SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 October 31, 1994: 37,638,195
ROCHESTER GAS AND ELECTRIC CORPORATION
INDEX
Page No.
Part I - Financial Information
Consolidated Balance Sheet - September 30, 1994 and
December 31, 1993 1 - 2
Consolidated Statement of Income - Three Months and
Nine Months Ended September 30, 1994 and 1993 3 - 4
Consolidated Statement of Cash Flows - Nine Months
Ended September 30, 1994 and 1993 5
Notes to Consolidated Financial Statements 6 - 16
Management's Discussion and Analysis of Financial
Condition and Results of Operations 17 - 28
Part II - Other Information
Legal Proceedings 28
Exhibits and Reports on Form 8-K 29
Signatures 30
PART 1 - FINANCIAL INFORMATION
- -----------------------------------------------------
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
Assets
September 30 December 31
1994 1993
------------ -----------
Utility Plant
Electric $2,273,180 $2,234,530
Gas 366,376 356,484
Common 134,567 125,428
Nuclear fuel 182,845 174,357
--------- ---------
2,956,968 2,890,799
Less: Accumulated depreciation 1,245,816 1,190,801
Nuclear fuel amortization 155,243 144,282
--------- ---------
1,555,909 1,555,716
Construction work in progress 120,060 112,750
--------- ---------
Net Utility Plant 1,675,969 1,668,466
--------- ---------
Current Assets:
Cash and cash equivalents 2,801 2,327
Accounts receivable 93,068 104,753
Unbilled revenue receivable 38,742 61,330
Materials and supplies 18,594 19,627
Gas stored underground 31,062 38,989
Prepayments 30,498 21,563
--------- ---------
Total Current Assets 214,765 248,589
--------- ---------
Deferred Debits:
Unamortized debt expense 18,804 19,326
Nuclear generating plant decommissioning fund 46,632 38,930
Nine Mile Two deferred plant costs 33,725 34,513
Deferred finance charges-Nine Mile Two 19,242 19,242
Investment in Empire 38,558 38,560
Regulatory Assets-
Income taxes 236,738 241,741
Uranium enrichment decommissioning deferral 20,690 23,421
Deferred ice storm charges 19,751 21,621
FERC 636 transition costs 37,691 41,265
DSM costs 20,594 20,573
Other regulatory assets 11,335 11,452
Other 72,512 29,931
--------- ---------
Total Deferred Debits 576,272 540,575
--------- ---------
$2,467,006 $2,457,630
========= =========
See Accompanying Notes to Financial Statements
1
/TABLE
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
Capitalization and Liabilities
September 30 December 31
1994 1993
------------ -----------
Capitalization
Long term debt - mortage bonds $643,265 $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; 37,474,680
shares outstanding at September 30,1994
and 36,911,265 shares outstanding at
December 31, 1993. 666,852 652,172
Retained earnings 67,767 75,126
--------- ---------
Total Common Shareholders' Equity 734,619 727,298
--------- ---------
Total Capitalization 1,591,784 1,583,929
--------- ---------
Long Term Liabilities (Department of Energy):
Nuclear waste disposal 69,973 68,055
Uranium enrichment decommissioning 18,472 21,749
--------- ---------
Total Long Term Liabilities 88,445 89,804
Current Liabilities:
Long term debt due within one year - 21,250
Preferred stock redeemable within one year - 6,000
Notes Payable - Empire 29,600 29,600
Short term debt 53,800 68,100
Accounts payable 33,414 52,596
Dividends payable 18,355 18,066
Taxes accrued 22,829 6,472
Interest accrued 14,985 12,955
Other 13,412 19,491
--------- ---------
Total Current Liabilities 186,395 234,530
--------- ---------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 415,718 425,648
Deferred finance charges - Nine Mile Two 19,242 19,242
Pension costs accrued 37,074 31,919
Other 128,348 72,558
--------- ---------
Total Deferred Credits and Other Liabilities 600,382 549,367
--------- ---------
Commitments and Other Matters - -
--------- ---------
Total Capitalization and Liabilities $2,467,006 $2,457,630
========= =========
See Accompanying Notes to Financial Statements
2
/TABLE
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
For the Three Months Ended
September 30, 1994 September 30, 1993
------------------ ------------------
Operating Revenues
Electric $180,542 $179,335
Gas 46,098 35,081
---------- ----------
226,640 214,416
Electric sales to other utilities 3,342 2,862
---------- ----------
Total Operating Revenues 229,982 217,278
Fuel Expenses
Fuel for electric generation 10,744 11,339
Purchased electricity 9,534 6,621
Gas purchased for resale 28,629 22,729
---------- ----------
Total Fuel Expenses 48,907 40,689
Operating Revenue less Fuel Expenses 181,075 176,589
