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, 1997
------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from _________________ to _______________
Commission file number: 1-672
-----
Rochester Gas and Electric Corporation
----------------------------------------
(Exact name of registrant as specified in its charter)
New York 16-0612110
----------------------- ---------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) identification No.)
89 East Avenue, Rochester, NY 14649
--------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (716) 546-2700
--------------
N/A
- --------------------------------------------------------------------
(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, 1997: 38,858,719
----------
ROCHESTER GAS AND ELECTRIC CORPORATION
Information Required on Form 10-Q
Page
Description Number
- ----------- ------
PART I - FINANCIAL INFORMATION
- ------
Consolidated Balance Sheet
as of September 30, 1997 and December 31, 1996 1 - 2
Consolidated Statement of Income
Three Months and Nine Months Ended September 30, 1997 and 1996 3 - 4
Consolidated Statement of Cash Flows
Nine Months Ended September 30, 1997 and 1996 5
Notes to Financial Statements 6 -11
Management's Discussion and Analysis of
Financial Condition and Results of Operations 11 -24
PART II - OTHER INFORMATION
- -------
Legal Proceedings 24
Other Events 24
Exhibits and Reports on Form 8-K 24 -25
Signatures 26
PART 1 - FINANCIAL INFORMATION
- ------------------------------
ITEM 1. FINANCIAL STATEMENTS
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
September 30, December 31,
Assets 1997 1996
- --------------------------------------------------------------------------------
Utility Plant
Electric $2,431,583 $2,413,881
Gas 406,755 391,231
Common 135,140 129,946
Nuclear fuel 242,727 224,701
------------ --------------
3,216,205 3,159,759
Less: Accumulated depreciation 1,479,948 1,381,908
Nuclear fuel amortization 200,909 187,170
------------ --------------
1,535,348 1,590,681
Construction work in progress 64,896 69,711
------------ --------------
Net Utility Plant 1,600,244 1,660,392
------------ --------------
Current Assets
Cash and cash equivalents 153,033 21,301
Accounts receivable, net of allowance for
doubtful accounts: 1997-$22,581, 1996-$17,500 85,938 112,908
Unbilled revenue receivable 33,209 53,261
Materials, supplies and fuels, at average cost 32,066 39,888
Prepayments 32,501 23,103
------------ --------------
Total Current Assets 336,747 250,461
------------ --------------
Deferred Debits
Nuclear generating plant decommissioning fund 123,413 91,195
Nine Mile Two deferred costs 30,571 31,360
Unamortized debt expense 13,653 14,820
Other deferred debits 23,968 28,759
Regulatory assets (Note 2) 241,273 284,489
------------ --------------
Total Deferred Debits 432,878 450,623
------------ --------------
Total Assets $2,369,869 $2,361,476
- ----------------------- ------------ --------------
The accompanying notes are an integral part of the financial statements.
1
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(THOUSANDS OF DOLLARS)
(UNAUDITED)
September 30, December 31,
Capitalization and Liabilities 1997 1996
- --------------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $485,417 $555,054
- promissory notes 101,900 91,900
Preferred stock redeemable at option of Company 47,000 67,000
Preferred stock subject to mandatory redemption 35,000 45,000
Common shareholders' equity:
Common stock
Authorized 50,000,000 shares; 38,851,464
shares outstanding at September 30, 1997
and at December 31, 1996. 696,273 696,019
Retained earnings 114,213 90,540
---------------- ----------------
Total common shareholders' equity 810,486 786,559
---------------- ----------------
Total Capitalization 1,479,803 1,545,513
---------------- ----------------
Long Term Liabilities (Department of Energy)
Nuclear waste disposal 82,221 79,057
Uranium enrichment decommissioning 14,978 14,695
---------------- ----------------
Total Long Term Liabilities 97,199 93,752
---------------- ----------------
Current Liabilities
Long term debt due within one year 131,900 20,000
Preferred stock redeemable within one year 10,000 10,000
Short term debt - 14,000
Accounts payable 56,858 49,462
Dividends payable 18,788 19,349
Taxes accrued 758 4,694
Interest accrued 13,804 10,317
Other 34,259 30,395
---------------- ----------------
Total Current Liabilities 266,367 158,217
---------------- ----------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 355,769 370,028
Pension costs accrued 69,345 69,806
Other 101,386 124,160
---------------- ----------------
Total Deferred Credits and Other Liabilities 526,500 563,994
---------------- ----------------
Commitments and Other Matters (Note 2) - -
---------------- ----------------
Total Capitalization and Liabilities $2,369,869 $2,361,476
- --------------------------------------------------------------------------------- ----------------
The accompanying notes are an integral part of the financial statements.
2
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
For the Three Months Ended
September 30,
1997 1996
- --------------------------------------------------------------------------------
Operating Revenues
Electric $ 178,625 $ 190,507
Gas 36,886 42,481
---------- ----------
215,511 232,988
Electric sales to other utilities 5,824 1,855
---------- ----------
Total Operating Revenues 221,335 234,843
---------- ----------
Fuel Expenses
Fuel for electric generation 13,463 9,893
Purchased electricity 6,873 9,380
Gas purchased for resale 22,606 29,904
---------- ----------
Total Fuel Expenses 42,942 49,177
---------- ----------
OPERATING REVENUE LESS FUEL EXPENSES 178,393 185,666
---------- ----------
Other Operating Expenses
Operations excluding fuel expenses 62,973 65,114
Maintenance 8,550 11,148
Depreciation and amortization 29,051 29,349
Taxes - local, state and other 27,539 29,603
Federal income tax 15,664 14,293
---------- ----------
Total Other Operating Expenses 143,777 149,507
---------- ----------
OPERATING INCOME 34,616 36,159
---------- ----------
Other (income) and Deductions
Allowance for other funds
used during construction (150) (72)
Federal income tax (626) (552)
Other - net 1,355 1,440
---------- ----------
Total Other Income and Deductions 579 816
---------- ----------
INCOME BEFORE INTEREST CHARGES 34,037 35,343
---------- ----------
Interest Charges
Long term debt 10,859 11,892
Other - net 1,695 2,505
Allowance for borrowed funds
used during construction (241) (116)
---------- ----------
Total Interest Charges 12,313 14,281
---------- ----------
NET INCOME 21,724 21,062
---------- ----------
Dividends on Preferred Stock 1,305 1,866
---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 20,419 $ 19,196
---------- ----------
Weighted average number of shares
outstanding in each period (000's) 38,851 38,851
Earnings per Common Share $0.52 $0.49
Cash Dividends Paid per Common Share $0.45 $0.45
- ------------------------------------------------------
The accompanying notes are an integral part of the financial statements.
3
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
For the Nine Months Ended
September 30,
1997 1996
- --------------------------------------------------------------------------------
Operating Revenues
Electric $516,042 $524,143
Gas 234,932 242,676
--------- ---------
750,974 766,819
Electric sales to other utilities 14,625 12,797
--------- ---------
Total Operating Revenues 765,599 779,616
--------- ---------
Fuel Expenses
Fuel for electric generation 35,825 29,750
Purchased electricity 17,313 35,688
Gas purchased for resale 137,689 139,478
--------- ---------
Total Fuel Expenses 190,827 204,916
--------- ---------
OPERATING REVENUE LESS FUEL EXPENSES 574,772 574,700
--------- ---------
Other Operating Expenses
Operations excluding fuel expenses 191,938 195,008
Maintenance 30,333 36,166
Depreciation and amortization 87,575 76,707
Taxes - local, state and other 90,596 97,101
Federal income tax 53,395 53,578
--------- ---------
Total Other Operating Expenses 453,837 458,560
--------- ---------
OPERATING INCOME 120,935 116,140
--------- ---------
Other (Income) and Deductions
Allowance for other funds
used during construction (283) (600)
Federal income tax (2,395) (1,556)
Other - net 3,519 544
--------- ---------
Total Other Income and Deductions 841 (1,612)
--------- ---------
INCOME BEFORE INTEREST CHARGES 120,094 117,752
--------- ---------
Interest Charges
Long term debt 33,999 36,733
Other - net 5,220 7,025
Allowance for borrowed funds
used during construction (454) (1,289)
--------- ---------
Total Interest Charges 38,765 42,469
--------- ---------
NET INCOME 81,329 75,283
--------- ---------
Dividends on Preferred Stock 4,500 5,599
--------- ---------
EARNINGS APPLICABLE TO COMMON STOCK $ 76,829 $69,684
--------- ---------
Weighted average number of shares
outstanding in each period (000's) 38,851 38,735
Earnings per Common Share $1.97 $1.79
Cash Dividends Paid per Common Share $1.35 $1.35
______________________________________________________________________
The accompanying notes are an integral part of the financial statements.
