SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1995
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-672
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Rochester Gas and Electric Corporation
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(Exact name of registrant as specified in its charter)
New York 16-0612110
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) identification No.)
89 East Avenue, Rochester, NY 14649
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (716) 546-2700
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N/A
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Former name, former address and former fiscal year, if changed since last
report.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
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Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Common Stock, $5 par value, at April 30, 1995: 38,032,248
ROCHESTER GAS AND ELECTRIC CORPORATION
INDEX
Page No.
Part I - Financial Information
Consolidated Balance Sheet - March 31, 1995 and
December 31, 1994 1 - 2
Consolidated Statement of Income - Three Months Ended
March 31, 1995 3
Consolidated Statement of Cash Flows - Three Months
Ended March 31, 1995 and 1994 4
Notes to Financial Statements 5 - 12
Management's Discussion and Analysis of Financial
Condition and Results of Operations 13 - 21
Part II - Other Information
Legal Proceedings 21
Submission of Matters to a Vote of Security Holders 21
Exhibits and Reports on Form 8-K 22
Signatures 23
PART I-FINANCIAL INFORMATION
- ----------------------------
ROCHESTER GAS AND ELECTRIC CORPORATION
Consolidated Balance Sheet
(Thousands of Dollars) March 31, December 31,
(Unaudited) 1995 1994
- -------------------------------------------------------------------------
Assets
Utility Plant
Electric $2,302,557 $2,284,634
Gas 371,691 370,205
Common 137,047 135,975
Nuclear fuel 201,856 190,337
---------- ----------
3,013,151 2,981,151
Less: Accumulated depreciation 1,286,433 1,263,637
Nuclear fuel amortization 162,844 159,461
---------- ----------
1,563,874 1,558,053
Construction work in progress 138,907 128,860
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Net Utility Plant 1,702,781 1,686,913
---------- ----------
Current Assets
Cash and cash equivalents 4,651 2,810
Accounts receivable 141,162 110,417
Unbilled revenue receivable 46,232 54,270
Materials and supplies, at average cost
Fossil fuel 5,511 7,908
Construction and other supplies 13,815 13,264
Gas stored underground 5,382 24,315
Prepayments 34,454 23,535
---------- ----------
Total Current Assets 251,207 236,519
---------- ----------
Investment in Empire 38,560 38,560
Deferred Debits
Unamortized debt expense 17,882 18,343
Nuclear generating plant decommissioning fund 52,232 49,011
Nine Mile Two deferred costs 33,199 33,462
Deferred finance charges - Nine Mile Two 19,242 19,242
Other Deferred Debits 15,819 19,214
Regulatory assets -
Income taxes 199,561 205,794
Uranium enrichment decommissioning deferral 19,628 20,169
Deferred ice storm charges 18,472 19,111
FERC 636 transition costs 30,683 32,479
Demand side management costs 18,206 19,807
Deferred fuel costs - gas 14,109 33,845
Other regulatory assets 39,673 33,727
---------- ----------
Total Deferred Debits 478,706 504,204
---------- ----------
Total Assets $2,471,254 $2,466,196
- ------------------------------------------- ========== ==========
The accompanying notes are an integral part of the financial statements.
1
ROCHESTER GAS AND ELECTRIC CORPORATION
Consolidated Balance Sheet
(Thousands of Dollars) March 31, December 31,
(Unaudited) 1995 1994
- ----------------------------------------------------------------------------
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds $ 643,292 $ 643,278
- promissory notes 91,900 91,900
Preferred stock redeemable at option of Company 67,000 67,000
Preferred stock subject to mandatory redemption 55,000 55,000
Common shareholders' equity
Common stock
Authorized 50,000,000 shares; 37,866,131
shares outstanding at March 31, 1995
and 37,669,963 shares outstanding at
December 31, 1994. 674,931 670,569
Retained earnings 86,179 74,566
---------- ----------
Total Common Shareholders' Equity 761,110 745,135
---------- ----------
Total Capitalization 1,618,302 1,602,313
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Long Term Liabilities (Department of Energy)
Nuclear waste disposal 71,949 70,895
Uranium enrichment decommissioning 17,037 16,931
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Total Long Term Liabilities 88,986 87,826
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Current Liabilities
Note Payable - Empire 29,600 29,600
Short term debt 2,500 51,600
Accounts payable 42,640 42,934
Dividends payable 18,906 18,818
Taxes accrued 48,801 3,471
Interest accrued 15,175 11,967
Other 23,893 22,937
---------- ----------
Total Current Liabilities 181,515 181,327
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 380,643 402,894
Deferred finance charges - Nine Mile Two 19,242 19,242
Pension costs accrued 76,084 75,912
Other 106,482 96,682
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Total Deferred Credits and Other Liabilities 582,451 594,730
---------- ----------
Commitments and Other Matters (Note 2) -- --
---------- ----------
Total Capitalization and Liabilities $2,471,254 $2,466,196
- --------------------------------------- ========== ==========
The accompanying notes are an integral part of the financial statements.