Other Operating Expenses
Operations excluding fuel expenses 58,257 59,307
Maintenance 11,300 13,278
Depreciation and amortization 22,198 21,180
Taxes - local, state and other 31,014 30,362
Federal income tax 17,299 14,404
---------- ----------
Total Other Operating Expenses 140,068 138,531
Operating Income 41,007 38,058
Other Income and Deductions
Allowance for other funds
used during construction 111 52
Federal income tax 12,615 2,538
Pension Plan Curtailment (33,679) (5,220)
Other - net (627) (389)
---------- ----------
Total Other Income and Deductions (21,580) (3,019)
Income before Interest Charges 19,427 35,039
Interest Charges
Long term debt 13,152 13,794
Other - net 1,841 1,459
Allowance for borrowed funds
used during construction (478) (418)
---------- ----------
Total Interest Charges 14,515 14,835
Net Income 4,912 20,204
Dividends on Preferred Stock 1,866 1,825
---------- ----------
Earnings Applicable to Common Stock $3,046 $18,379
========== ==========
Weighted average number of shares
outstanding in each period (000's) 37,412 35,582
Earnings per Common Share $0.08 $0.51
Cash Dividends Paid per Common Share $0.44 $0.43
See Accompanying Notes to Consolidated Financial Statements
3
/TABLE
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
For the Nine Months Ended
September 30, 1994 September 30, 1993
------------------ ------------------
Operating Revenues
Electric $502,956 $480,398
Gas 243,406 198,148
---------- ----------
746,362 678,546
Electric sales to other utilities 10,754 14,259
---------- ----------
Total Operating Revenues 757,116 692,805
Fuel Expenses
Fuel for electric generation 33,530 35,497
Purchased electricity 30,134 21,960
Gas purchased for resale 147,127 114,436
---------- ----------
Total Fuel Expenses 210,791 171,893
Operating Revenue less Fuel Expenses 546,325 520,912
Other Operating Expenses
Operations excluding fuel expenses 177,876 177,475
Maintenance 43,325 46,439
Depreciation and amortization 65,193 62,820
Taxes - local, state and other 101,829 92,608
Federal income tax 45,339 38,093
---------- ----------
Total Other Operating Expenses 433,562 417,435
Operating Income 112,763 103,477
Other Income and Deductions
Allowance for other funds
used during construction 282 96
Federal income tax 13,532 3,779
Pension Plan Curtailment (33,679) (5,220)
Other - net (375) 795
---------- ----------
Total Other Income and Deductions (20,240) (550)
Income before Interest Charges 92,523 102,927
Interest Charges
Long term debt 40,444 42,705
Other - net 4,747 5,284
Allowance for borrowed funds
used during construction (1,426) (1,258)
--------- ----------
Total Interest Charges 43,765 46,731
Net Income 48,758 56,196
Dividends on Preferred Stock 5,502 5,475
---------- ----------
Earnings Applicable to Common Stock $43,256 $50,721
========== ==========
Weighted average number of shares
outstanding in each period (000's) 37,228 35,210
Earnings per Common Share $1.16 $1.44
Cash Dividends Paid per Common Share $1.32 $1.29
See Accompanying Notes to Consolidated Financial Statements
4
/TABLE
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Nine Months Ended
September 30,
---------------------
1994 1993
-------- -------
Cash Flow from Operations:
Net income $48,758 $56,196
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 65,193 62,820
Amortization of nuclear fuel 12,906 14,792
Deferred fuel costs (33,145) (13,133)
Deferred income taxes, net (2,488) 11,275
Allowance for funds used during construction (1,707) (1,354)
Ice storm costs 1,870 1,961
Nuclear generating plant decommissioning (7,702) (7,085)
Pension costs accrued 48,404 6,352
Uranium enrichment decommissioning (3,277) 21,436
Changes in certain current assets and liabilities:
Accounts receivable 11,685 7,698
Unbilled revenue, net 22,588 15,874
Materials and supplies 1,033 7,291
Taxes accrued 16,357 (4,957)
Interest accrued 2,030 54
Accounts payable (19,182) 21,351
Gas stored underground 7,926 (32,100)
Other current assets and liabilities, net (15,113) (7,626)
Other, net 8,795 (20,339)
------- -------
Total Operating $164,931 $140,506
------- -------
Cash Flow from Investing Activities:
Utility Plant
Plant additions (76,471) (85,724)
Nuclear fuel additions (8,515) (10,398)
Less:Allowance for funds used during construction 1,707 1,354
------- -------
Additions to Utility Plant (83,279) (94,768)
Other, net 1,737 (1,846)
------ -------
Total Investing ($81,542) ($96,614)
------- -------
Cash Flow from Financing Activities:
Proceeds from sale of common stock 13,304 56,903
Proceeds from sale of long term debt - 200,000
