SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1995
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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 July 31, 1995: 38,239,295
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ROCHESTER GAS AND ELECTRIC CORPORATION
INDEX
Page No.
Part I - Financial Information
Consolidated Balance Sheet - June 30, 1995 and
December 31, 1994 1 - 2
Consolidated Statements of Income - Three Months and Six
Months Ended June 30, 1995 3 - 4
Consolidated Statement of Cash Flows - Six Months
Ended June 30, 1995 and 1994 5
Notes to Financial Statements 6-15
Management's Discussion and Analysis of Financial
Condition and Results of Operations 16-25
Part II - Other Information
Legal Proceedings 25
Exhibits and Reports on Form 8-K 25
Signatures 26
PART I-FINANCIAL INFORMATION
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ROCHESTER GAS AND ELECTRIC CORPORATION
Consolidated Balance Sheet
(Thousands of Dollars) June 30, December 31,
(Unaudited) 1995 1994
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Assets
Utility Plant
Electric $2,324,641 $2,284,634
Gas 374,549 370,205
Common 142,118 135,975
Nuclear fuel 202,624 190,337
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3,043,932 2,981,151
Less: Accumulated depreciation 1,307,723 1,263,637
Nuclear fuel amortization 165,039 159,461
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1,571,170 1,558,053
Construction work in progress 131,289 128,860
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Net Utility Plant 1,702,459 1,686,913
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Current Assets
Cash and cash equivalents 9,169 2,810
Accounts receivable 112,551 110,417
Unbilled revenue receivable 41,428 54,270
Materials and supplies, at average cost
Fossil fuel 6,416 7,908
Construction and other supplies 13,129 13,264
Gas stored underground 13,894 24,315
Prepayments 26,057 23,535
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Total Current Assets 222,644 236,519
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Investment in Empire 38,560 38,560
Deferred Debits
Unamortized debt expense 17,458 18,343
Nuclear generating plant decommissioning fund 54,967 49,011
Nine Mile Two deferred costs 32,937 33,462
Deferred finance charges - Nine Mile Two 19,242 19,242
Other Deferred Debits 24,087 19,214
Regulatory assets -
Income taxes 190,978 205,794
Uranium enrichment decommissioning deferral 19,271 20,169
Deferred ice storm charges 17,832 19,111
FERC 636 transition costs 46,478 32,479
Demand side management costs 16,626 19,807
Deferred fuel costs - gas 17,282 33,845
Other regulatory assets 38,150 33,727
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Total Deferred Debits 495,308 504,204
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Total Assets $2,458,971 $2,466,196
---------------------------------------------------- ========== ==========
The accompanying notes are an integral part of the financial statements.
1
ROCHESTER GAS AND ELECTRIC CORPORATION
Consolidated Balance Sheet
(Thousands of Dollars)
(Unaudited) June 30, December 31,
1995 1994
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Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds $ 625,305 $ 643,278
- promissory notes 91,900 91,900
Preferred stock redeemable at option of Company 67,000 67,000
Preferred stock subject to mandatory redemption 55,000 55,000
Common shareholders' equity
Common stock
Authorized 50,000,000 shares; 38,067,868
shares outstanding at June 30, 1995
and 37,669,963 shares outstanding at
December 31, 1994 679,144 670,569
Retained earnings 82,043 74,566
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Total Common Shareholders' Equity 761,187 745,135
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Total Capitalization 1,600,392 1,602,313
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Long Term Liabilities (Department of Energy)
Nuclear waste disposal 73,018 70,895
Uranium enrichment decommissioning 17,248 16,931
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Total Long Term Liabilities 90,266 87,826
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Current Liabilities
Long term debt due within one year 18,000 -
Short Term Debt - 51,600
Note Payable - Empire 29,600 29,600
Accounts payable 43,415 42,934
Dividends payable 18,997 18,818
Taxes accrued 20,240 3,471
Interest accrued 12,415 11,967
Other 23,854 22,937
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Total Current Liabilities 166,521 181,327
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Deferred Credits and Other Liabilities
Accumulated deferred income taxes 366,217 402,894
Deferred finance charges - Nine Mile Two 19,242 19,242
Pension costs accrued 76,170 75,912
Other 140,163 96,682
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Total Deferred Credits and Other Liabilities 601,792 594,730
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Commitments and Other Matters (Note 2) - -
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Total Capitalization and Liabilities $2,458,971 $2,466,196
------------------------------------------------ =========== ==========
The accompanying notes are an integral part of the financial statements.
2
ROCHESTER GAS AND ELECTRIC CORPORATION
Consolidated Statement of Income For the Three Months Ended
(Thousands of Dollars) June 30, June 30,
(Unaudited) 1995 1994
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Operating Revenues
Electric $ 169,038 $ 154,943
Gas 46,529 58,788
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215,567 213,731
Electric sales to other utilities 3,979 3,352
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Total Operating Revenues 219,546 217,083
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Operating Expenses
Fuel Expenses
Fuel for electric generation 10,373 10,231
Purchased electricity 17,149 9,931
Gas purchased for resale 26,789 33,432
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Total Fuel Expenses 54,311 53,594
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Operating Revenues Less Fuel Expenses 165,235 163,489
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Other Operating Expenses
Operations excluding fuel expenses 60,321 59,518
Maintenance 13,971 15,519
Depreciation and amortization 22,546 21,588
Taxes - local, state and other 29,698 33,816
Federal income tax 9,245 8,470
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Total Other Operating Expenses 135,781 138,911
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Operating Income 29,454 24,578
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Other Income and Deductions
Allowance for other funds used during construction 90 79
Federal income tax 62 905
Regulatory Disallowances - (600)
Other, net (166) (850)
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Total Other Income and (Deductions) (14) (466)
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Interest Charges
Long term debt 13,131 13,607
Other, net 2,212 1,299
Allowance for borrowed funds used during construction (764) (402)
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Total Interest Charges 14,579 14,504
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Net Income 14,861 9,608
Dividends on Preferred Stock 1,866 1,866
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Earnings Applicable to Common Stock $ 12,995 $ 7,742
=========== ===========
Weighted Average Number of Shares for Period 38,003,872 37,219,990
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Earnings per Common Share $ 0.34 $ 0.20
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Cash Dividends Paid per Common Share $ 0.45 $ 0.44
--------------------------------------------------- ----------- -----------
The accompanying notes are an integral part of the financial statements.