2
ROCHESTER GAS AND ELECTRIC CORPORATION
Consolidated Statement of Income For the Three Months Ended
(Thousands of Dollars) March 31, March 31,
(Unaudited) 1995 1994
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Operating Revenues
Electric $163,499 $167,472
Gas 112,867 138,520
-------- --------
276,366 305,992
Electric sales to other utilities 4,753 4,060
-------- --------
Total Operating Revenues 281,119 310,052
-------- --------
Operating Expenses
Fuel Expenses
Fuel for electric generation 11,075 12,556
Purchased electricity 7,469 10,670
Gas purchased for resale 62,546 85,066
-------- --------
Total Fuel Expenses 81,090 108,292
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Operating Revenues Less Fuel Expenses 200,029 201,760
-------- --------
Other Operating Expenses
Operations excluding fuel expenses 56,861 60,100
Maintenance 10,523 16,506
Depreciation and amortization 22,409 21,408
Taxes - local, state and other 38,331 36,999
Federal income tax 25,348 19,569
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Total Other Operating Expenses 153,472 154,582
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Operating Income 46,557 47,178
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Other Income and Deductions
Allowance for other funds used during construction 207 92
Federal income tax 1,122 12
Other, net (3,120) 1,702
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Total Other Income and (Deductions) (1,791) 1,806
-------- --------
Interest Charges
Long term debt 13,105 13,685
Other, net 1,853 1,607
Allowance for borrowed funds used during construction (711) (545)
-------- --------
Total Interest Charges 14,247 14,747
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Net Income 30,519 34,237
Dividends on Preferred Stock 1,866 1,770
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Earnings Applicable to Common Stock $ 28,653 $ 32,467
======== ========
Weighted Average Number of Shares for Period (000's) 37,805 37,034
-------- --------
Earnings per Common Share $ 0.75 $ 0.87
-------- --------
Cash Dividends Paid per Common Share $ 0.45 $ 0.44
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The accompanying notes are an integral part of the financial statements.
3
ROCHESTER GAS AND ELECTRIC CORPORATION
Consolidated Statement of Cash Flows Three Months Ended
(Thousands of Dollars) March 31, March 31,
(Unaudited) 1995 1994
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CASH FLOW FROM OPERATIONS
Net income $ 30,519 $ 34,237
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation and amortization 22,409 21,408
Amortization of nuclear fuel 4,438 4,106
Deferred fuel - electric 1,363 (6,112)
Deferred fuel - gas 20,466 (657)
Deferred income taxes (15,048) (663)
Allowance for funds used during construction (918) (637)
Unbilled revenue, net 8,038 13,595
Deferred ice storm costs 639 615
Nuclear generating plant decommissioning fund (3,221) (2,560)
Changes in certain current assets and liabilities:
Accounts receivable (30,745) (33,107)
Materials and supplies - fossil fuel 2,397 2,659
- construction and other supplies (551) (171)
- gas stored underground 18,933 29,309
Taxes accrued 45,330 26,269
Accounts payable (294) 3,264
Interest accrued 3,208 3,507
Other current assets and liabilities, net (7,480) (18,883)
Other, net 10,222 9,647
-------- --------
Total Operating $109,705 $ 85,826
- ------------------------------------------------------------- ======== ========
CASH FLOW FROM INVESTING ACTIVITIES
Utility Plant
Plant additions $(31,231) $(20,202)
Nuclear fuel additions (11,519) (6,389)
Less: Allowance for funds used during construction 918 637
-------- --------
Additions to Utility Plant (41,832) (25,954)
Investment in Empire - net -- (65)
Other, net 5 7
-------- --------
Total Investing $(41,827) $(26,012)
- ------------------------------------------------------------- ======== ========
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issue of common stock $ 4,365 $ 4,495
Sale of preferred stock -- 25,000
Short term borrowings (49,100) (48,100)
Retirement of long term debt -- (2,750)
Retirement of preferred stock -- (18,000)
Capital stock expense (3) 1,375
Dividends paid on preferred stock (1,866) (1,825)
Dividends paid on common stock (16,951) (16,241)
Other, net (2,482) (2,525)
-------- --------
Total Financing $(66,037) $(58,571)
-------- --------
Increase in cash and cash equivalents $ 1,841 $ 1,243
Cash and cash equivalents at beginning of period $ 2,810 $ 2,327
-------- --------
Cash and cash equivalents at end of period $ 4,651 $ 3,570
- ------------------------------------------------------------ ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Three Months Ended
March 31, March 31,
1995 1994
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Cash Paid During the period
Interest paid (net of capitalized amount) $ 10,565 $ 10,469
Income taxes paid $ -- $ 1,198
- ------------------------------------------------------------ ======== ========
The accompanying notes are an integral part of the financial statements.
4
ROCHESTER GAS AND ELECTRIC CORPORATION
NOTES TO FINANCIAL STATEMENTS
Note 1: General
The accompanying unaudited financial statements reflect all
adjustments which are, in the opinion of management, necessary to a fair
presentation of the Company's results for these interim periods. All such
adjustments are of a normal recurring nature. The results for these interim
periods are not necessarily indicative of results to be expected for the year,
due to seasonal, operating, and other factors. These financial statements
should be read in conjunction with the financial statements and notes thereto
contained in the Company's Annual Report on Form 10-K for the year ended
December 31, 1994.
Note 2. Commitments and Other Matters
The following matters supplement the information contained in Note 10
to the financial statements included in the Company's Annual Report on Form 10-K
for the year ended December 31, 1994 and should be read in conjunction with the
material contained in that Note.
CAPITAL EXPENDITURES.
The Company's 1995 construction expenditures program is currently
estimated at $132 million, including $30 million related to replacement of the
steam generators at the Ginna Nuclear Plant. The Company had expended $43
million, including $16 million for steam generator replacement at the Ginna
Nuclear Plant as of March 31, 1995. The Company has entered into certain
commitments for the purchase of materials and equipment in connection with that
program.
LITIGATION WITH CO-GENERATOR.
Under Federal and New York State laws and regulations, the Company is
required to purchase the electrical output of unregulated cogeneration
facilities which meet certain criteria (Qualifying Facilities). With the
exception of one contract which the Company was compelled by regulators to enter
into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts
of capacity, the Company has no long-term obligations to purchase energy from
Qualifying Facilities.
