SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2001
-------------------------
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from______________to_______________
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
- ----------- ---------------------------- ------------------
0-30338 RGS Energy Group, Inc. 16-1558410
(Incorporated in New York)
Rochester, NY 14649
Telephone (716)771-4444
1-672 Rochester Gas and Electric Corporation 16-0612110
(Incorporated in New York)
Rochester, NY 14649
Telephone (716)546-2700
Indicate by check mark whether each 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 ___
---
As of the close of business on April 30, 2001, (i) RGS Energy Group, Inc.
("RGS") had outstanding 34,577,426 shares of Common Stock ($.01 par value) and,
(ii) all of the outstanding shares of Common Stock ($5 par value) of Rochester
Gas and Electric Corporation ("RG&E")were held by RGS.
RG&E meets the conditions set forth in General Instructions (H)(1)(a) and
(b) of Form 10-Q and is therefore filing this form with the reduced disclosure
format pursuant to General Instruction (H)(2).
INDEX
Page No.
PART I - FINANCIAL INFORMATION
RGS Energy Group, Inc.
Consolidated Balance Sheet - March 31, 2001 and
December 31, 2000....................................................................................... 1 - 2
Consolidated Statement of Income - Three Months Ended
March 31, 2001 and 2000................................................................................. 3
Consolidated Statement of Cash Flows - Three Months
Ended March 31, 2001 and 2000........................................................................... 4
Rochester Gas and Electric Corporation
Balance Sheet - March 31, 2001 and December 31, 2000.................................................... 5- 6
Statement of Income - Three Months Ended
March 31, 2001 and 2000................................................................................. 7
Statement of Cash Flows - Three Months Ended
March 31, 2001 and 2000................................................................................. 8
Notes to Financial Statements........................................................................... 9 - 18
Management's Discussion and Analysis of Financial
Condition and Results of Operations..................................................................... 18 - 32
Quantitative and Qualitative Disclosures About
Market Risk............................................................................................. 32
PART II - OTHER INFORMATION
Legal Proceedings....................................................................................... 33
Submission of Matters to a Vote of Security Holders..................................................... 33
Exhibits and Reports on Form 8-K........................................................................ 33
Signatures.............................................................................................. 34
____________
Filing Format
This Quarterly report on Form 10-Q is a combined quarterly report being filed by
two different registrants: RGS and RG&E. RGS became the holding company for RG&E
on August 2, 1999. Except where the content clearly indicates otherwise, any
references in this report to "RGS" include all subsidiaries of RGS including
RG&E. RG&E makes no representation as to the information contained in this
report in relation to RGS and its subsidiaries other than RG&E.
Abbreviations and Glossary
Company or RGS RGS Energy Group, Inc., a holding company formed
August 2, 1999, which is the parent company of
Rochester Gas and Electric Corporation, RGS
Development Corporation and Energetix, Inc.
Electric Settlement Competitive Opportunities Case Settlement among
RG&E, PSC and other parties which provides the
framework for the development of competition in the
electric energy marketplace through June 30, 2002
Energetix Energetix, Inc., a wholly-owned subsidiary of RGS
Energy Choice A competitive electric retail access program of
RG&E being phased-in over a period ending July,
2001
FERC Federal Energy Regulatory Commission
Ginna Plant Ginna Nuclear Plant which is wholly owned by RG&E
Griffith Griffith Oil Company Inc., an oil, gasoline and
propane distribution company acquired by Energetix
in 1998
Heating degree day A measure that quantifies the extent to which the
daily outdoor average temperature falls below a
base of 65 degrees Fahrenheit. One degree day is
counted for each degree day falling below the
assumed base for each calendar day
Nine Mile Two Nine Mile Point Nuclear Plant Unit No. 2 of which
RG&E owns a 14% share
NRC Nuclear Regulatory Commission
NYISO New York Independent System Operator
NYPA New York Power Authority
NYSDEC New York State Department of Environmental
Conservation
PSC New York State Public Service Commission
Regulatory Assets Deferred costs whose classification as an asset on
the balance sheet is permitted by SFAS-71,
Accounting for the Effects of Certain Types of
Regulation
RG&E Rochester Gas and Electric Corporation, a wholly-
owned subsidiary of RGS
RGS Development RGS Development Corporation, a wholly-owned
subsidiary of RGS
RTO Regional Transmission Organization
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
SFAS 71 Accounting for the Effects of Certain Types of
Regulation
1
PART 1 - FINANCIAL INFORMATION
- ------------------------------
ITEM1. FINANCIAL STATEMENTS
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
(Unaudited)
March 31, December 31,
2001 2000
Assets
- -------------------------------------------------------------------------------------------
Utility Plant
Electric $2,481,340 $2,467,289
Gas 478,328 471,051
Common 167,457 164,872
Nuclear 292,430 292,588
---------- ----------
3,419,555 3,395,800
Less: Accumulated depreciation 1,761,407 1,750,493
Nuclear fuel amortization 258,605 254,435
---------- ----------
1,399,543 1,390,872
Construction work in progress 118,438 111,486
---------- ----------
Net Utility Plant 1,517,981 1,502,358
---------- ----------
Current Assets
Cash and cash equivalents 22,963 16,258
Accounts receivable, net of allowance for
doubtful accounts:
2001 - $34,648; 2000 - $34,550 160,350 136,374
Unbilled revenue receivable 63,566 71,120
Fuels 11,961 46,868
Materials and supplies 9,273 8,187
Prepayments 35,539 26,268
Other current assets 3,358 2,292
---------- ----------
Total Current Assets 307,010 307,367
---------- ----------
Intangible Assets
Goodwill, net 27,706 27,971
Other intangible assets, net 22,096 22,614
---------- ----------
Total Intangible Assets 49,802 50,585
---------- ----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 234,551 244,514
Nine Mile Two deferred costs 26,892 27,155
Unamortized debt expense 16,199 16,602
Other deferred debits 4,336 4,674
Regulatory assets 402,242 412,790
Other assets 1,545 1,330
---------- ----------
Total Deferred Debits and Other Assets 685,765 707,065
---------- ----------
Total Assets $2,560,558 $2,567,375
========== ==========
2
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
(Unaudited)
March 31, December 31,
2001 2000
Capitalization and Liabilities
- -------------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $ 580,148 $ 580,132
- promissory notes 241,010 243,728
Preferred stock redeemable at option of RG&E 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholders' equity
Common stock
Authorized 100,000,000 shares; 38,956,726 shares issued at
March 31, 2001 and at December 31, 2000 704,304 702,807
Retained earnings 211,395 181,546
---------- ----------
915,699 884,353
Less: Treasury stock at cost (4,379,300 shares at March 31, 2001
and at December 31, 2000) 117,238 117,238
---------- ----------
Total Common Shareholders' Equity 798,461 767,115
---------- ----------
Total Capitalization 1,691,619 1,662,975
---------- ----------
Long Term Liabilities
Nuclear waste disposal 98,635 97,291
Uranium enrichment decommissioning 9,750 9,649
Site remediation 24,528 24,420
---------- ----------
132,913 131,360
---------- ----------
Current Liabilities
Long term debt due within one year 12,105 12,095
Short term debt 76,900 122,400
Accounts payable 86,866 108,618
Dividends payable 16,485 16,515
Other 85,943 57,491
---------- ----------
Total Current Liabilities 278,299 317,119
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 275,029 277,787
Pension costs accrued 20,736 26,547
Kamine deferred credit 50,260 51,920
Post employment benefits 55,585 54,505
Other 56,117 45,162
---------- ----------
Total Deferred Credits and Other Liabilities 457,727 455,921
---------- ----------
Total Capitalization and Liabilities $2,560,558 $2,567,375
========== ==========
The accompanying notes are an integral part of the financial statements.
3
RGS Energy Group Inc.
Consolidated Statement of Income
(Thousands of dollars)
(Unaudited)
- --------------------------------------------------------------------------------
For the Three Months Ended
March 31,
2001 2000
--------------- ------------
OPERATING REVENUES
Electric $190,756 $179,784
Gas 166,425 119,568
Other 150,598 86,499
--------------- ------------
Total Operating Revenues 507,779 385,851
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 12,549 10,963
Purchased electricity 21,511 18,215
Gas purchased for resale 113,486 63,937
Unregulated fuel expenses 129,758 75,789
--------------- ------------
Total Fuel Expenses 277,304 168,904
--------------- ------------
Operating Revenues Less Fuel Expenses 230,475 216,947
Other Operating Expenses
Operations and maintenance excluding fuel 66,269 70,517
Unregulated operating and maintenance expenses excluding fuel 11,773 7,385
Depreciation and amortization 30,487 28,995
Taxes - state, local and other 27,676 29,826
Income taxes 30,649 26,568
--------------- ------------
Total Other Operating Expenses 166,854 163,291
--------------- ------------
Operating Income 63,621 53,656
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds used during construction (238) (191)
Income taxes (1,392) 445
RGS/Energy East Merger Expenses 3,407 0
Other - net (120) (1,079)
--------------- ------------
Total Other (Income) and Deductions 1,657 (825)
INTEREST CHARGES
Long term debt 14,157 14,465
Other - net 1,886 980
Allowance for borrowed funds used during construction (382) (306)
--------------- ------------
Total Interest Charges 15,661 15,139
--------------- ------------
Net Income 46,303 39,342
--------------- ------------
Preferred Stock Dividend Requirements 925 925
--------------- ------------
Net Income Applicable to Common Stock 45,378 38,417
--------------- ------------
Average Number of Common Shares (000's)
Common Stock 34,577 35,783
Common Stock and Equivalents 34,879 35,803
Earnings per Common Share - Basic $ 1.31 $ 1.07
Earnings per Common Share - Diluted $ 1.30 $ 1.07
Cash Dividends Paid per Common Share $ 0.45 $ 0.45
The accompanying notes are an integral part of the financial statements.