3
ROCHESTER GAS AND ELECTRIC CORPORATION
Consolidated Statement of Income For the Six Months Ended
(Thousands of Dollars) June 30, June 30,
(Unaudited) 1995 1994
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Operating Revenues
Electric $ 332,537 $ 322 ,414
Gas 159,284 197,308
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491,821 519,722
Electric sales to other utilities 8,732 7,412
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Total Operating Revenues 500,553 527,134
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Operating Expenses
Fuel Expenses
Fuel for electric generation 21,448 22,787
Purchased electricity 24,618 20,600
Gas purchased for resale 89,223 118,498
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Total Fuel Expenses 135,289 161,885
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Operating Revenues Less Fuel Expenses 365,264 365,249
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Other Operating Expenses
Operations excluding fuel expenses 117,181 119,618
Maintenance 24,494 32,025
Depreciation and amortization 44,956 42,995
Taxes - local, state and other 68,029 70,815
Federal income tax 34,593 28,040
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Total Other Operating Expenses 289,253 293,493
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Operating Income 76,011 71,756
Other Income and Deductions ----------- -----------
Allowance for other funds used during construction 298 171
Federal income tax 1,184 918
Regulatory Disallowances - (600)
Other, net (3,287) 851
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Total Other Income and (Deductions) (1,805) 1,340
Interest Charges ----------- -----------
Long term debt 26,236 27,292
Other, net 4,065 2,905
Allowance for borrowed funds used during construction (1,475) (947)
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Total Interest Charges 28,826 29,250
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Net Income 45,380 43,846
Dividends on Preferred Stock 3,732 3,636
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Earnings Applicable to Common Stock $ 41,648 $ 40,210
========== ===========
Weighted Average Number of Shares for Period 37,909,656 37,131,230
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Earnings per Common Share $ 1.09 $ 1.08
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Cash Dividends Paid per Common Share $ 0.90 $ 0.88
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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 Six Months Ended
(Thousands of Dollars) June 30, June 30,
(Unaudited) 1995 1994
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CASH FLOW FROM OPERATIONS
Net income $ 45,380 $ 43,846
Adjustments to reconcile net income to net cash provided
from operating activities
Depreciation and amortization 44,956 42,995
Amortization of nuclear fuel 7,701 8,388
Deferred fuel - electric (5,926) (6,692)
Deferred fuel - gas 20,806 (7,340)
Deferred income taxes (1,861) 506
Allowance for funds used during construction (1,773) (1,118)
Unbilled revenue, net 12,842 21,807
Deferred ice storm costs 1,279 1,231
Nuclear generating plant decommissioning fund (5,956) (5,038)
Post employment benefit internal reserve 2,352 2,301
Research and development amortization 1,280 182
Rate settlement amortizations 3,524 5,000
Changes in certain current assets and liabilities:
Accounts receivable (2,134) (6,305)
Materials and supplies - gas stored underground 10,421 15,534
- other, net 1,627 (1,008)
Taxes accrued 16,769 14,024
Other current assets and liabilities, net 1,944 (1,465)
Other, net 1,999 (8,849)
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Total Operating $ 155,230 $117,999
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CASH FLOW FROM INVESTING ACTIVITIES
Utility Plant
Plant additions $( 55,576) $(51,594)
Nuclear fuel additions (12,287) (6,676)
Less: Allowance for funds used during construction 1,773 1,118
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Additions to Utility Plant (66,090) (57,152)
Investment in Empire - net - (15)
Other, net (8) (37)
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Total Investing $ (66,098) $(57,204)
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CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issue of common stock $ 8,601 $ 9,032
Sale of preferred stock - 25,000
Short term borrowings (51,600) (23,300)
Retirement of long term debt - (17,750)
Retirement of preferred stock - (18,000)
Capital stock expense (26) 1,375
Dividends paid on preferred stock (3,732) (3,691)
Dividends paid on common stock (33,991) (32,563)
Other, net (2,025) (2,396)
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Total Financing $ (82,773) $(62,293)
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Increase in cash and cash equivalents $ 6,359 $ (1,498)
Cash and cash equivalents at beginning of period $ 2,810 $ 2,327
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Cash and cash equivalents at end of period $ 9,169 $ 829
========= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Six Months Ended
June 30, June 30,
1995 1994
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Cash Paid During the period
Interest paid (net of capitalized amount) $ 27,467 $ 27,945
Income taxes paid $ 27,000 $ 25,198
-------------------------------------------------------- ========= ========
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 accompanying unaudited financial statements reflect all adjustments
which are, in the opinion of management, necessary to a fair presentation of the
Company's results for these interim periods. All such adjustments are of a
normal recurring nature, except for the reduction to reported earnings from a
Public Service Commission (PSC) order as described in Note 2 under Gas Cost
Recovery. The results for these interim periods are not necessarily indicative
of results to be expected for the year, due to seasonal, operating, and other
factors. These financial statements should be read in conjunction with the
financial statements and notes thereto contained in the Company's Annual Report
on Form 10-K for the year ended December 31, 1994.