Proceeds from sale of preferred stock 25,000 -
Short term borrowing (14,300) (27,300)
Retirement of long term debt (33,750) (200,250)
Retirement of preferred stock (18,000) (12,000)
Capital stock expense 1,375 (524)
Discount and expense of issuing long term debt (931) (7,909)
Dividends paid on preferred stock (5,461) (5,723)
Dividends paid on common stock (48,968) (45,088)
Other, net (1,184) (1,140)
------- -------
Total Financing (82,915) (43,031)
------- -------
Increase in cash and cash equivalents 474 861
Cash and cash equivalents at beginning of period 2,327 1,759
------- -------
Cash and cash equivalents at end of period $2,801 $2,620
======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Nine Months Ended
September 30,
-----------------------
1994 1993
------- -------
Cash paid during the period:
Interest paid (net of capitalized amount) $41,748 $44,248
Income taxes paid $28,198 $23,720
See Accompanying Notes to Financial Statements.
5
ROCHESTER GAS AND ELECTRIC CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1: GENERAL
The accompanying unaudited financial statements reflect all
adjustments which are, in the opinion of management, necessary to a fair
presentation of the Company's results for these interim periods. All
such adjustments are of a normal recurring nature, except for non-
recurring adjustments as described in Management's Discussion and
Analysis of Financial Condition and Results of Operations under the
heading entitled "Earnings Summary". 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 and 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" was
adopted by the Company in the first quarter 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 (see following discussion under "Decommissioning
Trust"). Accordingly, the adoption of SFAS 115 is not expected to
significantly impact the Company's financial statements.
6
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 $82
million, including $13 million for steam generator replacement at the Ginna
Nuclear Plant and has accrued $2 million of AFUDC as of September 30, 1994.
The Company has entered into certain commitments for the purchase of
materials and equipment in connection with the construction expenditures
program.
NUCLEAR-RELATED MATTERS.
DECOMMISSIONING TRUST. The Company is collecting in its electric
rates amounts for the eventual decommissioning of its Ginna Plant and for
its 14% share of the decommissioning of Nine Mile Two. The operating
licenses for these plants expire in 2009 and 2026 respectively.
Under accounting procedures approved by the PSC, the Company has
collected approximately $67.9 million through September 30, 1994. In
connection with the Company's rate settlement completed in August 1993, the
PSC approved the collection during the rate year ending June 30, 1995 of an
aggregate $8.9 million for decommissioning, covering both nuclear units.
The amount allowed in rates is based on estimated ultimate decommissioning
costs of $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 Nuclear Regulatory Commission (NRC)
formula to determine minimum funding with an additional allowance for
removal of non-contaminated structures. Site specific studies of the
anticipated costs of actual decommissioning are required to be submitted to
the NRC at least five years prior to the expiration of the license.
The NRC requires reactor licensees to submit funding plans that
establish minimum NRC external funding levels for reactor decommissioning.
The Company's plan, filed in 1990, consists of an external decommissioning
trust fund covering both its Ginna Plant and its Nine Mile Two share. The
Company is depositing in an external decommissioning trust the amount of
the NRC minimum funding requirement only. Since 1990, the Company has
contributed $43.6 million to this fund and, including investment returns,
the fund has a balance of $46.6 million as of September 30, 1994. The
amount attributed to the allowance for removal of non-contaminated
structures is being held in an internal reserve. The internal reserve
balance as of September 30, 1994 is $24.3 million.
The Company is aware of recent NRC activities related to upward
7
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 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 September 30,
1994 is $20.0 million ($18.5 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 incurred
obligations to the DOE for the disposal of SNF some of which has been paid.
DOE has determined that it will not be in a position to accept SNF in 1998.