4
RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
Three Months Ended
(Thousands of Dollars) March 31,
- ------------------------------------------------------------------------------------------------------
2001 2000
-------- --------
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 46,303 $ 39,342
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 35,230 33,380
Deferred recoverable fuel costs 10,791 15,242
Income taxes deferred (81) (3,348)
Allowance for funds used during construction (620) (497)
Unbilled revenue 7,554 1,164
Post employment benefit/pension costs 869 1,525
Provision for doubtful accounts 98 (25)
Changes in certain current assets and liabilities; net of assets
acquired and liabilities assumed in acquisitions:
Accounts receivable (24,074) (8,043)
Materials, supplies and fuels 33,821 17,674
Taxes accrued 6,040 2,804
Accounts payable (21,752) 1,183
Other current assets and liabilities, net 13,976 24,037
Other, net 2,717 (7,529)
-------- ---------
Total Operating 110,872 116,909
-------- ---------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (32,438) (26,771)
Nuclear generating plant decommissioning fund (5,136) (5,136)
Acquisitions, net of cash - (1,296)
Other, net (1,723) 2
-------- ---------
Total Investing (39,297) (33,201)
-------- ---------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Short term borrowings, net (45,500) (500)
Retirement of long term debt - (30,000)
Repayment of promissory notes (990) (919)
Dividends paid on preferred stock (925) (925)
Dividends paid on common stock (15,560) (16,153)
Payment for treasury stock - (7,837)
Other, net (1,895) (7,904)
-------- ---------
Total Financing (64,870) (64,238)
-------- ---------
Increase in cash and cash equivalents 6,705 19,470
Cash and cash equivalents at beginning of
period 16,258 8,288
-------- ---------
Cash and cash equivalents at end of period $ 22,963 $ 27,758
======== =========
The accompanying notes are an integral part of the financial statements.
5
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
(Unaudited)
March 31, December 31,
Assets 2001 2000
- ------------------------------------------------------------------------------------------
Utility Plant
Electric $2,481,340 $2,467,289
Gas 478,328 471,051
Common 118,715 117,473
Nuclear 292,430 292,588
---------- ----------
3,370,813 3,348,401
Less: Accumulated depreciation 1,745,591 1,735,752
Nuclear fuel amortization 258,605 254,435
---------- ----------
1,366,617 1,358,214
Construction work in progress 118,438 111,486
---------- ----------
Net Utility Plant 1,485,055 1,469,700
---------- ----------
Current Assets
Cash and cash equivalents 13,118 4,851
Accounts receivable, net of allowance for
doubtful accounts:
2001 - $33,482; 2000 - $33,482 110,462 93,130
Affiliate receivable 51,740 51,558
Unbilled revenue receivable 49,398 61,838
Fossil Fuel 4,295 33,896
Materials and supplies 9,273 8,187
Prepayments 32,943 23,782
---------- ----------
Total Current Assets 271,229 277,242
---------- ----------
Deferred Debits and Other Assets
Nuclear generating plant
decommissioning fund 234,551 244,514
Nine Mile Two deferred costs 26,892 27,155
Unamortized debt expense 16,199 16,602
Other deferred debits 4,336 4,674
Regulatory assets 402,242 412,788
Other assets 367 -
---------- ----------
Total Deferred Debits
and Other Assets 684,587 705,733
---------- ----------
Total Assets $2,440,871 $2,452,675
========== ==========
6
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
(Unaudited)
March 31, December 31,
Capitalization and Liabilities 2001 2000
- -------------------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $ 580,148 $ 580,132
- promissory notes 210,791 211,703
Preferred stock redeemable at option of RG&E 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholder's equity
Authorized 50,000,000 shares; 38,885,813 shares issued at
March 31, 2001 and at December 31, 2000 700,318 700,318
Retained earnings 192,682 166,184
---------- ----------
892,999 866,502
Less: Treasury stock at cost (4,379,300 shares at March 31, 2001
and at December 31, 2000) 117,238 117,238
---------- ----------
Total Common Shareholder's Equity 775,761 749,264
---------- ----------
Total Capitalization 1,638,700 1,613,099
---------- ----------
Long Term Liabilities
Nuclear waste disposal 98,635 97,291
Uranium enrichment decommissioning 9,750 9,649
Site remediation 22,357 22,356
---------- ----------
130,742 129,296
---------- ----------
Current Liabilities
Long term debt due within one year 4,149 4,227
Short term debt 58,000 98,000
Accounts payable 59,586 79,356
Affiliate payable 11,974 18,451
Dividends payable 16,485 16,515
Other 67,433 41,664
---------- ----------
Total Current Liabilities 217,627 258,213
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 271,429 274,299
Pension costs accrued 20,736 26,548
Kamine deferred credit 50,260 51,920
Post employment benefits 55,585 54,505
Other 55,791 43,219
---------- ----------
Total Deferred Credits and Other Liabilities 453,802 450,491
---------- ----------
Total Capitalization and Liabilities $2,440,871 $2,451,099
========== ==========
The accompanying notes are an integral part of the financial statements.
7
Rochester Gas and Electric Corporation
Statement of Income
(Thousands of dollars)
(Unaudited)
- ------------------------------------------------------------------------------------------------
For the Three Months Ended
March 31,
2001 2000
------------ --------------
OPERATING REVENUES
Electric $189,060 $176,708
Gas 141,107 114,143
------------ --------------
Total Operating Revenues 330,167 290,851
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 12,549 10,963
Purchased electricity 20,793 16,163
Gas purchased for resale 89,428 59,238
------------ --------------
Total Fuel Expenses 122,770 86,364
------------ --------------
Operating Revenues Less Fuel Expenses 207,397 204,487
Other Operating Expenses
Operations and maintenance excluding fuel 66,267 70,517
Depreciation and amortization 28,379 28,060
Taxes - state, local and other 26,023 28,584
Income taxes 27,535 25,145
------------ --------------
Total Other Operating Expenses 148,204 152,306
------------ --------------
Operating Income 59,193 52,181
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds used during construction (238) (191)
Income taxes (1,571) 417
RGS/Energy East Merger Expenses 3,311 0
Other - net 280 (1,042)
------------ --------------
Total Other (Income) and Deductions 1,782 (816)
INTEREST CHARGES
Long term debt 13,850 14,096
Other - net 1,055 865
Allowance for borrowed funds used during construction (382) (306)
------------ --------------
Total Interest Charges 14,523 14,655
------------ --------------
Net Income 42,888 38,342
------------ --------------
Dividends on Preferred Stock 925 925
------------ --------------
Net Income Applicable to Common Stock 41,963 37,417
------------ --------------
Average Number of Common Shares (000's)
Common Stock 34,577 35,783
The accompanying notes are an integral part of the financial statements.
8
ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS
(Unaudited)
Three Months Ended
(Thousands of Dollars) March 31,
- -----------------------------------------------------------------------------------------------------------
2001 2000
---------- ----------
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 42,888 $ 38,342
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 32,839 32,428
Deferred recoverable fuel costs 10,791 15,242
Income taxes deferred (193) (1,970)
Allowance for funds used during construction (620) (497)
Unbilled revenue 12,440 4,360
Post employment benefit/pension costs 869 1,525
Provision for doubtful accounts - 13
Changes in certain current assets and liabilities:
Accounts receivable (17,514) (9,729)
Materials, supplies and fuels 28,515 18,288
Taxes accrued 7,169 4,028
Accounts payable (14,267) 4,580
Other current assets and liabilities, net 9,699 18,809
Other, net 1,534 (5,033)
---------- ----------
Total Operating 114,150 120,386
---------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (31,095) (26,345)
Nuclear generating plant decommissioning fund (5,136) (5,136)
Other, net - (475)
---------- ----------
Total Investing (36,231) (31,956)
---------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Short term borrowings, net (40,000) -
Retirement of long term debt - (30,000)
Repayment of promissory notes (990) (919)
Dividends paid on preferred stock (925) (925)
Dividends paid on common stock (15,560) (16,153)
Payment for treasury stock - (7,837)
Other, net (12,177) (10,377)
---------- ----------
Total Financing (69,652) (66,211)
---------- ----------
Increase in cash and cash equivalents 8,267 22,219
Cash and cash equivalents at beginning of period 4,851 6,443
---------- ----------
Cash and cash equivalents at end of period $ 13,118 $ 28,662
---------- ----------
The accompanying notes are an integral part of the financial statements.
9
RGS ENERGY GROUP, INC.
ROCHESTER GAS AND ELECTRIC CORPORATION
NOTES TO FINANCIAL STATEMENTS
Note 1. SUMMARY OF ACCOUNTING PRINCIPLES
HOLDING COMPANY FORMATION
On August 2, 1999, Rochester Gas and Electric Corporation ("RG&E") was
reorganized into a holding company structure in accordance with the Agreement
and Plan of Exchange between RG&E and RGS Energy Group, Inc. ("RGS"). RG&E's
common stock was exchanged on a share-for-share basis for RGS' common stock.
RG&E's preferred stock was not exchanged as part of the share exchange and will
continue as shares of RG&E.
BASIS OF PRESENTATION
This is a combined report of RGS and RG&E, a regulated Electric and Gas
subsidiary. The Notes to Financial Statements apply to both RGS and RG&E. RGS's
Consolidated Financial Statements include the accounts of RGS and its wholly
owned subsidiaries, including RG&E, and two non-utility subsidiaries, Energetix,
Inc. ("Energetix") and RGS Development Corporation ("RGS Development"). RGS and
RG&E, in the opinion of management, have included adjustments (which include
normal recurring adjustments) which are necessary for the fair statement of the
results of operations for the interim periods presented. The consolidated
financial statements for 2001 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. Moreover, 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 RGS
and RG&E combined Annual Report on Form 10-K for the year ended December 31,
2000.
RECLASSIFICATIONS
Certain amounts in the prior years' financial statements were reclassified
to conform with current year presentation.
