SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1997
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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 April 30, 1997: 38,851,464
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INDEX
Page No.
PART I - FINANCIAL INFORMATION
Consolidated Balance Sheet - March 31,1997 and
December 31, 1996................................... 1 - 2
Consolidated Statement of Income - Three Months Ended
March 31, 1997 and 1996.............................. 3
Consolidated Statement of Cash Flows - Three Months
Ended March 31, 1997 and 1996....................... 4
Notes to Financial Statements.......................... 5 - 7
Management's Discussion and Analysis of Financial
Condition and Results of Operations................. 7 -16
PART II - OTHER INFORMATION
Legal Proceedings...................................... 16
Submission of Matters to a Vote of Security Holders.... 16
Exhibits and Reports on Form 8-K....................... 17
Signatures............................................. 18
PART I - FINANCIAL INFORMATION
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ITEM 1. FINANCIAL STATEMENTS
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
March 31, December 31,
Assets 1997 1996
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Utility Plant
Electric $2,424,058 $2,413,881
Gas 395,524 391,231
Common 131,639 129,946
Nuclear fuel 226,141 224,701
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3,177,362 3,159,759
Less: Accumulated depreciation 1,408,812 1,381,908
Nuclear fuel amortization 191,783 187,170
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1,576,767 1,590,681
Construction work in progress 62,667 69,711
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Net Utility Plant 1,639,434 1,660,392
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Current Assets
Cash and cash equivalents 86,281 21,301
Accounts receivable, net of allowance for
doubtful accounts: 1997 - $19,400, 1996 - $17,500 139,076 112,908
Unbilled revenue receivable 46,064 53,261
Materials, supplies and fuels, at average cost 17,594 39,888
Prepayments 33,656 23,103
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Total Current Assets 322,671 250,461
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Deferred Debits
Nuclear generating plant decommissioning fund 96,160 91,195
Nine Mile Two deferred costs 31,097 31,360
Unamortized debt expense 14,443 14,820
Other deferred debits 27,137 28,759
Regulatory assets (Note 2): 258,859 284,489
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Total Deferred Debits 427,696 450,623
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Total Assets $2,389,801 $2,361,476
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The accompanying notes are an integral part of the financial statements.
1
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
March 31, December 31,
Capitalization and Liabilities 1997 1996
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Capitalization
Long term debt - mortgage bonds $ 555,067 $ 555,054
- 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 45,000
Common shareholders' equity:
Common stock
Authorized 50,000,000 shares; 38,851,464
shares outstanding at March 31, 1997
and 38,851,464 shares outstanding at
December 31, 1996. 696,017 696,019
Retained earnings 112,785 90,540
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Total common shareholders' equity 808,802 786,559
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Total Capitalization 1,567,769 1,545,513
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Long Term Liabilities (Department of Energy)
Nuclear waste disposal 80,089 79,057
Uranium enrichment decommissioning 14,786 14,695
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Total Long Term Liabilities 94,875 93,752
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Current Liabilities
Long term debt due within one year 20,000 20,000
Preferred stock redeemable within one year 10,000 10,000
Short term debt -- 14,000
Accounts payable 41,487 49,462
Dividends payable 19,187 19,349
Taxes accrued 40,539 4,694
Interest accrued 14,467 10,317
Other 29,467 30,395
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Total Current Liabilities 175,147 158,217
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Deferred Credits and Other Liabilities
Accumulated deferred income taxes 355,383 370,028
Pension costs accrued 69,688 69,806
Other 126,939 124,160
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Total Deferred Credits and Other Liabilities 552,010 563,994
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Commitments and Other Matters (Note 2) -- --
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Total Capitalization and Liabilities $2,389,801 $2,361,476
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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
March 31,
1997 1996
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Operating Revenues
Electric $174,063 $170,508
Gas 136,993 131,816
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311,056 302,324
Electric sales to other utilities 3,789 6,871
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Total Operating Revenues 314,845 309,195
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Fuel Expenses
Fuel for electric generation 10,832 11,112
Purchased electricity 4,884 8,951
Gas purchased for resale 79,355 71,759
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Total Fuel Expenses 95,071 91,822
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Operating Revenue less Fuel Expenses 219,774 217,373
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Other Operating Expenses
Operations excluding fuel expenses 64,194 61,602
Maintenance 11,530 9,512
Depreciation and amortization 29,212 23,489
Taxes - local, state and other 34,967 36,507
Federal income tax 24,677 29,397
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Total Other Operating Expenses 164,580 160,507
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Operating Income 55,194 56,866
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Other Income and Deductions
Allowance for other funds
used during construction 71 245
Federal income tax 763 598
Other - net (1,184) 320
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Total Other Income and Deductions (350) 1,163
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Income before Interest Charges 54,844 58,029
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Interest Charges
Long term debt 11,853 12,877
Other - net 1,672 3,382
Allowance for borrowed funds
used during construction (114) (719)
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Total Interest Charges 13,411 15,540
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Net Income 41,433 42,489
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Dividends on Preferred Stock 1,704 1,866
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Earnings Applicable to Common Stock $39,729 $40,623
