SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1996
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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 July 31, 1996: 38,851,464
INDEX
Page No.
PART I - FINANCIAL INFORMATION
Consolidated Balance Sheet - June 30, 1996 and
December 31, 1995................................................... 1 - 2
Consolidated Statement of Income - Three Months and Six Months
Ended June 30, 1996 and 1995......................................... 3 - 4
Consolidated Statement of Cash Flows - Six Months
Ended June 30,1996 and 1995......................................... 5
Notes to Financial Statements.......................................... 6 - 9
Management's Discussion and Analysis of Financial
Condition and Results of Operations................................. 9 -16
PART II - OTHER INFORMATION
Legal Proceedings....................................................... 16
Exhibits and Reports on Form 8-K........................................ 16
Signatures.............................................................. 17
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
June 30, December 31,
Assets 1996 1995
- --------------------------------------------------------------------------------
Utility Plant
Electric $2,437,424 $2,342,981
Gas 382,483 382,071
Common 137,117 135,526
Nuclear fuel 220,181 207,525
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3,177,205 3,068,103
Less: Accumulated depreciation 1,391,648 1,345,552
Nuclear fuel amortization 179,767 173,326
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1,605,790 1,549,225
Construction work in progress 81,631 121,725
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Net Utility Plant 1,687,421 1,670,950
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Current Assets
Cash and cash equivalents 36,486 44,121
Accounts receivable, net of allowance for
doubtful accounts: 1996 - $14,650, 1995 - $11,950 125,138 121,123
Unbilled revenue receivable 35,877 64,169
Note receivable - Empire 16,147 -
Materials and supplies, at average cost:
Construction and other supplies 10,775 10,223
Fossil fuel 5,414 8,101
Gas stored underground 7,791 20,326
Prepayments 26,808 24,533
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Total Current Assets 264,436 292,596
---------- ----------
Investment in Empire - 38,879
Deferred Debits
Nuclear generating plant decommissioning fund 78,761 71,540
Nine Mile Two deferred costs 31,885 32,411
Deferred finance charges - Nine Mile Two 19,242 19,242
Unamortized debt expense 15,575 16,712
Other deferred debits 25,765 21,857
Regulatory assets:
Income taxes 184,577 188,599
FERC 636 transition costs 36,698 40,965
Uranium enrichment decommissioning deferral 18,160 18,707
Deferred ice storm charges 15,274 16,553
Demand side management costs 9,617 14,759
Other regulatory assets 29,237 31,623
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Total Regulatory assets 293,563 311,206
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Total Deferred Debits 464,791 472,968
---------- ----------
Total Assets $2,416,648 $2,475,393
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The accompanying notes are an integral part of the financial statements.
1
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
June 30, December 31,
Capitalization and Liabilities 1996 1995
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Capitalization
Long term debt - mortage bonds $ 575,359 $ 624,332
- 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; 38,851,464
shares outstanding at June 30, 1996
and 38,453,163 shares outstanding at
December 31, 1995. 696,087 687,518
Retained earnings 85,949 70,330
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Total common shareholders' equity 782,036 757,848
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Total Capitalization 1,571,295 1,596,080
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Long Term Liabilities (Department of Energy)
Nuclear waste disposal 77,041 75,077
Uranium enrichment decommissioning 16,053 15,810
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Total Long Term Liabilities 93,094 90,887
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Current Liabilities
Long term debt due within one year - 18,000
Notes Payable - Empire - 29,600
Accounts payable 41,999 52,578
Dividends payable 19,349 19,170
Taxes accrued 35,375 18,638
Interest accrued 10,421 12,844
Other 28,407 31,508
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Total Current Liabilities 135,551 182,338
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Deferred Credits and Other Liabilities
Accumulated deferred income taxes 369,201 377,652
Pension costs accrued 71,704 71,580
Deferred finance charges - Nine Mile Two 19,242 19,242
Other 156,561 137,614
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Total Deferred Credits and Other Liabilities 616,708 606,088
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Commitments and Other Matters (Note 2) - -
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Total Capitalization and Liabilities $2,416,648 $2,475,393
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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
June 30
1996 1995
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Operating Revenues
Electric $163,127 $169,038
Gas 68,380 46,529
-------- --------
231,507 215,567
Electric sales to other utilities 4,070 3,979
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Total Operating Revenues 235,577 219,546
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Fund Expenses
Fuel for electric generation 8,746 10,373
Purchased electricity 17,356 17,149
Gas purchased for resale 37,815 26,789
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Total Fuel Expenses 63,917 54,311
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Operating Revenues less Fuel Expenses 171,660 165,235
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Other Operating Expenses
Operations excluding fuel expenses 68,292 60,321
Maintenance 15,506 13,971
Depreciation and amortization 23,867 22,546
Taxes - local, state and other 30,992 29,698
Federal income tax 9,888 9,245
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Total Other Operating Expenses 148,545 135,781
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Operating Income 23,115 29,454
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Other Income and Deductions
Allowance for other funds
used during construction 283 90
Federal income tax 406 62