4
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
(Thousands of Dollars) September, 30,
- --------------------------------------------------------------------------------------------------
1997 1996*
----------------------------
CASH FLOW FROM OPERATING ACTIVITIES
Net income $ 81,329 $ 75,283
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 101,713 88,470
Deferred fuel (1,709) (3,352)
Deferred income taxes (2,116) 5,948
Allowance for funds used during construction (737) (1,890)
Unbilled revenue, net 20,051 23,693
Nuclear generating plant decommissioning fund (14,831) (6,652)
Pension costs accrued (2,383) (869)
Post employment benefit internal reserve 4,998 4,485
Changes in certain current assets and liabilities:
Accounts receivable 26,969 15,865
Materials, supplies and fuels 7,822 (443)
Taxes accrued (3,936) (18,229)
Accounts payable 7,396 4,330
Other current assets and liabilities, net (2,607) (11,021)
Other, net 14,653 10,894
----------- -----------
Total Operating 236,612 186,512
----------- -----------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (55,710) (95,620)
Other, net - 9,216
----------- -----------
Total Investing (55,710) (86,404)
----------- -----------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/issuance of common stock - 8,612
Issuance of Promissory notes 101,900 -
Repayment of Short term borrowings (14,000) -
Retirement of preferred stock (30,000) -
Retirement of long term debt (49,668) (67,332)
Dividends paid on preferred stock (5,061) (5,599)
Dividends paid on common stock (52,449) (52,173)
Other, net 108 3,118
----------- -----------
Total Financing (49,170) (113,374)
----------- -----------
Increase (decrease) in cash and cash equivalents 131,732 (13,266)
Cash and cash equivalents at beginning of period 21,301 44,121
----------- -----------
Cash and cash equivalents at end of period $153,033 $ 30,855
----------- -----------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Nine Months Ended
(Thousands of Dollars) September, 30,
- --------------------------------------------------------------------------------------------------
1997 1996
----------- -----------
Cash Paid During the Period
Interest paid (net of capitalized amount) $ 33,906 $ 37,573
----------- -----------
Income taxes paid $ 47,000 $ 55,638
----------- -----------
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
5
ROCHESTER GAS AND ELECTRIC CORPORATION
NOTES TO FINANCIAL STATEMENTS
Note 1: GENERAL
The Company, in the opinion of management, has included adjustments (which
include normal recurring adjustments) necessary for a fair statement of the
results of operations for the interim periods presented. The consolidated
financial statements for 1997 are subject to adjustment at the end of the year
when they will be audited by independent accountants. The preparation of
financial statements requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates. 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, 1996.
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, 1996 and should be read in conjunction with the
material contained in that Note.
LITIGATION
Department of Justice Lawsuit. On June 24, 1997, the Antitrust Division of
the United States Department of Justice filed a civil complaint against the
Company in the United States District Court for the Western District of New
York. The complaint follows a Civil Investigative Demand investigation. That
investigation included a broad look at the Company's activities in the electric
power industry including initially, the Company's power purchase agreement with
an independent power producer. The investigation then focused primarily upon
the flexible rate long term contracts entered between the Company and a number
of its large customers under a tariff approved by the New York State Public
Service Commission (PSC). The tariff and the PSC policies it implemented
recognized that if large customers took their electrical load off the system,
the rates for remaining customers would have to increase to cover the fixed
costs of operation.
The Division in its complaint has challenged only certain provisions of one
flexible rate contract, the contract with the University of Rochester. The
Complaint alleges that those provisions in that contract violate Section 1 of
the Sherman Act by restricting the customer's right to compete with the Company
in the sale of electricity and seeks an injunction prohibiting the Company from
enforcing that contract and from entering other agreements that limit
competition in the sale of electricity to other customers.
The Company believes that the investigation and the Complaint reflect the
desire by the Antitrust Division to become involved in the deregulation of
electric utilities, but that the proper way to do that is in the proceedings
before the PSC in the Competitive Opportunities Case.
On September 3, 1997, the Company filed its answer which denied the material
allegations of the Complaint. At the same time, the Company filed a motion for
summary judgment asking the Court to dismiss the action with prejudice on the
grounds that the Company's actions are immune from antitrust liability under the
state action exemption, that the Company's actions did not injure competition
and that the Department of Justice's claims are speculative. On November 3,
1997, the Department of Justice filed its
6
opposition to the Company's motion for summary judgment and filed its own Motion
for Summary Judgement. The Company's response to the Justice Department motion
is due on December 5, 1997. These motions for summary judgment are scheduled
for argument on December 19, 1997.
Litigation with Co-Generator. The Company is engaged in litigation with
Kamine/Besicorp Allegany L.P. (Kamine), the only co-generator with a power
purchase agreement attempting to operate in its service territory. The details
of the litigation, involving several different proceedings, are described in
Note 10 of the Company's 1996 Annual Report on Form 10-K. One of the complaints
served by Kamine seeks damages in the amount of $420,000,000.
Significant developments in these proceedings since the filing of the 1996
Annual Report on Form 10-K are described below.
In November 1995 Kamine filed in Newark, New Jersey for protection under the
bankruptcy laws and filed a complaint in an adversary proceeding seeking, among
other things, specific performance of the agreement to sell power to the
Company. Kamine filed a motion to compel the Company to pay what would be due
under Kamine's view of the terms of that agreement during the pendency of the
Adversary Proceeding. After hearing, the Bankruptcy Court denied that motion.
The Court also denied various motions made by the Company to change the venue of
the proceeding to New York State and to lift the automatic stay of the pending
New York State action. On appeal, the Bankruptcy Court was reversed and the
case sent back to the Bankruptcy Court to decide where the contract issues in
the Adversary Proceeding should be adjudicated. As of June 16, 1997, the
Company filed a Second Amended Complaint in the State Court action asserting
additional claims based on subsequent occurrences.
On March 19, 1997, the Bankruptcy Court stayed the Adversary Proceeding
pending resolution of the contract issues in the New York State court trial.
Kamine has indicated it will not appeal this action.
On June 26, 1997, the defendants filed a Joint Notice of Removal of Action,
removing the action to the United States District Court for the Western District
of New York. There have been no further proceedings to date.
Numerous other procedural motions have been presented in the Bankruptcy
Court, some of which may now be considered by the New York State court. While
these proceedings are pending, the Company would pay approximately two cents per
kilowatt hour when the plant operates. It is not operating at the present time.
General Electric Capital Corporation Lawsuit. On July 3, 1997, General
Electric Capital Corporation (GECC) filed a complaint against the Company in the
United States District Court for the Western District of New York in connection
with the Kamine project in Hume, New York, for which GECC provided financing.
The complaint asserts that the Company violated the antitrust laws in its
dealings with Kamine and seeks injunctive relief, treble damages and alleged
actual damages of not less than $100,000,000. The claims made in the complaint
filed are substantially similar to the claims made by Kamine in the same court
under Kamine's version of the terms of the Power Purchase Agreement for the Hume
project. The court denied Kamine's motion for preliminary injunction on grounds
which included Kamine's failure to establish a likelihood of success on the
merits of its claims. Kamine had filed a notice of appeal from a decision
denying Kamine's motion for a preliminary injunction. Kamine subsequently
withdrew the appeal. The Company believes the complaint by GECC is also without
merit and intends to defend the action.
ENVIRONMENTAL MATTERS
Federal Clean Air Act Amendments. The Company is developing strategies
responsive to
7
the federal clean air act amendments of 1990 (Amendments) which will primarily
affect air emissions from the Company's fossil-fueled generating facilities.
The strategy being developed is a combination of hardware solutions which have a
capital and operation and maintenance (O&M) component and allowance trading
solutions which have strictly an O&M impact. The most recent strategic
developments still envision this combination of efforts as the most cost
effective means of proceeding although there is some activity in the New York
State Legislature that could impact the Company's ability to rely upon the
emission allowance market as a reliable means of meeting some of its
environmental commitments. At this time, it is impossible to predict the
outcome of these proceedings in the Legislature and, as a result, the Company's
projections are based solely on the combination strategy. A range of capital
costs between $2.9 and $3.5 million has been estimated for the implementation of
several potential alterations for meeting the foreseeable nitrogen oxide and
sulfur dioxide requirements of the Amendments, as well as $1.0 to $1.5 million
per year in operating expenses. These capital costs would be incurred between
1998 and 2000. The O&M expenses would be for the year 1999. For the year 2000
and beyond, the Company estimates that the annual operating expenses would rise
to between $2.4 million and $3.7 million. Any additional post-2000 capital
costs and operating expense cannot be predicted until state and federal
legislation stabilizes sufficiently to enable the Company to finalize its
compliance strategy.
