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, 1994
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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
--- ----
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, 1994: 37,236,812
ROCHESTER GAS AND ELECTRIC CORPORATION
INDEX
Page No.
Part I - Financial Information
Consolidated Balance Sheet - March 31, 1994 and
December 31, 1993 1 - 2
Consolidated Statement of Income - Three Months
Ended March 31, 1994 3
Consolidated Statement of Cash Flows - Three Months
Ended March 31, 1994 and 1993 4
Notes to Financial Statements 5 - 15
Management's Discussion and Analysis of Financial
Condition and Results of Operations 16 - 24
Part II - Other Information
Legal Proceedings 24
Submission of Matters to a Vote of Security Holders 24 - 25
Other Events 25
Exhibits and Reports on Form 8-K 25
Signatures 26
Exhibit Index 27
</TABLE
PART 1 - FINANCIAL INFORMATION
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ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
Assets
March 31 December 31
1994 1993
------------ ------------
Utility Plant
Electric $2,249,429 $2,234,530
Gas 360,324 356,484
Common 128,182 125,428
Nuclear fuel 180,746 174,357
------------ ------------
2,918,681 2,890,799
Less: Accumulated depreciation 1,208,366 1,190,801
Nuclear fuel amortization 147,851 144,282
------------ ------------
1,562,464 1,555,716
Construction work in progress 107,233 112,750
------------ ------------
Net Utility Plant 1,669,697 1,668,466
------------ ------------
Current Assets:
Cash and cash equivalents 3,570 2,327
Accounts receivable 137,860 104,753
Unbilled revenue receivable 47,735 61,330
Materials and supplies 17,139 19,627
Gas stored underground 9,680 38,989
Prepayments 34,813 21,563
------------ ------------
Total Current Assets 250,797 248,589
------------ ------------
Deferred Debits:
Unamortized debt expense 19,194 19,326
Deferred finance charges-Nine Mile Two 19,242 19,242
Deferred ice storm charges 21,006 21,621
Uranium enrichment decommissioning
deferral 23,192 23,421
Nuclear generating plant decommissioning
fund 41,490 38,930
Nine Mile Two deferred costs 34,251 34,513
Regulatory asset-income taxes 241,437 241,741
Investment in Empire 38,625 38,560
Other 115,634 103,221
------------ ------------
Total Deferred Debits 554,071 540,575
------------ ------------
$2,474,565 $2,457,630
============ ============
See Accompanying Notes to Financial Statements
1
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
Capitalization and Liabilities
March 31 December 31
1994 1993
------------ ------------
Capitalization
Long term debt - mortage bonds $655,742 $655,731
Long term debt - 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 42,000
Common shareholders' equity
Common stock
Authorized 50,000,000 shares; 37,096,064
shares outstanding at March 31, 1994
and 36,911,265 shares outstanding at
December 31, 1993. 658,042 652,172
Retained earnings 89,873 75,126
------------ ------------
Total Common Shareholders' Equity 747,915 727,298
------------ ------------
Total Capitalization 1,617,557 1,583,929
------------ ------------
Long Term Liabilities (Department of Energy):
Nuclear waste disposal 68,591 68,055
Uranium enrichment decommissioning 21,870 21,749
------------ ------------
Total Long Term Liabilities 90,461 89,804
Current Liabilities:
Long term debt due within one year 18,500 21,250
Preferred stock redeemable within one year - 6,000
Notes Payable - Empire 29,600 29,600
Short term debt 20,000 68,100
Accounts payable 55,860 52,596
Dividends payable 18,092 18,066
Taxes accrued 32,741 6,472
Interest accrued 16,462 12,955
Other 12,711 19,491
------------ ------------
Total Current Liabilities 203,966 234,530
------------ ------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 423,765 425,648
Deferred finance charges - Nine Mile Two 19,242 19,242
Pension costs accrued 33,642 31,919
Other 85,932 72,558
------------ ------------
Total Deferred Credits and Other Liabilities 562,581 549,367
------------ ------------
Commitments and Other Matters (Note 2) - -
------------ ------------
Total Capitalization and Liabilities $2,474,565 $2,457,630
============ ============
See Accompanying Notes to Financial Statements
2
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
For the Three Months Ended
March 31, 1994 March 31, 1993
-------------- --------------
Operating Revenues
Electric $167,472 $153,489
Gas 138,520 111,265
---------- ----------
305,992 264,754
Electric sales to other utilities 4,060 7,521
---------- ----------
Total Operating Revenues 310,052 272,275
Fuel Expenses
Fuel for electric generation 12,556 14,567
Purchased electricity 10,670 7,003
Gas purchased for resale 85,066 62,886
---------- ----------
Total Fuel Expenses 108,292 84,456
Operating Revenue less Fuel Expenses 201,760 187,819
Other Operating Expenses
Operations excluding fuel expenses 60,100 58,761
Maintenance 16,506 14,097
Depreciation and amortization 21,408 20,727
Taxes - local, state and other 36,999 33,209
Federal income tax 19,569 16,901
---------- ----------
Total Other Operating Expenses 154,582 143,695
Operating Income 47,178 44,124
Other Income and Deductions
Allowance for other funds
used during construction 92 17
Federal income tax 12 548
Other - net 1,702 805
---------- ----------
Total Other Income and Deductions 1,806 1,370
Income before Interest Charges 48,984 45,494
Interest Charges
Long term debt 13,685 14,804
Other - net 1,607 1,974
Allowance for borrowed funds
used during construction (545) (368)
---------- ----------
Total Interest Charges 14,747 16,410
Net Income 34,237 29,084
Dividends on Preferred Stock 1,770 1,825
---------- ----------
Earnings Applicable to Common Stock $32,467 $27,259
========== ==========
Weighted average number of shares
outstanding in each period (000's) 37,033,679 34,903,016
Earnings per Common Share $0.87 $0.78
Cash Dividends Paid per Common Share $0.44 $0.43
See accompanying Notes to Financial Statments 3
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Three Months Ended
March 31,
1994 1993
-------- --------
Cash Flow from Operations:
Net income $34,237 $29,084
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 21,408 20,727
Amortization of nuclear fuel 4,106 4,674
Deferred fuel - electric (6,112) (1,594)
Deferred income taxes, net (663) 237
Allowance for funds used during construction (637) (385)
Unbilled revenue, net 13,595 9,367
Ice storm costs 615 825
Nuclear generating plant decommissioning (2,560) (2,373)
Uranium enrichment decommissioning 121 -
Changes in certain current assets and liabilities:
Accounts receivable (33,107) (27,070)
Materials and supplies 2,488 4,356
Taxes accrued 26,269 20,314
Interest accrued 3,507 (441)
Accounts payable 3,264 2,061
Other current assets and liabilities, net 10,425 (10,485)
Other, net 9,270 4,184
-------- --------
Total Operating 86,226 53,481
Cash Flow from Investing Activities:
Utility Plant
Plant additions (20,202) (24,898)
Nuclear fuel additions (6,389) (6,233)
Less:Allowance for funds used during construction 637 385
-------- --------
Additions to Utility Plant (25,954) (30,746)
Investment in Empire-net (65) -
Other, net 7 (120)
-------- --------
Total Investing (26,012) (30,866)
Cash Flow from Financing Activities:
Proceeds from sale of common stock 4,495 4,084
Proceeds from sale of long term debt - 120,000
Proceeds from sale of preferred stock 25,000 -
Short term borrowing (48,100) (38,600)
Retirement of long term debt (2,750) (72,750)
Retirement of preferred stock (18,000) (12,000)
Capital stock expense 1,375 933
Discount and expense of issuing long term debt (400) (4,254)
Dividends paid on preferred and common stock (18,066) (17,036)
Other, net (2,525) (2,364)
-------- --------
Total Financing (58,971) (21,987)
Increase in cash and cash equivalents $1,243 $628
Cash and cash equivalents at beginning of period 2,327 1,759
-------- --------
Cash and cash equivalents at end of period $3,570 $2,387
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Three Months Ended
March 31,
1994 1993
---------- ----------
Cash paid during the period:
Interest paid (net of capitalized amount) $10,469 $15,830
Income taxes paid $1,198 $720
See Accompanying Notes to Financial Statements.
