taxes in the first nine
months of 1996 reflects mainly lower property taxes due to decreases in
assessments. The decrease in local, state and other taxes for the third quarter
comparison period reflects mainly lower property, sales and revenue taxes.
The variances in federal income tax in both comparison periods reflect
mainly changes in pretax income.
OTHER STATEMENT OF INCOME ITEMS. The net decreases in allowance for
funds used during construction (AFUDC) in both comparison periods reflect mainly
decreases in the amount of utility plant under construction. Other Income and
Deductions, Other-net increased mainly due to the elimination in 1996 of two
1995 expense items, depreciation expense for the Empire State Pipeline which was
sold and amortization of certain early retirement costs. Interest charges
decreased reflecting lower amounts of long term debt outstanding (see
"Redemption of Securities").
COMMON STOCK DIVIDEND. On September 18, 1996, the Board of Directors
authorized a common stock dividend of $.45 per share, which was paid on October
25, 1996 to shareholders of record on October 2, 1996. 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 and Management's Discussion and Analysis of
Financial Condition and Results of Operations.
18
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K: None
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: November 12, 1996 By J.B. STOKES
-----------------------------------------
J. Burt Stokes
Senior Vice President, Corporate Services
and Chief Financial Officer
(Duly Authorized Officer)
Date: November 12, 1996 By DANIEL J. BAIER
-----------------------------------------
Daniel J. Baier
Controller
(Principal Accounting Officer)
19