Opacity Issue. In May 1997, the Company commenced negotiations with the New
York State Department of Environmental Conservation (NYSDEC) to resolve
allegations of past opacity violations at the Company's Beebee and Russell
Stations. The opacity standard is a regulation which limits the density of the
smoke emitted from the Stations' smokestacks. The Company believes that it will
reach an agreement with NYSDEC on this issue and that the amount of any civil
penalty will likely include both cash and environmental benefit project
components which, in the aggregate, will not be material to the Company's
financial condition or results of operations. This matter has resulted in
operational adjustments which are discussed in Item 2, Management's Discussion
and Analysis of Financial Condition and Results of Operations under the heading
"Fossil Unit Deratings".
FERC 636 TRANSITION COSTS
As a result of the restructuring of the gas transportation industry by the
Federal Energy Regulatory Commission (FERC) pursuant to Order No. 636 and
related decisions, the Company was required to pay a share of certain transition
costs incurred by the interstate pipelines through which it has purchased gas.
The Company, as a customer, estimated total costs of about $50 million which,
for the most part, have been paid to its suppliers. The pipeline with the
largest transition cost liability has reached a negotiated settlement with its
customers, including the Company. This settlement agreement, filed with the
FERC and awaiting FERC approval, would resolve the last transition cost case.
Under the settlement, transition costs will be paid until January 1999, then
cease. A regulatory asset and related deferred credit have been established on
the balance sheet to account for these costs. Approximately $42.7 million of
these costs were paid to suppliers, of which about $37.1 million has been
included in purchased gas costs. An amount of $12.9 million remains for future
collection from customers. The Company has a $10 million credit agreement with
a domestic bank to provide funds for the Company's transition cost liability to
CNG Transmission Corporation. At September 30, 1997 the Company had $5.5
million of borrowings outstanding under the credit agreement. The Company is
collecting those costs through the Gas Cost Adjustment clause in its rates.
GAS RESTRUCTURING PROCEEDING
In the PSC's Proceeding on Restructuring the Emerging Competitive Natural Gas
Market, the PSC established a three-year period (ending March 28, 1999) during
which the State's local distribution companies (LDCs) would be permitted to
require customers converting from sales service to take associated pipeline
capacity for which the LDCs had originally contracted. Prior to the beginning
of the third year, the LDCs would be required to
8
demonstrate their efforts to dispose of "excess" capacity. On September 4,
1997, the PSC issued an Order clarifying the March 28, 1996 Order. The
September 4 Order requires, among other things, that the LDCs (a) assess
strandable costs; (b) evaluate and pursue options to address strandable costs,
including exploration of alternative uses and quantification of market values
for the capacity that could be stranded by converting customers; (c) actively
encourage competition including collaboration with marketers to expand the
number of customers taking transportation service from the LDC and to provide
customer education; and (d) to the extent LDCs cannot shed all their capacity as
contracts expire, to continue to seek lower cost options and more flexibility
and shorter contract terms, where cost effective. LDCs are required to file
plans addressing the foregoing issues by April 1, 1998. Pursuant to the PSC's
orders, the cost of capacity defined as "excess" may not be fully recoverable in
rates. Accordingly, the Company's ability to avoid absorbing this cost will
depend on the success of remarketing and portfolio structuring efforts, as
described in Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations under the heading "1995 Gas Settlement", and, if such
efforts do not result in eliminating all "excess" capacity, on a satisfactory
explanation as to why all such capacity could not be eliminated. The Company is
engaged in negotiations with the Staff of the PSC and other parties to address
these and other issues related to the future provision of gas service. At this
time, no assessment of the potential impact of these requirements on the Company
can be made.
On September 4, 1997, the PSC also issued for comment a Staff position paper
which proposes that LDCs exit their merchant function, i.e., cease to supply the
natural gas commodity to their existing customers, within five years and that
they eliminate or restructure transportation and storage capacity contracts
extending beyond five years so as to eliminate obligations beyond that point,
except where capacity is required to fulfill operational requirements or the
LDC's obligations as the "supplier of last resort" to customers having no
competitive alternative. If adopted by the PSC, the Staff proposal could
require the Company to remarket more capacity and to do so more rapidly than
currently contemplated. Since the comment period will not conclude until
December 20, 1997, no prediction can be made as to whether the Staff proposal
will be adopted or, if so, the extent of its potential impact on the Company.
ASSERTION OF TAX LIABILITY
The Company's federal income tax returns have been examined by the Internal
Revenue Service (IRS) through the calendar year 1992. The Company has reached
an Agreement with the IRS on the issues related to the Nine Mile Two in-service
date. With this Agreement, all outstanding issues will have essentially been
resolved and the Company has ultimately prevailed concerning the use of a 1987
in-service date and all other outstanding issues for the years 1987-1992. As a
result of this favorable settlement, the Company received a refund of $762,938
on October 31, 1997.
REGULATORY AND STRANDABLE ASSETS
With PSC approval the Company has deferred certain costs rather than
recognize them on its books when incurred. Such deferred costs are then
recognized as expenses when they are included in rates and recovered from
customers. Such deferral accounting is permitted by Statement of Financial
Accounting Standards No. 71 (SFAS-71). These deferred costs are shown as
Regulatory Assets on the Company's Balance Sheet. Such cost deferral is
appropriate under traditional regulated cost-of-service rate setting, where all
prudently incurred costs are recovered through rates. In a purely competitive
pricing environment, such costs might not have been incurred and could not have
been deferred. Accordingly, if the Company's rate setting was changed from a
cost-of-service approach, and it was no longer allowed to defer these costs
under SFAS-71, these assets would be adjusted for any impairment to recovery
(pursuant to Statement of Financial Accounting Standards No. 121 (SFAS-121)).
In certain cases, the entire amount could be written off.
9
Below is a summarization of the Regulatory Assets as of September 30, 1997.
Millions
of Dollars
----------
Income Taxes $162.4
Uranium Enrichment Decommissioning Deferral 16.7
Deferred Ice Storm Charges 12.1
FERC 636 Transition Costs 12.9
Demand Side Management Costs Deferred 4.8
Gas Deferred Fuel 9.3
Other, net 23.1
------
Total - Regulatory Assets $241.3
======
See the Company's Form 10-K for the fiscal year ended December 31,
1996 Item 8, Note 10 of the Notes to Financial Statements, "Regulatory and
Strandable Assets" for a description of the Regulatory Assets shown above.
SFAS-121,"Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of", requires write-down of assets whenever
events or circumstances occur which indicate that the carrying amount of a long-
lived asset may not be fully recoverable.
In a competitive electric market, strandable assets would arise when
investments are made in facilities, or costs are incurred to service customers,
and such costs are not fully recoverable in market-based rates. Examples
include purchase power contracts (e.g., the Kamine/Besicorp Allegany L.P.
contract), or high cost generating assets. Estimates of strandable assets are
highly sensitive to the competitive wholesale market price assumed in the
estimation. The amount of potentially strandable assets at September 30, 1997
depends on market prices and the competitive market in New York State which is
still under development and subject to continuing changes which are not yet
determinable, but could be significant. Strandable assets, if any, could be
written down for impairment of recovery in the same manner as deferred cost
discussed above.
In a competitive natural gas market, strandable assets would arise
where customers migrate away from dependence on the Company for full service,
leaving the Company with surplus pipeline and storage capacity, as well as
natural gas supplies, under contract. The Company has been restructuring its
transportation, storage and supply portfolio to reduce its potential exposure to
strandable costs. Regulatory developments discussed under " GAS RESTRUCTURING
PROCEEDING," above, may affect this exposure; but whether and to what extent
there may be an impact on the level and recoverability of strandable asset costs
cannot be determined at this time.
At September 30, 1997 the Company believes that its regulatory and
strandable assets, if any, are not impaired and are probable of recovery,
although no assurance can be given. The proposed settlement in the Competitive
Opportunities proceeding does not impair the opportunity of the Company to
recover its investment in these assets. However, the PSC has published a Staff
paper to address issues surrounding Nuclear generation, including the
determination of fair market value for facilities after a five year
restructuring transition period. It appears that the PSC may seek to apply
similar principles to other types of generating facilities. A determination in
this proceeding could have an impact on strandable assets.
10
EITF ISSUE 97-4 - DEREGULATION OF THE PRICING OF ELECTRICITY.