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Weighted average number of shares
outstanding in each period (000's) 38,851 38,577
Earnings per Common Share $1.02 $1.05
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 CASH FLOWS
(Unaudited)
Three Months Ended
(Thousands of Dollars) March 31,
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1997 1996*
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CASH FLOW FROM OPERATING ACTIVITIES
Net income $ 41,433 $ 42,489
Adjustments to reconcile net income to net cash flow provided
from operating activities:
Depreciation and amortization 34,047 28,865
Deferred fuel 14,165 25,155
Deferred income taxes (10,356) (6,385)
Allowance for funds used during construction (185) (964)
Unbilled revenue, net 7,197 9,434
Nuclear generating plant decommissioning fund (5,031) (2,252)
Pension costs accrued (1,417) (1,022)
Post employment benefit internal reserve 2,580 1,598
Changes in certain current assets and liabilities:
Accounts receivable (26,168) (34,813)
Materials, supplies and fuels 22,294 21,803
Taxes accrued 35,845 33,943
Accounts payable (7,975) (3,644)
Other current assets and liabilities, net (5,434) (11,635)
Other, net 11,240 (2,043)
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Total Operating $ 112,235 $ 100,529
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CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant $ (12,006) $ (37,286)
Other, net -- (14)
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Total Investing $ (12,006) $ (37,300)
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CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/issuance of common stock $ -- $ 4,214
Short term borrowings (14,000) --
Retirement of long term debt -- (49,000)
Dividends paid on preferred stock (1,866) (1,866)
Dividends paid on common stock (17,483) (17,304)
Other, net (1,900) 1,061
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Total Financing $ (35,249) $ (62,895)
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Increase in cash and cash equivalents $ 64,980 $ 334
Cash and cash equivalents at beginning of period $ 21,301 $ 44,121
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Cash and cash equivalents at end of period $ 86,281 $ 44,455
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Three Months Ended
March 31,
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(Thousands of Dollars) 1997 1996
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Cash Paid During the Period
Interest paid (net of capitalized amount) $ 8,870 $ 10,075
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Income taxes paid $ -- $ 8,000
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* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
4
ROCHESTER GAS AND ELECTRIC CORPORATION
NOTES TO FINANCIAL STATEMENTS
Note 1: GENERAL
The Company, in the opinion of management, has included adjustments (which
include normal recurring adjustments) necessary for a fair statement of the
results of operations for the interim periods presented. The consolidated
financial statements for 1997 are subject to adjustment at the end of the year
when they will be audited by independent accountants. The preparation of
financial statements requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates. The
results for these interim periods are not necessarily indicative of results to
be expected for the year, due to seasonal, operating, and other factors. These
financial statements should be read in conjunction with the financial statements
and notes thereto contained in the Company's Annual Report on Form 10-K for the
year ended December 31, 1996.
Note 2. COMMITMENTS AND OTHER MATTERS
The following matters supplement the information contained in Note 10 to
the financial statements included in the Company's Annual Report on Form 10-K
for the year ended December 31, 1996 and should be read in conjunction with the
material contained in that Note.
LITIGATION WITH CO-GENERATOR
The Company is engaged in litigation with Kamine/Besicorp Allegany L.P.
(Kamine), the only co-generator operating in its service territory. The details
of the litigation, involving several different proceedings, are described in
Note 10 of the Company's 1996 Annual Report on Form 10-K. One of the complaints
served by Kamine seeks damages in the amount of $420,000,000.
There have been two developments in these proceedings since the filing of the
1996 Annual Report on Form 10-K. In the Action in the United States District
Court for the Western District of New York, Kamine had filed a notice of appeal
from a decision denying Kamine's motion for a preliminary injunction. Kamine
subsequently withdrew the appeal.
In November 1995 Kamine filed in Newark, New Jersey for protection under the
bankruptcy laws and filed a complaint in an adversary proceeding seeking, among
other things, specific performance of the agreement to sell power to the
Company. Kamine filed a motion to compel the Company to pay what would be due
under Kamine's view of the terms of that agreement during the pendency of the
Adversary Proceeding. After hearing, the Bankruptcy Court denied that motion.
The Court also denied various motions made by the Company to change the venue of
the proceeding to New York State and to lift the automatic stay of the pending
New York State action. On appeal, the Bankruptcy Court was reversed and the
case sent back to the Bankruptcy Court to decide where the contract issues in
the Adversary Proceeding should be adjudicated.
On March 19, 1997, the Bankruptcy Court stayed the Adversary Proceeding
pending resolution of the contract issues in the New York State court trial. On
March 31, 1997, Kamine filed notice with the District Court that they will
appeal the Bankruptcy Court's March 19 Order. On May 6, 1997, Kamine advised the
District Court that it was withdrawing its appeal.
Numerous other procedural motions have been presented in the Bankruptcy Court,
some of which may now be considered by the New York State court. While these
procedural issues are pending, the Company would pay approximately two cents per
kilowatt hour when the plant operates. It is not operating at the present time.
5
FERC 636 TRANSITION COSTS
As a result of the restructuring of the gas transportation industry by the
Federal Energy Regulatory Commission (FERC) pursuant to Order No. 636 and
related decisions, the Company was required to pay a share of certain transition
costs incurred by the interstate pipelines through which it has purchased gas.
The Company, as a customer, estimated total costs of about $40-45 million which,
for the most part, have been paid to its suppliers. The pipeline with the
largest transition cost liability has reached a negotiated settlement with its
customers, including the Company. This settlement agreement, filed with the
FERC and awaiting FERC approval, would resolve the last transition cost case.