Note 2. Commitments and Other Matters
The following matters supplement the information contained in Note 10 to
the financial statements included in the Company's Annual Report on Form 10-K
for the year ended December 31, 1994 and should be read in conjunction with the
material contained in that Note.
LITIGATION WITH CO-GENERATOR.
Under Federal and New York State laws and regulations, the Company is
required to purchase the electrical output of unregulated cogeneration
facilities which meet certain criteria (Qualifying Facilities). With the
exception of one contract which the Company was compelled by regulators to enter
into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts
of capacity, the Company has no long-term obligations to purchase energy from
Qualifying Facilities.
Under State law and regulatory requirements in effect at the time the
contract with Kamine was negotiated, the Company was required to pay Kamine a
price for power that is substantially greater than the Company's own cost of
production and other purchases. Since that time the State law mandating a
minimum price higher than the Company's own costs has been repealed and PSC
estimates of future costs on which the contract was based have declined
dramatically.
6
In September 1994, the Company filed a lawsuit against Kamine in New York
State Supreme Court seeking to void its contract for the forced purchase of
unneeded electricity at above-market prices which would result in substantial
cost increases for the Company's customers. The Company estimates that Kamine
will owe the Company $400 million by the midpoint of the contract term and if
the contract extends to its full 25 year term, the total amount of such
overpayments (plus interest) could reach approximately $700 million. The
Company believes that Kamine will be unable to meet the contract security
requirements for these sums when due. Alternatively, the Company sought relief
to ensure that its customers would pay no more for the Kamine power than they
would pay for power from the Company's other sources of electricity. Kamine
answered the Company's complaint, seeking to force the Company to take and pay
for power at the above-market rates and claiming damages in an unspecified
amount alleged to have been caused by the Company's conduct. The Company began
receiving test generation from the Kamine facility during the last quarter of
1994. In late December 1994, the Company announced it would no longer be
accepting electric power from this facility, unless charged at the current
avoided cost rate, because it is the Company's position, among other reasons,
that the Kamine facility is no longer a "Qualifying Facility" as specified under
Federal regulations. On February 17, 1995 Kamine petitioned the Federal Energy
Regulatory Commission (FERC) for a "Temporary Waiver of Operating and Efficiency
Standards" seeking to confirm its status as a Qualifying Facility in 1994
despite the undisputed fact that no thermal host existed when the plant is
claimed to have entered commercial service. The PSC has joined the Company in
opposing Kamine's request for waiver of the Qualifying Facility standards.
By a decision rendered March 16, 1995, the state court denied Kamine's
motion for summary judgement. Kamine has appealed that decision. The Company
intends to vigorously pursue this lawsuit, but is unable to predict the outcome
at this time.
On January 27, 1995, Kamine initiated a lawsuit against the Company in
United States District Court for the Western District of New York for alleged
anti-trust violations by the Company that are based on the same issues that are
raised by the Company's New York State Court lawsuit. The Kamine lawsuit seeks
injunctive relief similar to that requested in Kamine's answer to the Company's
lawsuit in New York State Court and damages of $420 million. Kamine also moved
for a preliminary injunction and a temporary restraining order to require the
Company,
7
during the pendency of the lawsuit, to accept and pay for electricity generated
by Kamine's facility. On March 20, 1995, the District Court issued a decision
and order granting Kamine's application for a temporary restraining order to
require the Company, for a period of ten days from entry of the order, to
purchase electricity generated by Kamine at a rate of at least six cents per
kilowatt hour. The Court subsequently extended the temporary restraining order
until a ruling is made on the pending motion for preliminary injunction. During
the first six months of 1995 the Company purchased approximately 100,844,000
kilowatt hours of electricity under this contract. The Company intends to
vigorously defend against Kamine's lawsuit, but is unable to predict the outcome
at this time.
The United States Department of Justice, Antitrust Division, has issued a
Civil Investigative Demand calling for the production of documents and answers
to interrogatories concerning the electric utility industry. Among documents
requested are ones that relate to the Kamine project. The Company has been
informed that the Antitrust Division has not concluded that there is an
antitrust violation, and that it is not a target of this investigation, since
there are no targets. The Company is cooperating with the investigation.
On May 9, 1995, the Company filed a petition with the PSC which, among
other things, requested that the Commission investigate Kamine,s qualification
as a "cogenerator", as defined in the New York State Public Service Law, to
determine if Kamine is in compliance with contract requirements. It is the
Company's position that Kamine is not a cogenerator as defined by such law and,
as a result, is in violation of a crucial contract provision. The Company has
been unable to clearly resolve this issue and the PSC suggested that it would
consider pursuing the matter if the Company requested that it do so. The PSC
issued a Notice of Proposed Rulemaking on June 21, 1995 and Kamine responded to
that Notice on August 4, 1995. There is no formal deadline for PSC action.
ENVIRONMENTAL MATTERS.
In March 1995, the Company recorded an additional estimated liability of
$10 million which it anticipates spending on Site Investgation and/or
Remediation (SIR) efforts at six Company-owned sites where past waste handling
and disposal may have occurred. Concurrently, the Company recorded a similar
increase in its Regulatory Assets. For
8
further information on these sites and SIR activities at non-Company owned
Superfund or other sites for which the Company has been or may be associated as
a potentially responsible party see Note 10 of the Notes to Financial Statements
in the Company's Form 10-K for the fiscal year ended December 31, 1994.
GAS COST RECOVERY.