4
/TABLE
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. 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 for the year ended December 31, 1993.
Operating Federal Income Tax Provision (Thousands of Dollars)
For the Three Months
Ended March 31,
--------------------
1994 1993
---- ----
Current $20,902 $17,193
Deferred: ------- -------
Ice Storm (215) (177)
Class life depreciation 4,270 4,575
Excess fuel costs - net 2,193 263
Nuclear decommissioning (283) (467)
Unbilled revenues (4,758) (3,184)
Other (2,540) (1,302)
------- -------
Total Deferred (1,333) (292)
------- -------
Total Operating $19,569 $16,901
======= =======
STATEMENT OF FINANCIAL ACCOUNTING STANDARDS 112 AND 115
Statement of Financial Accounting Standards 112 (SFAS-112),
"Employees' Accounting for Postemployment Benefits", was adopted by the Company
during the first quarter of 1994. SFAS-112 requires the Company to recognize
the obligation to provide postemployment benefits to former or
5
inactive employees after employment but before retirement.
The postemployment obligation at March 31, 1994 was approximately $11 million.
The postemployment benefit obligation is being deferred on the balance sheet.
The Company will petition the PSC for recovery of incremental expenses as the
result of SFAS-112 by the end of 1994.
Statement of Financial Accounting Standards 115 (SFAS-115),
"Accounting for Certain Investments in Debt and Equity Securities" is effective
for calendar year 1994 and requires that debt and equity securities not held to
maturity or held for trading purposes be recorded at fair value with unrealized
gains and losses excluded from earnings and recorded as a separate component of
shareholders' equity. The Company's accounting policy prescribed by the PSC
with respect to its Nuclear Decommissioning Trusts is to reflect the Trusts'
assets at market value and reflect unrealized gains and losses as a change in
the corresponding accrued decommissioning liability. Accordingly, the adoption
of SFAS 115 is not expected to significantly impact the Company's financial
statements.
Note 2. Commitments and Other Matters
CAPITAL EXPENDITURES.
The Company's 1994 construction expenditures program is currently
estimated at $138 million, including $16 million related to replacement of the
steam generators at the Ginna Nuclear Plant and $2 million of Allowance for
Funds Used During Construction (AFUDC). The Company had expended $25 million,
including $1 million for steam generator replacement at the Ginna Nuclear Plant
and $1 million of AFUDC as of March 31, 1994. The Company has entered into
certain commitments for the purchase of materials and equipment in connection
with that program.
NUCLEAR-RELATED MATTERS.
DECOMMISSIONING TRUST. Under accounting procedures approved by
Public Service Commission of the State of New York (PSC), the Company has been
collecting in its electric rates amounts for the eventual decommissioning of
its Ginna Plant and for its 14% share of the decommissioning of Nine Mile Two.
The operating licenses for these plants expire in 2009 and 2026 respectively.
The Company has collected approximately $63.4 million through March 31, 1994.
The Nuclear Regulatory Commission (NRC) requires reactor licensees to
submit funding plans that establish minimum external funding levels for reactor
decommissioning. The Company's plan consists principally of an external
decommissioning trust fund covering both its Ginna Plant and its Nine Mile Two
share. Since 1990, the Company has contributed some $39.2 million to this
fund. In addition, the Company maintains an internal reserve to fund the
removal of non-radioactive structures, a feature not covered by the NRC minimum
funding.
6
In connection with the Company's rate settlement completed in August
1993, the PSC approved the collection during the rate year ending June 30, 1994
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 $150.7 million for Ginna and $34.3 million for the Company's 14% share
of Nine Mile Two (January 1993 dollars). This estimate is based principally on
the application of a NRC formula to determine minimum funding. 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 intends to fund the external decommissioning trust in the
amount of the NRC minimum funding requirement. The difference between the
amount to be collected and the NRC minimum will be held in an internal reserve.
The Company is aware of recent NRC activities related to upward
revisions to the required minimum funding levels. These activities, primarily
focused on disposition of low level radioactive waste, may require the Company
to increase funding. The Company continues to monitor these activities but
cannot predict what regulatory actions the NRC may ultimately take.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND.
Nuclear reactor licensees in the U.S. are assessed annually for the
decontamination and decommissioning of Department of Energy (DOE) enrichment
facilities. The Company made the first of 15 annual payments for this purpose
in September 1993, remitting approximately $1.6 million ($1.5 million for the
Ginna Plant and $0.1million for its share of the Nine Mile Two plant). For the
two facilities the Company recognized liabilities at March 31, 1994 of $23.5
million ($21.8 million as a long-term liability and $1.7 million as a current
liability). In October 1993, the Company began recovery of this deferral
through its fuel adjustment clause.