Other - net 576 (166)
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Total Other Income and Deductions 1,265 (14)
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Income before Interest Charges 24,380 29,440
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Interest Charges
Long term debt 11,964 13,131
Other - net 1,138 2,212
Allowance for borrowed funds
used during construction (454) (764)
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Total Interest Charges 12,648 14,579
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Net Income 11,732 14,861
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Dividends on Preferred Stock 1,866 1,866
-------- --------
Earnings Applicable to Common Stock $9,866 $12,995
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Weighted average numbr of shares
outstanding in each period (000's) 38,782 38,004
Earnings per Common Share $0.25 $0.34
Cash Dividends Paid per Common Share $0.45 $0.45
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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 Six Months Ended
June 30
1996 1995
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Operating Revenues
Electric $333,635 $332,537
Gas 200,196 159,284
-------- --------
533,831 491,821
Electric sales to other utilities 10,942 8,732
-------- --------
Total Operating Revenues 544,773 500,553
-------- --------
Fund Expenses
Fuel for electric generation 19,857 21,448
Purchased electricity 26,308 24,618
Gas purchased for resale 109,574 89,223
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Total Fuel Expenses 155,739 135,289
-------- --------
Operating Revenues less Fuel Expenses 389,034 365,264
-------- --------
Other Operating Expenses
Operations excluding fuel expenses 129,894 117,181
Maintenance 25,018 24,494
Depreciation and amortization 47,357 44,956
Taxes - local, state and other 67,499 68,029
Federal income tax 39,285 34,593
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Total Other Operating Expenses 309,053 289,253
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Operating Income 79,981 76,011
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Other Income and Deductions
Allowance for other funds
used during construction 528 298
Federal income tax 1,004 1,184
Other - net 897 (3,287)
-------- --------
Total Other Income and Deductions 2,429 (1,805)
-------- --------
Income before Interest Charges 82,410 74,206
-------- --------
Interest Charges
Long term debt 24,841 26,236
Other - net 4,520 4,065
Allowance for borrowed funds
used during construction (1,172) (1,475)
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Total Interest Charges 28,189 28,826
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Net Income 54,221 45,380
-------- --------
Dividends on Preferred Stock 3,732 3,732
-------- --------
Earnings Applicable to Common Stock $50,489 $41,648
-------- --------
Weighted average numbr of shares
outstanding in each period (000's) 38,686 37,910
Earnings per Common Share $1.30 $1.09
Cash Dividends Paid per Common Share $0.90 $0.90
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The accompanying notes are an integral part of the financial statements.
4
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Six Months Ended
June 30,
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1996 1995*
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CASH FLOW FROM OPERATING ACTIVITIES
Net income $ 54,221 $ 45,380
Adjustments to reconcile net income to net cash flow
from operating activities:
Depreciation and amortization 47,357 44,956
Amortization of nuclear fuel 8,406 7,701
Deferred fuel costs - electric 1,312 (5,926)
Deferred fuel costs - gas 12,283 20,806
Deferred income taxes (4,428) (1,861)
Allowance for funds used during construction (1,701) (1,773)
Unbilled revenue, net 28,293 12,842
Deferred ice storm costs 1,279 1,279
Nuclear generating plant decommissioning fund (4,402) (5,956)
Pension costs accrued (2,036) 4,051
Post employment benefit internal reserve 3,197 2,352
Research and development amortization 2,293 1,280
Rate settlement amortizations 4,982 4,000
Changes in certain current assets and liabilities:
Accounts receivable (4,015) (2,134)
Materials and supplies - gas stored underground 12,535 10,421
- other, net 2,135 1,627
Taxes accrued 16,737 16,769
Accounts payable (10,579) 481
Interest accrued (2,423) 448
Other current assets and liabilities, net (6,622) 1,015
Other, net 9,210 (2,528)
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Net cash flow from operating activities $ 168,034 $ 155,230
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CASH FLOW FROM INVESTING ACTIVITIES
Utility Plant
Plant additions $ (62,187) $ (55,576)
Nuclear fuel additions (12,656) (12,287)
Less: Allowance for funds used during construction 1,701 1,773
------------- --------------
Additions to Utility Plant (73,142) (66,090)
Note receivable - Empire (16,147) -
Investment in Empire, net 9,279 -
Other, net (52) (8)
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Net cash used by investing activities $ (80,062) $ (66,098)
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CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/issuance of common stock $ 8,612 $ 8,601
Short term borrowings - (51,600)
Retirement of long term debt (67,000) -
Dividends paid on preferred stock (3,733) (3,732)
Dividends paid on common stock (34,690) (33,991)
Other, net 1,204 (2,051)
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Net cash used by financing activities $ (95,607) $ (82,773)
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Net (decrease)increase in cash and cash equivalents $ (7,635) $ 6,359
Cash and cash equivalents at beginning of period $ 44,121 $ 2,810
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Cash and cash equivalents at end of period $ 36,486 $ 9,169
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Six Months Ended
June 30,
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(Thousands of Dollars) 1996 1995*
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Cash Paid During the Period
Interest paid (net of capitalized amount) $ 27,888 $ 27,467
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Income taxes paid $ 33,000 $ 27,000
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* 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 1996 are subject to adjustment at the end of the year
when they will be audited by independent accountants. 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, 1995.