As a result of the restructuring of the gas transportation industry by the
FERC pursuant to Order No. 636 and related decisions, there have been and will
be a number of changes in this aspect of the Company's business over the next
several years. For additional information with respect to these transition
costs see Note 10 of the Notes to Financial Statements in the Company's Form 10-
K for the fiscal year ended December 31, 1994.
The Company is committed to transportation capacity on the Empire State
Pipeline (Empire) as well as to upstream pipeline transportation and storage
services. The Company also has contractual obligations with CNG and upstream
pipelines whereby the Company is subject to charges for transportation and
storage services for a period extending to the year 2001. The combined CNG and
Empire transportation capacity exceeds the Company's current requirements. This
temporary excess has occurred largely due to the Company's initiatives to
diversify its supply of gas and the industry changes and increasing competition
resulting from the implementation of FERC Order 636.
Under FERC rules, the Company may release its excess transportation
capacity in the market. The Company is attempting to do that, whenever
possible.
The Company has entered into a marketing agreement with CNG Transmission
Corporation (CNG), pursuant to which CNG will assist the Company in obtaining
permanent replacement customers for transporation capacity the Company will not
require. As a result of this marketing agreement and FERC approval of the
Chambersburg Project (described below), a substantial portion of this capacity
will be released to replacement shippers through the contract period described
above. The Company is now in the process of assigning the subject capacity. On
May 31, 1995, the FERC issued an order approving the construction and rate
treatment of the Chambersburg Project which includes modifications to CNG,s
pipeline which are required to facilitate the use of pipeline
9
capacity by the replacement shippers. The Company is contributing $10 million
to the construction of this project. Chambersburg is expected to become
operational by December 1, 1995.
The Company also exercised its option to postpone for one year the
commencement of certain Empire-related transportation service that was scheduled
for November 1994.
The Company will continue to pursue other options for the release of
capacity. Specifically, the Company has entered into a Supply Portfolio
Management agreement with MidCon Gas Services Corp. (MGSC). MGSC will work with
the Company to identify and implement opportunities for temporary and permanent
release of surplus pipeline capacity, as well as advise with respect to the
management of the Company,s gas supply, transportation and storage assets
consistent with the goal of providing reliable service and reducing the cost of
gas. MGSC was selected from 15 companies that submitted proposals because it
brings a high level of expertise in supply management and has successfully
demonstrated its abilities with companies of our size.
A reconciliation of gas costs incurred and gas costs billed to customers
is done annually, as of August 31, and the excess or deficiency is refunded to
or recovered from customers during a subsequent period. In October 1994, the
Company submitted to the PSC its annual Gas Clause Adjustment reconciliation
providing for recovery of $24 million of deferred gas costs, which was
substantially higher than in previous years principally due to factors mentioned
above.
The Staff of the PSC reviewed the Company's application for recovery of
deferred costs and the Consumer Protection Board, along with certain individuals
or groups of ratepayers, requested that the PSC conduct hearings to determine
whether and on what terms the deferral should be recovered. On December 19,
1994, the PSC instituted a proceeding to review the Company's practices
regarding acquisition of pipeline capacity, the deferred costs of the capacity
and the Company's recovery of those costs. As an interim measure, on February
1, 1995 the PSC directed the Company to remove from existing rates the revenue
effect of $16 million of gas costs attributable to capacity costs, resulting in
a net $2.7 million or $.07 per share reduction in earnings
10
for the first six months of 1995. The Company was permitted to offset the costs
excluded from rates with capacity release credits obtained in
February and thereafter.
Depending on the outcome of the PSC's investigation and the Company's
ability to secure permanent capacity release on favorable terms, such net costs
will continue to be incurred. These net costs will vary from month to month and
may increase if the Company cannot continue to maintain capacity release at the
current level and depending on expenses incurred in obtaining the releases. At
this time, the Company is unable to predict the timing and extent to which
future capacity release credits will be available to offset the $16 million
annual amount described above. These net costs would also be impacted if the PSC
determines that capacity was imprudently incurred and that the related cost
exceeds the $16 million previously described. In a more adverse decision, the
PSC could order the Company to refund a portion of such costs previously
collected from ratepayers.
The Company's purchased gas expense charged to customers was higher during
the 1994-95 heating season for the reasons described above. The impact of these
cost increases on bills generated substantial customer concern, especially since
the heating season was unseasonably warm. The action the Company took to reduce
rates included refunding the weather normalization adjustment charged to
customers in January and discontinuation of those charges through the remainder
of the heating season ending in May. This reduced earnings from gas operations
for the six months ended June 30, 1995 by approximately $3.5 million, $.09 per
share. The weather normalization adjustment provides for recovery of fixed
charges by producing higher unit rates when the weather is warm and usage is
low. Conversely, it would produce lower unit rates during colder periods of
high usage.
On April 21, 1995, the PSC issued a Department of Public Service (DPS)
staff report on the Company's 1994-1995 billings which presented recommendations
regarding changes in the Company's natural gas purchasing, billing, meter
reading and communication activities. The Company responded to the Staff report
with its implementation plan on May 18, 1995. In most respects, the Company
agreed to implement Staff's recommendations. The Company also proposed to
eliminate the weather normalization adjustment on a permanent basis before the
beginning of the 1995-1996 heating season. Parties to the case have commented
on the plan and the Commission is expected to issue a ruling accepting or
modifying the Company's plan this summer.
11
The Company is also in the process of negotiating with the DPS Staff and
other intervenors (including the American Association of Retired Persons, the
New York State Consumer Protection Board, the Citizen's Utility Board, the New
York State Department of Law and Multiple Intervenors) to develop a resolution
of the cost and price issues raised in the PSC investigation of the Company's
gas costs. These issues include the prudence of the Company's acquisition of
interstate pipeline capacity and the management of its gas supply activities.