INSURANCE PROGRAM. The Price-Anderson Act establishes a federal
program, providing indemnification and insurance against public liability,
applicable in the event of a nuclear accident at a licensed U.S. reactor. As a
result of amendments to the Act in 1988, the limit of liability has increased
to approximately $9.3 billion. Also in 1988 coverage was expanded to include
precautionary evacuations and the Act was extended until the year 2002. Under
the program, claims would first be met by insurance which licensees are
required to carry in the maximum amount available (currently $200 million). If
claims exceed that amount, licensees are subject to a retrospective assessment
up to $75.5 million per licensed facility for each nuclear incident, payable at
a rate not to exceed $10 million per year. Those assessments are subject to
periodic inflation-indexing and to a 5% surcharge if funds prove insufficient
to pay claims. In addition, the retrospective assessments would be subject to
a
7
three percent charge for premium tax. The Company's interests in two nuclear
units could thus expose it to a potential liability for each accident of $86.1
million through retrospective assessments of $11.4 million per year in the
event of a sufficiently serious nuclear accident at its own or another U.S.
commercial nuclear reactor.
Beginning in 1988, coverage for claims alleging radiation-induced
injuries to some workers at nuclear reactor sites was removed from the nuclear
liability insurance policies purchased by the Company. Coverage for workers
first engaged in nuclear-related employment at a nuclear site prior to 1988
continues to be provided under then-existing nuclear liability insurance
policies. Those workers first employed at a nuclear facility in 1988 or later
are covered under a separate, industry-wide insurance program. That program
contains a retrospective premium assessment feature whereby participants in the
program can be assessed to pay incurred losses that exceed the program's
reserves. Under the plan as currently established, the Company could be
assessed a maximum of $3.1 million over the life of the insurance coverage.
The Company is a member of Nuclear Electric Insurance Limited, which
provides insurance coverage for the cost of replacement power during certain
prolonged accidental outages of nuclear generating units and coverage for
property losses in excess of $500 million at nuclear generating units. As of
March 31, 1994, the Company is purchasing a weekly indemnity limit of $3.5
million in the NEIL I replacement power expense program and full policy limits
of $1.4 billion in the NEIL II Property Insurance Program for the Ginna Nuclear
Power Plant. Coverage under the Property Insurance Program includes the
shortfall in the NRC required external trust fund resulting from the premature
decommissioning of a nuclear power plant following an accident with property
damage in excess of $500 million. The Company currently has designated $166
million as a sublimit for this coverage at the Ginna Nuclear Power Plant. For
its share in the generation of Nine Mile Two the Company purchases a weekly
indemnity limit of $.5 million in the NEIL I replacement power expense program.
The owners at Nine Mile Two purchase the full policy limit of $1.4 billion in
the NEIL II Property Insurance Program and the Company pays its proportionate
share of those premiums. The owners at Nine Mile Two have selected the maximum
available sublimit of $250 million for premature decommissioning. If an
insuring program's losses exceeded its other resources available to pay claims,
the Company could be subject to maximum assessments in any one policy year of
approximately $4.9 million and $14.2 million in the event of losses under the
replacement power and property damage coverages, respectively.
ENVIRONMENTAL MATTERS.
The production and delivery of energy are necessarily accompanied by
the release of by-products subject to environmental controls. In
8
recognition of the Company's responsibility to preserve the quality of the air,
water, and land it shares with the community it serves, the Company has taken a
variety of measures (e.g., self-auditing, recycling and waste minimization,
training of employees in hazardous waste management) to reduce the potential
for adverse environmental effects from its energy operations and, specifically,
to manage and appropriately dispose of wastes currently being generated. The
Company, nevertheless, has been contacted, along with numerous others,
concerning wastes shipped off-site to licensed treatment, storage and disposal
sites where authorities have later questioned the handling of such wastes. In
such instances, the Company typically seeks to cooperate with those authorities
and with other site users to develop cleanup programs and to fairly allocate
the associated costs.
As part of its commitment to environmental excellence, the Company is
conducting proactive Site Investigation and Remediation (SIR) efforts at
Company-owned sites where past waste handling and disposal may have occurred.
The Company currently estimates the total costs it could incur for SIR
activities at Company-owned sites to be about $20 million. This estimate will
vary as better site information is available. The Company anticipates spending
$10 million over the next 5 years on SIR initiatives. Approximately $4.5
million has been provided for in rates through June 1996 for recovery of SIR
costs. To the extent actual expenditures differ from this amount, they will be
deferred for future disposition and recovery as authorized by the PSC.
In 1985, the New York State Department of Environmental Conservation
(NYSDEC) identified property in the vicinity of the Lower Falls of the Genesee
River (the Lower Falls) in Rochester as an inactive hazardous waste disposal
site. The Company owns, and was the prior owner or operator of, a number of
locations within the Lower Falls. In mid-1991, NYSDEC advised the Company that
it had delisted the Lower Falls site, i.e., removed it from its Registry of
Inactive Hazardous Waste Disposal Sites. The effect of delisting is to
terminate the Company's status as a potentially responsible party for the Lower
Falls site, to discontinue the pending NYSDEC review of a joint Company/City of
Rochester proposal for a limited further investigation of the Lower Falls, to
defer the prospect of remedial action and perhaps to end any Company sharing of
the cost thereof. However, NYSDEC also stated its intention to consider
listing individual coal gasification sites within the larger, original site
once the State of New York adopts new federal hazardous waste criteria. There
is at least some material at one of the individual coal gasification sites that
could trigger relisting. The Company is unable to predict what further listing
action NYSDEC may take, but regards the delisting as a positive development.
The Company and its predecessors formerly owned and operated coal
gasification facilities within the Lower Falls. In September 1991 the Company
initiated a study of subsurface conditions in the vicinity of
9
retired facilities at its West Station property and has since commenced the
removal of soils containing hazardous substances in order to minimize any
potential long-term exposure risks. Cleanup efforts have been temporarily
suspended while the Company investigates more cost effective remedial
technologies. The Company is now in the process of obtaining a modification of
an air permit in order to allow some material from its West Station property to
be burned in a coal-fired boiler as a possible disposal strategy.