Under the settlement, transition costs will be paid for an additional 24 months,
then cease. A regulatory asset and related deferred credit have been
established on the balance sheet to account for these costs. Approximately
$41.4 million of these costs were paid to suppliers, of which about $33.5
million has been included in purchased gas costs. At March 31, 1997, $29.7
million remains deferred for future collection from customers. The Company has
a $10 million credit agreement with a domestic bank to provide funds for the
Company's transition cost liability to CNG Transmission Corporation. At March
31, 1997 the Company had $7.9 million of borrowings outstanding under the credit
agreement. The Company is collecting those costs through the Gas Cost
Adjustment clause in its rates.
SPENT NUCLEAR FUEL LITIGATION
The Nuclear Waste Act obligates the United States Department of Energy (DOE)
to accept for disposal spent nuclear fuel (SNF) starting in 1998. Since the
mid-1980s the Company and other nuclear plant owners and operators have paid
substantial fees to the DOE to fund its obligations under the Nuclear Waste Act.
DOE has indicated that it will not be in a position to accept SNF in 1998. On
June 20, 1994, Northern States Power Company and other owners and operators of
nuclear power plants filed suit against DOE and the U.S. in the U.S. Court of
Appeals for the District of Columbia Circuit seeking a declaration that DOE is
violating its obligation to begin accepting and disposing of such waste,
requiring DOE to report progress thereon and requesting other relief. In a July
1996 decision, the court upheld the utilities' position that DOE is obligated to
accept and dispose of the utilities' SNF beginning not later than January 31,
1998. DOE had contended in effect that it could defer the disposal until the
availability of a suitable SNF repository. The court rejected this DOE reading
of the Nuclear Waste Act, but stopped short of providing the utilities a remedy
since DOE has not yet defaulted on its obligations. By letter dated December
17, 1996, DOE invited the parties to the proceeding to provide written comments
on how DOE's anticipated inability to meet its January 31, 1998 obligation to
begin accepting SNF could "best be accommodated". The Company and a number of
other parties have responded to that invitation. By Joint Petition for Review,
dated January 31, 1997, the Company and a number of other nuclear utilities
petitioned the United States Court of Appeals for the District of Columbia
Circuit for a declaration that the Petitioners are relieved of the obligation to
pay fees into the Nuclear Waste Fund, and authorized to place those fees into
escrow when and until DOE commences disposing of SNF. The Petition further
requests that DOE be ordered to develop a program that will enable it to begin
acceptance of SNF by January 31, 1998.
REGULATORY AND STRANDABLE ASSETS
With PSC approval the Company has deferred certain costs rather than recognize
them on its books when incurred. Such deferred costs are then recognized as
expenses when they are included in rates and recovered from customers. Such
deferral 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,
6
where all prudently incurred costs are recovered through rates. In a purely
competitive pricing environment, such costs might not have been incurred and
could not have been deferred. Accordingly, if the Company's rate setting was
changed from a cost-of-service approach, and it was no longer allowed to defer
these costs under SFAS-71, these assets would be adjusted for any impairment to
recovery (pursuant to Financial Accounting Standards No. 121 (SFAS-121)). In
certain cases, the entire amount could be written off.
SFAS-121,"Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to be Disposed Of", requires write-down of assets whenever events
or circumstances occur which indicate that the carrying amount of a long-lived
asset may not be fully recoverable.
Below is a summarization of the Regulatory Assets as of March 31, 1997.
Millions
of Dollars
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Income Taxes $170.3
Uranium Enrichment Decommissioning Deferral 17.3
Deferred Ice Storm Charges 13.4
FERC 636 Transition Costs 29.7
Demand Side Management Costs Deferred 7.2
Other, net 20.9
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Total - Regulatory Assets $258.8
======
See the Company's Form 10-K for the fiscal year ended December 31,
1996 Item 8, Note 10 of the Notes to Financial Statements, "Regulatory and
Strandable Assets" for a description of the Regulatory Assets shown above.
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 March 31, 1997
cannot be determined at this time, but could be significant. Strandable assets,
if any, would be written down for impairment of recovery in the same manner as
deferred cost discussed above.
At March 31, 1997 the Company believes that its Regulatory and
Strandable Assets, if any, are not impaired and are probable of recovery,
although no such assurance can be given.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following is Management's assessment of certain significant factors
affecting the financial condition and operating results of the Company. This
assessment contains forward-looking statements which are subject to various
risks and uncertainties. The Company's actual results could differ from those
anticipated in such forward-looking statements as a result of numerous factors
which may be beyond the Company's control by reason of factors such as electric
and gas utility restructuring, future economic conditions and developments in
the legislative, regulatory and competitive markets in which the Company
operates. Shown below is a listing of the principal items discussed.
7
Earnings Summary Page 8
Competition Page 9
PSC Competitive Opportunities Case Settlement
FERC Open Transmission Orders
PSC Gas Restructuring Case
Rates and Regulatory Matters Page 13
1996 Rate Settlement
1995 Gas Settlement
Liquidity and Capital Resources Page 13
Projected Capital and Other Requirements
Redemption of Securities
Financing
Capital Structure
Results of Operations Page 14
Operating Revenues and Sales
Operating Expenses
Dividend Policy Page 16
EARNINGS SUMMARY
Earnings per common share for the current and prior year three month
periods ended March 31, are as follows:
1997 1996
Earnings per share $1.02 $1.05
In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128 ("SFAS-128"), "Earnings per
Share," which changes the methodology of calculating earnings per share. Had
the Company adopted SFAS-128 during the first quarter the impact on earnings
would not have been significant.