On June 20, 1994, Northern States Power Company and other owners and
operators of nuclear power plants filed suit against DOE and the U.S. in
the U.S. Court of Appeals for the District of Columbia Circuit 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. On September 9, 1994
the DOE responded to the petition by filing a motion to dismiss stating
that (1) the petition was premature, (2) it has taken no "final" action
that would be subject to review and (3) any injury suffered as a result of
its failure to begin spent fuel acceptance in 1998 is too speculative. On
September 30, 1994 Petitioners filed their response contradicting those
claims. On October 14, 1994 DOE responded by restating its arguments
presented September 9.
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 for 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
8
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 years (priced at the most current rate) is
expected to be $6 million in 1994 and ranges from $10 million to $11
million every 18 months thereafter.
INSURANCE PROGRAM. The Price-Anderson Act establishes a federal
program insuring against public liability in the event of a nuclear
accident at a licensed U.S. reactor. 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 certain surcharges. 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.
Claims alleging radiation-induced injuries to workers at nuclear
reactor sites 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. 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 $5.0 million and $14.2
million in the event of losses under the replacement power and property
damage coverages, respectively.
ENVIRONMENTAL MATTERS.
GENERAL. The production and delivery of energy are necessarily
9
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.
COMPANY-OWNED WASTE SITE ACTIVITIES. As part of its commitment
to environmental excellence, the Company is conducting proactive Site
Investigation and/or Remediation (SIR) efforts at six Company-owned sites
where past waste handling and disposal may have occurred. Remediation
activities are being completed at two of these sites and the Company is
conducting a program to restore, as necessary, to meet environmental
standards the other four sites. The Company currently estimates the total
costs it could incur for SIR activities at Company-owned sites will not
exceed approximately $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
10
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
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 most recent 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
11
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.
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.
SUPERFUND AND OTHER SITES. The Company has been or may be
associated as a potentially responsible party (PRP) at seven sites not
owned by it, but for which the Company has been identified as a PRP.
Estimates of the Company's potential liability for these sites are
currently not expected to exceed approximately $1.3 million.
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 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. Although 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 determine the
cost to design and conduct at the site any remedial measures which federal
or state authorities may require, the Company does not expect its costs to
exceed $250,000.
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.
The Company is involved in the investigation and cleanup of the
Maxey Flats Nuclear Disposal Site in Morehead, Kentucky. The Company has
contributed to a study of the site and estimates that its share of the cost
of investigation and remediation would approximate $205,000.
The Company has been named as a PRP at three other sites and has
been associated with another site for which the Company's share of total
projected costs is not expected to exceed $120,000. Actual Company
expenditures for these sites are dependent upon the total cost of
investigation and remediation and the ultimate determination of the
Company's share of responsibility for such costs as well as the financial
viability of other identified responsible parties since clean-up
obligations are joint and several.
FEDERAL CLEAN AIR ACT AMENDMENTS. 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.
The first phase, designed to reduce NOx emissions by 18% of 1990 levels,
must be in effect by the federally mandated compliance date of May 31,
1995. In September 1994 a commission of Northeastern states approved a
memorandum of understanding regarding a second phase of NOx emission
controls which will require the Company to reduce annual NOx emissions by
55% of 1990 levels by May 1999. 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. The Company has
expended $1.0 million for NOX controls through October 31, 1994. 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 NOx and sulphur dioxide
13
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" 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.
As a result of the restructuring of the gas transportation
industry by the Federal Energy Regulatory Commission (FERC), there will be
a number of changes in this aspect of the Company's business over the next
several years. These changes will require the Company 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 $44 and $52 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
entered into a $30 million credit agreement with a domestic bank until May
31, 1995 to provide funds for the Company's transition cost liability to
CNG. At September 30, 1994 the Company had $20.7 million of borrowings
outstanding under the credit agreement. 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 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 transportation service to be provided by Empire will be
phased in over 12 months, at which point the combined CNG and Empire
transportation capacity would have exceeded the Company's current
requirements. The Company has exercised its option to postpone for one
year the commencement of certain Empire-related transportation service that
14
was scheduled for November 1994. The Company also 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. 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 ability of CNG to market
this capacity may depend on FERC approval of rolled-in (rather than
incremental) rate treatment for the CNG new facility costs necessary to
serve the letter of intent customers. Several CNG customers have protested
CNG's proposed rolled-in rate treatment, arguing that such costs should be
borne as incremental by the letter of intent customers. The FERC has
issued a preliminary determination on non-environmental issues in which
they concluded that it would be in the public convenience and necessity to
authorize construction and operation of the proposed facilities. The
timing of the FERC decision with respect to environmental issues and rate
treatment cannot be determined at the present time.