Under State law and regulatory requirements in effect at the time the
contract with Kamine was negotiated, the Company was required to pay Kamine a
price for power that is substantially greater than the Company's own cost of
production and other purchases. Since that time the State law mandating a
minimum price higher than the Company's own costs has been repealed and PSC
estimates of future costs on which the contract was based have declined
dramatically.
5
In September 1994, the Company filed a lawsuit against Kamine in New
York State Supreme Court seeking to void its contract for the forced purchase of
unneeded electricity at above-market prices which would result in substantial
cost increases for the Company's customers. The Company estimates that Kamine
will owe the Company $400 million by the midpoint of the contract term and if
the contract extends to its full 25 year term, the total amount of such
overpayments (plus interest) could reach approximately $700 million. The
Company believes that Kamine will be unable to meet the contract security
requirements for these sums when due. Alternatively, the Company sought relief
to ensure that its customers would pay no more for the Kamine power than they
would pay for power from the Company's other sources of electricity. Kamine
answered the Company's complaint, seeking to force the Company to take and pay
for power at the above-market rates and claiming damages in an unspecified
amount alleged to have been caused by the Company's conduct. The Company began
receiving test generation from the Kamine facility during the last quarter of
1994. In late December 1994, the Company announced it would no longer be
accepting electric power from this facility because it is the Company's
position, among other reasons, that the Kamine facility is no longer a
"Qualifying Facility" as specified under Federal regulations. On February 17,
1995 Kamine petitioned the Federal Energy Regulatory Commission (FERC) for a
"Temporary Waiver of Operating and Efficiency Standards" seeking to technically
retain their status as a Qualifying Facility in 1994 despite the undisputed fact
that no thermal host existed when the plant is claimed to have entered
commercial service. The PSC has joined the Company in opposing Kamine's request
for waiver of the Qualifying Facility standards.
By a decision rendered March 16, 1995, the state court denied Kamine's
motion for summary judgement. The Company intends to vigorously pursue this
lawsuit, but is unable to predict the outcome at this time.
On January 27, 1995, Kamine initiated a lawsuit against the Company in
United States District Court for the Western District of New York for alleged
anti-trust violations by the Company that are based on the same issues that are
raised by the Company's New York State Court lawsuit. The Kamine lawsuit seeks
injunctive relief similar to that requested in Kamine's answer to the Company's
lawsuit in New York State Court and damages of $420 million. Kamine also moved
for a preliminary injunction and a temporary restraining order to require the
Company, during the pendency of the lawsuit, to accept and pay for electricity
generated by Kamine's facility. On March 20, 1995, the District Court issued a
decision and order granting Kamine's application for a temporary restraining
order to require the Company, for a period of ten days from entry of the order,
to purchase electricity generated by Kamine at a rate of at least six cents per
kilowatt hour. The Court subsequently extended the temporary restraining order
to April 27, 1995 to permit certain discovery requested by the Company in regard
to the pending motion for preliminary injunction. The Company intends to
vigorously defend against Kamine's lawsuit, but is unable to predict the
6
outcome at this time.
ENVIRONMENTAL MATTERS.
In March 1995, the Company recorded an additional estimated liability
of $10 million which it anticipates spending on Site Investgation and/or
Remediation (SIR) efforts at six Company-owned sites where past waste handling
and disposal may have occurred. Concurrently, the Company recorded a similar
increase in its Regulatory Assets. For further information on these sites and
SIR activities at non-Company owned Superfund or other sites for which the
Company has been or may be associated as a potentially responsible party see
Note 10 of the Notes to Financial Statements in the Company's Form 10-K for the
fiscal year ended December 31, 1994.
GAS COST RECOVERY.
As a result of the restructuring of the gas transportation industry by
the FERC pursuant to Order No. 636 and related decisions, there have been and
will be a number of changes in this aspect of the Company's business over the
next several years. For additional information with respect to these transition
costs see Note 10 of the Notes to Financial Statements in the Company's Form 10-
K for the fiscal year ended December 31, 1994.
The Company is committed to transportation capacity on the Empire
State Pipeline (Empire) as well as to upstream pipeline transportation and
storage services. The Company also has contractual obligations with CNG and
upstream pipelines whereby the Company is subject to charges for transportation
and storage services for a period extending to the year 2001. The combined CNG
and Empire transportation capacity exceeds the Company's current requirements.
This temporary excess has occurred largely due to the Company's initiatives to
diversify its supply of gas and the industry changes and increasing competition
resulting from the implementation of FERC Order 636.
Under FERC rules, the Company may release its excess transportation
capacity in the market. The Company is attempting to do that, whenever
possible. The Company also entered into a marketing agreement with CNG
Transmission Corporation (CNG), pursuant to which CNG will assist the Company in
obtaining permanent replacement customers for the transportation capacity the
Company will not require. While CNG has already secured letters of intent for a
substantial portion of such capacity and has ordered compressors and other
related equipment associated with the planned modifications to CNG's pipeline,
whether and to what extent CNG and/or the Company can successfully negotiate the
assignment of the excess capacity, or at what price, cannot be determined at the
present time. Several CNG customers protested CNG's proposed rolled-in rate
treatment, arguing that the new facility costs should be borne as incremental by
the letter of intent customers. The FERC issued a preliminary determination on
non-environmental issues in which it concluded that it would be in the public
interest to authorize
7
construction and operation of the proposed facilities. Subsequent to the
protests filed in response to the proposed rolled-in rate treatment of the
facility costs, the Company entered into an amended and restated marketing
agreement with CNG. As a result of this agreement and the negotiations
surrounding its implementation, CNG and Texas Eastern, joined by the Company and
the replacement customers filed a settlement agreement with the FERC, reflecting
certain changes in the facilities and their cost. While the impact of the
changes on rates is favorable to the approval of rolled-in treatment of the
facility costs, a few parties objected to the portion of the settlement dealing
with the cost treatment. Subsequently, CNG filed comments with the FERC
removing the roll-in issue from the settlement, thereby accepting incremental
rate treatment for the facilities pending the outcome of a future rate
proceeding. As a result, the Company anticipates that there will not be
significant objection to the settlement, however, the timing of the FERC
decision on the settlement and with respect to environmental issues cannot be
determined at the present time and that decision is necessary to implement the
permanent assignment of the excess capacity. The Company has also exercised its
option to postpone for one year the commencement of certain Empire-related
transportation service that was scheduled for November 1994. The Company will
continue to pursue other options for the release of the capacity and is
evaluating requests for proposals for management of its gas supply,
transportation and storage assets consistent with its need to provide reliable
service and reduce its cost of gas.