In July, 1997, the Financial Accounting Standards Board's Emerging
Issues Task Force (EITF) reached a consensus on accounting rules for utilities'
transition plans for moving to more competitive environments and provided
guidance on when utilities with transition plans will need to discontinue the
application of Financial Accounting Standards Board Statement No. 71 (SFAS 71),
"Accounting for the Effects of Certain Types of Regulation".
The major EITF consensus was that the application of SFAS 71 to a
segment (e.g. generation) which is subject to a deregulatory transition plan
should cease when the legislation or enabling rate order contains sufficient
detail for the utility to reasonably determine what the transition plan will
entail. The EITF also concluded that a decision to continue to carry some or
all of the regulatory assets (including stranded costs) and liabilities of the
separable portion of the business that is discontinuing the application of SFAS
71 should be determined on the basis of where the regulated cash flows to
realize and settle them will be derived. The president of the Edison Electric
Institute has stated that "The combined effect of the above EITF conclusions is
that if a transition plan provides for a non-bypassable fee for the recovery of
stranded costs, there may not be any significant write-off when Statement 71 is
discontinued for generation. An individual company's facts and circumstances
will determine the final accounting impact."
The current Competitive Opportunities Settlement language provides for
recovery of regulatory and stranded costs associated with generation as
discussed in further detail below under Management's Discussion and Analysis of
Financial Condition and Results of Operations, "PSC Competitive Opportunities
Case Settlement". Under the Settlement, if approved by the PSC, there would be
no expectation of a material write-off in the transition to competition.
DECOMMISSIONING TRUST
The Nuclear Regulatory Commission has released for comments a notice of
proposed rule (NOPR) modifying certain aspects of the financial assurance
requirements for decommissioning nuclear power reactors. The NOPR includes,
among other things, changes to the definition of "electric utility" for the
purposes of providing financial assurance for decommissioning as well as new
reporting requirements regarding each licensee's progress on external funding.
The Company does not anticipate any material impact of the application of these
rules today, however it cannot predict the impact of these rules as resolution
of nuclear plant regulation progresses in New York (see Management's Discussion
and Analysis of Financial Condition and Results of Operations under the heading
"PSC Position Paper on Nuclear Generation"). See the Company's 1996 Form 10-K,
Item 8, Note 10 to the Financial Statements regarding the Company's plan for the
eventual decommissioning of the Ginna Nuclear Plant and its 14% share of Nine
Mile Two.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following is Management's assessment of certain significant factors
affecting the financial condition and operating results of the Company. This
assessment contains
11
forward-looking statements which are subject to various risks and uncertainties.
The Company's actual results could differ from those anticipated in such
forward-looking statements as a result of numerous factors which may be beyond
the Company's control by reason of factors such as electric and gas utility
restructuring, future economic conditions, and developments in the legislative,
regulatory and competitive environments in which the Company operates. Shown
below is a listing of the principal items discussed .
Earnings Summary Page 12
Competition Page 13
PSC Competitive Opportunities Case Settlement
PSC Position Paper on Nuclear Generation
Nuclear Operating Company
FERC Open Transmission Orders
FERC Market Based Electric Rates
PSC Gas Restructuring Case
Securitization
Rates and Regulatory Matters Page 19
1996 Rate Settlement
Gas Settlement Negotiations
1995 Gas Settlement
Gas Fixed Price Proposal
Liquidity and Capital Resources Page 20
Capital and Other Requirements
Redemption of Securities
Financing
Results of Operations Page 22
Operating Revenues and Sales
Fossil Unit Deratings
Operating Expenses
Dividend Policy Page 24
EARNINGS SUMMARY
Earnings per common share for the current and prior year three month and nine
month periods ended September 30, are as follows:
1997 1996
Three Months $ .52 $ .49
Nine Months $1.97 $1.79
In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128 ("SFAS-128"), "Earnings per
Share," which changes the methodology of calculating earnings per share. The
Company will adopt SFAS No. 128 in the fourth quarter of 1997. Had the Company
adopted SFAS-128 during the first quarter the impact on earnings would not have
been significant.
The Company reported higher earnings of $.52 per share for the third
quarter compared to $.49 per share for the same period in 1996. The three cent
per share increase in earnings was achieved despite an electric rate reduction
begun July 1, 1997. Retail electric sales were flat in the third quarter when
compared to the same period last year. Gas sales were up about 3% in the same
comparison periods.
12
Earnings for the nine month period were $1.97 per share compared to $1.79
per share for the same period in 1996. A significant factor in the increase in
earnings for the year to date is a difference in timing for the refueling and
steam generator replacement outage at the Ginna facility during the first nine
months of 1996. The purchased electricity cost for this outage reduced the 1996
nine months results by about $.18 per share. The 1997 refueling outage at Ginna
began October 20 and is anticipated to be about one month long. The next
refueling outage is not scheduled to occur until 1999.
The Company has maintained its earnings while reducing electric rates on
July 1, 1996 and again on July 1, 1997. Additional electric rate reductions in
accordance with the Amended and Restated Competitive Opportunities Settlement
(see description below) recently filed with the New York State Public Service
Commission (PSC) are scheduled to begin July 1, 1998, assuming approval from the
PSC. The Company believes that the Settlement, when implemented, allows for a
phase-in to open electric markets while lowering customer prices and
establishing an opportunity for competitive returns on shareholder investments.
The nature and magnitude of the potential impact of any proposals ultimately
adopted by the PSC on the business of the Company will depend on the specific
details of any plan for increased competition and resolution of the complex
issues involved, especially competition at the retail level.
Future earnings will also be affected, in part, by the Company's degree
of success in remarketing its excess gas capacity as set under the terms of the
1995 Gas Settlement and in controlling its local gas distribution costs. The
Company believes it will be successful in meeting the 1995 Gas Settlement
targets over the remaining year of the Settlement period, although no assurance
can be given.
COMPETITION
See the Company's Form 10-K for the fiscal year ended December 31, 1996,
Item 7.- "Competition" for a discussion of the Company's business strategy . See
Note 2 of the Notes to Financial Statements for a discussion of regulatory and
strandable assets and related accounting issues.
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. By Opinion No. 96-12
issued May 20, 1996 in the "Competitive Opportunities Proceeding," the PSC
endorsed a fundamental restructuring of the electric utility industry in the
State. Among other elements, the PSC's goals included lower rates for consumers
and increased customer choice in obtaining electricity and other energy
services.
On April 8, 1997, the Company, the PSC Staff ("Staff") and other parties
entered into a Settlement Agreement (the "Settlement") with regard to the
Competitive Opportunities Proceeding. The Settlement was the subject of a PSC
examination to determine whether it is in the public interest. This examination
included hearings before an Administrative Law Judge ("ALJ") in early June 1997,
followed by a Recommended Decision by the ALJ recommending approval of the
Settlement in all material respects. At its Open Session held October 8, 1997,
the PSC identified a number of issues for further consideration by the parties
to the Settlement. Additional negotiations were held and an Amended and
Restated Settlement Agreement was entered into on October 23, 1997 and filed the
following day. PSC consideration of the Settlement as amended had been
scheduled for November 5, 1997; but the PSC has postponed such consideration.
At this time, a new date for a decision has not been set. (In the following
description, references to the Settlement are to the revised version.)
Summary. The Settlement, which is subject to PSC approval, provides for
a transition to competition during the five-year term of the Settlement (July 1,
1997 through June 30, 2002). The Settlement would establish the Company's
electric rates for each annual period commencing July 1 ("Rate Year") during the
term. A Retail Access Program will be phased in, allowing customers to purchase
electricity, and later electricity and capacity commitments, from sources other
than the Company. During the
13
term, the Company's non-nuclear generating sources (fossil-fuel, hydro, gas-
turbine generation and purchased power contracts, excluding Kamine) will be
required to compete in the market. The Company will be provided a reasonable
opportunity to recover prudently incurred costs, including those pertaining to
generation and purchased power.
The Settlement also requires the Company to functionally separate its
component operations: distribution, generation, and retailing. The Company
would be required to separate, structurally, any unregulated retail operations
from the remainder of the regulated utility functions. In addition, the Company
would have the option to establish a holding company structure and to utilize
certain funds derived from rendering utility service for unregulated operations.
Although the Settlement provides incentives for the sale of generating assets,
it requires neither divestiture of generating or other assets, nor writing off
of "stranded costs" (the above-market costs, presumed to result from
competition).
The Company believes that the Settlement Agreement will not adversely
affect its eligibility to continue to apply SFAS-71. If, contrary to the
Company's view, such eligibility were adversely affected, a material write-down
of assets, the amount of which is not presently determinable, could be required.