The Company recently announced that it expects higher gas costs
during the upcoming heating season. The projected increases result mainly
from continuing transition costs associated with the federal deregulation
of the natural gas industry, current excess transportation capacity and the
cost of added gas supply brought to the community by the Empire State
Pipeline, which enhances supply reliability for the Company's customers
during the coldest weather, along with some increases in the cost of
existing transportation and distribution. The Company incurs certain gas
costs which are not charged to customers currently but are deferred for
collection over a future twelve-month period. A reconciliation of gas
costs incurred with gas costs billed to customers is done annually, as of
August 31, and the excess or deficiency is refunded to or recovered from
the customers during a subsequent twelve-month period beginning in
December. In October 1994, the Company submitted to the PSC its annual
reconciliation providing for recovery of $24 million of deferred gas costs,
substantially higher than in previous years due to the factors mentioned
above. Coupled with projected gas supply cost increases, the Company's
residential customers may see gas cost increases of more than fifteen
percent during the twelve months beginning December 1, 1994.
The Staff of the Public Service Commission is now reviewing the
Company's application for recovery of deferred costs and the Consumer
Protection Board, along with certain individuals or groups of ratepayers,
have requested that the PSC conduct hearings to determine whether and on
what terms the deferral should be recovered. The costs included in the
deferral have ordinarily been recovered in the past and the Company
believes that they should be recovered in this instance. However, we
cannot predict at this time what action the PSC will take. It is
15
anticipated that the PSC will decide how to proceed in December 1994, but
that a final decision about the recovery of those costs will occur sometime
thereafter.
The Company is reviewing ways to mitigate the gas cost increase
imposed on customers. This would include extending the deferral process
from twelve months to nineteen months, allowing customers to spread
payments during the high bill months of February and March over several
months and increased use of budget billing.
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 initial hearings 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 nine 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.
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
$82 million, including $2 million for AFUDC, had been expended for
construction as of September 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.
17
COGENERATION CONTRACT LITIGATION
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.
On September 6, 1994, the Company filed a civil lawsuit in New
York State Supreme Court against Kamine/Besicorp Allegany L.P. (Kamine),
the NUG with which the Company has a contract, which seeks rescission of
the contract on the grounds that it has become impossible for Kamine to
perform. Alternatively, the Company seeks to have the Court order Kamine
to provide adequate assurances that it will perform its obligations and, if
Kamine is unable to do so, to declare Kamine in breach and order rescission
of the contract.
Under federal and New York State laws and regulations, the
Company is required to purchase the electrical output of cogeneration
facilities, such as the Kamine facility, which meet certain criteria. Such
purchases are required to be made at or below the Company's Avoided Cost
(the cost the Company would otherwise incur to generate the power itself or
to purchase it from other sources). At the time the contract with Kamine
was negotiated, the New York law requiring utilities to pay a minimum of
six cents per kilowatt hour for cogenerated electricity was in effect.
Similarly, estimates by the PSC of Avoided Costs over the long run,
including the 25-year term of the contract, escalated dramatically above
that figure.
Under the contract, payments for electricity during the first 15
years of the term were to be higher than the Company's actual Avoided Cost.
The excess above Avoided Cost was to be accumulated in a tracking account.
During the last ten years of the term, payments were to be at less than
Avoided Cost and the balance accumulated in the tracking account was to be
reimbursed to the Company.
Since the contract was executed, the statutory six-cent per
kilowatthour minimum payment provision has been repealed and the Avoided
Cost projections of the PSC have declined precipitously. The Company now
estimates that Kamine will owe the Company $400 million by the midpoint of
the contract term and if the contract extends to its full 25-year term, the
total amount of such overpayments (plus interest) could reach approximately
$700 million. The Company believes there is no reasonable likelihood that
Kamine will be able to repay that amount or to obtain the letter of credit
called for in the contract to secure that obligation.
Prior to commencement of the lawsuit, both the Company and Kamine
18
had sought, among other relief, a determination from the PSC regarding
whether Kamine had breached material representations in the contract
regarding the size of the cogeneration facility. By an order issued on
September 15, 1994, the PSC declined to decide the issues pertaining to the
size of the cogeneration facility on the grounds that they constituted a
contract dispute in which the PSC will not ordinarily intervene.