A reconciliation of gas costs incurred and gas costs billed to
customers is done annually, as of August 31, and the excess or deficiency is
refunded to or recovered from customers during a subsequent period. In October
1994, the Company submitted to the PSC its annual GCA reconciliation providing
for recovery of $24 million of deferred gas costs, which was substantially
higher than in previous years principally due to factors mentioned above.
The Staff of the PSC has reviewed the Company's application for
recovery of deferred costs and the Consumer Protection Board, along with certain
individuals or groups of ratepayers, has requested that the PSC conduct hearings
to determine whether and on what terms the deferral should be recovered. On
December 19, 1994, the PSC instituted a proceeding to review the Company's
practices regarding acquisition of pipeline capacity, the deferred costs of the
capacity and the Company's recovery of those costs. As an interim measure, on
February 1, 1995 the PSC directed the Company to remove from existing rates the
revenue effect of $16 million of gas costs attributable to capacity costs,
resulting in a net $370,000 or $.01 per share reduction in earnings for the 1995
first quarter. The Company has been permitted to offset the costs excluded from
rates with capacity release credits obtained in March and thereafter. Depending
on the outcome of the PSC's investigation and the Company's ability to secure
permanent capacity release on favorable terms, such net costs will continue to
be incurred. These net costs will vary from month to month and may increase if
the Company cannot continue to maintain capacity release at the current
8
level as the heating season concludes and the market for non-permanent capacity
release softens. At this time, the Company is unable to predict the timing and
extent to which future capacity release credits will be available to offset the
$16 million annual amount described above. These net costs would also be
impacted if the PSC determines that capacity was imprudently incurred and that
the related cost exceeds the $16 million previously described. In a more adverse
decision, the PSC could order the Company to refund a portion of such costs
previously collected from ratepayers.
The Company's purchased gas expense charged to customers has been
higher during the 1994-95 heating season for the reasons described above. The
impact of these cost increases on bills generated substantial customer concern,
especially since the heating season was unseasonably warm. The action the
Company took to reduce rates included refunding the weather normalization
adjustment charged to customers in January and discontinuation of those charges
through the remainder of the heating season ending in May. This reduced
earnings from gas operations for the three months ended March 31, 1995 by
approximately $4.2 million, $.08 per share. Earnings could be reduced by an
additional $0.8 million by the end of May if the weather remains mild. The
weather normalization adjustment provides for recovery of fixed charges by
producing higher unit rates when the weather is warm and usage is low.
Conversely, it would produce lower unit rates during colder periods of high
usage.
On April 21, 1995, the PSC issued a Department of Public Service (DPS)
staff report on the Company's 1994-1995 billings which presented recommendations
regarding changes in the Company's natural gas purchasing, billing, meter
reading and communication activities. The Company was ordered to respond to the
report with an implementation plan within 30 days.
REGULATORY AND STRANDED ASSETS.
Certain costs are deferred and recognized as expenses when they are
reflected in rates and recovered from customers as permitted by Statement of
Financial Accounting Standard No. 71, "Accounting of the Effects of Certain
Types of Regulation". These costs are shown as Regulatory Assets. Such costs
arise from the traditional cost-of-service rate setting approach where all
prudently incurred costs are recoverable through rates. Deferral of these costs
is appropriate while the Company's rates are regulated under a cost-of-service
approach.
In a purely competitive pricing approach, such costs might not have
been incurred or deferred. Accordingly, if the Company's rate setting were
changed from a cost-of-service approach and it was no longer allowed to defer
these costs under SFAS 71, certain of these assets may not be fully recoverable.
Below is a summarization of the Regulatory Assets as of March 31,
1995.
9
Millions
of dollars
----------
Income Taxes $199.5
Deferred Ice Storm Charges 18.5
Uranium Enrichment Decommissioning Deferral 19.6
FERC 636 Transition Costs 30.7
Demand Side Management Costs Deferred 18.2
Deferred Fuel Costs - Gas 14.1
Other, net 39.7
------
Total - Regulatory Assets $340.3
======
- Income Taxes: This amount represents the unrecovered portion of
tax benefits from accelerated depreciation and other timing
differences which were used to reduce tax expense in past years.
The recovery of this deferral is anticipated when the effect of the
past deductions reverses in future years.
- Deferred Ice Storm Charges: These costs result from the non-
capital storm damage repair costs following the March 1991 ice
storm.
- Uranium Enrichment Decommissioning Deferral: This amount is
mandated to be paid to DOE over the next 13 years. The Energy
Policy Act of 1992 requires nuclear licensees to contribute such
amounts based on the amount of uranium enriched by DOE for each
licensee.
- FERC 636 Transition Costs: These costs are payable to gas supply
and pipeline companies which are passing various restructuring and
other transition costs on to the Company, as ordered by FERC.
- Demand Side Management Costs Deferred: These costs are Demand Side
Management costs which relate to programs initiated to increase
efficiency with which electricity is used.
- Deferred Fuel Costs - Gas: These costs are recoverable over future
years and arise from an annual reconciliation of gas revenues and
costs.