On a portion of the Company's property in the Lower Falls, and
elsewhere in the general area, the County of Monroe has installed and operates
sewer lines. During sewer installation, the County constructed over Company
property, pursuant to an easement which the Company granted the County, certain
retention ponds which reportedly received from the sewer construction area
certain fossil-fuel-based materials ("the materials") found there. In July
1989 the Company received a letter from the County asserting that activities of
the Company left the County unable to effect a regulatorily-approved closure of
the retention pond area. The County's letter takes the position that it
intends to seek reimbursement for its additional costs incurred with respect to
the materials once the NYSDEC identifies the generator thereof and that any
further cleanup action which the NYSDEC may require at the retention pond site
is the Company's responsibility. In the course of discussions over this
matter, the County has claimed, without offering any evidence, that the Company
was the original generator of the materials. It asserts that it will hold the
Company liable for all County costs -- presently estimated at $1.5 million --
associated both with the materials' excavation, treatment and disposal and with
effecting a regulatorily-approved closure of the retention pond area. The
Company could incur costs as yet undetermined if it were to be found liable for
such closure and materials handling, although provisions of the easement afford
the Company rights which may serve to offset all or a portion of any such
County claim. To date, the Company has agreed to pay a 20% share of the
County's investigation of this area, which commenced in September 1993 and
which is estimated to cost no more than $150,000, but no commitment has been
made toward any remedial measures which may be recommended by the
investigation.
In the letter announcing the delisting of the Lower Falls site,
NYSDEC indicated an intention to pursue appropriate closure of the County's
former retention pond area, suggesting that it will be evaluated separately to
determine whether it meets the criteria of a hazardous waste site. The Company
is unable to assess what implications the NYSDEC letter may have for the
County's claim against it.
At another location along the River where the Company owns property,
a boring taken in Fall 1988 for a sewer system project showed a layer
containing a black viscous material. The Company undertook an investigation to
determine the extent of the layer. The study found that some of the soil and
ground water on-site had been adversely impacted by
10
the hazardous substance constituents of the black viscous material, but
evidence was inadequate to determine whether the material or its constituents
had migrated off-site. The matter was reported to the NYSDEC and, in September
1990, the Company also provided the agency with a risk assessment for its
review. That assessment concluded that the findings warranted no agency action
and that site conditions posed no significant threat to the environment.
Although NYSDEC could require the Company to undertake further investigation
and/or remediation, the agency has taken no action in the over three and one-
half years since the report's submittal.
In August 1990 the Company was notified of the existence of a federal
Superfund site located in Syracuse, NY, known as the Quanta Resources Site.
The federal Environmental Protection Agency (EPA) has included the Company in
its list of approximately 25 potentially responsible parties (PRPs) at the
site,but no data has been produced showing that any of its wastes were
delivered to the site. In return for its release from liability for that
phase, the Company has joined other PRPs in agreeing to divide among them,
utilizing a two-tier structure, EPA's cost of a contractor-performed removal
action intended to stabilize the site. The Company, in the lower tier of PRPs,
paid its $27,500 share of such cost. The NYSDEC has not yet made an assessment
for certain response and investigation costs it has incurred at the site, nor
is there as yet any information on which to base an estimate of the cost to
design and conduct at the site any remedial measures which federal or state
authorities may require.
On May 21, 1993, the Company was notified by NYSDEC that it was
considered a potentially responsible party (PRP) for the Frontier Chemical
Pendleton Superfund Site located in Pendleton, NY. The Company has signed a
PRP Agreement with 14 other participating parties who have signed an
Admiistrative Order on Consent with NYSDEC. The Order on Consent obligates the
parties to implement a work plan and remediate the site. The PRPs have
negotiated a workplan for site remediation and have retained a consulting firm
to implement the workplan. Preliminary estimates indicate site remediation
will be between $6 and $8 million. The Company is participating with the group
to allocate costs among the PRPs. Although an allocation scheme has yet to be
developed, in April 1994 the Company recorded an estimated liability of $0.7
million for site remediation based on volume of material shipped.
Monitoring wells installed at another Company facility in 1989
revealed that an undetermined amount of leaded gasoline had reached the
groundwater. The Company has continued to monitor free product levels in the
wells, and has begun a modest free product recovery project, reports on both of
which are routinely furnished to the NYSDEC. Free product levels in the wells
have declined, but authorities may require further remediation once most of the
free product has been recovered.
The Company is developing strategies responsive to the Federal Clean
Air Act Amendments of 1990 (Amendments). The Amendments will
11
primarily affect air emissions from the Company's fossil-fueled electric
generating facilities. The Company is in the process of identifying the
optimum mix of control measures that will allow the fossil fuel based portion
of the generation system to fully comply with applicable regulatory
requirements. Although work is continuing, not all compliance control measures
have been determined. The Company has adopted control measures for nitrogen
oxides (NOx) emissions which must be in effect by the federally mandated
compliance date of May 31, 1995. The chosen NOx control measures consist of
the installation of low NOx burners on some units, the derating of unit
generation by taking burners out of service on other units and placing one unit
on cold standby with the redistribution of load to the remaining more efficient
units. Capital costs for NOx controls and the installation of continuous
emission monitoring systems are not expected to exceed $6.8 million and will be
incurred during 1994 and 1995. A range of capital costs between $20 million
and $30 million (1993 dollars) has been estimated for the implementation of
several potential scenarios which would enable the Company to meet the
foreseeable future NOx and sulphur dioxide requirements of the Amendments.
These capital costs would be incurred between 1996 and 2000. The Company
currently estimates that it could also incur up to $2 million (1993 dollars) of
additional annual operating expenses, excluding fuel, to comply with the
Amendments. The use of scrubbing equipment is not presently being considered.
Likewise, the purchase or sale of "emission allowances," as allowed by the
Amendments, is not currently being considered. The Company anticipates that
the costs incurred to comply with the Amendments will be recoverable through
rates based on previous rate recovery of environmental costs required by
governmental authorities.
GAS COST RECOVERY.
Many interstate gas pipeline companies entered into contracts with
gas producers which required the pipeline companies to pay for a minimum amount
of gas whether or not the gas is actually taken from the producer (take-or-pay
costs). Pursuant to FERC authorization, the Company's gas suppliers have
included certain amounts of their take-or-pay costs in the rates charged to the
Company.
The PSC instituted a proceeding in October 1988 to determine the
extent to which the gas distribution companies in New York State would be
permitted to recover in rates the take-or-pay costs imposed upon them. Through
a series of subsequent settlements between the Staff of the PSC and the
Company, the Company was permitted to recover in rates 87.5% of the first $12
million of the pipeline take-or-pay costs imposed upon it and all such costs in
excess thereof except for a maximum of $562,500.
As of March 31, 1994 the Company had been billed for $17.7 million of
take-or-pay costs and has thus far recovered $16.4 million from its customers.
The Company expects only insignificant amounts of take-or-pay costs remain to
be billed to the Company.