MERGER AGREEMENT
On February 20, 2001, RGS announced that it had entered into an Agreement
and Plan of Merger ("Merger Agreement"), dated as of February 16, 2001, with
Energy East ("Energy East"), a New York corporation, and Eagle Merger Corp., a
New York corporation that will be a wholly owned subsidiary of Energy East at
the effective time of the merger ("Merger Sub"), pursuant to which RGS will be
merged with and into Merger Sub (the "Merger") and RGS will become a wholly
owned subsidiary of Energy East. As a result of the Merger, all of the
outstanding common stock of RGS will be exchanged for a combination of cash and
Energy East common stock valued at approximately $1.4 billion in the aggregate.
Energy East will also assume approximately $1.0 billion of RGS debt.
Under the Merger Agreement, subject to possible adjustments for tax
reasons, 45% of the RGS common stock will be converted into a number of shares
of Energy East common stock with a value of $39.50 per RGS share, subject to
restrictions on the maximum and minimum number of shares of Energy East common
stock to be issued, and 55% of the RGS common stock will be converted into
$39.50 in cash per RGS share. RGS shareholders will be able to specify the
percentage of the consideration they wish to receive in shares of Energy East
common stock and in cash, subject to proration.
10
The Merger is subject to, among other things, the approval of RGS
shareholders and Energy East shareholders, and the approvals of various
regulatory agencies, including the New York State Public Service Commission
("PSC"), Federal Energy Regulatory Commission ("FERC"), Nuclear Regulatory
Commission ("NRC") and the Securities and Exchange Commission ("SEC"). A Joint
Petition by the parties to the Merger, seeking approval of the PSC pursuant to
Section 70 of the Public Service Law, was filed on March 23, 2001. All
regulatory approvals are expected to be obtained in about 12 months.
NEW YORK STATE TAX CHANGES
On May 15, 2000 changes to the New York State tax laws were signed into law
effective January 1, 2000. In June 2000 the Company recorded taxes in accordance
with these changes. The effect of these changes was a reduction in the gross
receipts tax rate, elimination of excess dividends taxes, and the imposition of
a state income tax. As a result, deferred state income taxes were established in
accordance with the transition rules to recognize timing differences between
book and tax deductibility. This transition item results in a one-time tax
benefit that has been deferred for future rate treatment in accordance with the
Electric Settlement.
ADOPTION OF SFAS 133 - ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING
ACTIVITIES
The Company has adopted SFAS 133 as of January 1, 2001. For a description
of SFAS 133, see Note 1 of the combined Form 10-K for RGS and RG&E for the year
ended December 31, 2000. The cumulative effect of this change has not materially
impacted the Company's net income. This broad and complex standard requires,
with limited exception, derivative transactions to be recognized and recorded on
the Company's balance sheet at fair value. At March 31, 2001, the balance sheet
effect of adopting SFAS 133 was not significant.
11
Note 2. OPERATING SEGMENT FINANCIAL INFORMATION
The Company has identified three operating segments of its business based
on the types of products and services it offers and the regulatory environment
under which it operates. The three segments are regulated electric, regulated
gas, and unregulated. The regulated segments' financial records are maintained
in accordance with the accounting principles generally accepted in the United
States of America ("GAAP") and PSC accounting policies. The unregulated
segment's financial records are maintained in accordance with GAAP.
For the Three Months Ended March 31
Regulated Regulated
Electric Gas Unregulated
-------- --- -----------
(thousands of dollars) 2001 2000 2001 2000 2001 2000
---- ---- ---- ---- ---- ----
Operating Income $ 42,306 $ 34,298 $ 16,887 $ 17,883 $ 4,422 $ 1,449
Revenues - External Customers 189,060 176,708 141,107 114,143 214,573 111,892
Revenues - Intersegment Transactions 27,301 16,892 9,660 - - -
The operations of RGS Development are included in Other (Income) and Deductions
in the RGS Consolidated Statement of Income. The total amount of the revenues
identified by operating segment do not equal the total Company consolidated
amounts as shown in the RGS Consolidated Statement of Income. This is due to the
elimination of certain intersegment revenues during consolidation. A
reconciliation follows:
For the Three Months
Ended March 31,
(thousands of dollars)
Revenues 2001 2000
-------- --------
Regulated Electric $189,060 $176,708
Regulated Gas 141,107 114,143
Unregulated 214,573 111,892
-------- --------
Total $544,740 $402,743
Reported on RGS Consolidated
Income Statement 507,779 385,851
Difference to reconcile 36,961 16,892
Intersegment Revenue
Regulated Electric from Unregulated 27,301 16,892
Regulated Gas from Unregulated 9,660 -
-------- --------
Total Intersegment $ 36,961 $ 16,892
12
The following matters supplement the information contained in Notes 2, 3, & 12
to the Financial Statements included in the RGS and RG&E combined Annual Report
on Form 10-K for the year ended December 31, 2000 and should be read in
conjunction with the material contained in those Notes.
Note 3. NUCLEAR-RELATED MATTERS
- ---------------------------------
NINE MILE NUCLEAR PLANTS
On June 24, 1999, Niagara Mohawk and New York State Electric & Gas
Corporation ("NYSEG") announced their intention to sell their interests in the
Nine Mile One and Nine Mile Two nuclear plants to AmerGen Energy Company, L.L.C.
("AmerGen"), a joint venture of PECO Energy and British Energy. Niagara Mohawk
owns 41 percent of Nine Mile Two and 100 percent of Nine Mile One and NYSEG owns
18 percent of Nine Mile Two.
RG&E's 14 percent interest in Nine Mile Two was not included in the
proposal, but RG&E has a right of first refusal to buy the interests of the
other owners of Nine Mile Two on terms at least as favorable as those offered.
RG&E exercised its right of first refusal and broadened it to include Nine Mile
One with which Nine Mile Two was paired in the proposal. However, in the
ensuing discussions with the PSC staff it became clear that the transaction on
the terms proposed would not be approved by the PSC.
On April 25, 2000, the PSC issued an order that allowed NYSEG and Niagara
Mohawk to withdraw their petition to sell their interests in the Nine Mile
plants to AmerGen. The order concluded that Nine Mile's market value is "greatly
in excess of the original AmerGen purchase price" and that multiple entities are
now interested in the Nine Mile plants. The order also concluded that
"...failure for the utilities to determine the market value of the Nine Mile
facilities at this time, through an open process, would raise serious prudence
questions." With respect to stranded costs, the PSC order indicated that
stranded costs cannot be finally quantified "until the disposition of the plants
by the utilities is decided." The PSC's order did, however, observe that (1) a
sale would be considered within its policy of separating generation from
transmission and distribution, (2) a sale at current market values would
constitute appropriate mitigation of stranded costs and (3) ratemaking treatment
of a sale would be resolved in accordance with each company's competitive
opportunities/restructuring order taking into account reduced risk and corollary
divestiture effects.
After issuance of the PSC's order, RG&E decided to determine the market
value of its interest in Nine Mile Two. On June 1, 2000, RG&E issued a press
release announcing an auction process by RG&E, Central Hudson, NYSEG and Niagara
Mohawk in connection with their ownership interests in Nine Mile Two and Niagara
Mohawk's interest in Nine Mile One.
On December 11, 2000, RG&E, Niagara Mohawk, Central Hudson and NYSEG
entered into an agreement to sell their ownership interests in Nine Mile Two
(and in the case of Niagara Mohawk, Nine Mile One) to Constellation Nuclear,
L.L.C. ("Constellation Nuclear"). Constellation Nuclear was the successful
bidder in a competitive auction conducted for the plants. The Long Island Power
Authority, an 18 percent owner of Nine Mile Two, is not participating in the
sale.
The purchase price for RG&E's 14% ownership interest in Nine Mile Two is
$99.2 million, $49.6 million of which will be paid in cash at closing and $49.6
million of which will be paid in five equal annual principal installments plus
interest at a rate of 11% pursuant to a five year promissory note. Principal and
interest payments under the promissory note will total approximately $66 million
unless the note is pre-paid. The purchase price is subject to adjustment at the
time of closing. The aggregate purchase price for 82 percent of Nine Mile Two is
$581 million. The aggregate purchase price, including cash payments at closing
and payments of principal and interest to all of the sellers under the
promissory notes, is $676.6 million for 82 percent of Nine Mile Two.
13
Also, part of the transaction is a power purchase agreement whereby
Constellation Nuclear has agreed to sell the output from 90 percent of RG&E's 14
percent interest in Nine Mile Two back to RG&E for approximately 10 years at an
average price of less than $35 per MWh over the term of the power purchase
agreement.
After the completion of the power purchase agreement, a 10-year revenue
sharing agreement begins. The revenue sharing agreement will provide RG&E with a
hedge against electricity price increases and could provide RG&E additional
revenue through 2021. The revenue sharing agreement provides that, to the extent
market prices (for energy and capacity) exceed certain strike prices, 14% of the
market value of Nine Mile Two's actual output (capped at 160 MW) above the
strike price will be shared 80% to RG&E and 20% to Constellation Nuclear. When
actual market prices are lower than strike prices, such negative amounts will be
carried forward as credits against subsequent payments.
At closing, the sellers' pre-existing decommissioning funds will be
transferred to Constellation Nuclear and Constellation Nuclear will assume the
sellers' obligation to decommission Nine Mile Two.
The NRC, FERC, PSC and other regulatory bodies must approve the sale.
Receipt of such regulatory approvals in form and substance satisfactory to RG&E,
is a condition to RG&E's obligation to close the transaction. The transaction is
targeted to close in mid-2001. At March 31, 2001, the net book value of RG&E's
14 percent interest in the Nine Mile Two generating facility was approximately
$357 million. RG&E also had investments in fuel of approximately $7.8 million,
transmission and distribution facilities of $3.4 million and construction work
in progress of $5.3 million
On January 31, 2001, RG&E, together with Niagara Mohawk, Central Hudson,
NYSEG and Constellation Nuclear filed a petition with the PSC pursuant to
Section 70 of the Public Service Law, requesting that the PSC authorize the
sellers to transfer to Constellation Nuclear their interests in Nine Mile Two in
accordance with the rate treatment proposed. For RG&E, the rate treatment
proposed includes full recovery of the regulatory asset remaining after the
sale. Certain parties to the Section 70 proceeding, including the PSC Staff,
have taken the position that RG&E and other co-tenants should not be allowed to
recover their full costs resulting from the sale. RG&E does not concur with
these proposed adjustments and intends to contest them vigorously. The outcome
of the proceeding cannot be predicted.