First quarter earnings were slightly lower in 1997 due to weather being
about 8% warmer and lower electric rates. Total gas sales were down about 8%
for the quarter. Partially reducing the earnings decline was approximately 2%
growth in electric sales to customers for the quarter.
Future earnings may be affected by a proposed settlement with the
staff of the New York State Public Service Commission (PSC) and other parties on
a five-year transition to competition which, among other things, reduces rates
and allows the Company to pursue new business opportunities. The Competitive
Opportunities Settlement (see description below) requires approval of the PSC.
The nature and magnitude of the potential impact of any proposals ultimately
adopted by the PSC on the business of the Company will depend on the specific
details of any plan for increased competition and resolution of the complex
issues involved, especially competition at the retail level.
Future earnings will be affected, in part, by the Company's degree of
success in remarketing its excess gas capacity as set under the terms of the
1995 Gas Settlement and in controlling its local gas distribution costs. The
Company believes it will be successful in meeting the 1995 Gas Settlement
targets over the remaining two years of the Settlement period, although no
assurance can be given.
8
COMPETITION
See the Company's Form 10-K for the fiscal year ended December 31, 1996,
Item 7.- "Competition" for a discussion of the PSC gas restructuring case,
formation of a joint nuclear operating company and the Company's business
strategy . See Note 2 of the Notes to Financial Statements for a discussion of
regulatory and strandable assets and related accounting issues.
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. By Opinion No. 96-12
issued May 20, 1996 in the "Competitive Opportunities Proceeding," the PSC
endorsed a fundamental restructuring of the electric utility industry in the
State. Among other elements, the PSC's goals included lower rates for consumers
and increased customer choice in obtaining electricity and other energy
services.
On April 8, 1997, the Company, the PSC Staff ("Staff") and other parties
entered into a Settlement Agreement dated April 8, 1997 (the "Settlement") with
regard to the Competitive Opportunities Proceeding.
Summary. The Settlement, which is subject to PSC approval, provides for
a transition to competition during the five-year term of the Settlement (July 1,
1997 through June 30, 2002). The Settlement would establish the Company's
electric rates for each annual period commencing July 1 ("Rate Year") during the
term. A Retail Access Program will be phased in, allowing customers to purchase
electricity, and later electricity and capacity commitments, from sources other
than the Company. During the term, the Company's non-nuclear generating sources
(fossil-fuel, hydro, gas-turbine generation and purchased power contracts,
excluding Kamine) will be required to compete in the market. The Company will
be provided a reasonable opportunity to recover prudently incurred costs,
including those pertaining to generation and purchased power.
The Settlement also requires the Company to functionally separate its
component operations: distribution, generation, and retailing. The Company
would be required to separate, structurally, any unregulated retail operations
from the remainder of the regulated utility functions. In addition, the Company
would have the option to establish a holding company structure and to utilize
certain funds derived from rendering utility service for unregulated operations.
The Settlement requires neither divestiture of generating or other assets, nor
writing off of "stranded costs" (the above-market costs, presumed to result from
competition).
The Settlement will be the subject of PSC examination to determine
whether it is in the public interest. A PSC decision regarding the Settlement
is expected by mid-1997.
The Company believes that the Settlement Agreement will not adversely
affect its eligibility to continue to apply SFAS-71. If, contrary to the
Company's view, such eligibility were adversely affected, a material write-down
of assets, the amount of which is not presently determinable, could be required.
Rate Plan. Subject to certain conditions, the Rate Plan contained in the
Settlement continues and augments the rate reductions provided for in the
Company's 1996 settlement ("the 1996 Settlement") approved by the PSC. Over the
five rate years of the term, the cumulative rate reductions will be as follows:
Rate Year 1: $3.5 million; Rate Year 2: $10.5 million; Rate Year 3: $22.6
million; Rate Year 4: $32.2 million; and Rate Year 5: $34.8 million. To the
extent that "Mandates" (i.e., governmentally required and external costs imposed
----
on the Company) are reduced, the foregoing reductions may increase in Rate Years
2 through 5.
The Rate Plan permits the Company to offset against the foregoing total
-----
reductions certain amounts related to a Purchase Power Agreement with Kamine
which is the subject of substantial litigation described in Item 1, Financial
Statements under the caption "Litigation with Co-Generator" in Note 2,
Commitments and Other Matters. To provide for possible settlement of the Kamine
litigation, the Rate Plan permits the
9
Company to make the following offsets, by "Rate Year": Rate Year 2: $3.5
million; Rate Year 3: $8.5 million; Rate Year 4: and following (until payment is
completed): $10.6 million. The Settlement also would permit the Company to
recover the full amount of any difference between Kamine costs currently
included in rates and any increased amount resulting from enforcement of the
purported PPA or judicially required payments. Seven-eighths of this difference
may be added, on a current basis, to the amount already included in rates.
Amounts not currently recovered may be deferred for future recovery.