12
As a result of the restructuring of the gas transportation industry
by the FERC, there will be a number of changes in this aspect of the Company's
business over the next several years. These changes, which will apply
throughout the industry, will affect different companies differently and may
result, at least initially, in increases in the gas transportation costs of the
Company. The Company will also be required to pay a share of certain
transition costs incurred by the pipelines as a result of the FERC
restructuring. Although the final amounts of such transition costs are subject
to continuing negotiations with several pipelines and ongoing pipeline filings
requiring FERC approval, the Company expects such costs to range between $43.5
and $52.0 million. A substantial portion of such costs will be on the CNG
Transmission Corporation (CNG) system of which approximately $27 million was
billed to the Company on December 3, 1993 payable over the following three
years. The Company has begun collecting those costs in its gas adjustment
clause.
In a related matter, in connection with the development of the Empire
State Pipeline ("Empire") which commenced operation in November 1993, the
Company is committed to transportation capacity from Empire, to upstream
pipeline transportation and storage service and to the purchase of natural gas
in quantities corresponding to these transportation and storage arrangements.
The Company also has certain contractual obligations with CNG whereby the
Company is subject to demand charges for transportation capacity for a period
of eight years. In October 1993, the effective date of implementation of
pipeline restructuring pursuant to FERC Order No. 636 and CNG's individual
restructuring in Docket No. RS92-14, CNG's transportation rights on upstream
pipelines were assigned to its customers, including the Company. The Company
has concluded the corresponding contracts with those upstream pipelines.
The transportation service to be provided by Empire was scheduled to
phase in over 12 months, at which point the combined CNG and Empire
transportation capacity would have exceeded the Company's current requirements.
Therefore, the Company recently entered into a marketing agreement with CNG,
pursuant to which CNG will assist the Company in obtaining permanent
replacement customers for the transportation capacity the Company will not
require. It may renegotiate its arrangements with CNG and/or Empire or it may
negotiate assignment, on a permanent or temporary basis, of the transportation
capacity that exceeds the requirements of its customers. In addition, under
FERC rules, the Company may sell its excess transportation capacity in the
market. While CNG has already secured letters of intent for a substantial
portion of such capacity, whether and to what extent CNG and/or the Company can
successfully negotiate the assignment or sale of the excess capacity, or at
what price, cannot be determined at the present time. The retention of some or
all of this excess transportation capacity may cause an increase in the
Company's gas supply costs. This would be in addition to any increase caused
by other aspects of the gas transportation restructuring.
13
GAS PURCHASE UNDERCHARGES.
The Company became aware during 1993 that it did not account properly
for certain gas purchases for the period August 1990 - August 1992 resulting in
undercharges to gas customers of approximately $7.5 million. The Company had
previously estimated the effect to approximate as much as $10 million; however,
further review determined that the magnitude of the error on previously
reported operations was substantially less.
The undercharges arose from the increased complexity arising from the
federal deregulation of the gas industry and the Company's transition from a
full requirements customer of one gas supplier to the purchase of gas
transportation service and natural gas on the open market. Problems of this
type are routinely corrected through the Gas Adjustment Clause process and
appropriate amounts are collected from or refunded to customers. Of the total
undercharges, $2.3 million has previously been expensed and $5.2 million had
been deferred on the Company's balance sheet.
The Company advised the PSC and all parties to the Company's most
recent rate proceeding of the undercharges. In its August 24, 1993 Order
approving the Company's three-year rate settlement the PSC made the Company's
current gas rates temporary solely to consider the impacts of the erroneous gas
accounting, and in a September 13, 1993 Order the PSC instituted a proceeding
to investigate the resulting undercollections and the recoverability of such
amounts from customers. In its September 13 Order the PSC directed the Company
to demonstrate fully the existence and amount of the undercharges, to explain
the reasons for the errors, and to address possible general and specific legal
limitations on the Company's right to recover portions of the undercharges.
The Company filed evidence and analysis responsive to that Order on October 27,
1993.
On December 30, 1993, a proposed settlement among the Company, PSC
Staff and another party was filed with the PSC. It provided for the recovery
in rates of $3.2 million over three years, subject to audit and to limitations
on rate adjustments established in the August 24 Order. Due to the limitations
established for the first year of the rate settlement and higher than expected
costs for gas, the Company will not be able to begin recovery of the
undercharges until the second year of the rate settlement. The PSC invited
public comment on the proposed settlement and received no opposing comments.
The PSC Staff completed its audit, reporting its results by letter to the PSC
dated February 14, 1994 and recommended, as a consequence of the audit, that
the amount recovered in rates be reduced by $.6 million. The Company accepted
the PSC Staff adjustment. By Order issued March 21, 1994, the PSC approved the
settlement, including the PSC Staff Adjustment, and made permanent the gas
rates that had previously been made temporary pursuant to the August 24 Order.
The Company wrote off $2.0 million of the undercharges as of December 31, 1993.
The 1993 write-off amounted to a reduction in 1993 earnings of four cents per
share, net of tax. In April 1994 the Company wrote off an additional $.6
million. The
14
1994 writeoff amounts to a reduction in 1994 earnings of approximately one cent
per share, net of tax.
OTHER MATTERS.
NUCLEAR FUEL ENRICHMENT SERVICES. The Company has a contract with
the United States Enrichment Corporation (USEC), formerly with the DOE, for
nuclear fuel enrichment services which assures provision of 70% of the Ginna
Nuclear Plant's requirements throughout its service life or 30 years, whichever
is less. No payment obligation accrues unless such enrichment services are
needed. Annually, the Company is permitted to decline USEC-furnished
enrichment for a future year upon giving ten years' notice. Consistent with
that provision, the Company has terminated its commitment to USEC for the years
2000, 2001 and 2002. The USEC waived, for an interim period, the obligation to
give ten years' notice for 2003. The Company has secured the remaining 30% of
its Ginna requirements for the reload years 1994 through 1995 under different
arrangements with USEC. The Company plans to meet its enrichment requirements
for years beyond those already committed by making further arrangements with
USEC or by contracting with third parties. The cost of USEC enrichment
services utilized for the next seven reload years (priced at the most current
rate) ranges from $4 million to $7 million per year.
ASSERTION OF TAX LIABILITY. The Company's federal income tax returns
for 1987 and 1988 have been examined by the Internal Revenue Service (IRS)
which has proposed adjustments of approximately $29 million.
The adjustments at issue generally pertain to the characterization
and treatment of events and relationships at the Nine Mile Two project and to
the appropriate tax treatment of investments made and expenses incurred at the
project by the Company and the other co-tenants. A principal issue appears to
be the year in which the plant was placed in service.