Stranded assets (or other costs) arise when investments are made in
facilities, or costs are incurred to serve customers, and such costs and
investments may not be fully recoverable in market-based rates. Examples may
include purchased power contracts (i.e., the Kamine contract) or high cost
generating assets.
Excluding the Kamine contract described above, estimates of possible
stranded asset amounts vary as to scope and methodology and are
10
highly sensitive to the competitive wholesale price assumed in the estimation
for electricity. The amount of potential stranded assets at March 31, 1995,
cannot be determined at this time but could be significant.
While the Company currently believes that its regulatory and
potentially stranded assets are probable of recovery in rates, industry trends
have moved more toward competition, and in a purely competitive environment, it
is not clear to what extent, if any, writeoffs of such assets may occur.
NUCLEAR DECOMMISSIONING TRUST. The Company is collecting in its
electric rates amounts for the eventual decommissioning of its Ginna Plant and
for its 14% share of the 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 $72.3 million through March 31, 1995. In connection
with the Company's rate settlement completed in August 1993, the PSC approved
the collection during the rate year ending June 30, 1995 of an aggregate $8.9
million for decommissioning, covering both nuclear units. The amount allowed in
rates is based on estimated ultimate decommissioning costs of $163.0 million for
Ginna and $37.1 million for the Company's 14% share of Nine Mile Two (January
1994 dollars). This estimate is based principally on the application of a
Nuclear Regulatory Commission (NRC) formula to determine minimum funding with an
additional allowance for removal of non-contaminated structures. Site specific
studies of the anticipated costs of actual decommissioning are required to be
submitted to the NRC at least five years prior to the expiration of the license.
The Company believes that future estimates of decommissioning costs could
substantially exceed these current estimates but is unable to predict the costs
at this time. The Company is currently performing a site specific cost analysis
of decommissioning at Ginna.
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 $47.9 million
to this fund and, including investment returns, the fund has a balance of $52.2
million as of March 31, 1995. The amount attributed to the allowance for
removal of non-contaminated structures is being held in an internal reserve.
The internal reserve balance as of March 31, 1995 is $24.4 million.
The Company is aware of recent NRC activities related to upward
revisions to the required minimum funding levels. These activities, primarily
focused on disposition of low level radioactive
11
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.
The Staff of the Securities and Exchange Commission and the Financial
Accounting Standards Board are currently studying the recognition, measurement
and classification of decommissioning costs for nuclear generating stations in
the financial statements of electric utilities. If current accounting practices
for such costs were changed, the annual provisions for decommissioning costs
would increase, the estimated cost for decommissioning could be reclassified as
a liability rather than as accumulated depreciation and trust fund income from
the external decommissioning trusts could be reported as investment income
rather than as a reduction to decommissioning expense. If annual
decommissioning costs increased, the Company would defer the effects of such
costs pending disposition by the Public Service Commission.
12
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is Management's assessment of certain significant
factors affecting financial condition and operating results.
EARNINGS SUMMARY
Earnings Per Common Share
For the Periods Ended
March 31,
------------------------
1995 1994
---- ----
Three Months $ .75 $ .87
Earnings for the first quarter of 1995 decreased 13.8% from the 1994
quarter, primarily due to warm weather during this heating season and actions
the Company took to reduce customer gas bills, which had reflected increased
costs per therm over the prior heating season. As previously discussed, gas
costs per therm increased significantly in January reflecting the cost impact of
excess capacity resulting from transition from a single to two principal
pipeline suppliers. Gas costs also increased due to Federal Energy Regulatory
Commission (FERC) Order 636 transition costs as a result of industry
restructuring, weather normalization costs and operation of the gas cost
adjustment provisions under the Company's allowed rates. The impact of these
cost increases on bills generated substantial customer concern, especially since
the heating season was unseasonably warm.
The actions the Company took to reduce rates included refunding of the
weather normalization adjustment stemming from the milder weather charged to
customers in January and discontinuation of those charges through the remainder
of the heating season ending in May. This reduced earnings from gas operations
for the quarter ended March 31 by approximately $4.2 million, $.08 per share
after tax. Earnings could be reduced by an additional $0.8 million if the
weather remains mild through the end of May. The weather normalization
adjustment provides for recovery of fixed charges by producing higher unit rates
when the weather is warm and usage is low. Conversely, it produces lower unit
rates during periods of high usage.
Earnings were reduced by a net $370,000, $.01 per share, arising from a $16
million annual reduction of gas capacity costs beginning in February by order of
the New York State Public Service Commission (PSC). The Company has been
permitted to offset this impact with market capacity release credits obtained in
March and thereafter. Depending on the outcome of the PSC's investigation and
the Company's ability to secure permanent capacity release on favorable terms,
such costs will continue to be incurred. These costs will vary from month to
month and may increase if the Company cannot maintain capacity release at the
current level as the heating season concludes and the market for non-permanent
capacity release softens. At this time, the Company is unable to predict the
timing and extent to which future capacity release credits will be available to
offset the $16 million annual amount described above. These costs would also be
impacted if the PSC determines that capacity was imprudently incurred and that
the related
13
cost exceeds the $16 million previously described.
The cost structure of its gas business is a major challenge for the Company
today. The Company is taking various actions to stabilize the current gas
price, reduce the long-term cost of gas, change the rate structure to make the
bills easier to understand and respond to the anticipated expansion of options,
including choice of suppliers, to customers. Nevertheless, a substantial portion
of the cost related to the gas business is fixed. The contracts for excess
capacity will continue for several years and the ability of the Company to
reduce its costs will depend in large measure on its ability to market gas
capacity on favorable terms.
Earnings for the first three months of 1995 and 1994 include savings
associated with corporate downsizing initiatives conducted in 1993 and 1994.