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, 1995 and should be read in conjunction with the
material contained in that Note.
LITIGATION WITH CO-GENERATOR
During 1995 Kamine/Besicorp Allegany L.P. (Kamine) filed a petition before
the Federal Energy Regulatory Commission (FERC) to waive certain requirements
for federal Qualified Facility status for 1994. The Company and the New York
State Public Service Commission (PSC) filed in opposition to the request.
Subsequently FERC issued an order granting the waiver request and the Company's
motion for rehearing was denied. The Company has filed a petition for review
with the U.S. Court of Appeals for the District of Columbia Circuit.
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 Power Purchase Agreement. Kamine
filed a motion to compel the Company to pay what would be due under Kamine's
view of the terms of the Power Purchase 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 proceedings to New York State and to lift the automatic stay of the pending
New York State action. The Company has appealed to the U.S. District Court from
the denial of its motions. On August 5, 1996 the District Court reversed the
Bankruptcy Court and remanded the case for further proceedings. The PSC filed a
motion to lift the stay to permit it to proceed with its investigation of
cogeneration facility status under New York State Law but the motion was denied.
Kamine sought an order requiring the Company to pay 3.7 cents per kilowatt hour
for power produced during the pendency of the proceeding but the motion was
denied, although the Company was ordered to pay $1.6 million for power delivered
in October 1995 under the terms of a temporary restraining order that had been
entered by the U.S. District Court for the Western District of New York.
General Electric Capital Corporation (GECC), which provided financing to the
cogeneration project, has intervened in the Adversary Proceeding as a plaintiff.
The Company has filed an answer with affirmative defenses and counterclaims in
the Adversary Proceeding. In April 1996, the Bankruptcy Court dismissed one of
the Company's counterclaims, noting that the Company could bring that claim in a
separate action at a later date. That counterclaim alleged that GECC failed to
disclose that it knew the Power Purchase Agreement could not be performed when
it financed the transaction in August 1993. The remaining counterclaims seek
relief similar to that sought in the New York State court action. The parties
are now engaged in discovery in connection with the Adversary Proceeding. A
trial date of August 20, 1996 has been scheduled in the Adversary
6
Proceeding.
The existence of mandated, high-priced independent power purchase agreements
is a significant problem throughout the State of New York and there are various
efforts by State officials to resolve the problem. The Company is litigating
this matter vigorously while it continues to work to resolve this particular
dispute in a fashion that is fair and equitable to all parties. However, it will
continue to take aggressive action on behalf of customers and the Company to
assure that their interests are respected in any resolution. The Company is
unable to predict the ultimate outcome of these legal proceedings. For further
information with respect to the Kamine contract and related litigation, see the
Company's 1995 Form 10-K, Item 8, Note 10 of the Notes to Financial
Statements.
1995 GAS SETTLEMENT
Under provisions of the 1995 Gas Settlement with the Staff of the PSC and
other parties, the Company faces an economic risk of remarketing $74.2 million
of excess gas transportation and storage capacity through October 1998. The
Company has entered into a marketing agreement with CNG that is expected to
result in the release of approximately $29 million of this capacity through the
period. CNG is assisting the Company in obtaining permanent replacement
customers for transportation capacity the Company does not require. The Company
is also in the process of implementing transportation and storage capacity
reductions on the Empire and upstream pipelines which represent approximately
$21 million of release through the period. To help manage the balance of the
excess capacity costs at risk, the Company has retained MidCon Gas Services
Corp. which is working with the Company to identify and implement opportunities
for temporary and permanent release of surplus pipeline capacity and to advise
in the management of the Company's gas supply, transportation and storage assets
consistent with the goals of providing reliable service and reducing the cost of
gas.
The FERC approved a change in rate design for the Great Lakes Gas Transmission
Limited Partnership ("Great Lakes") on which the Company holds transportation
capacity. This change resulted in a retroactive surcharge by Great Lakes to the
Company in the amount of approximately $7 million. Under the terms of the 1995
Gas Settlement, the Company may recover approximately one-half of the surcharge
in rates charged to customers; but the remainder may not be passed through. The
Company is vigorously contesting the Great Lakes assessment before the FERC. On
April 25, 1996, the FERC upheld this determination that the charge to the
Company is proper. The Company has filed a petition for review with the U.S.
