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, 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 otherjurisdiction 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 July 31, 1994: 37,435,435
ROCHESTER GAS AND ELECTRIC CORPORATION
INDEX
Page No.
Part I - Financial Information
Consolidated Balance Sheet - June 30, 1994 and
December 31, 1993 1 - 2
Consolidated Statement of Income - Three Months and
Six Months Ended June 30, 1994 and 1993 3 - 4
Consolidated Statement of Cash Flows - Six Months
Ended June 30, 1994 and 1993 5
Notes to Financial Statements 6 - 16
Management's Discussion and Analysis of Financial
Condition and Results of Operations 17 - 26
Part II - Other Information
Legal Proceedings 26
Other Events 26 - 27
Exhibits and Reports on Form 8-K 27
Signatures 28
/TABLE
PART 1 - FINANCIAL INFORMATION
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ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
Assets
June 30 December 31
1994 1993
------------ --------------
Utility Plant
Electric $2,268,202 $2,234,530
Gas 363,505 356,484
Common 132,255 125,428
Nuclear fuel 181,012 174,357
------------ --------------
2,944,974 2,890,799
Less: Accumulated depreciation 1,225,930 1,190,801
Nuclear fuel amortization 151,458 144,282
------------ --------------
1,567,586 1,555,716
Construction work in progress 108,510 112,750
------------ --------------
Net Utility Plant 1,676,096 1,668,466
------------ --------------
Current Assets:
Cash and cash equivalents 829 2,327
Accounts receivable 111,058 104,753
Unbilled revenue receivable 39,523 61,330
Materials and supplies 20,635 19,627
Gas stored underground 23,454 38,989
Prepayments 25,573 21,563
------------ --------------
Total Current Assets 221,072 248,589
------------ --------------
Deferred Debits:
Unamortized debt expense 19,235 19,326
Deferred finance charges-Nine Mile Two 19,242 19,242
Deferred ice storm charges 20,390 21,621
Uranium enrichment decommissioning deferral 20,829 23,421
Nuclear generating plant decommissioning fund 43,968 38,930
Nine Mile Two deferred costs 33,988 34,513
Regulatory asset-income taxes 239,087 241,741
Investment in Empire 38,575 38,560
Other 126,086 103,221
------------ --------------
Total Deferred Debits 561,400 540,575
------------ --------------
$2,458,568 $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
June 30 December 31
1994 1993
------------ --------------
Capitalization
Long term debt - mortage bonds $643,253 $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; 37,284,580
shares outstanding at June 30, 1994
and 36,911,265 shares outstanding at
December 31, 1993. 662,579 652,172
Retained earnings 81,210 75,126
------------ --------------
Total Common Shareholders' Equity 743,789 727,298
------------ --------------
Total Capitalization 1,600,942 1,583,929
------------ --------------
Long Term Liabilities (Department of Energy):
Nuclear waste disposal 69,246 68,055
Uranium enrichment decommissioning 18,338 21,749
------------ --------------
Total Long Term Liabilities 87,584 89,804
Current Liabilities:
Long term debt due within one year 16,000 21,250
Preferred stock redeemable within one year - 6,000
Notes Payable - Empire 29,600 29,600
Short term debt 44,800 68,100
Accounts payable 43,261 52,596
Dividends payable 18,175 18,066
Taxes accrued 20,496 6,472
Interest accrued 12,808 12,955
Other 14,951 19,491
------------ --------------
Total Current Liabilities 200,091 234,530
------------ --------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 421,708 425,648
Deferred finance charges - Nine Mile Two 19,242 19,242
Pension costs accrued 35,365 31,919
Other 93,636 72,558
------------ --------------
Total Deferred Credits and Other Liabilities 569,951 549,367
------------ --------------
Commitments and Other Matters (Note 2) - -
------------ --------------
Total Capitalization and Liabilities $2,458,568 $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
June 30, 1994 June 30, 1993
------------- -------------
Operating Revenues
Electric $154,943 $147,573
Gas 58,788 51,802
---------- ----------
213,731 199,375
Electric sales to other utilities 3,352 3,877
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Total Operating Revenues 217,083 203,252
Fuel Expenses
Fuel for electric generation 10,231 9,591
Purchased electricity 9,931 8,336
Gas purchased for resale 33,432 28,821
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Total Fuel Expenses 53,594 46,748
Operating Revenue less Fuel Expenses 163,489 156,504
Other Operating Expenses
Operations excluding fuel expenses 59,518 59,407
Maintenance 15,519 19,065
Depreciation and amortization 21,588 20,913
Taxes - local, state and other 33,816 29,036
Federal income tax 8,470 6,788
---------- ----------
Total Other Operating Expenses 138,911 135,209
Operating Income 24,578 21,295
Other Income and Deductions
Allowance for other funds
used during construction 79 27
Federal income tax 905 693
Regulatory disallowances (600) -
Other - net (850) 379
---------- ----------