Prior to the events discussed above, the PSC had initiated a proceeding to
examine the appropriate role of the nuclear power plants in New York State in
developing a competitive market for electricity. Collaborative efforts of the
parties led to the development of a report on the subject which the PSC
discussed at a July 1999 session without issuing an order. No significant
activity has since occurred in the proceeding and RG&E cannot predict what the
PSC may do to continue or conclude it. Since all nuclear plants in the state
either have now been sold or are under contract to be sold, except for RG&E's
Ginna Plant, the PSC could regard the proceeding as moot.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND
The Energy Policy Act of 1992 required nuclear plant owners that had
previously contracted with the federal government for uranium enrichment
services to pay DOE-levied annual assessments for a portion of the cost to
decontaminate and decommission the government's uranium enrichment facilities.
In June 1998, approximately twenty electric utilities including RG&E brought
suit against the United States in the Federal District Court for the Southern
District of New York, seeking a declaratory judgment that this $2.25 billion
retroactive assessment should be enjoined because it was unconstitutional on due
process and taking grounds. In December 2000, the Court of Appeals for the
Federal Circuit upheld, by a 2-1 vote, the District Court's denial of a
government motion either to transfer the case to the Court of Federal Claims,
where cases seeking assessment refunds on similar facts have been dismissed, or
in the alternative to dismiss the complaint. Proceedings continue in the Federal
District Court.
14
The assessments for Ginna and RG&E's share of Nine Mile Two are estimated
to total $22.1 million, excluding inflation and interest. Installments
aggregating approximately $14.7 million have been paid through March 31, 2001. A
liability has been recognized on the financial statements along with a
corresponding regulatory asset. RG&E's liability for the two facilities at March
31, 2001 was $11.6 million ($9.8 million as a long-term liability and $1.8
million as a current liability). RG&E is recovering these costs in rates.
Note 4. REGULATORY MATTERS
REGULATORY ASSETS
With PSC approval RG&E has deferred certain costs rather than recognize
them as expense 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 SFAS-71, "Accounting for the Effects of
Certain Types of Regulation". These deferred costs are shown as regulatory
assets on the Company's and RG&E's Balance Sheets. Such cost deferral is
appropriate in a 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 RG&E were no longer allowed to defer some or a
portion of these costs under SFAS-71, these assets would be adjusted
accordingly, which could include writing off up to the entire amount.
Below is a summary of RG&E's regulatory assets as of March 31, 2001 and
December 31, 2000:
Millions of Dollars
March 31, 2001 Dec. 31, 2000
------------------- -------------
Kamine Settlement $176.7 $179.1
Income Taxes 99.2 101.9
Oswego Plant Sale 72.3 74.4
Deferred Environmental SIR costs 13.7 16.6
Uranium Enrichment Decommissioning Deferral 12.4 12.7
Labor Day 1998 Storm Costs 9.5 9.3
Other, net 18.4 18.8
------ ------
Total - Regulatory Assets $402.2 $412.8
====== ======
See the combined 2000 Form 10-K of RGS and RG&E, Item 8, Note 3 of the
Notes to Financial Statements, "Regulatory Matters" 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. An example
includes 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 March 31, 2001 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 the amount could be significant. Strandable assets, if any, could be written
down for impairment of recovery based on SFAS-121, "Accounting for the
Impairment of Long Lived Assets and for Long Lived Assets to be Disposed of",
which requires write-down of long-lived assets whenever events or circumstances
occur which indicate that the carrying amount of a long-lived asset may not be
recoverable.
At March 31, 2001 RG&E believed that its regulatory assets are probable of
recovery. The Electric Settlement does not impair the opportunity of RG&E to
recover its investment in these assets. However, the Electric Settlement
provides for the non-nuclear generation to-go costs to be subject to market
forces during the current Settlement term. Should the costs of non-nuclear
generation exceed market prices, the Company may no longer be able to apply
SFAS-71. These costs have been below prevailing market prices. The PSC
15
issued an Opinion and Order Instituting Further Inquiry on March 20, 1998 to
address issues surrounding nuclear generation. RG&E is unable to determine when
this proceeding may conclude. The ultimate determination in this proceeding or
any proceeding to consider RG&E's proposed sale of its interest in Nine Mile Two
as discussed under "Nuclear-Related Matters" could have an impact on strandable
assets and the recovery of nuclear costs.
In a competitive natural gas market, strandable assets would arise where
customers migrate away from dependence on RG&E for full service, leaving RG&E
with surplus pipeline and storage capacity, as well as natural gas supplies
under contract. RG&E has been restructuring its transportation, storage and
supply portfolio to reduce its potential exposure to strandable assets.
Regulatory developments referred to under "Gas Retail Access Settlements" below,
may affect this exposure, but whether and to what extent there may be an impact
on the level and recoverability of strandable assets cannot be determined at
this time.
GAS RETAIL ACCESS SETTLEMENTS.
On January 25, 2001, RG&E reached agreement with PSC Staff and other
parties on a comprehensive rate and restructuring proposal for its natural gas
business (the "Gas Rates and Restructuring Proposal"), as contemplated in the
PSC's Restructuring Policy Statement issued November 3, 1998.
Since mid-1998, RG&E, PSC Staff and other parties had engaged in settlement
negotiations regarding RG&E's rates and restructuring. These negotiations
resulted in two previous agreements among RG&E, PSC Staff and several other
parties. The first was implemented in September 1999 and addressed the following
issues: a capacity release revenue imputation, capacity cost mitigation
measures, a timetable for public filing and resumption of negotiations, and
improvement of RG&E's retail access program. The September 1999 agreement was
approved by the PSC in an Order issued September 30, 1999.
Pursuant to the September 1999 agreement, RG&E, on January 28, 2000, made a
filing addressing various issues pertaining to RG&E's natural gas business,
including proposals for restructuring that business and facilitating migration
from fully bundled sales service to retail service provided by natural gas
marketers. Certain issues presented by the January 28, 2000 filing, principally
relating to the commencement of a single-retailer retail access program for gas,
in substantially the same form as currently in effect for electric retail access
(see "Energy Choice" under Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations), and the establishment of a
"backout credit" to be paid to natural gas marketers serving retail customers,
were resolved in a June 2000 Gas Settlement.
The Gas Rates and Restructuring Proposal is intended to resolve all issues
identified by the parties and not resolved in either the September 1999
settlement or the June 2000 Gas Settlement, as approved by the PSC. The Proposal
was approved by the PSC, with some modifications, on February 28, 2001 and made
effective on March 1, 2001.
The Gas Rates and Restructuring Proposal contains a number of features that
are intended to extend for different periods. The two most significant periods
are the Rate Term, which applies principally to rate-related provisions and
extends from July 1, 2000 through June 30, 2002, and the Rate and Restructuring
Program Term which applies to most other provisions and extends from the date of
approval of the Proposal through March 31, 2004. The principal features of the
Proposal, as filed with the PSC, are as follows:
(1) For the purpose of setting base, or local delivery, rates for the
period beginning July 1, 2000, natural gas revenues are decreased a total of
$2,806,000 from the levels in effect on June 30, 2000. This rate level is based
on an agreed-upon return on equity of 11.00 percent.
(2) Base rates are adjusted effective March 1, 2001 to reflect the revenue
requirements decrease. Because the base rates that were in effect through
February 28, 2001 were higher than those agreed to by the parties, RG&E, in
March 2001, passed back to all its retail gas customers a temporary credit
applied to rates, on a volumetric basis, equal to the amount of the reduction in
rates for the period July 1, 2000 through
16
February 28, 2001.
(3) In the event that RG&E achieves a return on equity in excess of 12.5
percent in any Rate Year covered by this Proposal, 90 percent of the excess over
that level shall be deferred for the benefit of customers.
(4) RG&E is allowed to defer certain prudent and verifiable costs,
described in items 5 and 6 below, for recovery after the Rate Term of the
Proposal, subject to PSC approval.
(5) RG&E shall be entitled to defer any costs associated with mandates and
catastrophic events that occur during the Rate Term of this Proposal. If the
incremental cost impact of any individual mandate or any individual catastrophic
event exceeds $600,000 per rate year, RG&E is entitled to defer the entire
amount for recovery.
(6) RG&E is entitled to defer for recovery, all incremental expenditures
for competition implementation costs to the extent that such costs exceed
$300,000 per year.
(7) If migration to retail access is expected to exceed 30 percent of the
small-volume customer market (i.e., customers eligible under Service
Classification No. 5 - Small General Service) during the Rate Term of the
Proposal, the parties will meet to discuss the PSC Transition Cost Surcharge
with a view to considering changes that would reduce the allocation of capacity
costs to Service Classification No. 1 - General Service customers.
(8) RG&E is authorized to implement a Retail Access Capacity Program,
contemplated to begin before the 2001-2002 heating season, pursuant to which
RG&E would release pipeline capacity it currently holds to marketers serving
customers in RG&E's service area. This Program will help to avoid stranded
capacity costs that might otherwise result from migration of customers to
marketers.
(9) RG&E will implement a Capacity Incentive Program ("CIP"), consisting of
a Capacity Cost Incentive and a Capacity Cost Imputation. Both elements are
intended to encourage aggressive management of RG&E's capacity costs. The
Capacity Cost Incentive is designed to share, between RG&E and its customers,
the savings resulting from the difference between a base level of capacity costs
and the actual capacity costs achieved. The Capacity Cost Imputation is intended
to provide customers with a guaranteed level of short-term savings through the
gas cost adjustment provision. "Short-term" refers to periods of one year or
less. "Savings" refers to capacity release savings, as well as net revenues
from off-system sales, if any. The imputed level of savings will be $1,100,000
per year for the period beginning April 1, 2001 and extending through June 30,
2002. The level will then be $500,000 per year for the period beginning July 1,
2002 and extending through March 31, 2004.