Rate Plan. Subject to certain conditions, the Rate Plan contained in the
Settlement continues and augments the rate reductions provided for in the
Company's 1996 settlement ("the 1996 Settlement") approved by the PSC. Over the
five rate years of the term, the cumulative rate reductions will be as follows:
Rate Year 1: $3.5 million; Rate Year 2: $12.8 million; Rate Year 3: $27.6
million; Rate Year 4: $39.5 million; and Rate Year 5: $51.1 million. The
foregoing amounts include assumed levels of reductions to state gross receipt
taxes ("GRT"). To the extent that the GRT rates are other than as anticipated,
the rate reductions would be revised accordingly. The reduction for Rate Year 1
is equal to the previously approved reduction planned as a provision of the
Company's 1996 Rate Settlement. It was implemented on July 1, 1997 pursuant to
the earlier agreement. No changes in rates would be required for this period
whether the Settlement is approved or not.
The Rate Plan permits the Company to offset against the foregoing total
-----
reductions certain amounts related to a Purchase Power Agreement with Kamine
which is the subject of substantial litigation described in Item 1, Financial
Statements under the caption "Litigation with Co-Generator" in Note 2,
Commitments and Other Matters. To provide for possible settlement of the Kamine
litigation, the Rate Plan permits the Company to make the following offsets, by
"Rate Year": Rate Year 2: $3.5 million; Rate Year 3: $8.4 million; Rate Year 4:
and following (until payment is completed): $10.5 million. The Settlement also
would permit the Company to recover the full amount of any difference between
Kamine costs currently included in rates and any increased amount resulting from
enforcement of the purported PPA or judicially required payments. Seven-eighths
of this difference may be added, on a current basis, to the amount already
included in rates. Amounts not currently recovered may be deferred for future
recovery.
The Settlement permits recovery of inflation-based increases to certain
Operation and Maintenance ("O&M") expenses above 4.0 percent, permits the
Company to retain a portion of property tax decreases, and allows the Company to
recover the costs of certain "Mandates" (i.e. governmentally required and
external costs imposed on the Company) to be included in a "System Benefits
Charge" and to recover others to the extent they exceed a $2.5 million
threshold. The Company also would be permitted to recover the costs of
Catastrophic Events and Competition Implementation Costs (i.e., the cost of
----
transition) to the extent they exceed the same threshold. Low-income and
service quality programs, established in prior proceedings would continue in
much their same form. The maximum service quality penalty, however, would be
reduced to $1.25 million per year.
In the event that the Company earns a return on common equity in excess
of an effective rate of 11.50 percent over the entire five-year term of the
Settlement, 50 percent of such excess will be used to write down deferred costs
accumulated during the term. With regard to the other 50 percent of the excess,
the first $.8 million will be used to reduce rates for certain large industrial
and commercial customer subclasses and
14
the remainder will be used to write down accumulated deferrals or investment in
electric plant and Regulatory Assets (which are deferred costs whose
classification as an asset on the balance sheet is permitted by SFAS-71). If the
Company's rate of return on common equity falls below 8.5 percent or increases
above 14.5 percent, or if the pre-tax interest coverage falls below 2.5 times,
or if certain governmental actions occur which cannot adequately be addressed by
the Settlement as it pertains to Mandates, either the Company or any party to
the Settlement would have the right to petition the PSC for review of the
Settlement and appropriate remedial action.
Retail Access. Over the five-year term of the Settlement, the Company
will phase in a Retail Access Program that will permit customers to purchase
their own electricity and capacity from alternative suppliers. Assuming that
certain operational requirements are met and certain governmental approvals are
in place, on July 1, 1998, customers whose electric loads total 670 Gigawatt
hours ("GWH") (representing approximately 10 percent of the Company's total
annual Retail Sales) will be eligible to purchase electricity (but not capacity
commitments) from alternative suppliers. On July 1, 1999, customers with loads
totaling up to 1,300 GWH (approximately 20 percent of total Sales) will be
eligible to purchase energy and capacity commitments from alternative suppliers.
As of July 1, 2000, aggregate customer load of up to 2,000 GWH (approximately 30
percent of total Sales) will be eligible; and, as of July 1, 2001, up to 3,000
GWH (approximately 46 percent of total Sales) will be eligible. The cited
amounts eligible for retail access would be increased for growth in retail sales
above 6,714 GWH. As of July 1, 2002, all retail customers will be eligible to
purchase energy and capacity from alternative suppliers.
Under the Retail Access Program, delivery of electricity will continue to
be through The Company's distribution system. The schedule for implementation
of the "Energy and Capacity" stage of the Program (commencing July 1, 1999)
assumes that a Statewide Energy and Capacity Market will be in place by July 1,
1998. If the operation of that Market is delayed, the Company may petition the
PSC for a delay in implementation of the Energy and Capacity stage.
During the initial, energy only stage of the Retail Access Program, the
Company delivery rate will be set by deducting from the rates that would apply
to bundled retail service 2.3 cents per kilowatt hour ("KWH") and Load Serving
Entities acting as retailers in the Company's service area will be entitled to
purchase electricity from the Company at a rate of 1.9 cents per KWH. During
the energy and capacity stage, the rate will generally equal the bundled rate
less the cost of the electric commodity and the Company's non-nuclear generating
capacity. These commodity and capacity costs, generally referred to as
"contestable costs," are estimated to be 3.2 cents per KWH.
The Company would not be required to divest any of its generation
facilities. Instead, the phasing-in of the Retail Access Program subjects the
Company's generation to competition from the market in increments, as described
above. "Sunk Costs", the investment in electric plant as of March 1, 1997,
would be included in electric distribution tariff rates during the term of the
Settlement. Future rate treatment of such costs is to be consistent with the
principle that the Company is to have a reasonable opportunity to recover such
costs.
To the extent that the Company sells any generating assets during the
term of the Settlement, gains on such sales will be shared between the Company
and customers according to the following: (1) the first $20.0 million of gains
on sales in the first three Rate Years will be allocated 60 percent to customers
and 40 percent to the Company, and customers will be entitled to 80 percent and
the Company to 20 percent of gains over $20.0 million; and (2) during the final
two Rate Years, customers will be entitled to 80 percent and the Company to 20
percent of all gains. With regard to losses on such sales, the Settlement
acknowledges an intent that the Company will be permitted to recover such losses
through distribution rates during the term of the Settlement in accordance with
SFAS-71. Future rate treatment is to be consistent with the principle that the
Company is to have a reasonable opportunity to recover such costs.
"To-Go Costs" of the Company's non-nuclear resources (i.e., capital costs
----
15
incurred after February 28, 1997, operation and maintenance expenses, and
property, payroll and other taxes) are to be recovered through the distribution
access tariff. The fixed portion of To-Go Costs would be recovered in full
through the distribution access tariff until July 1, 1999 and subject to the
market thereafter in accordance with the phase-in schedule for the Retail Access
program described above. The variable portion of non-nuclear To-Go Costs would
also be subject to the market in accordance with the phase-in Schedule described
above. Upon extension of eligibility for the Retail Access Program to all
retail customers on July 1, 2002, the Company would be authorized to modify its
distribution access rates, so as to hold constant the degree to which its To-Go
Costs are at risk for recovery through the market. Thus, while the recovery of
non-nuclear To-Go Costs would continue to be through the market, recovery of
nuclear costs would remain recoverable through regulated rates. If, during the
operation of the Energy and Capacity Stage of the Retail Access Program, the
market price of energy and capacity exceeds an average of 3.2 cents per KWH, the
pace of the Retail Access Program implementation schedule could, after
discussion among the Settlement parties, be accelerated.
During at least the first two and one-half years of the Settlement, all
prudently incurred costs associated with the Ginna nuclear plant and the
Company's share of the Nine Mile Point 2 nuclear facility would be recovered
through regulated retail rates. Future rate treatment of Nine Mile Point 2
would be determined through good faith negotiations among the Company, Staff and
the other co-tenants of the facility. It is expected that rate treatment of
Ginna would be similar. No change in such treatment of nuclear facilities may
be implemented prior to January 1, 2000. Shutdown and decommissioning costs
would be recovered during the term of the Settlement in a manner consistent with
past ratemaking treatment.
Corporate Structure. The Settlement envisions, and authorizes the
Company to form, a holding company ("HOLDCO") structure and provides standards
of conduct to govern relationships among affiliated entities within that
structure. Formation of the HOLDCO would require a separate petition to the
PSC, a form of which is appended to the Settlement, and approval by
shareholders, the Securities and Exchange Commission, the Federal Energy
Regulatory Commission ("FERC") and the Nuclear Regulatory Commission.