Total Other Income and Deductions (466) 1,099
Income before Interest Charges 24,112 22,394
Interest Charges
Long term debt 13,607 14,107
Other - net 1,299 1,851
Allowance for borrowed funds
used during construction (402) (473)
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Total Interest Charges 14,504 15,485
Net Income 9,608 6,909
Dividends on Preferred Stock 1,866 1,825
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Earnings Applicable to Common Stock $7,742 $5,084
========== ==========
Weighted average number of shares
outstanding in each period (000's) 37,220 35,055
Earnings per Common Share $0.20 $0.15
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 INCOME
(Thousands of Dollars)
(Unaudited)
For the Six Months Ended
June 30, 1994 June 30, 1993
------------- -------------
Operating Revenues
Electric $322,414 $301,062
Gas 197,308 163,068
---------- ----------
519,722 464,130
Electric sales to other utilities 7,412 11,397
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Total Operating Revenues 527,134 475,527
Fuel Expenses
Fuel for electric generation 22,787 24,158
Purchased electricity 20,600 15,339
Gas purchased for resale 118,498 91,707
---------- ----------
Total Fuel Expenses 161,885 131,204
Operating Revenue less Fuel Expenses 365,249 344,323
Other Operating Expenses
Operations excluding fuel expenses 119,618 118,168
Maintenance 32,025 33,162
Depreciation and amortization 42,995 41,640
Taxes - local, state and other 70,815 62,245
Federal income tax 28,040 23,688
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Total Other Operating Expenses 293,493 278,903
Operating Income 71,756 65,420
Other Income and Deductions
Allowance for other funds
used during construction 171 44
Federal income tax 918 1,240
Regulatory disallowances (600) -
Other - net 851 1,184
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Total Other Income and Deductions 1,340 2,468
Income before Interest Charges 73,096 67,888
Interest Charges
Long term debt 27,292 28,911
Other - net 2,905 3,825
Allowance for borrowed funds
used during construction (947) (841)
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Total Interest Charges 29,250 31,895
Net Income 43,846 35,993
Dividends on Preferred Stock 3,636 3,650
---------- ----------
Earnings Applicable to Common Stock $40,210 $32,343
========== ==========
Weighted average number of shares
outstanding in each period (000's) 37,131 34,983
Earnings per Common Share $1.08 $0.92
Cash Dividends Paid per Common Share $0.88 $0.86
See accompanying Notes to Financial Statments 4
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Six Months Ended
June 30,
-----------------
1994 1993
-------- -------
Cash Flow from Operations:
Net income $43,846 $35,993
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 42,995 41,640
Amortization of nuclear fuel 8,388 9,263
Deferred fuel costs (14,032) (2,965)
Deferred income taxes, net 506 1,918
Allowance for funds used during construction (1,118) (885)
Ice storm costs 1,231 1,346
Nuclear generating plant decommissioning (5,038) (4,694)
Uranium enrichment decommissioning (819) -
Changes in certain current assets and liabilities:
Accounts receivable (6,305) (3,198)
Unbilled revenue, net 21,807 19,827
Materials and supplies (1,008) 4,050
Taxes accrued 14,024 11,981
Interest accrued (147) (306)
Accounts payable (9,335) (9,468)
Other current assets and liabilities, net 8,017 (3,132)
Other, net 15,892 (1,716)
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Total Operating 118,904 99,654
-------- -------
Cash Flow from Investing Activities:
Utility Plant
Plant additions (51,594) (52,249)
Nuclear fuel additions (6,676) (9,869)
Less:Allowance for funds used during construction 1,118 885
-------- -------
Additions to Utility Plant (57,152) (61,233)
Investment in Empire-net (15) -
Other, net (37) (455)
-------- -------
Total Investing (57,204) (61,688)
-------- -------
Cash Flow from Financing Activities:
Proceeds from sale of common stock 9,032 8,256
Proceeds from sale of long term debt - 120,000
Proceeds from sale of preferred stock 25,000 -
Short term borrowing (23,300) 12,200
Retirement of long term debt (17,750) (125,250)
Retirement of preferred stock (18,000) (12,000)
Capital stock expense 1,375 847
Discount and expense of issuing long term debt (905) (6,582)
Dividends paid on preferred stock (3,691) (3,898)
Dividends paid on common stock (32,563) (29,993)
Other, net (2,396) (2,298)
-------- -------
Total Financing (63,198) (38,718)
-------- -------
Decrease in cash and cash equivalents (1,498) (752)
Cash and cash equivalents at beginning of period 2,327 1,759
-------- -------
Cash and cash equivalents at end of period $829 $1,007
======== =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Six Months Ended
June 30,
----------------
1994 1993
-------- --------
Cash paid during the period:
Interest paid (net of capitalized amount) $27,945 $30,317
Income taxes paid $25,198 $16,720