Regardless of the status of negotiations, litigation in these cases will begin
in August, and the Commission is expected to issue a final ruling in these cases
in November, 1995. At this time, the Company cannot predict the outcome of the
negotiations or the Commission,s decision in these cases.
In connection with these negotiations, the Company proposed that the gas
rate increase of approximately $7.7 million that would have been permitted to
take effect as of July 1, 1995 pursuant to the rate settlement approved by the
PSC in the Company's last gas rate proceeding be postponed by two months, until
September 1, 1995. The proposed increase in base rates does not include
capacity costs which are being considered in the PSC investigation of the
Company's gas costs. On June 30, 1995, the PSC suspended the increase for up to
120 days to permit consideration of the increase in the context of the
investigation of gas costs.
REGULATORY AND STRANDED ASSETS.
Certain costs are deferred and recognized as expenses when they are
reflected in rates and recovered from customers as permitted by Statement of
Financial Accounting Standard No. 71, "Accounting of the Effects of Certain
Types of Regulation". These costs are shown as Regulatory Assets. Such costs
arise from the traditional cost-of-service rate setting approach where all
prudently incurred costs are recoverable through rates. Deferral of these costs
is appropriate while the Company's rates are regulated under a cost-of-service
approach.
In a purely competitive pricing approach, such costs might not have been
incurred or deferred. Accordingly, if the Company's rate setting were changed
from a cost-of-service approach and it was no longer allowed to defer these
costs under SFAS 71, certain of these assets may not be fully recoverable.
12
Below is a summarization of the Regulatory Assets as of June 30, 1995.
Millions
of dollars
----------
Income Taxes $191.0
Deferred Ice Storm Charges 17.8
Uranium Enrichment Decommissioning Deferral 19.3
FERC 636 Transition Costs 46.5
Demand Side Management Costs Deferred 16.6
Deferred Fuel Costs - Gas 17.3
Other, net 38.1
----------
Total - Regulatory Assets $346.6
==========
The FERC 636 Transition Costs are based on June 1995 estimates. See the
Company's 1994 10-K, Note 10 of the Notes to Financial Statements under the
heading "Regulatory and Stranded Assets" for a description of the Regulatory
Assets shown above.
Stranded assets (or other costs) arise when investments are made in
facilities, or costs are incurred to serve customers, and such costs and
investments may not be fully recoverable in market-based rates. Examples may
include purchased power contracts (e.g., the Kamine contract) or high cost
generating assets.
Excluding the Kamine contract described above, estimates of possible
stranded asset amounts vary as to scope and methodology and are highly sensitive
to the competitive wholesale price for electricity assumed in the estimation.
The amount of potential stranded assets at June 30, 1995, cannot be determined
at this time but could be significant.
While the Company currently believes that its regulatory and other assets
potentially classifiable as stranded assets are probable of recovery in rates,
industry trends have moved more toward competition, and in a purely competitive
environment, it is not clear to what extent, if any, writeoffs of such assets
may occur.
NUCLEAR DECOMMISSIONING TRUST
The Company is collecting in its electric rates amounts for the eventual
decommissioning of its Ginna Plant and for its 14% share of the
13
decommissioning of Nine Mile Two. The operating licenses for these plants
expire in 2009 and 2026, respectively.
Under accounting procedures approved by the PSC, the Company has collected
decommissioning costs of approximately $74.5 million through June 30, 1995. In
connection with the Company's rate settlement completed in August 1993, the PSC
approved the collection during the rate year ending June 30, 1995 of an
aggregate $8.9 million for decommissioning, covering both nuclear units. The
amount allowed in rates is based on estimated ultimate decommissioning costs of
$163.0 million for Ginna and $37.1 million for the Company's 14% share of Nine
Mile Two (January 1994 dollars). This estimate is based principally on the
application of a Nuclear Regulatory Commission (NRC) formula to determine
minimum funding with an additional allowance for removal of non-contaminated
structures. Site specific studies of the anticipated costs of actual
decommissioning are required to be submitted to the NRC at least five years
prior to the expiration of the license.
The Company has recently completed a site specific cost analysis of
decommissioning at Ginna and incorporated the results of this study in its July
1995 rate filing with the PSC. Based on the site specific study the estimated
decommissioning cost increased to $296.3 million (May 1995 dollars). The
Company is awaiting the results of a site specific cost analysis currently in
progress at Nine Mile Two. The Company cannot predict the degree to which these
additional estimates will be recognized in rates stemming from its current rate
filing.
The NRC requires reactor licensees to submit funding plans that establish
minimum NRC external funding levels for reactor decommissioning. The Company's
plan, filed in 1990, consists of an external decommissioning trust fund covering
both its Ginna Plant and its Nine Mile Two share. Since 1990, the Company has
contributed $50.1 million to this fund and, including realized investment
returns, the fund has a balance of $55.0 million as of June 30, 1995. The
amount attributed to the allowance for removal of non-contaminated structures is
being held in an internal reserve. The internal reserve balance as of June 30,
1995 is $24.4 million.
The Company is aware of recent NRC activities related to upward revisions
to the required minimum funding levels. These activities, primarily focused on
disposition of low level radioactive waste, may
14
require the Company to further increase funding. The Company continues to
monitor these activities but cannot predict what regulatory actions the NRC may
ultimately take.
The Staff of the Securities and Exchange Commission and the Financial
Accounting Standards Board are currently studying the recognition, measurement
and classification of decommissioning costs for nuclear generating stations in
the financial statements of electric utilities. If current accounting practices
for such costs were changed, the annual provisions for decommissioning costs
would increase, the estimated cost for decommissioning could be reclassified as
a liability rather than as accumulated depreciation, the liability accounts and
corresponding plan asset carrying accounts would be increased and trust fund
income from the external decommissioning trusts could be reported as investment
income rather than as a reduction to decommissioning expense. If annual
decommissioning costs increased, the Company would expect to defer the effects
of such costs pending disposition by the Public Service Commission.