(10) RG&E will implement a Low-Income Program for customers who require
assistance. The Low-Income Program will be funded through a surcharge in
customer bills.
(11) RG&E implemented a Service Quality Performance Program to be effective
as of January 1, 2001 through at least June 30, 2002. This Program establishes
performance targets for six specific measures of service and provides for a
maximum overall penalty of 42 basis points of gas return on equity for failure
to meet the minimum levels specified.
(12) RG&E will implement a customer education plan to increase customer
awareness and understanding of competitive choice.
17
In approving the Gas Rates and Restructuring Proposal, the PSC made the
following modifications:
(a) the minimum charge will remain at the current level of $5.81 per month for
all Home Energy Assistance Program ("HEAP")-eligible, non-heating gas customers;
(b)with regard to the customer assistance portion of the Low-Income Program,
instead of using a surcharge for funding, RG&E is authorized to recover program
costs by netting them against costs and revenues that are reconciled annually
through the gas cost adjustment; (c) the weatherization assistance portion of
the Low-Income Program is eliminated and RG&E is required to coordinate
weatherization efforts with the PSC's System Benefits Charge ("SBC") program;
and (d) in view of the allocation of SBC funds to public awareness programs, the
$200,000 incremental annual expense for the Competition Education plan is
eliminated and that amount is, in effect, added to the original revenue
decrease, thereby increasing the total revenue reduction to $3,000,000.
Note 5. COMMITMENTS AND OTHER MATTERS
ENVIRONMENTAL MATTERS
RGS
NEW YORK INITIATIVES
By letter dated May 25, 2000, the New York State Department of
Environmental Conservation ("NYSDEC") issued a Notice of Violation ("NOV") to
RG&E, asserting that certain "modifications" to Russell and Beebee Stations
during 1983-1987 resulted in a "significant increase in the capacity to emit
sulfur dioxide." The NOV alleges that, as a result, permits required by the
federal Clean Air Act and the State Environmental Conservation Law should have
been obtained by RG&E prior to beginning the "modifications." The NOV asserts
that RG&E may be liable for civil penalties of up to $10,000 per day, per
violation, as well as subjected to unspecified injunctive relief. The
allegations in the NOV are similar to those being made by the United States
Department of Justice, on behalf of the United States Environmental Protection
Agency, in enforcement cases relating to a number of electric utility coal-fired
power plants in the midwest and southeast. The NOV invited RG&E to request an
informal conference with the NYSDEC. Since July 2000, RG&E has had several such
informal meetings with the NYSDEC and NYS Office of the Attorney General. On the
merits of the allegation, RG&E does not believe it has engaged in prohibited
activities at either station.
The Governor of New York directed the NYSDEC to require electric generators
to further reduce acid rain-causing emissions. The Governor has proposed
extending the existing Nitrous Oxide ("NOx") control program under which RG&E's
Russell Station operates to a year-round program (it is currently in effect only
for the five-month ozone season). In addition, the Governor has proposed that
there be a targeted reduction of approximately 50% in Sulfur Dioxide ("SO2")
emissions below the existing Acid Rain Phase II limits. The state emission
reductions would be phased-in during 2003 and be complete in 2007. Since this is
only a proposed change, and subject to review, comment, and modification, RG&E
is in the process of estimating the economic impact on it of the proposed
reductions.
RG&E-OWNED WASTE SITE ACTIVITIES
RG&E is conducting proactive Site Investigation and/or Remediation ("SIR")
efforts at eight Company-owned sites where past waste handling and disposal may
have occurred. Remediation activities at five of these sites are in various
stages of planning or completion and the Company is investigating the other
three sites. RG&E has recorded a total liability of approximately $21.9 million
which it anticipates spending on SIR efforts at the eight Company-owned sites.
Through March 31, 2001, the Company has incurred aggregate costs of $7.8 million
for these sites.
MANUFACTURED GAS PLANTS ("MGPs")
RG&E and its predecessors formerly owned and operated four manufactured gas
facilities and acquired (following cessation of MGP operations) two others for
which SIR costs are estimated to be approximately $20 million. RG&E estimates
that SIR costs at one of these sites known as East Station may
18
be as much as $14.5 million. These properties are in various stages of
investigation and remediation and RG&E is coordinating its activities with the
NYSDEC.
SUPERFUND AND NON-OWNED OTHER SITES
RG&E has been or may be associated as a potentially responsible party at
nine sites not owned by it and has recorded estimated liabilities of
approximately $0.5 million in connection with SIR efforts at these sites. RG&E
has signed orders of consent for five of these sites. RG&E's ultimate exposure
will depend on the final determination of RG&E's contribution to the waste at
these sites and the financial viability of the other potential responsible
parties at these sites.
In June, 1999, RG&E was named as a codefendant in a legal action brought by
a party who purchased a portion of its Ambrose Yard property. The party has
claimed that the RG&E's historic activities on the property resulted in the
presence of residual contaminants that have adversely impacted the party's use
of the property. RG&E is just beginning to investigate the claim and does not
know whether the claim has any merit. There is insufficient information
available at this time to predict the economic impact of the claim on RG&E.
UNREGULATED FACILITIES
RGS's subsidiary, Energetix, acquired Griffith in 1998. A review and audit
was conducted of all Griffith facilities by a nationally recognized engineering
firm as part of the due diligence acquisition process by Energetix. As a result
of this review 35 sites were identified which are currently undergoing
evaluation and/or remediation. Using historical NYSDEC remedial actions as a
guide, Griffith estimates the present value of future aggregate cleanup costs
for all active sites to be approximately $1.5 million, and has recorded an
accrual to reflect this liability.
The previous owner of Griffith is obligated under the purchase agreement to
pay for environmental claims or remedial action on Griffith property once the
amount of environmental losses incurred by Energetix exceeds $3.5 million less
any reserve reflected on the balance sheet at the time of acquisition. As of
March 31, 2001 approximately $1.3 million has been spent and it is estimated
$1.5 million will be spent in the future.
In November 2000, Griffith acquired both Burnwell(R) Gas ("Burnwell") and
certain assets of the New York Fuels Division of AllEnergy Marketing Company,
L.L.C. Griffith had Phase I and Phase II environmental investigations performed
by a nationally recognized engineering firm on all ten Burnwell properties and
identified ten items requiring some type of remedial measures. With regard to
the AllEnergy acquisition, Griffith reviewed Phase I and Phase II environmental
reports provided by AllEnergy, together with the investigative reports prepared
by independent consulting firms during the prior two years. As a result of
certain identified environmental conditions, a $1.5 million accrual (on a
discounted basis) has been established for AllEnergy and Burnwell. As of March
31, 2001 no environmental expenses have been incurred for AllEnergy and
Burnwell. Energetix estimates that $1.6 million will be spent in the future.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
The following is management's assessment of certain significant factors
affecting the financial condition and operating results of RGS Energy Group,
Inc. ("RGS" or "Company") and its subsidiaries over the past three months. The
Consolidated Financial Statements and the Notes thereto contain additional data.
For the three months ended
March 31, 2001, 38 percent of the Company's operating revenues were derived from
electric service, 33 percent from natural gas service, and 29 percent from
unregulated businesses.
19
FORWARD LOOKING STATEMENTS
The discussion presented below contains statements that are not historic
fact and which can be classified as forward looking. These statements can be
identified by the use of certain words that suggest forward looking information,
such as "believes," "will," "expects," "projects," "estimates" and
"anticipates". They can also be identified by the use of words that relate to
future goals or strategies. In addition to the assumptions and other factors
referred to specifically in connection with the forward looking statements, some
of the factors that could have a significant effect on whether the forward
looking statements ultimately prove to be accurate include:
(1) uncertainties related to the regulatory treatment of Rochester Gas and
Electric's ("RG&E's") nuclear generation facilities including the proposed
sale of RG&E's interest in the Nine Mile Two nuclear generating facility;
(2) any state or federal legislative or regulatory initiatives (including the
results of negotiations between RG&E and the PSC regarding certain gas
restructurings) that affect the cost or recovery of investments necessary
to provide utility service in the electric and natural gas industries.
Such initiatives could include, for example, changes in the regulation of
rate structures or changes in the speed or degree to which competition
occurs in the electric and natural gas industries;
(3) any changes in the ability of RG&E to recover environmental compliance
costs through increased rates;
(4) the determination in the nuclear generation proceeding initiated by the
PSC, including any changes in the regulatory status of nuclear generating
facilities and their related costs, including recovery of costs related to
spent fuel and decommissioning;
(5) fluctuations in energy supply and demand and market prices for energy,
capacity and ancillary services;
(6) any changes in the rate of industrial, commercial and residential growth in
RG&E's and RGS's service territories;
(7) the development of any new technologies which allow customers to generate
their own energy or produce lower cost energy;
(8) any unusual or extreme weather or other natural phenomena;
(9) the timing and extent of changes in commodity prices and interest rates;
(10) the ability of RGS to manage profitably new unregulated operations;
(11) certain unknowable risks involved in operating unregulated businesses in
new territories and new industries;
(12) risks associated with the proposed merger of RGS with and into Eagle
Merger Corp., that will be a wholly owned subsidiary of Energy East
Corporation ("Energy East"), a New York corporation at the effective time
of the merger, and if the merger is completed, the integration of RGS and
Energy East; and
(13) any other considerations that may be disclosed from time to time in the
publicly disseminated documents and filings of RGS and RG&E.