See Accompanying Notes to 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. 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 accompanying
notes contained in the Company's Annual Report for the year ended December 31,
1993.
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 inactive
employees after employment but before retirement.
The additional postemployment obligation at the time of the accounting change
was approximately $11 million. The postemployment benefit obligation is being
deferred on the balance sheet. The Company will petition the PSC for recovery of
the incremental expenses as the result of the adoption 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, as prescribed by the New
York State Public Service Commission (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
6
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 $56 million,
including $8 million for steam generator replacement at the Ginna Nuclear Plant
and $1 million of AFUDC as of June 30, 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 the
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
$65.6 million through June 30, 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 $41.4 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.
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 $156.7 million for Ginna and $35.7 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 with an 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 is
depositing in an external decommissioning trust the amount of the NRC minimum
funding requirement only. The estimated amount attributed to the allowance for
removal of non-contaminated structures is being 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
7
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 second of 15 payments for this purpose in April 1994, remitting
approximately $1.4 million ($1.3 million for the Ginna Plant and $0.1 million
for its share of the Nine Mile Two plant). For the two facilities the Company's
liability at June 30, 1994 is $19.8 million ($18.3 million as a long-term
liability and $1.5 million as a current liability). In October 1993, the
Company began recovery of this deferral through its fuel adjustment clause.
SPENT NUCLEAR FUEL LITIGATION. The Nuclear Waste Policy Act of 1982,
as amended, obligates the Department of Energy ("DOE") to accept spent nuclear
fuel ("SNF") starting in 1998. Since the mid-1980s the Company and other
nuclear plant owners and operators have been paying to the DOE amounts to cover
pre-1983 energy. DOE has determined that it will not be in a position to accept
SNF as early as 1998. On June 20, 1994, Northern States Power Company and other
owners and operators of nuclear power plants filed suit against DOE and the U.S.
in the U.S. Court of Appeals for the District of Columbia Circuit asking for a
declaration that DOE is not acting in accordance with law, seeking orders
directing DOE to submit to the Court a description of and progress reports on a
program to begin acceptance of SNF by 1998, and requesting other relief at
appropriate times including an order allowing petitioners to pay into an escrow
fund rather than to DOE. The Company has joined Northern States and the other
petitioners in this litigation. As of August 1, 1994, neither DOE nor the U.S.
had responded to the petition.
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
8
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 $6
million to $7 million per year.
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 $9.2 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
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 $90.4
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
June 30, 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
9
$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 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
10
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 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 has
obtained a research permit (including an air permit) in order to evaluate the
burning of material from its West Station property 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
11
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 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 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 Administrative
Order on Consent with NYSDEC. The Order on Consent
12
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 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.
13
GAS COST RECOVERY.
Many interstate gas pipeline companies entered into long-term
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). The Federal Energy Regulatory Commission
(FERC), in response to an industry wide problem of substantial take-or-pay
liability to producers, allowed pipeline companies to pass through a portion of
such costs to gas distribution companies. 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 thereafter all such costs
except for an amount not to exceed $562,500 to be absorbed by the Company.