15
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is Management's assessment of certain significant factors
affecting financial condition and operating results.
EARNINGS SUMMARY
Earnings Per Common Share
For the Periods Ended
June 30
-------------------------
1995 1994
---- ----
Three months $ .34 $ .20
Six months $1.09 $1.08
The Company's financial performance improved this past quarter, reflecting
cost savings from a major work force reduction completed in October 1994 and
ongoing cost controls. During the past two years, the work force has been
reduced by over 20%. Earnings also reflect lower local and state taxes in the
current quarter as compared to the second quarter of 1994. These positive
factors also lead to slightly higher earnings for the calendar year to date,
despite a milder than normal heating season and measures taken earlier in the
year to reduce the price of gas to customers.
Pre-tax earnings from gas operations were reduced by approximately $5.3
million this year due to a decision to eliminate weather normalization charges
on customer bills for the 1995 heating season which ended in May. Pre-tax
earnings for the calendar year to date were further reduced by an additional
$4.2 million due to the effect of removing $16 million of annual capacity costs,
net of capacity release credits, from rates beginning in February 1995.
In addition to the costs of work force reduction programs, pre-tax
earnings for the prior year periods include charges of $600 thousand for
unrecoverable gas costs written off in April 1994.
COMMON STOCK DIVIDEND
On June 21, 1995, the Board of Directors authorized a common stock
dividend of $.45 per share, which was paid on July 25, 1995 to
16
shareholders of record on July 5, 1995. The Company believes that future
dividend payments will need to be evaluated in the context of maintaining the
financial strength necessary to operate in a more competitive and uncertain
business environment. This will require consideration, among other things, of a
dividend payout ratio that is lower over time, reevaluating assets and managing
greater fluctuation in revenues. While the Company does not presently expect
the impact of these factors to affect the Company's ability to pay dividends at
the current rate, future dividends may be affected.
COMPETITION
As reported in the Company's 1994 Form 10-K, Management's Discussion
and Analysis of Financial Condition and Results of Operations under the heading
"Electric Utility Competition" the PSC had invited comments on proposed
principles to guide the transition to competition. In an opinion issued on June
7, 1995, the Commission provided a revision of the nine "Principles to Guide the
Transition to Competition" initially issued in December 1994. The revised
principles, which reflect input from the Commission staff and many of the
participants of the proceeding, are as follows:
- First, competition is endorsed as promoting economic and
environmental well-being in New York.
- Second, "rate shock" should be minimized and a reasonbly-
priced level of basic service should be maintained.
- Third, increased emphasis should be placed on market-based or
"competitively neutral" approaches to preserve research, environmental
protections, cost-effective energy efficiency, and fuel diversity.
- Fourth, safety and reliability must not be jeopardized.
- Fifth, new structure should provide increased customer
choice, a suitable forum for resolving complaints, and leeway for
approaches that reflect differences in New York's electric utilities.
- Sixth, as competition increases, regulation should decrease
and vigorous fair-trade safeguards must be in place.
17
- Seventh, the current vertically integrated industry structure
must be thoroughly examined to ensure that it does not impede effective
wholesale or retail competition.
- Eighth, utilities should have a reasonable opportunity to
recover expenditures and commitments made pursuant to their legal
obligations.
- Ninth, pro-competitive policies should further economic
development in New York State.
In general, the Company believes market-based solutions to the challenges
facing this industry will ultimately result in the greatest shareholder value.
While the Company agrees with the spirit underlying the modified principles, the
nature and magnitude of potential impacts on the business risks faced by the
Company will depend on the details of any implementation of the guiding
principles. In the June 7, 1995 Opinion, the Commission provided additional
information regarding the schedule for completing the analysis now being done by
the parties to the proceeding. The PSC indicated that it expects a
"[recommended] decision or report" to be completed by the end of 1995. The
Company cannot predict the final outcome of this proceeding. See the Company's
1994 Form 10-K, Management's Discussion and Analysis of Financial Condition and
Results of Operations under the heading "Competition" for information on how the
Company proposes to respond to the competitive challenges it faces in its
electric and gas business.
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 1995 cash flow from operations, together
with proceeds from external financing activity (see Consolidated Statement of
Cash Flows), provided the funds for construction expenditures and the retirement
of short-term borrowings. The Company has no debt maturity or sinking fund
obligations scheduled in 1995.
PROJECTED CAPITAL AND OTHER REQUIREMENTS
The Company's capital requirements relate primarily to expenditures for
electric generation including replacement of its Ginna steam generators,
transmission and distribution facilities and gas mains and services as well as
the repayment of existing debt. Construction
18
programs of the Company focus on the need to serve new customers, to provide for
the replacement of obsolete or inefficient utility property and to modify
facilities consistent with the most current environmental and safety
regulations. The Company has no current plans to install additional base load
generation.
The Company's most current Integrated Resource Plan (IRP) explores options
for complying with the 1990 Clean Air Act Amendments. The IRP is part of an
ongoing planning process to examine options for the future with regard to
generating resources and alternative methods of meeting electric capacity
requirements. Activities are currently under way to:
- Modify Units 2, 3, and 4 at Russell Station and Unit 12 at
Beebee Station, all coal-fired facilities, to meet Federal Environmental
Protection Agency standards and Clean Air Act requirements,
- Replace the two steam generators at the Ginna Nuclear Plant.
(See below.)