Court of Appeals and will also pursue options available at the FERC. The
ultimate outcome of the Company's appeal to the FERC and any judicial review
that may be sought following the FERC decision cannot be predicted.
The financial impact of the 1995 Gas Settlement on the Company's business in
1996 and subsequent years will be largely determined by the degree of success
achieved by the Company in remarketing its excess gas capacity and in
controlling its local gas distribution costs.
DECOMMISSIONING TRUST
The Nuclear Regulatory Commission (NRC) is currently considering proposals
which may impact financial funding requirements for decommissioning of nuclear
power plants. Under current NRC regulations electric utilities provide for
decommissioning funds annually over the estimated life of a plant. If
generating facilities were no longer subject to rate regulation, the related
source of income would become subject to competitive pricing; accordingly, the
NRC could require reactor licensees to provide assurance that the full estimated
cost of decommissioning will ultimately be available
7
through some guarantee mechanism.
The NRC sought public comment through late June on a number of questions,
including the likely timetable for utility restructuring and deregulation and to
what degree costs will be recoverable if a large baseload plant is deemed to be
non-competitive because of high construction costs and what funding sources will
be used to shut down a plant prematurely and safely. These comments were due in
late June after receipt of which the NRC will finalize its proposal. See the
Company's 1995 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.
REGULATORY AND STRANDABLE ASSETS
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 were to be changed from a cost-of-service approach, and it were no
longer allowed to defer these costs under SFAS-71, these assets would be
adjusted for any impairment to recovery (see discussion under Financial
Accounting Standards No. 121). In certain cases, the entire amount could be
written off.
Below is a summarization of the Regulatory Assets as of June 30, 1996.
Millions
of Dollars
----------
Income Taxes $184.6
Uranium Enrichment Decommissioning Deferral 18.2
Deferred Ice Storm Charges 15.3
FERC 636 Transition Costs 36.7
Demand Side Management Costs Deferred 9.6
Other, net 29.2
------
Total - Regulatory Assets $293.6
======
See the Company's Form 10-K for the fiscal year ended December 31,
1995, Item 8, Note 10 of the Notes to Financial Statements, "Regulatory and
Strandable Assets" for a description of the Regulatory Assets shown above.
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 June 30, 1996 cannot
be determined at this time, but could be significant.
CIVIL INVESTIGATIVE DEMAND
The United States Department of Justice, Antitrust Division
("Division"), has
8
issued a Civil Investigative Demand calling for the production of documents and
answers to interrogatories concerning the electric industry and competition. The
Company believes that the Division is interested in the transition of the
electric industry from a regulated monopoly to competition in order to ensure
that electric utilities do not use their existing lawful market position to gain
an unfair competitive advantage if and when wholesale and retail competition are
a reality. The primary preliminary focus of the Division appears to be on the
flexible rate, long-term contracts entered between the Company and a number of
its large customers under the tariff approved by the PSC, notwithstanding
extensive PSC review and its express determination that the Company may enter
into such contracts. The Company has urged the Division to address its concerns
to the PSC in the Competitive Opportunities Proceeding since the PSC intends to
specifically manage the transition to competition.
SPENT NUCLEAR FUEL LITIGATION
In a July 1996 decision, the United States Court of Appeals for the
District of Columbia Circuit upheld the position, advanced by the Company and
other owners of nuclear power plants, that the U.S. Department of Energy (DOE)
is obligated to dispose of the utilities' spent nuclear fuel (SNF) not later
than January 31, 1998. In the utilities' lawsuit, DOE had contended in effect
that it could defer the disposal until the availability of a suitable SNF
repository. The Court rejected this DOE reading of the Nuclear Waste Policy
Act, but stopped short of providing the utilities a remedy since DOE has not yet
defaulted on its obligations.
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.
EARNINGS SUMMARY
Earnings per common share for the current and prior year three month and
six month periods ended June 30, are as follows:
1996 1995
---- ----
Three months $ .25 $ .34
Six months $1.30 $1.09
Lower second quarter earnings were due to the planned expenses associated
with the 70-day outage for the Ginna Nuclear Power Plant steam generator
replacements and an increase in the reserve for doubtful accounts. The Ginna
Plant scheduled outage in 1995 was 39 days. The Company completed the steam
generator replacement on schedule and within budget while maintaining its high
safety standards. In addition, the Ginna Plant generation is higher than was
expected at the completion of the steam generator project.
Earnings were higher for the six month period due to increased electric
and gas sales. The Company continues to realize savings associated with the
early redemption and maturity of long-term debt through lower interest charges.
In addition, the Company continues its efforts to control ongoing capital as
well as operation and maintenance expenses.
Future earnings will be affected, in part, by the Company's ability to
control certain costs and its ability to remarket excess gas capacity as set
under the terms of the 1995 Gas Settlement, which is discussed in Note 2.