As of June 30, 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.
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 will
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-ordered industry
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 $47.2
and $57.5 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
14
capacity for a period extending to the year 2001. 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 is 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 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 for some period of time 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.
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 had previously been expensed and $5.2 million had
been deferred on the Company's balance sheet.
On March 21, 1994, the PSC approved a December 1993 settlement among
the Company, PSC Staff and another party providing for the recovery in rates of
$2.6 million over three years which incorporated a PSC Staff audit
recommendation that the originally proposed amount of $3.2 million be
15
reduced by $.6 million. The Company wrote off $2.0 million of the undercharges
as of December 31, 1993, reducing 1993 earnings by four cents per share, net of
tax. In April 1994 the Company wrote off an additional $.6 million reducing
1994 earnings by approximately one cent per share, net of tax. Due to rate
increase limitations established for the second year of the rate settlement the
Company is precluded from recovering the undercharges until the third year of
the rate settlement, which begins July 1, 1995.
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.
16
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 six 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.
During recent years unregulated non-utility generators (NUGS) have
proliferated throughout the country. New York State has drawn an over-supply of
NUGS largely because of a state law that required utilities to pay above-market
prices for power generated from NUGS. That law was repealed in 1992. Many
utility companies have taken action to buy out their NUG contracts to reduce the
impact of electric energy costs to their customers. The Company has a contract
for approximately 55 megawatts of capacity to be supplied by a NUG which will
have an adverse impact on the Company's rates. There is currently a dispute
between the Company and the NUG concerning the NUG's compliance with the
contract pending before the PSC. However, the NUG expects to begin operation in
the fourth quarter of 1994. The Company is exploring alternatives to
continuation of this contract and has no other NUG contracts.
17
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 $56
million, including $1 million for AFUDC, had been expended for construction as
of June 30, 1994, reflecting primarily expenditures for upgrading electric
transmission and distribution facilities and gas mains, expenditures for
electric generating plant to improve operating reliability and to comply with
regulatory requirements 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 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 $8 million on
this project in the first half of 1994 and expects to spend
about $16 million in 1994.
The Company redeemed $35.75 million of securities during the first six
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. On June 15, 1994 the Company redeemed $15
million of its 13 7/8% First Mortgage Bonds, Series JJ. Funds for these
redemptions came from the issuance of short-term debt and internally generated
funds.
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 provides capacity
for up to 30 percent of the Company's gas requirements and is expected to
provide up to 50 percent of requirements in the next several years.
SUBSIDIARIES
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 Empire. In June 1993
Empire secured a $150 million credit agreement, the proceeds of which
18
are to finance approximately 75 percent of the total construction cost and
initial operating expenses. At June 30, 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 $.8 million credit to Other Income
during the first half of 1994.
Roxdel Corporation, a wholly owned subsidiary of the Company, recently
sold 2,800 acres of land located in the Town of Sterling, New York to Cayuga
County. The property, once sited for a proposed nuclear power plant, was sold
for a total of $2.95 million.
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 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 June 30, 1994 the Company had
short-term borrowings outstanding of $44.8 million consisting of $35.8 million
of unsecured short-term debt and $9.0 million of secured short-term debt.
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. At June
30, 1994, including the $35.8 million of unsecured indebtedness already
outstanding, the Company was able to issue $69.0 million of unsecured debt under
this provision. A shelf registration on Form S-3 became effective in August
1993 providing for the offering of $250 million of new debt and equity
securities. Including the preferred stock described below, the Company has thus
far issued approximately $69.4 million of equity securities under this shelf
registration. The Company may use the shelf registration to offer from time to
time its First Mortgage Bonds in one or more series depending on market
conditions and Company requirements. The net proceeds from the sale of the
bonds will be used to finance a portion of the Company's capital requirements,
to discharge or refund certain outstanding indebtedness of the Company, or for
general corporate purposes.
19
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 six months of 1994, the Company issued 373,315 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 $9.0 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, 1994 the Company had Common Stock available
for issuance of 878,941 shares under the ADR Plan and 194,447 shares under the
Savings Plus Plan.