Savings associated with these programs and ongoing cost control efforts reduced
current period expenses and will have a positive effect on the Company's long-
term financial performance.
COMMON STOCK DIVIDEND
On March 15, 1995, the Board of Directors authorized a common stock dividend
of $.45 per share, which was paid on April 25, 1995 to shareholders of record on
April 6, 1995. The Company believes that future dividend payments will need to
be evaluated in the context of maintaining the financial strength necessary to
operate in a more competitive and uncertain business environment. This will
require consideration, among other things, of a dividend payout ratio that is
lower over time, reevaluating assets and managing greater fluctuation in
revenues. While the Company does not presently expect the impact of these
factors to affect the Company's ability to pay dividends at the current rate,
future dividends may be affected.
COMPETITION
The Company is operating in a rapidly developing competitive marketplace
for electric and gas service. In its electric business, this competitive
environment includes a Federal trend toward deregulation and a state trend
toward incentive regulation. The passage of the National Energy Policy Act of
1992 (Energy Act) has accelerated these competitive challenges by promoting
competition in the electric power industry at the wholesale level, and ensuring
that a new class of independent power producers established under the Energy
Act, as well as qualified facilities and other electric utilities, can achieve
access to utility-owned transmission facilities upon payment of appropriate
prices. (See following paragraph regarding a recently issued FERC proposal to
promote competition at the wholesale level.) In New York State, the PSC has
authorized flexible pricing for certain large customers who have "realistic
competitive alternatives". In a generic proceeding now underway to identify
regulatory practices that will assist in the transition to a more competitive
energy market, the PSC has indicated that the current vertically integrated
industry is incompatible with effective competition. Competition in the
Company's gas business was accelerated with the adoption of FERC Order No. 636,
14
requiring interstate natural gas pipeline companies to offer customers
"unbundled", or separately-priced, sale and transportation services. The PSC
has been conducting proceedings to investigate various issues regarding the
emerging competitive environment in the electric and gas business in New York
State. See the Company's 1994 Form 10-K, Management's Discussion and Analysis
of Financial Condition and Results of Operations under the heading "Competition"
for information on the competitive challenges the Company faces in its electric
and gas business and how it proposes to respond to those challenges.
The FERC in a Notice of Proposed Rulemaking issued March 29, 1995, proposed
significant changes in the wholesale electric industry, creating the foundation
for a more competitive bulk power market. The rules are designed to facilitate
the development of a competitive market by ensuring that wholesale buyers and
sellers can reach each other under non-discriminatory open access transmission
tariffs. The proposal addresses two primary areas - open transmission access
and recovery of stranded investment. The proposed rules include the following:
- each utility under FERC jurisdiction (including the Company)
would be required to file non-discriminatory open access
transmission tariffs, available to all wholesale sellers and
buyers of electric energy;
- each utility would be required to take service under these
tariffs for its own wholesale sales and purchases of
electric energy; and
- each utility would be allowed the opportunity to recover
stranded costs.
Stranded costs may result when a customer stops buying power from a utility
and, instead, simply uses the utility's transmission service to obtain power
from another source. The FERC proposes to establish the principle that
utilities are entitled to full recovery of legitimate and verifiable stranded
costs at both the state and federal level. It expects the States to deal with
any costs stranded due to retail wheeling or direct access programs. The FERC
will provide recovery mechanisms for stranded costs due to municipalization or
other instances where former retail customers become wholesale customers, as
well as wholesale stranded costs.
The Company is studying the proposal and is currently unable to fully assess
its effect on the Company's retail business or sales in the wholesale market.
However, the proposal provides a stranded cost recovery model that the States
may choose to emulate. To the extent that New York chooses to do so, the
Company may be better protected from losses that would otherwise occur if retail
competition becomes a reality. Comments on this proposed rulemaking are due in
early August.
LIQUIDITY AND CAPITAL RESOURCES
The Company anticipates meeting its 1995 capital requirements
primarily from the use of internally generated funds. It has no debt
15
maturity or sinking fund obligations scheduled in 1995. During the first three
months of 1995 cash flow from operations, together with proceeds from external
financing activity (see Consolidated Statement of Cash Flows), provided the
funds for construction expenditures and the retirement of short-term borrowings.
PROJECTED CAPITAL AND OTHER REQUIREMENTS
The Company's capital requirements relate primarily to expenditures for
electric generation including replacement of its Ginna steam generators,
transmission and distribution facilities and gas mains and services as well as
the repayment of existing debt. Construction programs of the Company focus on
the need to serve new customers, to provide for the replacement of obsolete or
inefficient utility property and to modify facilities consistent with the most
current environmental and safety regulations. The Company has no current plans
to install additional base load generation.
The Company's most current Integrated Resource Plan (IRP) explores options for
complying with the 1990 Clean Air Act Amendments. The IRP is part of an ongoing
planning process to examine options for the future with regard to generating
resources and alternative methods of meeting electric capacity requirements.
Activities are currently under way to:
- Modify Units 2, 3, and 4 at Russell Station and Unit 12 at Beebee
Station, all coal-fired facilities, to meet Federal Environmental
Protection Agency standards and Clean Air Act requirements,
- Replace the two steam generators at the Ginna Nuclear Plant.
(See below.)
Total 1995 capital requirements for construction are currently
estimated at $132 million, including replacement of the steam generators at the
Ginna Nuclear Plant as discussed below. Approximately $43 million had been
expended for construction as of March 31, 1995, reflecting primarily
expenditures for steam generator replacement, upgrading electric generating,
transmission and distribution facilities and gas mains and expenditures for
nuclear fuel.
Preparation for replacement of the two steam generators at the Ginna
Nuclear Plant began in 1993 and will continue until the replacement in 1996.