20
Shown below is a listing of the principal items discussed:
RGS ENERGY GROUP, INC. Pages 20 - 21
Unregulated Subsidiaries
ROCHESTER GAS AND ELECTRIC CORPORATION
Competition Pages 21 - 27
Gas Retail Access Settlements
Gas Retail Access Program
PSC Electric Settlement
Energy Choice
Nine Mile Nuclear Plants
New York Independent System Operator
Prospective Financial Position
Rates and Regulatory Matters Pages 27 - 28
PSC Gas Restructuring Policy Statement
FERC Gas Market Proposals
FERC Electric Restructuring Order
LIQUIDITY AND CAPITAL RESOURCES Pages 28 - 29
Merger Agreement
Capital and Other Requirements
Financing
Redemption of Securities
EARNINGS SUMMARY Page 30
RESULTS OF OPERATIONS Pages 30 - 31
Operating Revenues and Sales
Operating Expenses
Other Statement of Income Items
DIVIDENDS Pages 31 - 32
RGS ENERGY GROUP, INC.
- ----------------------
RGS is a holding company and not an operating entity. RGS's operations are
being conducted through its subsidiaries which include RG&E and two unregulated
subsidiaries - RGS Development Corporation ("RGS Development") and Energetix,
Inc. ("Energetix")
RG&E offers regulated electric and natural gas utility service in its
franchise territory. Energetix, Inc. provides energy products and services
throughout upstate New York. RGS Development Corporation offers energy systems
development and management services.
UNREGULATED SUBSIDIARIES
Part of RGS's financial strategy is to seek growth by entering into
unregulated businesses. The Electric Settlement allows RG&E to provide the
funding for RGS to invest up to $100 million in unregulated
21
businesses and RGS has invested $76 million (including loan guarantees) as of
March 31, 2001. The first step in this direction was the formation and
operation of Energetix, Inc. effective January 1, 1998. Energetix is an
unregulated subsidiary that brings energy products and services to the
marketplace both within and outside of RG&E's regulated franchise territory.
Energetix markets electricity, natural gas, oil, gasoline, and propane fuel
energy services throughout Upstate New York. Energetix has approximately 89,000
customers for natural gas and electricity service.
In August 1998, Energetix acquired Griffith Oil Company, Inc. ("Griffith"),
the second largest oil and propane distribution company in New York State. This
$31.5 million acquisition was accounted for using purchase accounting and the
results of Griffith's operations are reflected in the consolidated financial
statements of RGS since its acquisition.
In November 2000, Griffith acquired Burnwell(R) Gas ("Burnwell"), a full-
service propane gas retailer and distributor providing fuel, appliances, heating
equipment and service in the Western New York area. This acquisition adds
29,000 customers to the Griffith customer base. The acquisition was accounted
for using purchase accounting and Burnwell's results of operations are reflected
in the consolidated financial statements of RGS since the acquisition.
In November 2000, Griffith also acquired certain assets of the New York
Fuels Division of AllEnergy Marketing Company, L.L.C. ("AllEnergy") related to
its petroleum distribution business. This acquisition adds 24,000 customers to
the Griffith customer base. The acquisition was accounted for using purchase
accounting and the results of the acquired operations are reflected in the
consolidated financial statements of RGS since the acquisition.
Griffith and its recent acquisitions as discussed above give Energetix
access to over 123,000 customers, approximately 100,000 of whom are outside of
RG&E's regulated franchise territory. In total, Griffith had approximately 620
employees and operated 28 customer service centers as of March 31, 2001.
Additional information on Energetix's operations (including Griffith) is
presented under the headings Operating Revenues and Sales and Operating
Expenses.
During the second quarter of 1998, the Company formed RGS Development to
pursue unregulated business opportunities in the energy marketplace. Through
March 31, 2001, RGS Development's operations have not been material to RGS's
results of operations or its financial condition.
ROCHESTER GAS AND ELECTRIC CORPORATION
- --------------------------------------
COMPETITION
Gas Retail Access Settlements
On January 25, 2001, RG&E reached agreement with the New York State Public
Service Commission ("PSC") Staff and other parties on a comprehensive rate and
restructuring proposal for its natural gas business (the "Gas Rates and
Restructuring Proposal"), as contemplated in the PSC's Restructuring Policy
Statement issued November 3, 1998, with modifications, the Proposal was approved
by the PSC on February 28, 2001. For a description of the Gas Rates and
Restructuring Proposal, together with the modifications made by the PSC, see the
discussion under Note 4 of the Notes to Financial Statements under the heading
"Gas Retail Access Settlements".
Pursuant to the Capacity Incentive Program ("CIP") established by the Gas
Rates and Restructuring Proposal, RG&E, as of April 1, 2001, has released all of
its ANR Pipeline Company ("ANR") and Great Lakes Gas Transmission Limited
Partnership ("Great Lakes") transportation and storage capacity through March
31, 2004. To maintain the necessary level of service that had been provided by
the ANR and Great Lakes facilities, RG&E entered into an agreement with Union
Gas Limited ("Union") for storage service at facilities in
22
southern Ontario, Canada. Recovery by RG&E of the costs resulting from the new
storage contract with Union, as well as the recovery of the difference between
the cost to the gas marketers of the released service and the amount received
from the replacement shipper, will be subject to the CIP.
Gas Retail Access Program
On December 1, 2000, RG&E implemented the single-retailer system for small
volume gas customers, following the approval of a tariff filing with the PSC.
Under the June 2000 Gas Settlement discussed in Note 4 of the Notes to the
Financial Statements under the heading "Gas Retail Access Settlements", RG&E is
permitted to recover the difference between the backout credit paid marketers
($3.75 per customer per month) and RG&E's short-run avoided costs associated
with the migration of gas sales customers to retail access under the single
retailer system. For purposes of the June 2000 Gas Settlement, this assumed
difference was set at $2.55 per customer per month. Both the backout credit and
the assumed difference are to remain in effect at these levels over the term of
the Settlement (generally through June 30, 2002), subject to possible further
negotiations in the event of a particularly rapid migration of customers.
On April 1, 2001, RG&E also implemented the single-retailer model program
for large volume gas customers. With this transition completed, all small and
large volume retail customers are now eligible to participate under the single
retailer model.
As of May 1, 2001, twenty energy service companies, including Energetix,
are qualified by RG&E to serve retail gas customers under RG&E's Gas Retail
Access Program.
RG&E attempts to mitigate its risks of energy marketer defaults by
requiring security deposits as permitted by PSC Transportation Gas Customer
Tariffs.
PSC Electric Settlement
During 1996 and 1997, RG&E, the staff of the PSC and several other parties
negotiated an agreement which was approved by the PSC in November 1997
("Electric Settlement"). The Electric Settlement sets the framework for the
introduction and development of open competition in the electric energy
marketplace and lasts through June 30, 2002. In phases, RG&E will allow
customers to purchase electricity, and later capacity commitments, from sources
other than RG&E through its retail access program, Energy Choice. These energy
service companies will compete to package and sell energy and related services
to customers. The competing energy service companies will purchase distribution
services from RG&E who will remain the sole provider of distribution services,
and will be responsible for maintaining the distribution system and for
responding to emergencies.
The Electric Settlement sets RG&E's electric rates for each year during its
five-year term. Over the five-year term of the Electric Settlement, the
cumulative rate reductions for the bundled service will be as follows: Rate Year
1 (July 1, 1997 to June 30, 1998) $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 $64.6 million.
In the event that RG&E earns a return on common equity in its regulated
electric business in excess of an effective rate of 11.50 percent over the
entire five-year term of the Electric Settlement, 50 percent of such excess will
be used to write down deferred costs accumulated during the term of the Electric
Settlement. Any remaining amounts of this 50 percent will be retained as
earnings by RG&E. The other 50 percent will be used to write down accumulated
deferrals or investment in electric plant or regulatory assets. If certain
extraordinary events occur, including a rate of return on common equity below
8.5 percent or above 14.5 percent, or a pretax interest coverage below 2.5
times, then either RG&E or any other party to the Electric Settlement would have
the right to petition the PSC for review of the Electric Settlement and
appropriate remedial action.
The Electric Settlement requires unregulated energy retailing operations to
be structurally separate
23
from the regulated utility functions. Although the Electric Settlement provides
incentives for the sale of generating assets, it does not require RG&E to divest
generating or other assets or to write off stranded costs. RG&E believes that
the Electric Settlement has not adversely affected its eligibility to continue
to apply certain accounting rules applicable to regulated industries. In
particular, RG&E believes it continues to be eligible for the treatment provided
by the Statement of Financial Accounting Standards accounting for the effects of
certain types of regulation ("SFAS-71"), which allows RG&E to include assets on
its balance sheet based on its regulated ability to recoup the cost of those
assets. The Electric Settlement provides RG&E a reasonable opportunity to
recover substantially all of its prudently incurred costs, except certain
operational costs associated with non-nuclear generation.
RG&E's electric retail access program, Energy Choice, was approved by the
PSC as part of the Electric Settlement and went into effect on July 1, 1998.
Details of the Energy Choice Program are discussed below.
Energy Choice
On July 1, 1998, RG&E officially began implementation of its full-scale
electric retail access Energy Choice program. As of July 1, 2000, RG&E entered
its third year of this program. There are five basic components of the sale of
energy as follows:
(1) the sale of electricity which is the amount of energy actually used by the
consumer;
(2) the sale of capacity which is the ability, through generating facilities or
otherwise, to provide electricity when it is needed;
(3) the sale of transmission services, which is the physical transportation of
electricity to RG&E's distribution system;
(4) the sale of distribution services, which is the physical delivery of
electricity to the consumer over RG&E's distribution system; and
(5) retail services such as billing and metering.
Historically, RG&E has sold all five components bundled together for a fixed
rate approved by the PSC.
The implementation of Energy Choice included a four year phase-in process
to allow RG&E and other parties to manage the transition to electric competition
in an orderly fashion. During the first year of the program, participation in
Energy Choice was limited to no more than 10 percent of RG&E's total annual
retail electric kilowatt-hour sales (670,000 annualized megawatt-hours).