The Settlement permits recovery of inflation-based increases to certain
Operation and Maintenance ("O&M") expenses above 4.0 percent, permits the
Company to retain a portion of property tax decreases, and allows the Company to
recover the costs of certain Mandates to be included in a "System Benefits
Charge" and to recover others to the extent they exceed a $2.5 million
threshold. The Company also would be permitted to recover the costs of
Catastrophic Events and Competition Implementation Costs (i.e., the cost of
----
transition) to the extent they exceed the same threshold. Low-income and service
quality programs, established in prior proceedings would continue in much their
same form. The maximum service quality penalty, however, would be reduced to
$1.25 million per year.
In the event that the Company earns a return on common equity in excess
of 11.80 percent, the Company would be entitled to retain 50 percent of the
excess and to use the remaining 50 percent to write down accumulated deferred
costs or investment in electric plant and Regulatory Assets (which are deferred
costs whose classification as an asset on the balance sheet is permitted by
SFAS-71). If the Company's rate of return on common equity falls below 8.5
percent or increases above 14.5 percent, or if the pre-tax interest coverage
falls below 2.5 times, or if certain governmental actions occur which cannot
adequately be addressed by the Settlement as it pertains to Mandates, either the
Company or any party to the Settlement would have the right to petition the PSC
for review of the Settlement and appropriate remedial action.
Retail Access. Over the five-year term of the Settlement, the Company
will phase in a Retail Access Program that will permit customers to purchase
their own electricity and capacity from alternative suppliers. Assuming that
certain operational requirements are met and certain governmental approvals are
in place, on July 1, 1998, customers whose electric loads total 670
Gigawatthours ("GWH") (representing approximately 10 percent of the Company's
total annual Retail Sales) will be eligible to purchase electricity (but not
capacity commitments) from alternative suppliers. On July 1, 1999, customers
with loads totaling up to 1,300 GWH (approximately 20 percent of total Sales)
will be eligible to purchase energy and capacity commitments from alternative
suppliers. As of July 1, 2000, aggregate customer load of up to 2,000 GWH
(approximately 30 percent of total Sales) will be eligible; and, as of July 1,
2001, up to 3,000 GWH (approximately 46 percent of total Sales) will be
eligible. The cited amounts eligible for retail access would be increased for
growth in retail sales above 6,714 GWH. As of July 1, 2002, all retail customers
will be eligible to purchase energy and capacity from alternative suppliers.
Under the Retail Access Program, delivery of electricity will continue to
be through The Company's distribution system. The schedule for implementation
of the "Energy and Capacity" stage of the Program (commencing July 1, 1999)
assumes that a Statewide Energy and Capacity Market will be in place by July 1,
1998. If the operation of that Market is delayed, the Company may petition the
PSC for a delay in implementation of the Energy and Capacity stage.
During the initial, energy only stage of the Retail Access Program, the
Company delivery rate will generally equal the rate for fully bundled service
less the average non-nuclear fuel and purchased power cost of the electric
commodity. During the energy and capacity stage, the rate will generally equal
the bundled rate less the cost of the electric commodity and the Company's non-
nuclear generating capacity. These commodity and capacity costs, generally
referred to as "contestable costs," are estimated to be $.032 per kilowatt hour
("KWH").
The Company would not be required to divest any of its generation
facilities. Instead, the phasing-in of the Retail Access Program subjects the
Company's generation
10
to competition from the market in increments, as described above. "Sunk Costs",
the investment in electric plant as of March 1, 1997, would be included in
electric distribution tariff rates during the term of the Settlement. Future
rate treatment of such costs is to be consistent with the principle that the
Company is to have a reasonable opportunity to recover such costs.
"To-Go Costs" of the Company's non-nuclear resources (i.e., capital costs
----
incurred after February 28, 1997, operation and maintenance expenses, and
property, payroll and other taxes) are to be recovered through the distribution
access tariff. The fixed portion of To-Go Costs would be recovered in full
through the distribution access tariff until July 1, 1999 and subject to the
market thereafter in accordance with the phase-in schedule for the Retail Access
program described above. The variable portion of non-nuclear To-Go Costs would
also be subject to the market in accordance with the phase-in Schedule described
above. Upon extension of eligibility for the Retail Access Program to all
retail customers on July 1, 2002, the Company would be authorized to modify its
distribution access rates, so as to hold constant the degree to which its To-Go
Costs are at risk for recovery through the market. Thus, while the recovery of
non-nuclear To-Go Costs would continue to be through the market, recovery of
nuclear costs would remain recoverable through regulated rates. If, during the
operation of the Energy and Capacity Stage of the Retail Access Program, the
market price of energy and capacity exceeds an average of 3.2 cents per KWH, the
pace of the Retail Access Program implementation schedule could, after
discussion among the Settlement parties, be accelerated.
During at least the first two and one-half years of the Settlement, all
prudently incurred costs associated with the Ginna nuclear plant and the
Company's share of the Nine Mile Point 2 nuclear facility would be recovered
through regulated retail rates. Future rate treatment of Nine Mile Point 2
would be determined through good faith negotiations among the Company, Staff and
the other co-tenants of the facility. It is expected that rate treatment of
Ginna would be similar. No change in such treatment of nuclear facilities may
be implemented prior to January 1, 2000. Shutdown and decommissioning costs
would be recovered during the term of the Settlement in a manner consistent with
past ratemaking treatment.