STEAM GENERATOR REPLACEMENT
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 $13 million on this project in
the first nine months of 1994 and expects to spend about $16 million by
year end 1994.
SECURITIES REDEMPTIONS
The Company redeemed $51.75 million of securities during the
first nine 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. On September 15, 1994 the Company redeemed at maturity $16
million of its 4 5/8% First Mortgage Bonds, Series U. Funds for these
redemptions came from the issuance of short-term debt, preferred stock and
internally generated funds.
SUBSIDIARIES
In 1992, the Company formed a wholly owned subsidiary, Energyline
Corporation (Energyline) to acquire its ownership interest in Empire State
Pipeline (Empire), an intrastate natural gas pipeline subject to PSC
regulation. The PSC authorized the Company to invest up to $20 million in
Empire. Empire provides capacity for up to 50 percent of the Company's gas
requirements. 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
19
proceeds of which are to finance approximately 75 percent of the total
construction cost and initial operating expenses. At September 30, 1994
the Company had invested a net amount of $10.3 million in Energyline and
was committed to provide a guarantee for $9.7 million of the borrowings
under the credit agreement. This total of $20 million represents the
Company's maximum exposure to loss.
Roxdel Corporation, a wholly owned subsidiary of the Company,
recently became a Northeast regional distributor of carbon monoxide alarm
units manufactured by American Sensors Electronics, Inc. These units will
be marketed in large volume wholesale transactions to other utilities.
The Company's investment in Energyline and Roxdel 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 nine months of 1994.
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 September 30, 1994 the Company had short-term
borrowings outstanding of $53.8 million consisting of $13.8 million of
unsecured short-term debt and $40.0 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 September 30, 1994, including the $13.8 million of unsecured
indebtedness already outstanding, the Company was able to issue $72.2
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 Designated Secured Medium-Term Notes, Series B in an
aggregate principal amount not to exceed $195,000,000 depending on market
20
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.
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 nine months of 1994, the Company issued 563,415
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 $13.3 million to help finance its capital
expenditures program. The new shares were issued at a market price above
the book value per share at the time of issuance. At September 30, 1994
the Company had Common Stock available for issuance of 719,425 shares under
the ADR Plan and 163,863 shares under the Savings Plus Plan. Except for
shares of Common Stock under the ADR Plan and Savings Plus Plan the Company
does not expect to issue any long-term debt or equity securities for the
remainder of 1994.
CAPITAL STRUCTURE
The Company's retained earnings at September 30, 1994 were $67.8
million, a decrease of approximately $7.4 million compared with December
31, 1993. Retained earnings were reduced by approximately $21.5 million
due to a one time charge in September 1994 resulting from a workforce
reduction program. See following discussion under "Earnings Summary."
Long-term debt at September 30, 1994, including that due within one year,
decreased approximately $33.7 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 $7.3
million, reflecting mainly the issuance and sale of Common Stock as
discussed under "Financing" and a decrease in retained earnings reflecting
the write-offs mentioned above. Capitalization at September 30, 1994, was
comprised of 46.1 percent common equity, 7.7 percent preferred equity and
46.2 percent long-term debt. 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
21
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
from suppliers other than the Company. The passage of the National Energy
Policy Act of 1992 has accelerated these competitive challenges.
California and New York State regulatory agencies (among others)
have initiated proposals to stimulate competition. In April 1994 the
California Public Utilities Commission announced a six-year restructuring
plan which will allow customers to purchase their energy from either
utility or non-utility generators: the largest customers beginning in
1996, other industrial and commercial customers between 1997 and 1999
depending on energy requirements, and residential customers by 2002. In
New York, the PSC has encouraged competition by requiring utilities to
purchase power from NUG's at prices in excess of their internal cost of
production, has established various incentive mechanisms in recent rate
proceedings to provide lower cost energy, and has provided flexible pricing
for certain large customers who have "realistic competitive alternatives".
The PSC is also examining issues related to establishing a wholesale
competitive market (see Rate Base and Regulatory Policies).
The Company accepts these challenges and is working to anticipate
the impact of the increased competition. Its business strategy 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. It has implemented three workforce reduction programs in which
572 people, representing approximately 22 percent of its workforce, have
elected to participate and, except in rare instances, they will not be
replaced. The latest program, discussed more fully below, concluded at the
end of this quarter. The Company believes these programs have had, and
will continued to have, a favorable impact on costs.