CAPITAL STRUCTURE
The Company's retained earnings at June 30, 1994 were $81.2
million, an increase of approximately $6.1 million compared with December
31, 1993. Long-term debt at June 30, 1994, including that due within one year,
decreased approximately $17.7 million compared with December 31, 1993,
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 $16.5 million, reflecting
mainly the issuance and sale of Common Stock as discussed under "Financing" and
an increase in retained earnings. Capitalization at June 30, 1994, was
comprised of 44.5 percent common equity, 7.3 percent preferred equity and 48.2
percent long-term debt. The Company has $16.0 million of long-term debt due
within one year which, if included in capitalization, would increase the
long-term debt component of capitalization at June 30, 1994 to 48.7 percent,
decrease the preferred stock component to 7.2 percent and reduce common equity
to 44.1 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.
COMPETITION
The Company is operating in an increasingly competitive environment.
In its electric business, this environment includes a federal trend toward
deregulation and a state trend toward incentive regulation. In addition, excess
capacity in the region, new technology and cost pressures on major customers
have created incentives for major customers to investigate different electric
supply options. Initially, those options will include various forms of self
generation, but may eventually include customer access to the transmission
system in order to purchase electricity
20
from suppliers other than the Company. The passage of the National Energy
Policy Act of 1992 has accelerated these competitive challenges.
The Company accepts these challenges and is working to anticipate the
impact of the increased competition. Its Business Plan, both in detail for one
year and in summary for five years, focuses on improving service while reducing
expenses. The Company is engaged in a continuous process improvement program to
find opportunities for improved service and efficiency and has implemented two
early retirement programs, one in which 173 people, representing approximately
seven percent of its workforce, have retired early and will not be replaced.
The second program, discussed more fully below, will be implemented at the end
of this year. We believe these programs have had, and will continued to have, a
favorable impact on our costs.
In addition, the Company has agreed to a three-year rate settlement
which includes caps on rate increases that approximate or are less than
projected inflation, contains incentive programs that tie performance to
earnings and stabilizes revenue through revenue adjustment mechanisms. An
agreement has been reached with the PSC and others on the terms of a competitive
rate tariff that allows negotiated rates with larger industrial and commercial
customers that have competitive electric supply options. These regulatory
changes are discussed in more detail in the Rate Base and Regulatory Policies
section.
Competition in the Company's gas business has existed for some time,
as the larger customers have had the option of obtaining their own gas supply
and transporting it through the Company's distribution system. This process has
been accelerated with FERC Order 636. In addition, the Company has responded to
the changes in the gas business by positioning itself to obtain greater access
to both U.S. and Canadian natural gas supplies and storage, so that it can take
advantage of the unbundling of services that results from FERC Order 636. A
major element of this strategy went into place in 1993 with the start-up of the
Empire State Pipeline. The Company is engaged in various aspects of capacity
release and is investigating other options available to it to mitigate its cost
and increase its revenue in the new gas regulatory environment.
In connection with these competitive pressures, the Company is
evaluating all the factors which impact the rates it charges its customers and
therefore its competitive position, both with respect to industrial and
commercial customers as well as residential customers. In that regard, it is
reevaluating certain regulatory assets (costs which have been deferred for
collection in future rates) and generating facilities for their impact on the
Company's rate structure and their value in various competitive rate
structures. The Company's early retirement programs, efforts to control
fixed and operational costs and the decisions to defer the collection of
incentives earned under the 1993 Rate Agreement (see discussion below) all
relate to a focus on trying to maintain a rate structure which has long-term
benefits for the competitive presence of the Company in the industry.
21
Finally, the Company is reviewing its financing strategies as they relate to
debt and equity structures, the cost of these structures including the dividend
program and their impact on the Company's rate structure. All of these
evaluations are in the context of the new competitive environment and the
ability of the Company to shift from a fully regulated to a more competitive and
growth-oriented industrial organization.
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 resolved the
Company's rate proceedings initiated in July 1992 and determines the Company's
rates from July 1, 1993 through June 30, 1996. The 1993 Rate Agreement includes
certain incentive arrangements providing for both rewards and penalties. See
the Company's Form 10-Q for the quarter ended March 31, 1994, Management's
Discussion and Analysis of Financial Condition and Results of Operations under
the heading "Rate Base and Regulatory Policies" for a summary of the 1993 Rate
Agreement and a discussion of the incentive arrangements, including a discussion
of the risks and rewards available to the Company under the 1993 Rate Agreement.