The Settlement would authorize the Company to initially fund its
unregulated activities, whether conducted through a HOLDCO or otherwise, with
$50 million and would not require a separate authorization by the PSC for such
investment.
Miscellaneous. Consistent with a PSC order issued June 23, 1997 in a
separate proceeding involving establishment of pilot programs for farmers and
food processors, the Settlement provides that the Company's retail access
program will commence on February 1, 1998 for those groups of customers within
the Company's service area. To preserve rights in the event that the Settlement
were not approved, the Company, in October 1997, petitioned for judicial review
of the June 23, 1997 order.
Upon approval of the Settlement by the PSC, the Company would withdraw
from an appeal challenging the PSC's Opinion No. 96-12, terminate its petition
seeking judicial review of the PSC's decision regarding the settlement in the
previous electric rate proceeding (the 1996 Rate Settlement) and terminate its
petition seeking judicial review of the PSC's decision requiring implementation
of a retail access pilot program, as discussed in the preceding paragraph. The
present Settlement would, upon approval, supersede the 1996 Rate Settlement.
Various incentive and penalty provisions in the 1996 Rate Settlement would be
eliminated.
PSC POSITION PAPER ON NUCLEAR GENERATION. On August 27, 1997, the PSC
requested comments from interested parties on a PSC Staff position paper
concerning the treatment of Nuclear generation after a transition period. The
Staff paper concludes that (1) Nuclear generation should operate on a
competitive basis, (2) sale of generation plants at auction to third parties is
the preferred means of determining market value and offer the greatest potential
for mitigation of stranded costs and the elimination of anti-competitive
subsidies, and (3) where third party sales are not feasible, "to go" costs
(fuel, labor and other operating costs, prospective capital additions, property
taxes and insurance)
16
must be recovered in the wholesale market price of power.
On October 15, 1997, the Company and four other utilities jointly
responded (1) indicating the Staff report did not thoroughly consider
responsibility for decommissioning and disposal of spent fuel as well as other
safety, health, environmental and fuel diversity issues, (2) that the use of an
untested auction process may not be a practical way to achieve any reduction in
sunk costs to be borne by customers and (3) that the report did not address the
recovery of substantial transaction costs such as approvals of a sale by
bondholders and other lenders and by the NRC. The utilities believe that the
inherent operating characteristics of nuclear generation and the implications of
NRC regulation require that nuclear plants have access to an adequate revenue
stream and that such plants should be treated for dispatch purposes as baseload,
must run units. The utilities urge the PSC to adopt a process that would enable
all parties to fully develop the necessary facts and analyses and to invite the
NRC to participate in addressing the future of nuclear generation in New York
State.
NUCLEAR OPERATING COMPANY. On October 12, 1996, the Company and Niagara
Mohawk Power Corporation (Niagara) announced plans to establish a nuclear
operating company to be known as the New York Nuclear Operating Company (NYNOC).
Since that time NYNOC has been organized as a New York Limited Liability Company
and the Consolidated Edison Company of New York and New York Power Authority
have announced their desire to move forward with the Company and Niagara with
plans to implement NYNOC. It is envisioned that NYNOC would eventually assume
responsibility for operation of all the nuclear plants in New York State,
including the Company's totally owned Ginna Nuclear Plant and jointly owned Nine
Mile Two. The Company believes that NYNOC could contribute to maintaining a
high level of operational performance, contribute to continued satisfactory NRC
regulatory compliance, provide opportunities for continued cost reduction and
provide the basis for satisfactory economic regulation by the PSC. Various
groups are now involved in the detailed studies and analyses required before a
definitive decision to proceed with NYNOC can be made. The organizing utilities
have submitted comments on the PSC Staff position paper on nuclear generation
noting that the Staff proposal would nullify the potential benefits of NYNOC.
FERC OPEN TRANSMISSION ORDERS. In early 1996 FERC issued new rules to
facilitate the development of competitive wholesale markets by requiring
electric utilities to offer "open-access" transmission service on a non-
discriminatory basis in tariffs. The Company filed its required transmission
service tariff on July 9, 1996. The new tariff would apply to wholesale
purchases and sales made by the Company and the financial impact will depend on
prevailing energy prices in the wholesale market. The near-term impacts of this
tariff are not expected to be significant. On March 6, 1997, the Company
reached a settlement in principle with the other parties respecting rate issues.
FERC approval of the settlement was granted on June 25, 1997.
In December 1996 the Company and other New York utilities submitted a
compliance filing with FERC in accordance with the requirements of the FERC's
"open-access" order. In order to support the FERC's "open access" order, the
utilities also established a centralized transmission service information
network, which went on-line in early January 1997. This "open access same-time
information system" (OASIS) enables wholesale customers of New York State's bulk
power system to obtain timely information regarding transmission service
availability and pricing via the Internet.
On January 31, 1997, the utilities filed a "Comprehensive Proposal To
Restructure the New York Wholesale Electric Market" with the FERC. As proposed,
the existing New York Power Pool ("NYPP") will be dissolved and the independent
system operator (ISO) will administer a state-wide open access tariff and
provide for the short-term reliable operation of the bulk power system in the
state. In addition to proposing a FERC-endorsed ISO, the proposal calls for
creation of a New York Power Exchange ("NYPEx") and a New York State
Reliability Council ("NYSRC"). On May 2, 1997 the utilities made a supplemental
filing with FERC that provided additional details of the proposed NYSRC.
The NYPEx is a voluntary organization intended to facilitate development
of an
17
active wholesale market by providing facilities and procedures to offer energy
for sale and to make energy purchases. As proposed, generators of electricity
could submit bids to sell energy to, and load serving entities could submit bids
to buy energy from, the NYPEx or any other power exchange. Each power exchange
would then submit its delivery schedules to the ISO which would review them for
feasibility and reliability. The energy market would use a "locational-based
marginal pricing" mechanism that takes into account transmission limitations.
Generators would also have the opportunity to enter into bilateral contracts for
electricity. The NYSRC is an organization formed by the existing eight
transmission providers in New York plus three representatives of other market
participants (buyers, sellers, and consumer/environmental groups). The role of
the NYSRC would be to establish general reliability standards that the ISO would
use to establish day-to-day operating procedures.
The proposed NYSRC is viewed by the transmission providers as an
essential prerequisite to transferring control of their transmission facilities
to the ISO. The NYPP member systems believe that the combination of an ISO with
day-to-day operational responsibility and the NYSRC with limited authority to
establish basic reliability standards on a long-term basis provides a balanced
structure to resolve the inherent tension between maintaining current system
reliability and maximizing the commercial use of transmission facilities by an
increased number of market participants.
Significant changes to pricing procedures now in effect within NYPP are
expected, but it is unclear what effect these changes may have once other
regulatory changes in New York State are implemented. At the present time, the
Company cannot predict what effects regulations ultimately adopted by FERC will
have, if any, on future operations or the financial condition of the Company.
FERC MARKET-BASED ELECTRIC RATES. On July 1, 1997, as amended on July
25, 1997, the Company filed with the FERC seeking authorization to engage in the
wholesale sale of electric energy and capacity at market-based rates. Roxdel,
(now "Energetix, Inc.") the Company's wholly-owned, power marketer subsidiary,
also filed on July 1, 1997.
FERC allows power sales at market-based rates if the seller and its
affiliates do not have, or have adequately mitigated, market power in generation
and transmission, and cannot erect other barriers to entry. To satisfy the
latter, a transmission owning public utility must have an open access
transmission tariff for the provision of comparable service. The Company's
open access transmission tariff was accepted by the FERC on June 25, 1997.
On September 12, 1997, the FERC accepted the Company's and Energetix's
applications to engage in market-based rates transactions. Consistent with FERC
precedent, the Company must comply with a code of conduct governing the
relationship between it and Energetix and must seek separate authorization in
order to sell electric energy to Energetix at market-based rates.