Total 1995 capital requirements for construction are currently estimated
at $132 million, including replacement of the steam generators at the Ginna
Nuclear Plant. Approximately $67 million had been expended for construction as
of June 30, 1995, reflecting primarily expenditures for steam generator
replacement, upgrading electric generating, transmission and distribution
facilities and gas mains and expenditures for nuclear fuel.
Preparation for replacement of the two steam generators at the Ginna
Nuclear Plant began in 1993 and will continue until the replacement in 1996.
Steam generator fabrication is well underway. All major components for the
steam generators have been delivered and major sub-assemblies have been
fabricated. Manufacturing will be completed in early 1996 and the steam
generators will be shipped to the site. The installation contractor will remain
on site throughout 1995 in preparation for the 1996 replacement outage. Cost of
the replacement is estimated at $115 million; the costs comprise approximately
$40 million for the units, $50 million for installation and the remainder for
engineering, radiation protection, plant support, other services and finance
charges. The Company spent $23 million on this project in the first six months
of 1995 and expects to spend a total of $30 million this year. Installation
activities during 1995 will include a number of in-containment modifications,
foundations for building and equipment,
19
construction of a temporary building on site and construction of a storage
building for the old steam generators. The PSC order approving this project
provides that certain costs over $115 million will not be fully recoverable in
rates but the Company does not expect to exceed that estimated cost.
FINANCING
Under provisions of the Company's Charter, the Company may not issue
unsecured debt if immediately after such issuance the total amount of unsecured
debt outstanding would exceed 15 percent of the Company's total secured
indebtedness, capital, and surplus without the approval of at least a majority
of the holders of outstanding Preferred Stock. At June 30, 1995, the Company
was able to issue $66.5 million of additional unsecured debt under this
provision.
The Company is utilizing its credit agreements totaling $140 million
and unsecured lines of credit totaling $72 million to meet any interim external
financing needs prior to issuing any long-term securities. See the Company's
1994 Form 10-K, Managements Discussion and Analysis of Financial Condition and
Results of Operations under the heading "FINANCING AND CAPITAL STRUCTURE" for
information on these credit agreements. At June 30, 1995 the Company had short-
term borrowings outstanding of $16 million associated with FERC Order 636
transition costs (recorded on the Balance Sheet as a deferred credit).
During the first six months of 1995, the Company issued 397,905 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 June 30, 1995 the Company had Common Stock available
for issuance of 206,481 shares under the ADR Plan and 83,619 shares under the
Savings Plus Plan. In July, the Company received regulatory authorization to
issue an additional 1,500,000 shares under the ADR Plan and an additional
150,000 shares under the Savings Plus Plan.
CAPITAL STRUCTURE
The Company's retained earnings at June 30, 1995 were $82.0 million, an
increase of approximately $7.5 million compared with
20
December 31, 1994. There were virtually no changes in the amount of long term
debt and preferred stock at June 30, 1995 as compared with December 31, 1994.
Common equity increased approximately $16.1 million, reflecting the issuance and
sale of Common Stock as discussed under "Financing" and an increase in retained
earnings. Capitalization at June 30, 1995, including $18.0 million of long-term
debt due within one year, was comprised of 45.0 percent common equity, 7.2
percent preferred equity and 47.8 percent long-term debt. To improve its
capital structure, the Company currently anticipates the issuance of new shares
of common stock, primarily through the Company's ADR Plan. The Company is
reviewing its financing strategies as they relate to debt and equity structures
in the context of the new competitive environment and the ability of the Company
to shift from a fully regulated to a more competitive organization.
RATE BASE AND REGULATORY POLICIES
See the Company's 1994 Form 10-K, Management's Discussion and Analysis of
Financial Condition and Results of Operations under the heading "REGULATORY
MATTERS--New York State Public Service Commission" for information on the 1993
Rate Agreement which extends to June 30, 1996, including a discussion of the
incentive arrangements and the risks and rewards available to the Company.
Under this Agreement the PSC approved an electric rate increase of 2.5%
($18.3 million) effective for the rate year beginning July 1, 1995. The Company
proposed to postpone until September 1, 1995, a gas rate increase of
approximately $7.7 million that would have been permitted to take effect as of
July 1. The PSC further suspended the increase until October 28, 1995 to
permit consideration of this increase in the context of the investigation of gas
costs, as discussed in Note 2 of the Notes to Financial Statements under the
heading "Gas Cost Recovery".
On July 28, 1995 the Company filed a request with the PSC to increase its
rates for electricity commencing July 1, 1996. The filing asks for electric
rates to be increased by approximately $17.0 million or 2.4 percent annually
based on forecasted retail sales volumes for the twelve month period ending June
30, 1997. The Company also filed for a minimal gas rate increase (0.3 percent).
In its filing the Company requested a 11.75% rate of return on equity. The
higher rates have been requested to cover increases in capital and operating
costs projected for the Rate Year that are not provided for in present rates and
are not expected to be offset by increased revenues from sales.
21
With the current three-year electric and gas rate plan expiring in 1996,
the Company is also working with the PSC and others to develop a competitive
initiative that could lead to settlement of the filing described above, replace
the 1993 Rate Agreement with a new 3-5 year agreement and continue to provide
price benefits to customers. The goal of the collaborative effort is to
stabilize customer rates as low as possible and establish guidelines that will
allow the Company to assume more risk to take actions that could create
increased earnings for shareholders. The Company is unable to predict whether
any settlement will be achieved.