Pursuant to the terms of the 1993 Rate Agreement, the PSC authorized
the Company to file for base rate increases of $20.9 million (2.98%) electric
and $4.4 million (1.76%) gas for the second rate year (July 1, 1994 through June
30, 1995). Additionally, if the Company earned all of the incentive amounts
available in the first year, the Company could have sought a 4.48% increase in
electric rates, and a 3.26% increase in gas rates for the second rate year.
A Commission order, issued and effective on June 30, 1994, authorizes
the Company to increase electric rates by $20.9 million (2.98%) and gas rates by
$7.4 million (2.96%).
Also contained in the June 1994 rate order is recognition of $9.3
million related to the Company's performance in the first year of the 1993 Rate
Agreement, recovery of which the Company has reserved for future consideration.
The $9.3 million is comprised of the following:
- $1.6 million for ERAM (Electric Revenue Adjustment
Mechanism) designed to stabilize electric revenues
by eliminating the impact of variations in electric
sales.
- $6.7 million for IRMI (Integrated Resource Management
Incentive) or relative electric production efficiency.
- $1.0 million for Service Quality Incentive.
22
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 allows the Company to negotiate competitive electric rates at discount
prices to compete with alternative power sources, such as 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 future
Company rate proceeding. While the Company's flexible pricing tariff was made
subject to modification by an anticipated order to be issued by the PSC in a
pending generic proceeding, the issuance of that order, dated July 11, 1994 does
not appear to require any material change in the tariff.
The Company has negotiated a long term electric supply contract with
one and letter of intent with another of its large industrial and commercial
electric customers at discounted rates. It intends to pursue negotiations with
other large customers as the need and opportunities arise. The Company has not
experienced any customer loss due to competitive alternative arrangements.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses, comparing the three-month and
six-month periods ended June 30, 1994 to the corresponding three-month and
six-month periods ended June 30, 1993.
EARNINGS SUMMARY
Earnings Per Common Share
For the Periods Ended
June 30,
------------------------
1994 1993
---- ----
Three Months $ .20 $ .15
Six Months $1.08 $ .92
The Company's improved financial performance for each of the current
periods reflects successful cost control efforts on the part of employees,
recent work force reductions, lower interest costs and a modest increase in
rates. The positive results were partially offset by higher local, state and
federal tax expenses and the dilution effect of issuance of additional shares of
Common Stock. See Item 5 under the heading
23
"Retirement Program" for a discussion of a workforce reduction program which
will result in a charge against earnings in the second half of 1994.
OPERATING REVENUES AND SALES
Total Company revenues for the first six months of 1994 were $51.6
million or 10.9% above the first six months of 1993, reflecting mainly higher
fuel costs (particularly for purchased gas) and rate relief. The impact of
higher retail sales on earnings during the first quarter was reduced due to rate
provisions that moderate the effect of abnormal weather on customer bills.
Total Company revenues for the second quarter of 1994 were $13.8
million or 6.8% above the second quarter of 1993, with most of the gains coming
from higher fuel costs and rate relief. Summer heat waves resulted in record
hourly peak demand for electricity in June and again in July of this year.
Revenues from sales to other electric utilities decreased in both
comparison periods mainly due to a tight New York Power Pool energy market.
The principal factors causing changes in Electric and Gas Department
revenues are estimated below:
Comparison of Comparison of
Three Months Six Months
Ended June 30, Ended June 30,
1994 and 1993 1994 and 1993
----------------------- ----------------------
Increase or (Decrease) Increase or (Decrease)
for comparison period for comparison period
(Millions of Dollars) (Millions of Dollars)
Electric Gas Electric Gas
-------- --- -------- ---
Rate increases $ 5.2 $ .7 $ 11.1 $ 2.3
Fuel costs 2.2 4.6 7.2 26.8
Weather effects (Heating
& Cooling) .4 .5 3.4 1.1
Customer consumption (.1) (1.5) 1.0 (3.4)
Other (.4) 2.7 (1.3) 7.4
Total change in customer --------- --------- --------- --------
revenues 7.3 7.0 21.4 34.2
OEU sales (.5) - (4.0) -
--------- --------- --------- --------
Total change in operating
revenues $ 6.8 $ 7.0 $ 17.4 $ 34.2
========= ========= ========= ========
FUEL EXPENSES
Fuel expenses increased in both comparison periods reflecting higher
sendout and unit cost of purchased gas, higher unit cost of fossil fuel for
generated electricity, greater purchases of electricity and, for
24
the three month comparison period, an increase in generated electricity.