Essentially, until this 10 percent limit was achieved, RG&E's electric retail
customers could seek out or be approached by alternative energy service
companies for electricity to be resold and then delivered over RG&E's
distribution system. By February 1, 1999, only six months into the Energy
Choice program, this 10 percent limit was achieved by qualified competitive
energy service companies in RG&E's service territory. For the second year of the
program, beginning July 1, 1999, this limit increased from 10 percent to
approximately 20 percent. As of July 1, 2000, beginning the third year of the
program, this limit increased to 30 percent. As of May 1, 2001, approximately 24
percent of total RG&E sales had shifted to competitive energy service companies,
including the Company's unregulated subsidiary Energetix. Beginning July 1,
2001, all retail customers will be eligible to purchase energy, capacity and
retailing services from competitive energy service companies. Throughout the
term of the Electric Settlement, RG&E will continue to provide regulated and
fully bundled electric service under its retail service tariff to customers who
choose to continue with such service.
Energy Choice adopted the single-retailer model for the relationship
between RG&E as the distribution provider, qualified energy service companies,
and retail (end-use) customers. In this model, retail
24
customers have the opportunity for choice in their energy service company and
receive only one electric bill from the company that serves them. Except for
providing emergency services, satisfying requests for distribution services, and
scheduling outages, which remain RG&E's responsibility, the retail customer's
primary point of contact for billing questions, technical advice and other
energy-related needs, is with the customer's chosen energy service company.
Under the single-retailer model, energy service companies are responsible
for buying or otherwise providing the electricity their retail customers will
use, paying regulated rates for transmission and distribution, and selling
electricity to their retail customers (the price of which would include the cost
of the electricity itself and the cost to transport electricity through RG&E's
distribution system).
RG&E attempts to mitigate its risks of energy marketer defaults by
requiring security deposits as permitted by PSC Electric Distribution Customer
tariffs.
As of May 1 , 2001, six energy service companies, including Energetix, were
qualified by RG&E to serve retail customers under Energy Choice.
During the initial Energy-Only stage of the Energy Choice program, which
began on July 1, 1998 and ended on November 18, 1999, energy service companies
were able to choose their own sources of energy supply, while RG&E continued to
provide to them, through its bundled distribution rates, the generating capacity
("installed reserve") needed to serve their retail customers. In addition,
during the Energy-Only stage, energy service companies had the option of
purchasing "full-requirements" (i.e., delivery services plus energy) from RG&E.
During the initial Energy-Only stage of the retail access program, RG&E's
distribution rate was set by deducting a fixed energy backout credit of
approximately 2.31 cents per kilowatt-hour from its full service (bundled)
rates. The 2.31 cents per kilowatt-hour was comprised of 1.91 cents per
kilowatt-hour (an estimate of the wholesale market price of electricity) plus
0.40 cents per kilowatt-hour for RG&E's avoided cost of retailing services.
During the Energy and Capacity stage, which began on November 18, 1999,
RG&E's distribution rates equaled the bundled rate less RG&E's cost of both the
electric commodity and its non-nuclear generating capacity. Throughout this
stage of the program, up until June 30, 2000, RG&E's distribution rates were set
by deducting a fixed energy and capacity backout credit of 3.07 cents per
kilowatt-hour from its full service rates. The 3.07 cents per kilowatt-hour is
comprised of 2.67 cents per kilowatt-hour (an estimate of the wholesale market
price of electric energy and capacity) plus 0.40 cents per kilowatt-hour for its
avoided cost of retailing services. Beginning July 1, 2000, RG&E's distribution
rates were set by deducting 3.08 cents per kilowatt-hour from its full service
rates. The 3.08 cents per kilowatt-hour is comprised of 2.68 cents per kilowatt-
hour for energy and capacity plus 0.40 cents per kilowatt-hour for its avoided
cost of retailing services. This change in the distribution rates, set by
deducting 3.07 cents per kilowatt-hour and then 3.08 cents per kilowatt-hour, is
a result of pre-determined changes in average gross receipts taxes.
The Energy and Capacity stage, the second stage of the phase-in, began with
the implementation of the New York Independent System Operator on November 18,
1999 (see discussion under "New York Independent System Operator"). The
responsibility for purchasing not only energy, but also capacity, was to have
shifted to the energy service companies. However, the PSC and Federal Energy
Regulatory Commission ("FERC") had also approved a request by RG&E to extend
"full-requirements" availability to energy service companies through the current
winter capability period (from October 31, 2000 through April 30, 2001). All
energy service companies serving customers under retail access opted to continue
purchasing "full requirements" through the current winter capability period.
25
Through April 30, 2001, energy service companies will have the option to
serve a portion or all of their load from the competitive wholesale market, but
once they make this change, they will not be able to return this load to "full
requirements". Once RG&E no longer provides "full requirements" to the energy
service companies, they will assume responsibility for obtaining their own
supplies. RG&E will experience a revenue decrease when it no longer collects the
rates described above for energy and capacity. This will be offset to some
extent by decreased costs resulting from no longer acquiring energy and capacity
for the energy service companies. The extent of this offset will be determined
by market prices.
On March 29, 2001 the PSC approved a joint proposal among RG&E and several
other parties including the Staff of the PSC, which would replace the fixed
energy and capacity backout credit with one that varies based on the market
price of energy, installed capacity, ancillary services, and the NYPA
Transmission Adjustment Charge ("NTAC"). This new backout credit will become
effective May 1, 2001. The backout credit will initially be based on projected
prices and will be trued-up to actual prices after they are known. RG&E could
experience a decrease in distribution revenues from energy service companies if
the market-based backout credit is greater than the previous fixed backout
credit, but this decrease should be completely offset by increased revenues from
the sale into the market at market prices (or avoidance of purchases from the
market at market prices) of the energy, capacity, ancillary services and NTAC
that RG&E is no longer selling to the energy services companies. As part of the
joint proposal, RG&E will continue to offer "full requirements" service to
energy services companies who elect such option.
Throughout the remaining term of the Settlement, through June 30, 2002,
energy service companies will continue to have the option to serve a portion or
all of their load from the competitive marketplace, but once they make this
change, they will not be able to return this load to "full requirements". As of
May 1, 2001, all but one qualified energy service company serving customers
under retail access have opted to continue purchasing "full requirements". The
other energy service company has opted for the new market-based backout credit
described above.
In December 1999, two petitions were filed with the PSC, one by an electric
utility operating in New York State and the other jointly by five energy
marketers and consultants, calling upon the PSC to examine RG&E's retail access
program and to order certain changes in the program. In particular, these
petitioners objected to the single-retailer form of RG&E's program, under which
the retail marketer assumes responsibility for most retail service functions.
They claim that the "backout credit" (the amount by which RG&E's rates for
retail electric service are reduced to derive the rates charged for the delivery
service provided by RG&E to marketers) is too low, that it affords insufficient
prospect of profitable operation by marketers, and that it should be increased.
They further assert that the phased schedule for implementation of the program,
under which increasing percentages of customers in RG&E's service area are
eligible to obtain competitive service during the term of the Electric
Settlement, is too slow and should be significantly accelerated. On February 28,
2000 RG&E filed with the PSC its reply to both petitions. As set forth in that
reply, RG&E believes that its single-retailer program offers unique
opportunities for marketers, that its retail backout credit (in conjunction with
RG&E's rate for wholesale power sales to marketers) affords a sound basis for
competitive service, and that its implementation schedule is reasonable and
appropriate; moreover, each of these essential elements of the retail access
program is expressly established by the Electric Settlement. RG&E believes that
the program fully and fairly advances the goals of increased competition for
energy services and is in full compliance with the Electric Settlement.
Nevertheless, it is not possible at this time to predict with assurance whether
or not, in response to the petitions, the PSC might require that the program be
changed in some manner.
The PSC is conducting proceedings that are intended to bring more
administrative consistency among New York State utilities and potentially offer
additional services for energy service companies to provide. These include an
on-going national effort regarding uniform business practices, and proceedings
regarding standardized billing (single billing options), provider of last
resort, electronic data interchange, and competitive metering. RG&E continues to
assess the scope and impact of such changes on its operations as retail access
continues to evolve.
26
Nine Mile Nuclear Plants
On December 11, 2000, RG&E, Niagara Mohawk, Central Hudson and NYSEG
entered into an agreement to sell their ownership interests in Nine Mile Two
(and in the case of Niagara Mohawk, Nine Mile One) to Constellation Nuclear,
L.L.C. ("Constellation Nuclear"). Constellation Nuclear was the successful
bidder in a competitive auction conducted for the plants. The Long Island Power
Authority, an 18 percent owner of Nine Mile Two, is not participating in the
sale.
For further discussion and details on this transaction including the events
leading up to this point, see Note 3 to the Financial Statements under the
heading "Nuclear Related Matters".
New York Independent System Operator
In November 1999 following FERC approval, the New York State Independent
System Operator ("NYISO") sought to implement a competitive wholesale market for
the sale, purchase and transmission of electricity and ancillary services in New
York State. NYISO tariffs provide market-based rates for energy, ancillary
services, and installed capacity sold through the NYISO. The NYISO and the New
York State Reliability Council were formed to restructure the New York Power
Pool in response to FERC Order 888.
In early 2000, the NYISO's total cost of providing operating reserves on an
hourly basis exceeded the cost that would be expected in a workable competitive
marketplace. During the first quarter of 2000, RG&E, in addition to other New
York State public utilities and several load-serving entities, experienced
rising prices to maintain operating reserves within the NYISO system. As a
result of, among other things, the implementation of bidding restrictions that
limit reserve prices, as discussed in the following two paragraphs, the average
cost per MWH for operating reserves continued to decline from last quarter.