In addition, the Company is operating under 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. By settlement with the PSC and others the Company has 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
22
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 business 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 considering its regulatory assets (costs which have been deferred for
collection in future rates) and generating facilities for their impact on
the Company's rate structure. The Company's workforce reduction programs,
efforts to control fixed and operational costs and 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. 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.
RESTRUCTURING
In August 1994 the Company announced a plan to streamline
its internal organization by combining 14 division-sized functions into
three areas: Customer Operations, Customer Development and Corporate
Services. The restructuring is part of an ongoing effort to provide
customers with the best possible service at the lowest possible price. The
new organization will continue to evolve as the competitive marketplace
changes and customers' needs change. Customer Operations will be headed by
Senior Vice President Robert E. Smith. It includes customer field
operations,
all functions associated with producing and delivering energy to customers-
- -power plant operations, electric and gas transmission and distribution,
engineering support services and computer information support.
Corporate Services will be headed by Senior Vice President and
General Counsel, Thomas S. Richards. This area includes corporate support
functions such as financial services, public affairs, human resource
services and strategic development. Customer Development will be headed by
Vice President Wilfred J. Schrouder, Jr. It will be devoted to retaining,
developing and assisting customers. Functions include pricing, customer
23
outreach, energy conservation and marketing. As part of the
reorganization, David K. Laniak was named Executive Vice President and
Chief Operating Officer and was elected to the Board of Directors. He will
be responsible for overseeing merger of the production and distribution
divisions and development of a new marketing strategy.
The following are additional management appointments intended to
broaden executive responsibility and enhance future leadership of the
Company.
- David C. Heiligman becomes Vice President, Finance and
Corporate Secretary
- Robert C. Mecredy becomes Vice President, Nuclear Operations
- Daniel J. Baier has been elected Controller
- Mark Keogh has been elected Treasurer
The restructuring is part of the Company's efforts to move from a
regulation-driven to a competition-driven company. It follows a series of
three workforce reduction programs during the last year, the latest of
which ended October 1, 1994. See following discussion under "Earnings
Summary" for additional information concerning the workforce reduction
programs.
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.
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:
24
- $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.
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, in July 1994 does not
appear to require any material change in the tariff.
The Company has negotiated long term electric supply contracts
with two of its large industrial and commercial electric customers at
discounted rates. It intends to pursue negotiations with other large
customers as the need and opportunity arise. The Company has not
experienced any customer loss due to competitive alternative arrangements.
In June 1994, the PSC announced that it will begin a proceeding
to examine issues related to the establishment of a "wholesale competitive
market" to provide power that would be wheeled to local utilities through
the interconnected transmission system in the state. A conference was held
on September 12, 1994 to discuss the schedule and process for developing
general principles to guide the transition to competition which may then
form the basis for the development of a framework for movement toward a
more competitive marketplace. The Company is working with the Energy
Association of New York State on "guiding principles" and concerns
regarding possible industry restructuring which have been submitted to the
Administrative Law Judge and will be submitted to the PSC for a meeting
scheduled in November 1994 after which the PSC is expected to establish the
next phase of the proceeding. The schedule tentatively proposed extends
well into 1995. Similar rate initiatives on competitively-priced natural
gas are being addressed in a generic investigation by the PSC into issues
involving the restructuring of gas utility services to respond to emerging
competition.
25
RESULTS OF OPERATIONS
The following financial review identifies the causes of
significant changes in the amounts of revenues and expenses, comparing the
three-month and nine-month periods ended September 30, 1994 to the
corresponding three-month and nine-month periods ended September 30, 1993.
EARNINGS SUMMARY
Adjusted for
As Reported Non-Recurring Items
------------------------ -----------------------
1994 1993 1994 1993
---- ---- ---- ----
Three Months $ .08 $ .51 $ .67 $ .60
Nine Months $1.16 $1.44 $1.76 $1.53
The figures above are based on the weighted average number of
shares outstanding in each period.
Earnings as reported fell below 1993 levels, reflecting one-time
charges for workforce reduction programs completed during the past year. A
total of 572 persons, or about 22 percent of the workforce elected to
participate in one of three programs offered in 1993 and 1994. Of that
total, 399 were participants in the most recent program completed on
October 1. The overall after-tax savings of the program are estimated to
be $61.2 million through 1998. The latest program resulted in a one-time
charge in September 1994 of approximately $33.7 million recorded under the
Income Statement caption Other Income and Deductions or $.59 per share, net
of tax. This follows 1993 write-offs totaling approximately $5.2 million
or $.09 per share for the earlier programs.