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES
Operations excluding fuel expenses increased slightly in both
comparison periods reflecting mainly higher costs for the demand side management
program, site remediation and Nine Mile Two partially offset by lower payroll
and employee welfare costs due to employee reductions and reduced expenses for
contractors, consultants and Company vehicles. Lower maintenance expense in
both comparison periods also reflects reduced payroll and employee benefit
costs.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased in both comparison periods due
mainly to an increase in depreciable plant.
TAXES
The increases in local, state and other taxes resulted primarily from
an increase in revenues, an increase in property tax rates and higher property
assessments.
Federal income tax increased in both comparison periods due to higher
pre-tax book income.
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%) 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.
OTHER STATEMENT OF INCOME ITEMS
Variances in allowance for funds used during construction (AFUDC)
reflect an increase in the amount of utility plant under construction and not
included in rate base in both comparison periods offset by an
25
adjustment related to nuclear fuel which increased AFUDC in the 1993 second
quarter.
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 short term borrowing levels despite an upturn in interest rates in the
1994 first quarter.
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 5. OTHER EVENTS
RETIREMENT PROGRAM. On June 15, 1994 the Company announced a
retirement enhancement program designed to reduce the workforce by several
hundred employees. The program offers incentives to employees who have reached
age 50 with at least ten years of service, but also extends options to all other
employees. Employees will have to declare their intentions by September 1,
1994.
Two similar programs completed during the past several months have
reduced the workforce by 173 people, or approximately seven percent. The
retirement enhancement programs are part of the Company's business strategy to
move from a regulation-driven to a competition-driven company. The Company's
challenge is to reduce costs, maintain a high level of service and value to
customers and provide shareholders with an attractive return on their
investment.
The latest program will result in a charge against earnings in 1994,
which will vary depending on the level of participation. The actual cost will
be influenced by the age, years of service and position of participants. As the
program will encompass a wide range of employees, the final cost of the program
cannot by accurately determined at this time. The program will be accompanied
by a reorganization and require a redeployment of some employees and may, in
certain circumstances, require additional staffing to support the reorganization
process. The Company believes that at the estimated maximum level of
participation the after tax costs charged against earnings in 1994 will not
exceed $26 million ($.69 per share). In that case, the estimated after tax net
savings through 1998 would be approximately $56 million. The Company expects
that the actual level of participation will be something less than the estimated
maximum level.
PROPERTY SALE. The Company reached agreement to sell sixty acres of
property located in the Town of Henrietta, New York. The property currently
houses the Company operations and employee centers. The
26
agreement to proceed with the sale is subject to satisfaction of a number of
contingencies by the developer, including his obtaining necessary permits to
develop the site.
The Company expects to vacate the employee center in about nine months
and will lease back the operations center for approximately three years. During
that time the Company will evaluate the options for meeting continuing
operational needs.
DIRECTOR RETIREMENT. Effective July 1, 1994, Harry G. Saddock, former
Chairman of the Board and Chief Executive Officer, retired from the Board of
Directors. As Mr. Saddock's seat on the Board is not being filled at the
present time, the Board reduced the number of directors to eleven as of July 1,
1994.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: None
(b) Reports on Form 8-K: A report on Form 8-K dated June 15, 1994 was
filed during the quarter to report the retirement
enhancement program discussed in Item 5.
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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 11, 1994 By THOMAS S. RICHARDS
--------------------------------------
Thomas S. Richards
Senior Vice President, Finance
and General Counsel
Date: August 11, 1994 By DAVID C. HEILIGMAN
--------------------------------------
David C. Heiligman
Vice President,
Secretary and Treasurer
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