9
COMPETITION
PSC Competitive Opportunities Case. Reference is made to the Company's
Form 10-K for the fiscal year ended December 31, 1995, Item 7 under the heading
"Competition" for a discussion of the Competitive Opportunities case recently
decided by the PSC.
Effective May 20, 1996 the PSC issued an Opinion and Order setting forth
its plan to adopt a more competitive electric industry in New York State. Major
components of the plan are described below:
1. Competition in the generation and energy services sectors of
the electric industry will be pursued.
2. The PSC stated that it expects wholesale competition to begin in
early 1997 and retail competition to begin in early 1998.
3. Filings should be made with the PSC (and thereafter with FERC with
respect to proposals in (a) below) by each of the major New York
electric utilities by October 1, 1996 (except for Niagara Mohawk
Power Corporation and Long Island Lighting Company who are dealing
with some or all of these matters in other proceedings or forums)
describing proposals:
(a) to distinguish and classify transmission and distribution
facilities; together with a transmission pricing proposal
consistent with moving toward retail access; and
(b) at a minimum, setting forth the utility's proposed
corporate structure, retail access proposals, long-term rate
plans, proposals to implement PSC-mandated public forums,
potential market power problems, and proposals to mitigate
such problems and proposals for delivery of energy services.
The PSC order also states that all seven of the major New York electric
utilities by October 1, 1996 should file with the PSC and thereafter with FERC,
a proposal setting forth the details of the ownership, governance, practices and
procedures of an Independent System Operator and a Market Exchange that will
establish open spot market prices for electric energy.
The Order also provides for further examination of a proposal of the
Power Authority of the State of New York that it purchase all transmission
facilities and become the Independent System Operator.
Regarding strandable costs, the Order provides that utilities should have
a reasonable opportunity to seek recovery of such costs consistent with the
goals of lowering rates, fostering economic development, increasing customer
choices and maintaining reliable service. Strandable costs would be recovered
by a non-bypassable distribution charge imposed by the transmission and
distribution company. The order takes the position that recovery of a utility's
full stranded investment is not required by law. The Order provides that
utilities must take steps to mitigate strandable costs, the actual recoverable
amount of which and the timing of recovery will be determined individually for
each utility as part of rate plans to be filed on October 1, 1996.
Regarding corporate structure, the Order encourages total divestiture of
generation facilities in order to prevent market power. However, the Order does
not require divestiture "immediately" of generation facilities, stating that
incentive for divestiture should be worked out individually for each company in
conjunction with its required October 1, 1996 filing.
Regarding the obligation to serve customers, the Order directs that
transmission and distribution companies will remain obligated to serve all
customers "at least in the short-term".
10
Regarding PSC-mandated environmental and public policy programs, the
Order provides that the costs of such programs that would not otherwise be
recovered in a competitive market will be recovered by a non-bypassable system
benefits charge to be considered in the context of individual utility filings.
The Company is reviewing the Order and considering all options for
responding to the Order including potential litigation challenging the Order in
whole or in part. Implementation of the Order may require certain charges but
the Company is unable to predict what, if any, charges would be imposed or the
amount or implications of the charges. The Company can make no prediction as to
what effect the Order may have on it or whether the Order may be challenged by
one or more parties.
FERC Open Transmission Tariffs. In April 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 to be filed by July 9, 1996. The rule defines
the non-discriminatory terms and conditions under which unregulated generators,
neighboring utilities, and other suppliers could gain access to a utility's
transmission grid to deliver power to wholesale customers. A supplementary
release by FERC states the principle that utilities are entitled to full
recovery of "legitimate, prudent and verifiable" strandable costs at the state
and federal level. This supplementary release concludes that FERC should be the
principal forum for addressing wholesale strandable costs, while suggesting
state regulatory authorities should address the recovery of strandable costs
which may result from retail competition.
The Company individually filed the required transmission service tariff
on July 9, 1996. The Company is also continuing to participate in collateral
filings requesting clarification of FERC requirements and providing additional
tariffs for power pools similar to the New York Power Pool (NYPP). A joint NYPP
"open access" tariff is required by December, 1996. FERC has indicated that it
endorses the concept of an Independent System Operator to operate NYPP
facilities. The PSC has stated that the NYPP filing be made available to the
PSC on October 1, 1996 in the Competitive Opportunities Case discussed above.
The NYPP is actively evaluating the requirements for implementing
wholesale competition within the framework of the FERC proposals. Significant
changes to NYPP pricing procedures are expected, but their projected effects on
the Company's operations and financial performance are not substantial assuming
continued vertical integration of the utility industry in New York State. 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. The near term impacts of the FERC tariff filed on
July 9, 1996 are not expected to be significant since they apply to new
wholesale customers. Existing wholesale transmission services now provided to
existing municipal customers will continue to be provided under existing service
agreements.
PSC Gas Restructuring Case. On March 28, 1996 the PSC 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. The key element in the utility restructuring plans that
makes it possible for customers to "shop around" for sources of natural gas is
aggregation - the ability of customers to join together to make purchases.