In addition to the cost of the workforce reduction programs,
earnings for the current nine months include a charge of $.01 per share for
a write-off of $.6 million of unrecoverable gas costs in April 1994.
Excluding the impact of non-recurring items, earnings for the
current three and nine months increased by $.07 and $.23, respectively.
These results reflect significant savings due to cost control efforts on
the part of employees, combined with recent workforce reductions, a modest
increase in rates and lower interest costs resulting from refinancing
activities. The positive results were partially offset by the dilutive
effect of issuance of additional shares of Common Stock.
OPERATING REVENUES AND SALES
Total Company revenues for the first nine months of 1994 were
$64.3 million or 9.3% above the first nine months of 1993, reflecting rate
26
adjustments to cover higher fuel costs (particularly for purchased gas) and
a moderate increase in rates.
Total Company revenues for the third quarter of 1994 were $12.7
million or 5.8% above the third quarter of 1993, with most of the gains
coming from rate adjustments to cover higher fuel costs as well as rate
relief.
Variations in revenues from sales to other electric utilities in
both comparison periods reflect mainly changes in energy market conditions
at the New York Power Pool.
The principal factors causing changes in Electric and Gas
Department revenues are estimated below:
Comparison of Comparison of
Three Months Nine Months
Ended September 30, Ended September 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 $ 3.6 $ .5 $ 14.7 $ 2.8
Fuel costs 2.1 5.9 8.1 32.6
Weather effects (Heating
& Cooling) (.9) - 1.5 .6
Customer consumption (1.2) .1 .4 (2.8)
Other (2.4) 4.5 (2.1) 12.1
Total change in customer -------- -------- -------- -------
revenues 1.2 11.0 22.6 45.3
OEU sales .5 - (3.5) -
-------- -------- -------- -------
Total change in operating
revenues $ 1.7 $ 11.0 $ 19.1 $ 45.3
======== ======== ======== =======
FUEL EXPENSES
Fuel expenses increased in both comparison periods reflecting
significant increases in the unit cost of purchased gas and greater
purchases of electricity partially offset by decreases in generated
electricity.
Gas costs have been rising and are expected to rise during the
upcoming heating season. See discussion under Note 2, Gas Cost Recovery.
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES
Operations excluding fuel expenses increased slightly in the nine
month comparison period reflecting mainly higher costs for the demand side
27
management program, claims, uncollectibles and site remediation, partially
offset by lower payroll and employee welfare costs due to employee
reductions and reduced expenses for contractors and consultants.
Operations, excluding fuel expenses, decreased for the third quarter
comparison period reflecting lower expenses for payroll, contractors and
consultants, partially offset by higher costs for claims, employee welfare
and the demand side management program. Lower maintenance expense in both
comparison periods also reflects reduced payroll and contractor 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.
Operating Federal income tax increased in both comparison periods
due to higher pre-tax book income.
OTHER STATEMENT OF INCOME ITEMS
Increases 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 and a one-half percent
increase in the effective rate beginning September 1, 1994. The new rate
is 5.0 percent on an accrual basis. The decrease in Other Income and
Deductions reflects mainly accounting adjustments related to workforce
reductions and regulatory disallowance net of Federal income tax. For a
discussion regarding workforce reductions and regulatory disallowance see
"Earnings Summary". Decreases in interest charges, excluding AFUDC,
reflect the refinancing of long-term debt at lower interest rates,
decreases in the amount of long-term debt outstanding, partially offset by
higher-short term borrowing levels and higher interest rates since 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 and Management Discussion and Analysis
of Financial Condition and Results of Operations under the heading entitled
"Cogeneration Contract Litigation".
28
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Exhibit 27 - Financial Data Schedule, pursuant to Item 601(c)
of Regulation S-K.
(b) Reports on Form 8-K: None.
29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: November 14, 1994 By THOMAS S. RICHARDS
--------------------------------------
Thomas S. Richards
Senior Vice President, Corporate Services
and General Counsel
(Principal Financial Officer)
Date: November 14, 1994 By DANIEL J. BAIER
--------------------------------------
Daniel J. Baier
Controller
(Principal Accounting Officer)
30