PSC GAS RESTRUCTURING CASE. In March 1996 the PSC issued an Order and
approved utility restructuring plans designed to open up the local natural gas
market to competition and thereby allow residential, small business and
commercial/industrial users the same ability to purchase their gas supplies from
a variety of sources, other than the local utility, that larger industrial
customers already have. During a three-year phase-in period the State's gas
utilities would be permitted to require customers converting from sales service
to take associated pipeline capacity for which the utilities had originally
contracted. The PSC has indicated that it will address the issue of how the
costs of such capacity would be recovered after the three-year period during the
third year of the phase-in period. The PSC Staff has recently issued a position
paper on The Future of the Natural Gas Industry in which the Staff proposes that
LDCs exit the merchant function in five years. Treatment of existing pipeline
capacity contracts and Provider of Last Resort responsibilities are substantial
issues to be worked out between the PSC, LDCs and other stakeholders (see note 2
for further information). Under two new gas
18
transportation tariffs, gas customers have a choice of suppliers beginning
November 1, 1996. The Company will distribute the gas and charge for the
distribution as well as associated services. The Company believes its position
in the market is such that it will maintain its distribution system margins.
Under a phase-in limitation, loss of gas commodity sales may be limited to five
percent of the Company's annual gas volume the first year, and then five
additional percent for each of the following two years. The phase-in will be
reviewed as experience is gained with the program. The Company anticipates that
the use of transportation gas service will increase. Through September 30,
1997, 38 customers were being served under this new service.
SECURITIZATION. Legislation known as "securitization" was passed by the
New York State Senate on March 19, 1997. However, the 1997 regular session ended
without Assembly action. The Senate's securitization program, the Electric
Ratepayer Relief Act, would provide electric corporations the opportunity to
obtain highly secure, lower-cost financing for intangible assets - costs
incurred by the corporation, for which it does not acquire any physical property
(e.g. buy-outs and/or restructuring of above-market independent power purchase
(IPP) contracts, demand-side management expenditures, environmental remediation
costs, and other regulatory liabilities). Any net savings as a result of such
financing would be dedicated to electric rate reductions.
The Senate legislation specifically defines Qualified Intangible
Expenditures as:
(1) Expenditures which did not or will not result in the acquisition of real
or tangible personal property (including costs incurred due to
cancellation or reduction of IPP Contract obligations).
(2) Amounts necessary to refinance or retire existing debt or equity capital
in order to achieve an appropriate capital structure as approved by the
PSC.
(3) Costs incurred to obtain, carry, or administer financing for such
expenditures, and federal, state or local tax expense incurred by the
electric corporation from the financing transaction and/or the intangible
charges.
The bill states that the PSC is required to verify that securitization
will result in significant customer rate savings. The Company believes that
securitization will balance the interest of the electric company and consumers
by providing a reasonable and fair solution to the problem of stranded assets at
no cost to the state. Securitization has already been successfully enacted in
several other states. The Company believes that passage of securitization
legislation should be a priority during the upcoming legislative session.
RATES AND REGULATORY MATTERS
1996 ELECTRIC RATE SETTLEMENT. The PSC approved a Settlement Agreement
(1996 Rate Settlement) among the Company, PSC Staff and several other parties
which set rates for a three-year period, ending June 30, 1999. If the PSC
approves the Competitive Opportunities Settlement (Settlement) discussed
earlier, the Settlement would supersede the 1996 Rate Settlement and the Company
would terminate its petition seeking judicial review of the 1996 Rate
Settlement. For a description of the 1996 Rate Settlement see the Company's 1996
Form 10-K, Item 7, under the heading "Rates and Regulatory Matters".
GAS SETTLEMENT NEGOTIATIONS. In July 1997, the Company commenced negotiations
with the PSC Staff and other parties with the objective of developing a multi-
year settlement of issues pertaining to the Company's gas business that would
take effect upon expiration of the current Gas Settlement (see paragraph below.)
on June 30, 1999. A further objective of these negotiations is to maximize the
efficiencies of the entire business by structuring a settlement that will be as
consistent as possible with the provisions of the
19
settlement in the Competitive Opportunities Proceeding, as discussed earlier
under "Competition". Negotiations are at an early stage; accordingly, the
Company can make no prediction as to their outcome.
1995 GAS SETTLEMENT. The Company entered into several agreements to help
manage its pipeline capacity costs and successfully met settlement targets for
capacity remarketing for the twelve months' periods ending October 31, 1997 and
October 31, 1996, thereby avoiding negative financial impacts for those periods.
The Company believes that it will also be successful in meeting the Settlement
targets in the remaining year of the Settlement period, although no assurance
may be given. For further information with respect to the 1995 Gas Settlement
see the Company's 1996 Form 10-K Item 8, Note 10 of the Notes to Financial
Statements.
GAS FIXED PRICE OPTION. On October 7, 1997, the PSC issued an Order which
requires each New York gas utility to offer a gas fixed price plan commencing
with this heating season. The Company is offering a gas fixed price option to
help customers manage the price volatility exhibited in recent years. If
customer interest warrants, the Company may use financial instruments to manage
price risk.
LIQUIDITY AND CAPITAL RESOURCES
During the first nine months of 1997 cash flow from operations (see
Consolidated Statement of Cash Flows), provided the funds for construction
expenditures and the payment of dividends and short-term debt. At September 30,
1997 the Company had cash and cash equivalents of $153 million, however, $102
million of that amount, received from financing activities in August and
September, is being used to redeem debt in the fourth quarter. Capital
requirements during 1997 are being satisfied primarily from the combination of
internally generated funds and the use of short-term credit arrangements.
CAPITAL AND OTHER REQUIREMENTS. The Company's capital requirements relate
primarily to expenditures for energy delivery, including electric transmission
and distribution facilities and gas mains and services as well as nuclear fuel,
electric production and the repayment of existing debt. The Company has no
plans to install additional baseload generation.
Total 1997 capital requirements are currently estimated at $132 million, of
which $102 million is for construction and $30 million is for the redemption of
maturing securities and sinking fund obligations. Approximately $58 million had
been expended for construction as of September 30, 1997, reflecting primarily
expenditures for nuclear fuel and upgrading electric generating, transmission
and distribution facilities and gas mains.
Purchased Power Requirement. 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). The Company was compelled by regulators to enter into a contract
with Kamine for approximately 55 megawatts of capacity, the circumstances of
which are discussed in this report under Note 2 of the Notes to Financial
Statements and in the Company's 1996 Form 10-K under Item 8, Note 10 of the
Notes to Financial Statements. The Kamine contract and the outcome of related
litigation may have an important impact on the Company's electric rates and its
ability to function effectively in a competitive environment. In the event the
Settlement (described above) is approved by the PSC, recovery of costs
pertaining to Kamine will be governed by its terms. The Company has no other
long-term obligations to purchase energy from Qualifying Facilities.
Year 2000 Computer Issues. As the year 2000 approaches many companies face a
potentially serious information systems (computer) problem because most software
application and operational programs written in the past will not properly
recognize calendar dates beginning with the year 2000. Systems and devices in
the Company's
20
Customer Service, Operations and Financial systems which were written using two-
year digits to define the applicable year, rather than four may require
remediation. If not corrected, this could force computers to either halt or
lead to incorrect calculations. In July 1996, a formal Year 2000 project was
initiated and a project team, comprised of representatives from each of the
Company's business areas was established to oversee compliance efforts. The
Company has also entered into an agreement with a consultant, International
Business Machines Corporation, for assessment, remediation and testing services.
At this time, the Company believes that the problem is being addressed properly
to prevent any adverse operational or financial impacts. The Company believes
it will incur approximately $15 million of costs through January 1, 2000,
associated with making the necessary modifications identified to date.
REDEMPTION OF SECURITIES. During 1997 the Company has redeemed the
securities shown below as of November 15, 1997. Funds for these redemptions
came, largely, from cash and the refinancing of pollution control revenue bonds
(see following discussion under "Financing".).
Long Term Debt Redeemed.
- -----------------------
Amount
Date Series Rate (000's)
---- ------ ---- -------
5- 1-97 W* 6 1/4% $ 20,000
5- 1-97 Y* 8.00 29,668
10- 1-97 1984** monthly 51,700
10-15-97 EE** 6 1/2 10,000
11-15-97 1985** annually 40,200
--------
Total $151,568
* first mortgage bonds
** tax-exempt pollution control securities
Preferred Stock Redeemed.
- ------------------------
Amount
Date Series Rate (000's)
---- ------ ---- -------
4-22-97 N 7.50% $ 20,000
9- 1-97 S 7.45% 10,000
--------
Total $ 30,000
FINANCING. (See Form 10-K for the fiscal year ended December 31, 1996, Item
8. Note 9. Short-Term Debt, regarding the Company's short-term borrowing
arrangements.)
On August 19, 1997 the Company sold $101.9 million of New York State
Energy Research and Development Authority (NYSERDA) multi-mode tax-exempt bonds
due August 1, 2032. The proceeds from the multi-mode issue are being used to
redeem three tax-exempt issues during the fourth quarter of 1997 (see
"Redemption of Securities" above). The initial weighted average interest rate on
the multi-mode issue was 3.33%, on an annualized basis, for seven days.