Steam generator fabrication is well underway. All major components for the
steam generators have been delivered and major sub-assemblies have been
fabricated. Manufacturing will be completed in early 1996 and the steam
generators will be shipped to the site. The installation contractor will remain
on site throughout 1995 in preparation for the 1996 replacement outage. Cost of
the replacement is estimated at $115 million, about $40 million for the units,
about $50 million for installation and the remainder for engineering, radiation
protection, plant support, other services and finance charges. The Company
spent $16 million on this project in the first quarter and expects to spend
about $30 million in 1995. Installation activities during 1995 will include a
number of in-containment modifications,
16
foundations for building and equipment, construction of a temporary building on
site and construction of the old steam generator storage building. The PSC
order approving this project provides that certain costs over $115 million will
not be fully recoverable in rates but the Company does not expect to exceed that
estimated cost.
FINANCING
Under provisions of the Company's Charter, the Company may not issue
unsecured debt if immediately after such issuance the total amount of unsecured
debt outstanding would exceed 15 percent of the Company's total secured
indebtedness, capital, and surplus without the approval of at least a majority
of the holders of outstanding Preferred Stock. At March 31, 1995, the Company
was able to issue $68.1 million of additional unsecured debt under this
provision.
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, 1997
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
providing for up to $30 million for the exclusive purpose of financing FERC
Order 636 transition costs and up to $20 million as needed from time to time for
other working capital needs. Borrowings under this agreement which can be
renewed annually, are secured by a lien on the Company's accounts receivable.
The Company also has unsecured short-term lines of credit totaling $72 million
with several other banks. At March 31, 1995 the Company had short-term
borrowings outstanding of $20 million all of which were secured under the Loan
and Security Agreement described above.
During the first three months of 1995, the Company issued 196,168 shares of
Common Stock through its Automatic Dividend Reinvestment and Stock Purchase Plan
(ADR Plan) and the RG&E Savings Plus Plan (Savings Plus Plan) providing
approximately $4.4 million to help finance its capital expenditures program.
The new shares were issued at a market price above the book value per share at
the time of issuance. At March 31, 1995 the Company had Common Stock available
for issuance of 380,523 shares under the ADR Plan and 111,314 shares under the
Savings Plus Plan. The Company is seeking regulatory authorization to issue an
additional 1,500,000 shares under the ADR Plan and an additional 150,000 shares
under the Savings Plus Plan.
CAPITAL STRUCTURE
The Company's retained earnings at March 31, 1995 were $86.2 million, an
increase of approximately $11.6 million compared with December 31, 1994. There
were virtually no changes in the amount of long term debt and preferred stock at
March 31, 1995 as compared with December 31, 1994. Common equity increased
approximately $16.0 million, reflecting the issuance and sale of Common Stock as
discussed under
17
"Financing" and an increase in retained earnings. Capitalization at March 31,
1995, was comprised of 45.0 percent common equity, 7.2 percent preferred equity
and 47.8 percent long-term debt. To improve its capital structure, the Company
currently anticipates the issuance of new shares of common stock, primarily
through the Company's ADR Plan. The Company is reviewing its financing
strategies as they relate to debt and equity structures in the context of the
new competitive environment and the ability of the Company to shift from a fully
regulated to a more competitive organization.
RATE BASE AND REGULATORY POLICIES
The Company is subject to PSC regulation of rates, service, and sale of
securities, among other matters. 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. The 1993 Rate Agreement will determine the
Company's rates through June 30, 1996 and includes certain incentive
arrangements providing for both rewards and penalties. The 1993 Rate Agreement
amounts are based on an allowed return on common equity of 11.50% through June
30, 1996. Earnings between 8.50% and 14.50% will be absorbed/retained by the
Company. Earnings above 14.50% will be refunded to the customers. If, but not
unless, earnings fall below 8.50%, or cash interest coverage falls below 2.2
times, the Company can petition the PSC for relief. See the Company's 1994 Form
10-K, Management's Discussion and Analysis of Financial Condition and Results of
Operations under the heading "REGULATORY MATTERS--New York State Public Service
Commission" for additional information on the 1993 Rate Agreement including a
discussion of the incentive arrangements and the risks and rewards available to
the Company under the 1993 Rate Agreement.
In March and April 1995 the Company filed with the PSC the adjustments
required under the various clauses of the 1993 Rate Agreement and submitted a
proposal for an electric revenue increase of $18.3 million (2.50%), and a gas
revenue increase of $8.0 million (2.55%) for the rate year beginning July 1,
1995. With respect to electric operations, the Company is entitled to increase
electric revenues by $33.5 million, or 4.58%. Although the Company has earned
sufficient amounts under the terms of the various 1993 Rate Agreement provisions
to collect the maximum amount allowed, the increase sought by the Company gives
consideration to the price impact on customers by holding the rate increase to
below the rate of inflation at 2.5%. With regard to gas operations, the $8.0
million (2.55%) increase represents the amount to which the Company is entitled
under the 1993 Rate Agreement. In the filing, however, the Company acknowleged
that there are a number of factors that have increased the cost of natural gas
for its customers, including issues relating to excess capacity that are the
subject of a PSC proceeding and indicated its willingness to consider this
revenue requirement as part of the overall resolution of the factors affecting
the cost of natural gas in a way that minimizes the total impact on customers.
Excluded from the proposed electric increase are adjustments for Integrated
Resource Management and Demand Side Management incentive amounts which will be
filed when they are
18
available. A PSC decision on the proposed rates is expected by June 30, 1995.