- -----------
Aggregation is important to smaller customers, such as residential and small
business customers who individually might not have the same degree of access to
new sources of natural gas as larger customers because of their lower usage.
On April 26, 1996 the Company filed, subject to PSC approval, updated
tariffs pursuant to the March 28 Order. This new service will be available to
customers on November 1, 1996. The Order does allow a phase in of the new
service in the first few years in order to ease possible implementation
problems.
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RATES AND REGULATORY MATTERS
1996 Rate Settlement. On June 19, 1996 the PSC approved a Settlement
Agreement (1996 Settlement) among the Company, PSC Staff and several other
parties, resolving most issues in the rate proceedings for a three-year period,
commencing July 1, 1996 and concluding June 30, 1999. Under the 1996 Settlement
base electric rates (that is, rates excluding the Fuel Cost Adjustment (FCA))
for the first year (commencing July 1, 1996) are decreased to a level that
reduces revenues in an amount equal to 1.0 percent ($7.1 million) of the
revenues that would have been produced under the rates previously in effect. In
each of the second and third years base rates will be decreased by an additional
amount equal to 0.5 percent ($3.5 million) of the revenues that were produced by
the rates in effect in the immediately preceding year. In addition to these
base rate reductions, the 1996 Settlement reduces and holds constant fuel cost
recoveries for the three-year period. The freezing of costs, combined with the
foregoing base rate decreases, is expected to produce effective overall
decreases of 3.5% for residential customers and 5.0% to 6.0% for non-residential
customers over the three year period. The PSC failed to approve certain
provisions of the 1996 Settlement related to Kamine (which would have permitted
immediate flow through of increases in Kamine costs, subject to subsequent PSC
review) and gas cost adjustment (which are not affected by the 1995 Gas
Settlement). The actual details and implications of these exclusions cannot be
known until the PSC issues its full order, which the Commission has indicated it
will do. These two items will be addressed with the PSC as developments occur.
Under the 1996 Settlement, the Company is also permitted to defer and
to recover costs associated with Generic Mandates (defined as certain
governmentally-imposed requirements and changes in accounting required by
generally accepted accounting principles) and Catastrophic Events (defined as
events that trigger a designation of part of the Company's service territory as
a disaster area or as being under a state of emergency) if such costs for any
one event exceed 3.0 percent of electric common earnings.
Under the 1996 Settlement, certain incentives and adjustments provided
for under the 1993 Settlement that currently remain unused will be available as
offsets to pass-backs to customers that would otherwise occur under the 1996
Settlement.
The Settlement establishes a Customer Service Performance Program that
provides for penalties of up to 46 basis points of the return on common equity
if the Company fails to achieve certain minimum criteria pertaining to electric
reliability and service quality.
The 1996 Settlement provides that, if the Company achieves a return in
excess of 11.2 percent, calculated for the entire three-year period, the Company
can retain 50 percent of the excess as earnings and shall use the remaining 50
percent to write down its investment in nuclear assets. If the return on
equity, determined on a rate year basis, falls below 8.5 percent or increases
above 14.5 percent, or pre-tax cash interest coverage falls below 2.5 times, or
fuel cost changes (other than Kamine costs), result in a positive or negative
impact in excess of 10 percent of electric common earnings, then either the
Company or any other party has the right to petition the PSC for review of the
1996 Settlement and for appropriate remedial action.
Through changes to revenue allocation and rate design, the 1996
Settlement makes rates for large industrial customers more attractive than those
formerly in place. The 1996 Settlement also increases the Company's flexibility
in offering individually negotiated rate discounts to such customers to induce
them to remain in the service territory and to expand their facilities. During
the term of the 1996 Settlement, the Company will absorb, as it has done since
the inception of these rates, the difference between the discounted rates paid
under these individual contracts and the rates that would otherwise apply.
The 1996 Settlement is expressly made subject to any modification that
may be
12
required by a PSC decision in the Competitive Opportunities Proceeding
(discussed above). The costs of compliance with that decision are to be treated
as a Generic Mandate for purposes of the 1996 Settlement.
1995 Gas Settlement. Under provisions of the 1995 Gas Settlement, the
Company faces an economic risk of remarketing $74.2 million of excess gas
transportation and storage capacity through October 1998. The financial impact
of the 1995 Gas Settlement on the Company's business in 1996 and subsequent
years will be largely determined by the degree of success achieved by the
Company in remarketing its excess gas capacity and in controlling its local gas
distribution costs. It now appears likely that the Company will successfully
meet settlement targets for capacity remarketing for the twelve months ending
October 31, 1996, thereby avoiding negative financial impacts for that period.