Subsequent interest rates may be set weekly or may be set for varying periods
based on market conditions at the time.
On September 16, 1997, the Company completed arrangements for the delivery
in September 1998 of $25.5 million of 5.95% NYSERDA tax-exempt bonds due
September 1, 2033. Proceeds will be used to redeem an issue of tax-exempt first
mortgage bonds which is not redeemable until December 1998.
The multi-mode issue and the fixed-rate issue described above are insured
by MBIA
21
Insurance Corporation, and rated AAA/Aaa.
Under the Company's Performance Stock Option Plan, options for 261,261
shares of Common Stock have become exercisable due to Common Stock market price
performance during October 1997.
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, 1997 to the three-month and nine-month periods
ended September 30, 1996. A summary of changes in Electric and Gas department
revenues and expenses is presented in the Operating Revenues and Expenses table.
Operating Revenues and Expenses
(Millions of Dollars)
Three Months Nine Months
Ended Sept. 30 Ended Sept. 30
-------------- --------------
1996 Earnings $19.2 $ 69.7
Increase (decrease) in earnings:
Electric revenue changes (7.9) (6.3)
- Includes effect of rate changes
- Consumption changes including weather
- Changes in sales to other electric utilities
Electric fuel cost changes (1.1) 12.3
Gas margin (revenue less fuel) 1.7 (5.9)
- Consumption changes including weather
Miscellaneous non-fuel operating and maintenance 4.7 8.9
- Reflects operating cost associated with 1996
replacement of nuclear steam generators
- Reflects expense reductions for payroll, R&D
and outside services
Depreciation and amortization .3 (10.9)
Net federal income tax effects (1.3) 1.0
Local and state tax effects 2.1 6.5
Other income and deductions effects .2 (3.3)
Interest expense 2.0 3.7
- Redeemed 8 3/8% series CC bonds 3/7/96
- Redeemed 8.00% series Y bonds 5/1/97
- Reflects write off of unamortized debt expense
Dividends on preferred stock .5 1.1
- Redeemed 7.50% series N 4/22/97
- Redeemed 7.45% series S 9/ 1/97 _____ -----
1997 Earnings $20.4 $76.8
22
OPERATING REVENUES AND SALES. Total Company revenues for the first nine
months of 1997 were $14.0 million or 1.8% below the first nine months of 1996
with decreases in customer electric rates and lower therm sales of gas due to
warmer weather than last year partially offset by higher customer electric
kilowatt-hour sales and higher electric sales to other utilities (OEU sales).
For the third quarter, total Company revenues were $13.5 million or 5.8% below
last year reflecting mainly lower electric rates and lower gas costs partially
offset by higher OEU sales and an increase in gas sold and transported.
FOSSIL UNIT DERATINGS. Several of the Company's fossil-fueled generating
units have been temporarily derated since February 1997 to maintain acceptable
opacity levels while the Company investigates additional engineering solutions
to address the opacity of the Units' emissions ( see Note 2 of the Notes to
Financial Statements under the heading "Environmental Matters, Opacity Issue").
The financial impact of the deratings includes the lost opportunity associated
with energy sales and, at times, the need to make additional purchases to meet
system requirements. While the deratings have decreased earnings, and will
continue to do so, the amount is not expected to be material.
The NYPP is in the process of evaluating new rules for its system load
regulation. Opacity limitations are expected to reduce the ability of the
Company to react to changes in load and provide regulation services when called
upon by the NYPP, resulting in additional costs. Depending on the new NYPP
requirements, the revised rules could result in the Company having to purchase
additional regulation services which may cost between $500,000 and $2,500,000
annually. The Company intends to make a $2.7 million capital upgrade to the
precipitator of one of its fossil-fueled generating units which is expected to
remove a substantial portion of the opacity exceedance which led to the
derating.
FUEL EXPENSES. Fuel expenses decreased in both comparison periods
reflecting mainly lower kwh purchases of electricity due to efficiencies derived
from the new steam generators installed last year at the Ginna nuclear plant.
While the Ginna Plant operated throughout the first nine months of 1997, it was
in a refueling and steam generator replacement outage in the second quarter of
1996 and operated intermittently in the third quarter of 1996. Purchased
electricity is expected to increase in the fourth quarter of 1997 because the
Ginna plant began a scheduled refueling outage on October 20 and is expected to
be out of service for about a month.
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES. The
decreases in operations excluding fuel and maintenance expenses in both
comparison periods reflect mainly lower payroll due to less overtime and
workforce reductions, lower research and development and outside services
expenses and lower maintenance expenses following the Ginna steam generator
replacement outage last year.
DEPRECIATION AND AMORTIZATION. Depreciation and amortization increased
in the nine month comparison period due mainly to an increase in nuclear
decommissioning expense allowed in rates effective July 1, 1996 and completion
of the steam generator replacement at the Ginna nuclear plant in the summer of
1996. Depreciation and amortization was flat for the third quarter comparison
period.
TAXES. The decreases in local, state and other taxes in both
comparison periods reflect mainly lower property taxes due to decreases in
assessments and/or rates and lower revenue taxes due to decreases in revenues
and the New York State revenue tax surcharge rate.
The decrease in Federal income tax in the first nine months of 1997
reflects mainly the reversal of a prior provision for the in-service date of
Nine Mile Two as a result of an agreement reached with the Internal Revenue
Service. The increase in Federal income tax for the third quarter is a result
of increased pre-tax earnings for the period.
OTHER STATEMENT OF INCOME ITEMS. Other (Income) and Deductions, Other-net
increased in the nine month comparison period due mainly to a decline in
subsidiary earnings resulting from the sale of the Company's interest in the
Empire State Pipeline in
23
1996. The decreases in interest charges in both comparison periods reflect
mainly the early redemption of long-term debt in the second quarter. Preferred
stock dividends decreased due to the redemption of issues in April and
September, 1997.
DIVIDEND POLICY
On September 17, 1997, the Board of Directors authorized a common
stock dividend of $.45 per share, which was paid on October 25, 1997 to
shareholders of record on October 2, 1997. Dividends on the preferred stocks
were also declared at the regular rates per share payable December 1, 1997 to
stockholders of record at the close of business on November 5, 1997. The
Company believes that future common stock 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.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information on Legal Proceedings reference is made to Note 2 of the
Notes to Financial Statements.
ITEM 5. OTHER EVENTS
SENIOR MANAGEMENT CHANGES. In September the Board of Directors
announced that Thomas S. Richards will become Chairman, President and Chief
Executive Officer on January 1, 1998. He is currently President and Chief
Operating Officer. He will succeed Roger W. Kober, Chairman and Chief Executive
Officer who will retire on December 31.
Michael T. Tomaino was named Senior Vice President and General Counsel
on October 1, 1997. Mr. Tomaino was most recently Vice President, General
Counsel and Secretary of Goulds Pumps, Inc. Prior to that, he was a partner at
the law firm of Nixon, Hargrave, Devans & Doyle, where he concentrated his
practice in telecommunications and utility law and general civil litigation. He
also served on the Board of Directors of the former Rochester Telephone
Corporation (now Frontier Corp., Inc.) from 1974 to 1994 when the telephone
industry was undergoing substantial deregulation.
BOARD OF DIRECTORS CHANGES. In September two persons were elected to
the Board of Directors. They are Susan Holliday, President and Publisher of the
Rochester Business Journal, and Mark Grier, Executive Vice President for
Financial Management of the Prudential Insurance Company of America.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K: None
EXHIBIT INDEX
Exhibit 10-1* Form of Rochester Gas and Electric Corporation 1996 Performance
Stock Option Plan Agreement.
Exhibit 10-2* Agreement, dated October 1, 1997, between the Company and
Michael T. Tomaino, Senior Vice President and General Counsel.
24
Exhibit 10-3 Agreement dated as of September 23,1997 between the Company and
International Business Machines Corporation.
Exhibit 10-4 Amended and Restated Settlement Agreement dated October 23,
1997 between the Company, the Staff of the New York PSC and other
parties (excluding Schedules).
Exhibit 27 Financial Data Schedule pursuant to Item 601 (c) of
Regulation S-K.
* Denotes executive compensation plans and arrangements.
25
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: November 13, 1997 By /s/ J.B. STOKES
------------------------------------
J. Burt Stokes
Senior Vice President, Corporate Services
and Chief Financial Officer
Date: November 13, 1997 By /s/ WILLIAM J. REDDY
--------------------------------------
William J. Reddy
Controller
26