The Company has filed a protest of the IRS adjustments to its 1987-88
tax liability and has had an initial hearing before the appeals officers. The
Company believes it has sound bases for its protest, but cannot predict the
outcome thereof. Generally, the Company would expect to receive rate relief to
the extent it was unsuccessful in its protest except for that part of the IRS
assessment stemming from the Nine Mile Two disallowed costs, although no such
assurance can be given.
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.
LIQUIDITY AND CAPITAL RESOURCES
The Company anticipates meeting its 1994 capital requirements,
including debt maturity and sinking fund obligations, primarily from the use of
internally generated funds and short-term borrowings. Any refinancing activity
would require additional external financing. During the first three months of
1994 cash flow from operations, together with proceeds from external financing
activity (see Consolidated Statement of Cash Flows), provided the funds for
construction expenditures, the retirement of long-term debt and short-term
borrowings and the retirement and refinancing of preferred stock.
CAPITAL REQUIREMENTS
The Company's capital requirements relate primarily to expenditures
for electric generation, transmission and distribution facilities and gas mains
and services as well as the repayment of existing debt. The Company continues
to make generating plant modifications and its construction program focuses 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 either has contracts
or is continuing negotiations for the realization of approximately 24 megawatts
of capacity savings being phased-in over the 1993-1996 period under its demand
side management program and, beginning in late 1994 or early 1995, expects
approximately 55 megawatts of capacity to be supplied by a cogenerator under
contract with the Company. The Company has no other obligations with non-
utility generating companies at this time.
Total 1994 capital requirements are currently estimated at $177
million, of which $138 million are for construction, including $2 million of
AFUDC, and $39 million are for securities redemptions, maturities and mandatory
sinking fund obligations, excluding refinancings. Approximately $25 million,
including $1 million for AFUDC, had been expended for construction as of March
31, 1994, reflecting primarily expenditures for electric generating plant to
improve operating reliability and to comply with regulatory requirements,
expenditures for upgrading electric transmission and distribution facilities
and gas mains and expenditures for nuclear fuel.
16
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 ordered and most of these components have been
delivered. Major sub-assemblies are now being fabricated. Engineering for the
installation is underway and is expected to be completed well before the
scheduled installation. Cost of the replacement is estimated at $115 million,
about $40 million for the units, about $50 million for installation and the
remainder for engineering and other services. In 1993 the Company spent $15
million for the steam generator replacement. The Company spent $1 million on
this project in the first quarter and expects to spend about $16 million in
1994.
In November 1993 the Company received its first deliveries of gas on
the Empire State Pipeline (Empire), an intrastate natural gas pipeline subject
to PSC regulation which extends from Grand Island to Syracuse, New York and
connects to the Company's gas distribution facilities. Empire will provide
capacity for up to 50 percent of the Company's gas requirements by its second
year of operation. In 1992, the Company formed a wholly owned subsidiary,
Energyline Corporation (Energyline) to acquire its ownership interest in
Empire. The Company's share of ownership in Empire will be dependent upon final
project costs and the timing and method of financing selected by the Company.
In June 1993 Empire secured a $150 million credit agreement, the proceeds of
which are to finance approximately 75 percent of the total construction cost
and initial operating expenses. At March 31, 1994 the Company had invested a
net amount of $10.2 million in Energyline and was committed for $9.7 million of
the borrowings under the credit agreement. The Company's investment in
Energyline was consolidated for accounting and reporting purposes with the
accounts of the Company. Such consolidation resulted in a $.6 million credit
to Other Income during the first quarter of 1994.
The Company redeemed $20.75 million of securities during the first
three months of 1994. On February 15, 1994 the Company reduced its long term
debt by $2.75 million pursuant to a cash sinking fund payment on its 10.95%
First Mortgage Bonds, Series FF. On March 1, 1994 the Company redeemed $18
million of its 8.25% Preferred Stock, Series R. Funds for these redemptions
came from the issuance of short-term debt and internally generated funds.
FINANCING
The Company is utilizing its credit agreements to meet any interim
external financing needs prior to issuing any long-term securities. Interim
financing is available from certain domestic banks in the form of short-term
borrowings under a $90 million revolving credit agreement which continues until
December 31, 1996 and may be extended annually. Borrowings under this revolver
are secured by a subordinated mortgage on substantially
17
all its property except cash and accounts receivable. In addition, the Company
entered into a Loan and Security Agreement with a domestic bank until December
31, 1994 providing for up to $20 million of short-term debt. Borrowings under
this agreement are secured by the Company's accounts receivable. The Company
also has unsecured short-term credit facilities totaling $72 million. At March
31, 1994 the Company had short-term borrowings outstanding of $20 million all
of which were secured under the revolving credit agreement described above.
Under provisions of the Company's Certificate of Incorporation, 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 the majority of the holders of outstanding preferred stock. Under
this restriction the Company was able to issue $74 million of unsecured debt as
of March 31, 1994. A shelf registration on Form S-3 became effective in August
1993 providing for the offering of $250 million of new securities. The Company
may use the shelf registration to offer from time to time its First Mortgage
Bonds in one or more series, its Preferred Stock in one or more series and its
Common Stock depending on market conditions and Company requirements. The net
proceeds from the sale of the securities will be used to finance a portion of
the Company's capital requirements, to discharge or refund certain outstanding
indebtedness or preferred stock of the Company, to satisfy certain sinking fund
obligations or for general corporate purposes. Including the preferred stock
described below, the Company has thus far issued approximately $69.4 million of
equity securities under this shelf registration.
On March 22, 1994 the Company completed the public sale of 250,000
shares of 6.60% Preferred Stock, Series V (Cumulative, $100 par value). Net
proceeds to the Company of $24,781,250 after deducting underwriting commissions
of $218,750 were used to retire short-term debt.
During the first three months of 1994, the Company issued 184,799
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 $4.5 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 March 31, 1994 the Company had Common Stock
available for issuance of 1,038,386 shares under the ADR Plan and 223,518
shares under the Savings Plus Plan.
CAPITAL STRUCTURE
The Company's retained earnings at March 31, 1994 were $89.9 million,
an increase of approximately $14.7 million compared with December 31, 1993.
Long-term debt at March 31, 1994, including that due within one year, decreased
approximately $2.7 million compared with December 31, 1993,
18
reflecting the redemption of long-term debt as discussed under "Capital
Requirements". Preferred Stock, including that due within one year, increased
approximately $7.0 million, reflecting the net change from the sale and
redemption of preferred stock as discussed under "Capital Requirements" and
"Financing". Common equity increased approximately $20.6 million, reflecting
the issuance and sale of Common Stock as discussed under "Financing" and an
increase in retained earnings. Capitalization at March 31, 1994, was comprised
of 44.4 percent common equity, 7.2 percent preferred equity and 48.4 percent
long-term debt. The Company has $18.5 million of long-term debt due within one
year which, if included in capitalization, would increase the long-term debt
component of capitalization at March 31, 1994 to 49.8 percent, decrease the
preferred stock component to 6.9 percent and reduce common equity to 43.3
percent of capitalization. It is the Company's long-term objective to move to
a less leveraged capital structure and to increase the common equity percentage
of capitalization toward the 50 percent range.