Under a flexible pricing tariff for major industrial and commercial
electric customers the Company may negotiate competitive electric rates at
discount prices to compete with alternative power sources, such as customer-
owned generation facilities. Under the terms of the 1993 Rate Agreement, the
Company would absorb 30 percent of any net revenues lost as a result of such
discounts through June 1996, while the remainder would be recovered from other
customers. The portion recoverable after June 1996 is expected to be determined
in a future Company rate proceeding. Under these tariff provisions, the Company
has negotiated long-term electric supply contracts with three of its large
industrial and commercial electric customers at discounted rates. The Company is
negotiating long term electric supply contracts with several large customers and
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.
The PSC Staff is currently reviewing the Company's application for the
recovery of certain deferred gas costs and has required the Company to file a
plan pertaining to gas purchasing, billing, meter reading and communication
activities, as discussed in Note 2 of the Financial Statements under the heading
"Gas Cost Recovery".
The PSC has been conducting proceedings to investigate various issues
regarding the emerging competitive environment in the electric and gas business
in New York State, as noted under the heading Competition.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant changes
in the amounts of revenues and expenses, comparing the three-month period ended
March 31, 1995 to the corresponding three-month period ended March 31, 1994.
OPERATING REVENUES AND SALES
Total Company revenues for the first three months of 1995 were $28.9
million or 9.3% below the first three months of 1994, with most of the loss
resulting from lower gas revenues due to the mild weather, the deferral of $16
million of gas revenues representing a portion of the costs attritutable to
excess capacity subject to PSC review as described under Note 2, Gas Cost
Recovery and the Company decision to discontinue for the balance of the heating
season the operation of its weather normalization clause in order to moderate
the adverse effects on customer bills. Customer electric revenue also decreased
due to the mild weather and lower fuel costs.
Revenues from other electric utility (OEU) sales increased $0.7 million or
17.1% for the three-month comparison period reflecting higher kilowatt hour
sales and higher rates. In addition to sales through the New York Power Pool,
tariff changes in late 1994 allowed the Company to
19
participate in two-party sales.
The principal factors causing changes in Electric and Gas Department
revenues are estimated below:
Comparison of
Three Months
Ended March 31,
1995 and 1994
----------------------
Increase or (Decrease)
for comparison period
(Millions of Dollars)
Electric Gas
-------- ---
Rate increases $ 4.3 $ 2.9
Fuel costs (4.7) (22.8)
Weather effects (heating & cooling) (6.1) (9.8)
Customer consumption* 3.3 8.4
Other (.8) (4.4)
Total change in customer ----- ------
revenues (4.0) (25.7)
OEU sales .7 -
----- ------
Total change in operating
revenues $(3.3) $(25.7)
===== ======
* Customer consumption reflects retail and unbilled margins and
transportation less rate increases and weather effects.
FUEL EXPENSES
Fuel expenses decreased in the first three months of 1995 reflecting
lower unit electric and gas customer sales due to mild weather, elimination of
the gas weather normalization clause and deferral of gas excess capacity costs
in the 1995 first quarter as discussed under "Earnings Summary".
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES
The decreases in these line items reflect mainly lower cost for payroll,
employee welfare, contractor and consultant services and materials and supplies
due to Company cost control efforts and the workforce reduction program
undertaken in the second and third quarters of 1994. Also, expenses were higher
in the first quarter of 1994 due to the timing of the annual shutdown for the
Ginna Plant maintenance and refueling which included 22 more days in the first
quarter due to an earlier start.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased due mainly to an increase in
depreciable plant.
TAXES
The increase in local, state and other taxes reflects mainly an
20
additional assessment resulting from a New York State sales tax audit partially
offset by lower payroll taxes due to fewer employees and a 2.50% decrease in the
surcharge on the New York State Gross Revenue Tax.
The increase in Federal income tax during the first quarter as
compared to the first quarter a year ago reflects a variation in the effective
tax rate used in the Company's interim tax provision.
OTHER STATEMENT OF INCOME ITEMS
The increase in allowance for funds used during construction (AFUDC)
reflects an increase in the amount of utility plant under construction and not
included in rate base and a one-half percent increase in the effective rate from
the same period last year.
Interest charges, excluding AFUDC, were reduced due to a $31 million
decrease in long-term debt from last year. The increase in dividends on
preferred stock reflects the issuance of preferred stock in March 1994.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information on Legal Proceedings reference is made to Note 2 of the
Notes to Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The Company's Annual Meeting of Shareholders was held on April
18, 1995.
(b) The following Directors were elected for terms expiring at the
Annual Meeting of Shareholders in 1998: Angelo J. Chiarella,
Jay T. Holmes, David K. Laniak, and Cornelius J. Murphy.
The following Directors are continuing in office after the
meeting: William Balderston III, Allan E. Dugan, William F.
Fowble, Roger W. Kober, Theodore L. Levinson, Constance M.
Mitchell, Arthur M. Richardson and M. Richard Rose.
(c) The nominees for election as directors were elected by the
following vote:
Shares Shares Broker
For Withheld Non-Votes
---------- --------- ---------
Angelo J. Chiarella 32,913,011 1,187,341 0
Jay T. Holmes 32,916,617 1,183,735 0
David K. Laniak 32,448,872 1,651,480 0
Cornelius J. Murphy 32,931,963 1,168,389 0
21
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K:
The Company filed a Form 8-K, dated February 10, 1995 reporting
under Item 5. Other Events, information relating to gas cost
recovery and also cogeneration contract litigation.
EXHIBIT INDEX
Exhibit 27 - Financial Data Schedule pursuant to Item 601 (c) of
Regulation S-K.
22
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: May 12, 1995 By THOMAS S. RICHARDS
--------------------------------------
Thomas S. Richards
Senior Vice President, Corporate Services
and General Counsel
(Principal Financial Officer)
Date: May 12, 1995 By DANIEL J. BAIER
--------------------------------------
Daniel J. Baier
Controller
(Principal Accounting Officer)
23