Under a flexible pricing tariff for major industrial and commercial
electric customers the Company may negotiate competitive electric rates at
discount prices to compete with alternative power sources, such as customer-
owned generation facilities. Under the terms of the 1993 Rate Agreement, the
Company would absorb 30 percent of any net revenues lost as a result of such
discounts through June 1996, while the remaining 70 percent would be recovered
from other customers. The Company has not sought recovery of that 70 percent
from other customers. The portion recoverable after June 1996 is expected to be
determined in a recently commenced Company rate proceeding. Under these tariff
provisions, the Company has negotiated long-term electric supply contracts with
seven of its large industrial and commercial electric customers at discounted
rates. The Company is negotiating long term electric supply contracts with other
large customers as the need and opportunity arise. The Company has not
experienced any customer loss due to competitive alternative arrangements.
The PSC Staff is currently reviewing the Company's application for the
recovery of certain deferred gas costs and the Company has filed a plan
pertaining to gas purchasing, billing, meter reading and communication
activities, as discussed in Note 2 of the Financial Statements under the heading
"Gas Cost Recovery".
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses, comparing the three-month and
six months periods ended June 30, 1995 to the corresponding three-month and six
months periods ended June 30, 1994.
22
OPERATING REVENUES AND SALES
Total Company revenues for the first six months of 1995 were $26.6 million
or 5.0% below the first six months of 1994, resulting from lower gas revenues
due to the mild weather, the reduction of gas revenues representing a portion of
the $16 million of costs attributable to excess capacity subject to PSC review
as described under Note 2, Gas Cost Recovery and the Company decision in
February to discontinue for the balance of the heating season the operation of
its weather normalization clause in order to moderate the adverse effects on
customer bills. Customer electric revenue increased reflecting more expensive
purchased electricity during a scheduled shutdown of the Ginna Nuclear Plant.
Total Company revenues for the second quarter of 1995 were $2.5 million
or 1.1% above the second quarter of 1994 reflecting higher kilowatt hour sales
of electricity partially offset by lower gas revenues due to the factors
described above.
Revenues from other electric utility (OEU) sales increased in both
comparison periods reflecting higher kilowatt hour sales and higher rates. In
addition to sales through the New York Power Pool, tariff changes in late 1994
allowed the Company to participate in two-party sales.
The principal factors causing changes in Electric and Gas Department
revenues are estimated below:
Comparison Comparison
Three months Six months
Ended June 30, Ended June 30
1995 and 1994 1995 and 1994
------------------------- ------------------------
Increase or (Decrease) Increase or (Decrease)
for comparison period for comparison period
(Millions of Dollars) (Millions of Dollars)
Electric Gas Electric Gas
-------- --- -------- ---
Rate increases $ 3.9 $ 1.4 $ 8.2 $ 4.3
Fuel Costs 7.4 (6.4) 2.7 (29.2)
Weather effects (Heating & Cooling) .4 1.1 (5.7) (8.7)
Customer consumption/*/ .8 .6 4.1 8.9
Other/*/ 1.6 (8.9) .8 (13.3)
------ ------- ------- ------
Total change in customer revenues $ 14.1 $(12.2) $10.1 $(38.0)
OEU sales .6 - 1.3 -
------ ------- ------- ------
Total change in operating revenues $ 14.7 $(12.2) $11.4 $(38.0)
====== ====== ===== ======
/*/ Customer consumption reflects retail and unbilled margins and transportation
less rate increases and weather effects. Fluctuatons in other customer
revenues shown in the table above are largely the result of deferred fuel
costs, revenue taxes and miscellaneous revenues.
23
FUEL EXPENSES
Fuel expenses decreased in the first six months of 1995 reflecting mainly
lower unit gas customer sales due to mild weather and lower commodity costs.
Fuel expenses increased in the second quarter of 1995 due mainly to an
electric purchase/generation mix which included a higher proportion of
relatively expensive puchased power to meet customer requirements during a
scheduled shutdown at the Ginna Nuclear Plant. Partially offsetting this
increase were lower purchases of gas as discussed above.
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES
The net decreases in these line items in both comparison periods reflect
mainly lower cost for payroll, employee welfare, contractor and consultant
services and materials and supplies due to Company cost control efforts and the
workforce reduction program undertaken in the second and third quarters of 1994.
The net decrease for the second quarter was partially offset by higher nuclear
plant maintenance expense due to the timing of the annual shutdown for the Ginna
Plant maintenance and refueling which included more days in the second quarter
than a year ago.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased due mainly to an increase in
depreciable plant.
TAXES
The decreases in local, state and other taxes in both periods reflect
mainly an additional assessment in 1994 resulting from a New York State sales
tax audit, lower payroll taxes due to fewer employees and a five percent
decrease in the surcharge on the New York State Gross Revenue Tax in 1995.
The changes in Federal income tax in both comparison periods reflect
mainly changes in estimates in the effective tax rate used in the Company's
interim tax provision.
24
OTHER STATEMENT OF INCOME ITEMS
The increases in allowance for funds used during construction (AFUDC)
reflect increases in the amount of utility plant under construction and a one-
half percent increase in the effective rate in September 1994. The change in
regulatory disallowances reflects the write-off of unrecoverable gas costs in
April, 1994.
Interest charges, excluding AFUDC, were increased in both comparison
periods due to interest recognized in May 1995 related to a tax underpayment
resulting from a New York State sales tax audit.
The increase in dividends on preferred stock for the six month comparison period
reflects the issuance of preferred stock in March 1994.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information on Legal Proceedings reference is made to Note 2 of the
Notes to Financial Statements.
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.
25
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: August 14, 1995 By THOMAS S. RICHARDS
--------------------------------------
Thomas S. Richards
Senior Vice President, Corporate Services
and General Counsel
(Principal Financial Officer)
Date: August 14, 1995 By DANIEL J. BAIER
--------------------------------------
Daniel J. Baier
Controller
(Principal Accounting Officer)
26