RATE BASE AND REGULATORY POLICIES
The Company is subject to regulation of rates, service, and sale
of securities, among other matters, by the PSC. On August 24, 1993 the PSC
issued an order approving a settlement agreement (1993 Rate Agreement) among
the Company, PSC Staff and other interested parties. This agreement resolves
the Company's rate proceedings initiated in July 1992. Retroactive application
of new rates to July 1, 1993 was authorized by the PSC. The 1993 Rate
Agreement discussed below will determine the Company's rates through June 30,
1996 and includes certain incentive arrangements providing for both rewards and
penalties.
A summary of the 1993 Rate Agreement is presented in the table below.
The 1993 Rate Agreement amounts are based on an allowed return on common equity
of 11.50% through June 30, 1996. Earnings between 8.50% and 14.50% will be
absorbed/retained by the Company. Earnings above 14.50% will be refunded to
the customers. If, but not unless, earnings fall below 8.50%, or if cash
interest coverage falls below 2.2 times, the Company can seek relief by
petitioning the PSC for a review of the 1993 Rate Agreement terms.
19
Amount of
Increase Rate of Rate of
(Decrease) Percent Return on Return on
Class of (Annual Basis) Increase Rate Base Equity
Service Date of Increase (000's) (Decrease) Authorized Authorized
-------- ---------------- --------- --------- ---------- ----------
Electric July 1, 1993* $18,500 2.8% 9.46% 11.50%
July 1, 1994* 20,900 2.9 9.39 11.50
July 1, 1995* 21,800 2.9 9.41 11.50
Gas July 1, 1993* 2,600 1.1 9.46 11.50
July 1, 1994* 4,400 1.8 9.39 11.50
July 1, 1995* 4,300 1.7 9.41 11.50
* See below for additional details.
The following measures were incorporated into the 1993 Rate Agreement:
- - Incentive mechanisms that have the potential to either increase or reduce
earnings from 5 to 70 basis points each, depending on the Company's ability to
meet a variety of prescribed targets in the areas of electric fuel costs,
demand side management, service quality and integrated resource management
(relative electric production efficiency). During the rate year ending June
30, 1994, these incentives have the potential to affect earnings by
approximately $12 million.
- - Mechanisms for sharing costs between customers and shareholders for operation
and maintenance expenses. In general, non-fuel operation and maintenance
expense variations are treated in three different ways depending upon the
amount of control the Company can exert over them. Those costs that are
directly manageable (approximately $172 million in the first rate year) have no
sharing and are absorbed by the Company, those costs that are not significantly
affected by management action in the short run (approximately $34 million in
the first rate year) are trued up 100% and variances resulting from all other
such costs (approximately $110 million in the first rate year) are shared 50%
by customers and 50% by the Company.
- - Mechanisms for sharing variances between forecasted and actual electric
capital expenditures related to production and transmission facilities. The
Company will retain the savings for cost of money and depreciation on
underspending variances. If there is an overspending variance, cumulatively
for the three year settlement period, the Company will write off 50% of such
variance. The write-off will be reduced by the cost of money and depreciation
expense incurred as a result of the variances. The settlement also provides
for a sharing mechanism regarding the replacement of the Ginna nuclear station
steam generators. A graduated sharing percentage is applied for up to $15
million of variances, plus or minus, from the forecasted cost of $115 million.
Variances above $130 million or below $100 million are absorbed by the Company.
20
- - An Electric Revenue Adjustment Mechanism designed to stabilize electric
revenues by eliminating the impact of variations in electric sales. A gas
weather normalization clause previously in place was retained.
To the extent incentive and sharing mechanisms apply, the negotiated
revenue increase shown in the table above may be adjusted up or down in the
second and third year of the agreement. As shown in the table below negotiated
electric rate increases could be reduced to zero or increased up to an
additional 1.5% in year two, 1.6% in year three and 1.8% in the following
year. Negotiated gas rate increases could also be reduced to zero or increased
up to an additional 0.8% in year two, 0.9% in year three and 1.1% in the
following year, exclusive of the impact of the Empire State Pipeline going into
service.
Electric Gas
----------------------------- -----------------------------
Per After Adjustments Per After Adjustments
Rate ----------------- Rate -----------------
Agreement Minimum Maximum Agreement Minimum Maximum
--------- ------- ------- ---------- ------- -------
7/93 - 6/94 2.8% - - 1.1% - -
7/94 - 6/95 2.9% 0% 4.4% 1.8% 0% 2.6%
7/95 - 6/95 2.9% 0% 4.5% 1.7% 0% 2.6%
7/96 - 6/97 Forecast 0% Forecast Forecast 0% Forecast
+1.8% +1.1%
In March and April 1994 the Company filed with the PSC the
adjustments required under the various clauses of the 1993 Rate Agreement and
submitted a proposal for an electric revenue increase of $20.9 million (2.98%),
and a gas revenue increase of $6.3 million (2.52%) for the rate year beginning
July 1, 1994. In addition, cost recovery for Empire State Pipeline in the
amount of $1.4 million was transferred from the gas adjustment clause to base
rate revenues. A PSC decision on the proposed rates is expected by June 30,
1994.
Under the terms of the 1993 Rate Agreement the Company is entitled,
if adjustments so warrant, to increase electric revenues by 4.46%. The Company
has earned sufficient incentives to enable it to collect the maximum amount.
However, the proposed rates give consideration to the current and future
competitive environment by minimizing price impacts on the customer while
protecting earnings for shareholders. The Company has deferred for future
recovery under the terms of the 1993 Rate Agreement, those incentive amounts
which it has elected not to include in the proposed rates.
In July 1993 the Company requested approval from the PSC for a new
flexible pricing tariff for major industrial and commercial electric customers.
A settlement in this matter was approved by the PSC on March 19, 1994. This
tariff will allow the Company to negotiate competitive electric rates at
discount prices to compete with alternative power sources, such as
21
customer-owned generation facilities. Under the terms of the settlement, the
Company would absorb 30 percent of any net revenues lost as a result of such
discounts through June 1996, while the remainder would be recovered from other
customers. The portion recoverable after June 1996 is expected to be
determined in a generic proceeding currently being conducted by the PSC.