Corporate Structure. The Settlement envisions, and authorizes the
Company to form, a holding company ("HOLDCO") structure and provides standards
of conduct to govern relationships among affiliated entities within that
structure. Formation of the HOLDCO would require a separate petition to the
PSC, a form of which is appended to the Settlement, and approval by
shareholders, the Securities and Exchange Commission, the Federal Energy
Regulatory Commission ("FERC") and the Nuclear Regulatory Commission.
The Settlement would authorize the Company to initially fund its
unregulated activities, whether conducted through a HOLDCO or otherwise, with
$50 million and would not require a separate authorization by the PSC for such
investment.
Miscellaneous. Upon approval of the Settlement by the PSC, the Company
would withdraw from an appeal challenging the PSC's Opinion No. 96-12 and would
terminate its petition seeking judicial review of the PSC's decision regarding
the settlement in the previous electric rate proceeding (the 1996 Rate
Settlement). The present Settlement would, upon approval, supersede the 1996
Rate Settlement. Various incentive and penalty provisions in the 1996 Rate
Settlement would be eliminated.
FERC OPEN TRANSMISSION ORDERS. In early 1996 FERC issued new rules to
facilitate the development of competitive wholesale markets by requiring
electric utilities to offer "open-access" transmission service on a non-
discriminatory basis in tariffs. The Company filed its required transmission
service tariff on July 9, 1996. The new tariff would apply to wholesale
purchases and sales made by the Company and the financial impact will depend on
prevailing energy prices in the wholesale market. The near-term impacts of this
tariff are not expected to be significant. On March 6, 1997, the Company
reached a settlement in principle with the other parties respecting rate issues.
On March 21, 1997, the Company filed the Offer of Settlement with the
Administrative Law Judge (ALJ). The Offer of Settlement was certified by the
ALJ on April 14, 1997.
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In December 1996 the Company and other New York utilities submitted a
compliance filing with FERC in accordance with the requirements of the FERC's
"open-access" order. In order to support the FERC's "open access" order, the
utilities also established a centralized transmission service information
network, which went on-line in early January 1997. This "open access same-time
information system" (OASIS) enables wholesale customers of New York State's bulk
power system to obtain timely information regarding transmission service
availability and pricing via the Internet.
On January 31, 1997, the utilities filed a "Comprehensive Proposal To
Restructure the New York Wholesale Electric Market" with the FERC. As proposed,
the existing New York Power Pool ("NYPP") will be dissolved and the independent
system operator (ISO) will administer a state-wide open access tariff and
provide for the short-term reliable operation of the bulk power system in the
state. In addition to proposing a FERC-endorsed ISO, the proposal calls for
creation of a New York Power Exchange ("NYPEx") and a New York State
Reliability Council ("NYSRC").
The NYPEx is a voluntary organization intended to facilitate development
of an active wholesale market by providing facilities and procedures to offer
energy for sale and to make energy purchases. As proposed, generators of
electricity could submit bids to sell energy to, and load serving entities could
submit bids to buy energy from, the NYPEx or any other power exchange. Each
power exchange would then submit its delivery schedules to the ISO which would
review them for feasibility and reliability. The energy market would use a
"locational-based marginal pricing" mechanism that takes into account
transmission limitations. Generators would also have the opportunity to enter
into bilateral contracts for electricity. The NYSRC is an organization formed by
the existing eight transmission providers in New York plus three representatives
of other market participants (buyers, sellers, and consumer/environmental
groups). The role of the NYSRC would be to establish general reliability
standards that the ISO would use to establish day-to-day operating procedures.
The proposed NYSRC is viewed by the transmission providers as an
essential prerequisite to transferring control of their transmission facilities
to the ISO. The NYPP member systems believe that the combination of an ISO with
day-to-day operational responsibility and the NYSRC with limited authority to
establish basic reliability standards on a long-term basis provides a balanced
structure to resolve the inherent tension between maintaining current system
reliability and maximizing the commercial use of transmission facilities by an
increased number of market participants.
Significant changes to pricing procedures now in effect within NYPP are
expected, but it is unclear what effect these changes may have once other
regulatory changes in New York State are implemented. At the present time, the
Company cannot predict what effects regulations ultimately adopted by FERC will
have, if any, on future operations of the financial condition of the Company.
PSC GAS RESTRUCTURING CASE. In March 1996 the PSC issued an Order and
approved utility restructuring plans designed to open up the local natural gas
market to competition and thereby allow residential, small business and
commercial/industrial users the same ability to purchase their gas supplies from
a variety of sources, other than the local utility, that larger industrial
customers already have. During a three-year phase-in period the State's gas
utilities would be permitted to require customers converting from sales service
to take associated pipeline capacity for which the utilities had originally
contracted. The PSC has indicated that it will address the issue of how the
costs of such capacity would be recovered after the three-year period during the
third year of the phase-in period. Under two new gas transportation tariffs,
gas customers have a choice of suppliers beginning November 1, 1996. The
Company will distribute the gas and charge for the distribution as well as
associated services. The Company believes its position in the market is such
that it will maintain its distribution system margins. Under a phase-in
limitation, loss of gas commodity sales may be limited to five percent of the
Company's annual gas volume the first year, and then five additional percent for
each of the following two years. The phase-in will be reviewed as experience is
gained with the program. The Company
12
anticipates that the use of transportation gas service will increase; however,
through March 31, 1997 no customers were being served under this new service.