For further information with respect to the 1995 Gas Settlement see Note 2 of
the Notes to Financial Statements and the Company's 1995 Form 10-K Item 8, Note
10 of the Notes to Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 1996 cash flow primarily from operations
(see Consolidated Statement of Cash Flows), provided the funds for construction
expenditures and the redemption of long-term debt. At June 30, 1996 the Company
had cash and cash equivalents of $36.4 million. Capital requirements during 1996
are anticipated to be satisfied primarily from the combination of internally
generated funds and temporary cash investments.
PROJECTED CAPITAL AND OTHER REQUIREMENTS. The Company's capital
requirements relate primarily to expenditures for electric generation, including
the 1996 replacement of its Ginna steam generators, transmission and
distribution facilities, and gas mains and services as well as the repayment of
existing debt. The Company has no current plans to install additional baseload
generation.
Total 1996 capital requirements are currently estimated at $168 million,
of which $150 million is for construction, including replacement of the steam
generators at the Ginna Nuclear Plant and $18 million is for securities
maturities, which were paid on May 1, 1996. Approximately $74 million had been
expended for construction as of June 30, 1996, reflecting primarily expenditures
for steam generator replacement and nuclear fuel, upgrading electric generating,
transmission and distribution facilities and gas mains.
Ginna Steam Generator Replacement. Preparation for replacement of the
two steam generators at the Ginna Nuclear Plant began in 1993 and continued
until the outage which began April 1, 1996. The replacement outage is now
complete, having ended on June 10, 1996 for a total duration of 70 days. The new
steam generators will allow the plant to recapture output capacity that had been
lost due to the declining performance of the former generators. Cost of the
replacement is estimated to be approximately $112 million, about $40 million for
the steam generators, about $50 million for the installation and the remainder
for Company engineering, radiation protection, plant support, other services
and finance charges. In the first half of 1996, the Company spent $39 million
on this project and expects to spend a total of $50 million this year. The PSC
order approving this project provides that certain costs over $115 million, and
savings under that amount, will be shared between the Company and its customers
but the Company does not expect to exceed that amount.
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/Besicorp Allegheny L.P. (Kamine) for approximately 55 megawatts of
capacity, the circumstances
13
of which are discussed in the Company's 1995 Form 10-K under Item 8, Note 10 of
the Notes to Financial Statements. The Kamine contract and the outcome of
related litigation will have an important impact on the Company's electric rates
and its ability to function effectively in a competitive environment. The
Company has no other long-term obligations to purchase energy from Qualifying
Facilities.
Sale of Interest in Empire State Pipeline. In April, 1996 the Company's
wholly owned subsidiary, Energyline Corporation, agreed to sell its 20%
ownership interest in the Empire State Pipeline to the other co-tenants,
subsidiaries of The Coastal Corporation and Westcoast Energy Inc. and
accordingly was released of its obligations, including the $29.6 million note
payable previously shown under Current Liabilities on the Balance Sheet. The
sale is subject to PSC approval and a decision is expected in the third quarter.
The Company will remain a customer of Empire, which commenced operation in
November 1993. The sale of Empire is not expected to have a material impact on
the Company's financial condition.
The Company invested in Empire in 1992 because it believed there was a
need for access to an alternative supply of natural gas for its customers and
that meeting their need would best be achieved by its direct investment in the
pipeline. The Company's achievement of that goal and its current strategic
business decision to concentrate on delivering energy and energy services
directly to customers are the reasons for Energyline's decision to sell its
equity interest in Empire.
REDEMPTION OF SECURITIES. On March 7, 1996, the Company redeemed $49
million principal amount of its First Mortgage 8 3/8% Bonds, Series CC at
103.18% plus accrued interest from September 15, 1995. On May 1, 1996, the
Company redeemed $332 thousand of its First Mortgage 8% Bonds, Series Y at the
special redemption price of 100.17% plus accrued interest from February 15, 1996
under sinking and improvement fund provisions of it's General Mortgage. On May
1, 1996, the Company also redeemed at maturity $18 million principal amount of
its First Mortgage 5.30% Bonds, Series V.
FINANCING. (See Form 10-K for the fiscal year ended December 31, 1995,
Item 8. Note 9. Short-Term Debt, regarding the Company's short-term borrowing
arrangements.)
During the first six months of 1996, the Company issued 398,301 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 $8.6 million to help finance its capital expenditures program.
The new shares were issued at a market price above the book value per share at
the time of issuance. At June 30, 1996 the Company had Common Stock available
for issuance of 1,026,840 shares under the ADR Plan and 129,664 shares under the
Savings Plus Plan. In July, the Company began providing for ADR Plan and
Savings Plus Plan requirements through the purchase of shares on the open
market.
CAPITAL STRUCTURE. The Company's retained earnings at June 30, 1996 were
$85.9 million, an increase of approximately $15.6 million compared with December
31, 1995. The amount of long term debt (including due within one year) decreased
$67 million at June 30, 1996 as compared with December 31, 1995 due to the
redemption of First Mortgage Bonds discussed above. Common equity increased
approximately $24.2 million, reflecting an increase in retained earnings and the
issuance and sale of Common Stock as discussed under "Financing".