See Note 2 of the Notes to Financial Statements - Commitments and
Other Matters under the heading "Gas Purchase Undercharges" with respect to a
proceeding of the PSC to investigate the recoverability of certain undercharges
from customers.
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, 1994 to the corresponding three-month period ended March
31, 1993.
EARNINGS SUMMARY
Earnings Per Common Share
For the Periods Ended
March 31,
------------------------
1994 1993
---- ----
Three Months $ .87 $ .78
The Company's improved financial performance reflects a modest
increase in rates, reductions in interest on debt and continued cost control
efforts on the part of employees, coupled with savings due to a seven, percent
reduction in the work force resulting from early retirement programs
implemented late last year. The per share gain in earnings was partially
offset by the effect of issuance of an additional 2.1 million shares of Common
Stock since March of 1993.
OPERATING REVENUES AND SALES
Total Company revenues for the first three months of 1994 were $37.8
million or 13.9% above the first three months of 1993, with most of the gains
coming from rate relief and higher fuel costs. The impact of severe cold
weather this year was reduced due to rate provisions that moderate the effect
of abnormal weather on customer bills.
Revenues from OEU sales decreased $3.5 million or 46.0% for the
three-month comparison period mainly because excess generation was not
available from company generating facilities during planned shutdowns.
The principal factors causing changes in Electric and Gas Department
revenues are estimated below:
22
Comparison of
Three Months
Ended March 31,
1994 and 1993
-----------------------
Increase or (Decrease)
for comparison period
(Millions of Dollars)
Electric Gas
-------- ---
Rate increases $ 5.9 $ 1.6
Fuel costs 3.6 22.2
Weather effects (Heating) 3.1 .7
Customer consumption .9 (1.9)
Other .5 4.7
Total change in customer -------- -------
revenues 14.0 27.3
OEU sales (3.5) -
-------- -------
Total change in operating
revenues $ 10.5 $ 27.3
======= ======
FUEL EXPENSES
Fuel expenses increased in the first three months of 1994 reflecting
a higher sendout and unit cost of purchased gas and higher overall electric
fuel unit costs partially offset by a decrease in total unit sales of
electricity.
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES
The increases reflect mainly increased demand side management
expenses, higher cost for payroll and employee welfare and materials and
supplies.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased in the three-month comparison
period due mainly to an increase in depreciable plant.
TAXES
The increase in local, state and other taxes resulted primarily from
an increase in revenues combined with an increase in the revenue tax rate, an
increase in property tax rates and higher property assessments.
In August 1993, the Revenue Reconciliation Act of 1993 (1993 Tax Act)
was signed into law. Among other provisions, the 1993 Tax Act provides for a
Federal corporate income tax rate of 35% (previously 34%)
23
retroactive to January 1, 1993. The Company has adjusted its tax reserve
balances to reflect this new rate. There was no earnings impact since the
effects of the tax change have been deferred. The Company petitioned the PSC
in late 1993 for recognition and recovery of this incremental tax liability
which was not reflected in the provisions of its 1993 Rate Agreement. The PSC
issued a generic ruling on the treatment of the 1993 Tax Act providing for
deferral and future recovery of such expenses if jurisdictional companies met
certain requirements. On April 14, 1994 the Company made its compliance filing
demonstrating its belief that the effects of this Tax Act ($1,981,000 through
June 30, 1994, except for $160,000 stemming from gas operations in the first
half of calendar 1993) were recoverable. The ultimate recovery of this
deferral remains subject to a favorable decision by the PSC. See Note 1 of the
Notes to Financial Statements for further information regarding operating
federal income taxes.
OTHER STATEMENT OF INCOME ITEMS
The increase in allowance for funds used during construction (AFUDC)
reflects an increase in the amount of utility plant under construction and not
included in rate base.
Interest charges, excluding AFUDC, were reduced due to the
refinancing of long-term debt at lower interest rates, a decrease in long-term
debt and lower interest rates despite an upturn late in the 1994 first quarter.
The decrease in dividends on preferred stock reflects the redemption of
preferred stock on March 1, 1993 and March 1, 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The Company's Annual Meeting of Shareholders was held on April 20,
1994.
(b) The following Directors were elected for terms expiring at the
Annual Meeting of Shareholders in 1997: Allan E. Dugan,
Theodore L. Levinson, Arthur M. Richardson, and M. Richard Rose.
The following Directors are continuing in office after the meeting:
Angelo J. Chiarella, Jay T. Holmes, Cornelius J. Murphy,
Harry G. Saddock, William Balderston III, William F. Fowble,
Roger W. Kober and Constance M. Mitchell.
24
(c) The nominees for election as directors were elected by the
following vote:
Shares Shares Broker
For Withheld Non-Votes
---------- -------- ---------
Allan E. Dugan 31,680,918 496,005 0
Theodore L. Levinson 31,673,667 503,256 0
Arthur M. Richardson 31,615,570 561,353 0
M. Richard Rose 31,666,921 510,002 0
ITEM 5. OTHER EVENTS
In response to United Nations Framework Convention on Climate Change
treaty (Rio Treaty), the Clinton Administration released "The Climate Change
Action Plan" in October, 1993. This plan establishes a goal of limiting
greenhouse gas emissions to 1990 levels by the year 2000. The Action Plan
relies on innovative public/private partnerships to reach the President's goal.
The Edison Electric Institute (EEI) wrote the Secretary of Energy (DOE)
expressing a willingness to enter into discussions with the Administration to
define a voluntary program for the investor owned utilities to control
greenhouse gas emissions. The Company wrote the Secretary expressing our
interest in these discussions and was subsequently listed as one of the 87
"Global Climate Challenge" companies. DOE and EEI are currently developing
understandings upon which a voluntary program will be built. After these
negotiations have been completed, the Company will be formulating a strategy
for its participation in the plan.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index.
(b) Reports on Form 8-K: None
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: May 12, 1994 By THOMAS S. RICHARDS
--------------------------------------
Thomas S. Richards
Senior Vice President, Finance
and General Counsel
Date: May 12, 1994 By DAVID C. HEILIGMAN
--------------------------------------
David C. Heiligman
Vice President,
Secretary and Treasurer
26
EXHIBIT INDEX
Exhibit 4 - Certificate of Amendment of the Certificate of Incorporation of
Rochester Gas and Electric Corporation Under Section 805 of the
Business Corporation Law filed with the Secretary of State of
the State of New York on March 18, 1994.
27
1-10Q3-94.PDS2