RATES AND REGULATORY MATTERS
1996 ELECTRIC RATE SETTLEMENT. The PSC approved a Settlement Agreement
(1996 Rate Settlement) among the Company, PSC Staff and several other parties
which set rates for a three-year period, ending June 30, 1999. If the PSC
approves the Competitive Opportunities Settlement (Settlement) discussed
earlier, the Settlement would supersede the 1996 Rate Settlement and the Company
would terminate its petition seeking judicial review of the 1996 Rate
Settlement. For a description of the 1996 Rate Settlement see the Company's 1996
Form 10-K, Item 7, under the heading "Rates and Regulatory Matters".
1995 GAS SETTLEMENT. The Company entered into several agreements to help
manage its pipeline capacity costs and successfully met settlement targets for
capacity remarketing for the twelve months ending October 31, 1996, thereby
avoiding negative financial impacts for that period. The Company believes that
it will also be successful in meeting the Settlement targets in the remaining
two years of the Settlement period, although no assurance may be given. For
further information with respect to the 1995 Gas Settlement see the Company's
1996 Form 10-K Item 8, Note 10 of the Notes to Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
During the first three months of 1997 cash flow from operations (see
Consolidated Statement of Cash Flows), provided the funds for construction
expenditures and the payment of dividends and short-term debt. At March 31,
1997 the Company had cash and cash equivalents of $86.3 million. Capital
requirements during 1997 are anticipated to be satisfied primarily from the
combination of internally generated funds and the use of short-term credit
arrangements.
CAPITAL AND OTHER REQUIREMENTS. The Company's capital requirements
relate primarily to expenditures for energy delivery, including electric
transmission and distribution facilities and gas mains and services as well as
nuclear fuel, electric production and the repayment of existing debt. The
Company has no plans to install additional baseload generation.
Total 1997 capital requirements are currently estimated at $132 million,
of which $102 million is for construction and $30 million is for the redemption
of maturing securities and sinking fund obligations. Approximately $12 million
had been expended for construction as of March 31, 1997, reflecting primarily
expenditures for upgrading electric generating, transmission and distribution
facilities and gas mains.
Purchased Power Requirement. Under federal and New York State laws and
regulations, the Company is required to purchase the electrical output of
unregulated cogeneration facilities which meet certain criteria (Qualifying
Facilities). The Company was compelled by regulators to enter into a contract
with Kamine for approximately 55 megawatts of capacity, the circumstances of
which are discussed in this report under Note 2 of the Notes to Financial
Statements and in the Company's 1996 Form 10-K under Item 8, Note 10 of the
Notes to Financial Statements. The Kamine contract and the outcome of related
litigation may have an important impact on the Company's electric rates and its
ability to function effectively in a competitive environment. In the event the
Settlement (described above) is approved by the PSC, recovery of costs
pertaining to Kamine will be governed by its terms. The Company has no other
long-term obligations to purchase energy from Qualifying Facilities.
REDEMPTION OF SECURITIES. On April 22, 1997, the Company redeemed
200,000
13
shares of 7.50% Preferred Stock, Series N at $102 per share plus accrued
dividends from March 1, 1997. On May 1, 1997, the Company redeemed $20,000,000
principal amount of its First Mortgage 6 1/4% Bonds, Series W at 100.00% plus
accrued interest from March 15, 1997. On May 1, 1997, the Company redeemed
$29,335,000 principal amount of its First Mortgage 8% Bonds, Series Y at 100.59%
plus accrued interest from February 15, 1997. On May 1, 1997, the Company also
redeemed $332,000 of its First Mortgage 8% Bonds, Series Y at the special
redemption price of 100.14% plus accrued interest from February 15, 1997 under
sinking and improvement fund provisions of its General Mortgage.
FINANCING. (See Form 10-K for the fiscal year ended December 31, 1996,
Item 8. Note 9. Short-Term Debt, regarding the Company's short-term borrowing
arrangements.)
At March 31, 1997 the Company had Common Stock available for issuance
of 1,026,840 shares under the Automatic Dividend Reinvestment and Stock Purchase
Plan (ADR Plan)and 129,664 shares under the Savings Plus Plan. In July, 1996
the Company began providing for ADR Plan and Savings Plus Plan requirements
through the purchase of shares on the open market.
At the Company's Annual Meeting held April 16, 1997, Shareholders
approved the 1996 Performance Stock Option Plan providing for the issuance of an
additional 2,000,000 shares of Common Stock. None of the shares have been
issued.
CAPITAL STRUCTURE. The Company's retained earnings at March 31, 1997
were $112.8 million, an increase of approximately $22.2 million compared with
December 31, 1996. Capitalization at March 31, 1997, was comprised of 49.1
percent common equity, 6.8 percent preferred equity and 44.1 percent long-term
debt. As presented, these percentages are based on the Company's capitalization
exclusive of securities due within one year and inclusive of the Company's long-
term liability to the United States Department of Energy for nuclear waste
disposal. As financial market conditions warrant, the Company may, from time to
time, issue securities to permit early redemption of higher-cost senior
securities.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses, comparing the three-month
period ended March 31, 1997 to the three-month period ended March 31, 1996. A
summary of changes in Electric and Gas department revenues and expenses is
presented in the Operating Revenues and Expenses table.