Capitalization at June 30, 1996 was comprised of 47.4 percent common equity, 7.4
percent preferred equity and 45.2 percent long-term debt. As financial market
conditions warrant, the Company may, from time to time, issue securities to
permit early redemption of higher-cost senior securities. 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.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in
14
the amounts of revenues and expenses, comparing the three-month and six-month
periods ended June 30, 1996 to the three-month and six-month periods ended June
30, 1995.
A summary of changes in Electric and Gas Department revenues and
expenses is shown below:
(Millions of Dollars)
Three Months Six Months
Ended June 30 Ended June 30
------------- --------------
1995 Earnings $13.0 $41.6
Increase (decrease) in earnings:
Electric margin (revenue less fuel) (4.4) 3.2
- Includes effect of 7/1/95 rate increase
- Consumption changes including weather
- Changes in sales to other electric utilities
Gas margin (revenue less fuel) 10.8 20.6
- Consumption changes including weather
- Expense reductions
Maintenance associated with 70 day outage (1.7) (1.7)
Reserve for doubtful accounts (4.2) (5.4)
Payroll changes (2.6) (5.7)
- Increased amortization of early retirement
- Addition of ongoing outplacement program
- Improved employee performance
Miscellaneous non-fuel O&M (1.0) (0.3)
Depreciation and amortization (1.3) (2.4)
Net federal income tax effects (0.3) (4.9)
Local and state tax effects (1.3) 0.5
Other income and deductions effects 1.0 4.4
Interest Savings 1.9 0.6
- Redeemed 8 3/8% series CC bonds 3/7/96
- Matured 5.3% series V bonds 5/1/96
----- -----
1996 Earnings $ 9.9 $50.5
OPERATING REVENUES AND SALES. Total Company revenues for the first
six months of 1996 were $44.2 million or 9% above the first six months of 1995.
The higher revenues resulted from the impact of an extended period of cold
weather on electric and gas sales this year, compared to the revenue effect of
unusually warm weather in the first quarter of 1995, as well as higher revenue
stemming from purchased gas costs, deferred fuel costs and electric rates.
Total Company revenues for the second quarter were $16.0 million or 7%
above the second quarter last year. Gas sold and transported increased 9%,
reflecting increases in all customer classes including gas transportation
customers.
15
FUEL EXPENSES. Total fuel expenses increased in both comparison
periods reflecting mainly higher gas purchased for resale expense in 1996 driven
by higher volumes of purchased gas resulting from colder than normal weather as
well as higher commodity costs.
OPERATIONS EXCLUDING FUEL EXPENSES AND MAINTENANCE EXPENSES. The
increases in operations excluding fuel expenses and maintenance expenses in both
comparison periods reflect mainly the timing for recording lump sum payroll
performance incentives, employee redeployment/outplacement costs and additional
early retirement costs, an increase in the reserve for doubtful accounts and
higher maintenance expenses in the second quarter of 1996 due to the length and
timing of the Ginna Plant refueling and maintenance shutdown which did not begin
until April 1996 but started in March a year ago.
DEPRECIATION AND AMORTIZATION. Depreciation and amortization increased
due mainly to an increase in depreciable plant.
TAXES. The decrease in local, state and other taxes in the first half
of 1996 reflects mainly lower property taxes due to decreases in assessments.
The increase in local, state and other taxes for the second quarter comparison
period reflects mainly higher payroll and revenue taxes.
The increases in federal income tax in both comparison periods reflect
mainly increases in the federal income tax reserve.
OTHER STATEMENT OF INCOME ITEMS. The decreases in allowance for funds used
during construction (AFUDC) in both comparison periods reflect mainly a decrease
in the amount of utility plant under construction in the second quarter of 1996
reflecting the return to service of the Ginna nuclear plant following steam
generator replacement. Other Income and Deductions, Other-net increased mainly
due to lower depreciation expense for the Company's share of the Empire State
Pipeline which was sold in April, 1996 as discussed in the Liquidity and Capital
Resources section. Interest charges decreased reflecting lower amounts of long
term debt outstanding (see "Redemption of Securities").
COMMON STOCK DIVIDEND. On June 18, 1996, the Board of Directors
authorized a common stock dividend of $.45 per share, which was paid on July 25,
1996 to shareholders of record on July 2, 1996. 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.
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 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K: None
EXHIBIT INDEX
Exhibit 27 Financial Data Schedule pursuant to Item 601 (c) of Regulation S-K.
16
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: August 12, 1996 By J.B. STOKES
-----------------------------------------
J. Burt Stokes
Senior Vice President, Corporate Services
and Chief Financial Officer
(Duly Authorized Officer)
Date: August 12, 1996 By DANIEL J. BAIER
-----------------------------------------
Daniel J. Baier
Controller
(Principal Accounting Officer)
17