14
Operating Revenues and Expenses (Millions of Dollars)
Three Months
Ended Mar.31
------------
1996 Earnings $40.6
Increase (decrease) in earnings:
Electric revenue changes 0.5
- - Includes effect of rate change
- - Consumption changes including weather
- - Changes in sales to other electric utilities
Electric fuel cost changes 4.4
Gas margin (revenue less fuel) (2.4)
- - Consumption changes including weather
- - 1995 Gas Settlement effects
Miscellaneous non-fuel operating and maintenance (4.6)
- - Includes provision for storm costs in
1997 of $2.5 million
Depreciation and amortization (5.7)
Net federal income tax effects 4.9
Local and state tax effects 1.5
Other income and deductions effects (1.6)
Interest Expense 2.1
- - Redeemed 8 3/8% Series CC bonds 3/7/96
- - Matured 5.3% Series V bonds 5/1/96
------
1997 Earnings $39.7
OPERATING REVENUES AND SALES. Total Company revenues for the first
three months of 1997 were $5.7 million or 2% above the first three months of
1996. Higher customer electric kilowatt-hour sales were offset by decreases in
electric sales to other utilities and lower therm sales of gas due to warmer
weather than last year.
FUEL EXPENSES. Fuel expenses increased in the first quarter of 1997
reflecting mainly higher unit cost of gas purchased for resale partially offset
by lower kwh purchases of electricity.
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES. The
increases in operations excluding fuel and maintenance expenses reflect mainly
expenses incurred as a result of wind storms in the first quarter of 1997.
DEPRECIATION AND AMORTIZATION. Depreciation and amortization increased
due mainly to an increase in nuclear decommissioning expense and completion of
the steam generator replacement at the Ginna nuclear plant in the summer of
1996.
TAXES. The decrease in local, state and other taxes reflects mainly
lower property taxes due to decreases in assessments and lower revenue taxes due
to a decrease in the New York State revenue tax surcharge rate.
15
The decrease in Federal income tax reflects mainly the reversal of a
prior provision for the in-service date of Nine Mile Two as a result of an
agreement reached with the Internal Revenue Service.
OTHER STATEMENT OF INCOME ITEMS. The decrease in allowance for funds used
during construction reflects mainly a decrease in the amount of utility plant
under construction due to completion of the Ginna steam generator replacement in
June 1996. Other Income and Deductions, Other-net decreased mainly due to a
decline in subsidiary earnings resulting from the sale of its interest in the
Empire State Pipeline in 1996. Interest charges decreased due to the early
redemption of long-term debt in 1996. Interest charges also decreased due to the
effect of a one-time recording of debt expense in March 1996 relating to the
redemption.
DIVIDEND POLICY
On March 19, 1997, the Board of Directors authorized a common stock
dividend of $.45 per share, which was paid on April 25, 1997 to shareholders of
record on April 2, 1997. The Company believes that future dividend payments
will need to be evaluated in the context of maintaining the financial strength
necessary to operate in a more competitive and uncertain business environment.
This will require consideration, among other things, of a dividend payout ratio
that is lower over time, reevaluating assets and managing greater fluctuation in
revenues. While the Company does not presently expect the impact of these
factors to affect the Company's ability to pay dividends at the current rate,
future dividends may be affected.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information on Legal Proceedings reference is made to Note 2 of the
Notes to Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The Company's Annual Meeting of Shareholders was held on April 16, 1997.
(b) The following Directors were elected for three year terms expiring at the
Annual Meeting of Shareholders in 2000: Allan E. Dugan, Charles I. Plosser
and Thomas S. Richards. The following Directors elected to three year terms
at previous Annual Meetings continue as members of the Board: William
Balderston III, Angelo J. Chiarella, Jay T. Holmes, Samuel T. Hubbard, Jr.,
Roger W. Kober, Constance M. Mitchell, and Cornelius J. Murphy.
(c)1.The nominees for election as directors were elected by the
following vote:
Shares Shares
For Withheld
---------- ---------
Allan E. Dugan 32,080,065 1,572,168
Charles I. Plosser 32,069,108 1,583,125
Thomas S. Richards 32,135,248 1,516,985
(c)2.A proposal of the Company to approve the 1996 Performance Stock Option
Plan was adopted by a vote of 22,268,009 or 57.3% of the outstanding
shares for the proposal, 2,934,901 or 7.6% of the outstanding shares
against the proposal and 1,219,610 or 3.1% of the outstanding shares
abstained from voting.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K:
The Company filed a Form 8-K dated April 9, 1997, reporting under Item 5,
Other Events a settlement with the staff of the PSC and other parties in the
"Competitive Opportunities" proceeding with respect to the restructuring of the
electric utility industry in New York State, based on competition in the
generation and energy services sections of the industry.
EXHIBIT INDEX
Exhibit 27 Financial Data Schedule pursuant to Item 601 (c) of
Regulation S-K.
17
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: May 9, 1997 By /s/ J.B. STOKES
------------------------------------
J. Burt Stokes
Senior Vice President, Corporate Services
and Chief Financial Officer
Date: May 9, 1997 By /s/ WM. J. REDDY
--------------------------------------
William J. Reddy
Controller
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