On March 27, 2000, the NYISO filed with FERC for immediate authority to
suspend the use of market-based bids in the New York markets for operating
reserves. On April 7, 2000, RG&E also filed a complaint with FERC against the
NYISO. RG&E sought corrective re-calculation of operating reserve prices for
prior periods and prospective relief from injuries resulting from the NYISO's
operating reserves market. Niagara Mohawk and NYSEG filed similar complaints
with FERC against the NYISO. On May 31, 2000 FERC issued an order accepting the
NYISO's request and capped prices for the 10-minute non-spinning reserve market
at $2.52/MWH. In response to various complaints, FERC directed the NYISO to
permit self-supply of operating reserves and file a plan to correct software
problems inhibiting self-supply by September 1, 2000. However, FERC denied the
requests by RG&E and Niagara Mohawk for retroactive rate relief. On June 30,
2000, RG&E filed a request for rehearing seeking, in part, retroactive rate
relief for operating reserve overpayments. This request is currently pending
with FERC.
As directed by FERC, on September 1, 2000 the NYISO made a comprehensive
compliance filing addressing a number of compliance issues, including operating
reserves issues. Because the filing did not, in violation of FERC orders,
permit self-supply of operating reserves, RG&E filed a protest of the compliance
filing. RG&E also protested a new proposal made by the NYISO to pay suppliers
of operating reserves prices based on whether the supplier is located in the
west, east or on Long Island, while charging purchasers of operating reserves a
single, state-wide rate. On November 8, 2000, FERC issued an order extending
the existing bid cap of $2.52/MWH (plus opportunity costs) until such time as
FERC determines that the non-spinning reserve markets are demonstrated to be
workably competitive. FERC again stressed the requirement that the NYISO permit
self-supply of operating reserves. FERC suspended the proposal on pricing of
operating reserves based on location for the maximum 5-month period. FERC
established a technical conference, which was held on January 22 and 23, 2001,
to deal with market flaws and market performance in the NYISO, including
operating reserves issues. On March 28, 2001 FERC issued an order that will
permit the NYISO to implement its locational pricing system as filed. FERC has
not yet acted on the other issues that were the subject of the technical
conference. At the present time, RG&E cannot predict what effects, if any,
action ultimately taken by FERC on these issues will have on future operations
or on the financial condition of RGS or RG&E.
27
Competition and the Company's Prospective Financial Position
With PSC approval, RG&E has deferred certain costs rather than recognize
them on its statement of income 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 SFAS-71. These deferred
costs are shown as Regulatory Assets on the Company's and RG&E's Balance Sheet
and a discussion and summary of such Regulatory Assets is presented in Note 4 of
the Notes to Financial Statements.
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. Estimates of
strandable assets are highly sensitive to the competitive wholesale market price
assumed in the estimation. In a competitive natural gas market, strandable
assets would arise where customers migrate away from dependence on RG&E for full
service, leaving RG&E with surplus pipeline and storage capacity, as well as
natural gas supplies under contract. For a discussion of strandable assets, see
Note 4 of the Notes to Financial Statements under the heading "Regulatory
Assets".
At March 31, 2001 RG&E believes that its regulatory assets are probable of
recovery. The Electric Settlement does not impair the opportunity of RG&E to
recover its investment in these assets. However, the PSC initiated a proceeding
in 1998 to address issues surrounding nuclear generation (see Note 3 to the
Financial Statements under the heading "Nine Mile Nuclear Plants"). The
ultimate determination in this proceeding or any proceeding to consider RG&E's
proposed sale of Nine Mile Two as discussed under that heading could have an
impact on strandable assets and the recovery of nuclear costs.
RATES AND REGULATORY MATTERS
PSC Gas Restructuring Policy Statement
On November 3, 1998, the PSC issued a gas restructuring policy statement
("Gas Policy Statement") announcing its conclusion that, among other things, the
most effective way to establish a competitive gas supply market is for gas
distribution utilities to cease selling gas. The PSC established a transition
process in which it addressed three groups of issues: (1) individual gas utility
plans to implement the PSC's vision of the market; (2) key generic issues to be
dealt with through collaboration among gas utilities, marketers, pipelines and
other stakeholders, and (3) coordination of issues that are common to both the
gas and the electric industries. The PSC has encouraged settlement negotiations
with each gas utility pertaining to the transition to a fully competitive gas
market. RG&E, the PSC Staff and other interested parties engaged in settlement
discussions in response to the specific requirements of the Gas Policy
Statement. In January 2001, RG&E reached agreement with PSC Staff and other
parties on a comprehensive rate and restructuring proposal for its natural gas
business, as contemplated in the PSC's Gas Policy Statement (See "Gas Retail
Access Settlements").
FERC Gas Market Proposals
On February 9, 2000, FERC issued Order No. 637, its final rule addressing
"Regulation of Short-Term Natural Gas Transportation Services" and "Regulation
of Interstate Natural Gas Transportation Services". On June 5, 2000 FERC issued
Order No. 637-A providing clarification and additional guidance. On July 26,
2000 FERC issued Order No. 637-B upholding Orders No. 637 and No. 637-A. Order
No. 637 as clarified revises FERC's regulations to improve the efficiency of the
gas transportation market and to provide captive customers with the opportunity
to reduce their cost of holding long-term pipeline capacity. Specifically, Order
No. 637, as clarified:
(1) waives the price ceiling for released capacity of less than one year
until September 30, 2002;
(2) permits pipelines to propose peak, off-peak and term differentiated
rates, provided that they still satisfy the revenue and cost constraints of
traditional rate-making, and excess revenues are split with firm customers;
28
(3) revises FERC's regulations on scheduling procedures, capacity
segmentation and pipeline penalties;
(4) states that the right of first refusal will apply in the future to
contracts for 12 consecutive months or more of service at maximum rates;
and
(5) amends and supplements reporting requirements to require interstate
pipelines to report additional information on transactions, operationally
available capacity, and an expanded index of customers.
Order No. 637 as clarified requires each pipeline to make a compliance
filing. All of the pipelines' initial compliance filings were submitted to FERC
by August 15, 2000. FERC has established technical and settlement conference
procedures for many of the pipelines, including those on which RG&E holds
transportation capacity. FERC staff has indicated at the respective pipeline
settlement and technical conferences that no action on various pipeline
proposals will be taken prior to April 2001, after the heating season has ended.
On March 30, 2001 Dominion Transmission became the first pipeline upon which
RG&E holds capacity to file a 637 settlement with the FERC. It is not known when
FERC will respond.
Neither RGS nor RG&E can predict what effects, if any, FERC's initiatives
and the related pipeline tariff changes will have on future operations or the
financial condition of RGS or RG&E.
FERC Electric Restructuring Order No. 2000.
On December 15, 1999, FERC adopted Order No. 2000 (the "Rule"), a
significant action regarding electric industry restructuring which calls for
transmission owners to join regional transmission organizations ("RTOs"). The
RTOs will serve as umbrella organizations that will place all public utility
transmission facilities in a region under common control. The Rule required all
public utilities that own, operate or control interstate transmission facilities
to file by October 15, 2000 (or, for public utilities, like RG&E, already
participating in an ISO, by January 15, 2001), a proposal for an RTO, or,
alternatively, a description of any efforts made by the utility to participate
in an RTO.
On January 16, 2001, the NYISO and all the New York State public utilities
made a joint filing with FERC regarding the establishment of an RTO. In the
consensus filing, the parties submit that the NYISO meets the general
requirements of an RTO, and the NYISO agrees to make certain enhancements of its
structure and programs to benefit the markets. Minor modifications are proposed
to the governance structure and transmission planning, and the NYISO agrees to
coordinate more closely with other RTOs. On February 22, 2001, RG&E filed with
NYSEG supporting the January 16th filing, but asking FERC to explore the
functional and structural integration of the three existing Northeastern ISOs.
RG&E cannot predict what effect, if any, the ultimate ruling by FERC will
have on future operations or on the financial condition of the Company.
LIQUIDITY AND CAPITAL RESOURCES
- ---------------------------------
During the first three months of 2001, RGS's and RG&E's cash flow from
operations and short-term borrowings (see Statements of Cash Flows) provided the
funds for utility plant construction expenditures, and the payment of dividends.
Capital requirements of the Company during 2001 are anticipated to be satisfied
from the combination of internally generated funds, short-term credit
arrangements, and some external long-term financing. In addition, completion of
the Nine Mile Two sale would also provide additional funds as previously
discussed in Note 3 to the Financial Statements under the heading "Nine Mile
Nuclear Plants". Early in the second quarter, RG&E refinanced long-term
securities obligations (see Financing and Redemption of Securities below).
29
MERGER AGREEMENT
On February 20, 2001, RGS announced that it had entered into an Agreement
and Plan of Merger ("Merger Agreement"),dated as of February 16, 2001, with
Energy East, a New York corporation, and Eagle Merger Corp., a New York
corporation that will be a wholly owned subsidiary of Energy East at the
effective time of the merger ("Merger Sub"), pursuant to which RGS will be
merged with and into Merger Sub (the "Merger") and RGS will become a wholly
owned subsidiary of Energy East. As a result of the Merger, all of the
outstanding common stock of RGS will be exchanged for a combination of cash and
Energy East common stock valued at approximately $1.4 billion in the aggregate.
Energy East will also assume approximately $1.0 billion of RGS debt.
Under the Merger Agreement, subject to possible adjustments for tax
reasons, 45% of the RGS common stock will be converted into a number of shares
of Energy East common stock with a value of $39.50 per RGS share, subject to
restrictions on the maximum and minimum number of shares of Energy East common
stock to be issued, and 55% of the RGS common stock will be converted into
$39.50 in cash per RGS share. RGS shareholders will be able to specify the
percentage of the consideration they wish to receive in shares of Energy East
common stock and in cash, subject to proration.
The Merger is subject to, among other things, the approval of RGS
shareholders and Energy East shareholders, and the approvals of various
regulatory agencies, including the PSC, FERC, NRC and the Securities and
Exchange Commission ("SEC"). A Joint Petition by the parties to the Merger,
seeking approval of the PSC pursuant to Section 70 of the Public Service Law,
was filed on March 23, 2001. All regulatory approvals are expected to be
obtained in about 12 months.
CAPITAL AND OTHER REQUIREMENTS
RGS's and RG&E's capital requirements have related primarily to
expenditures for energy delivery, including electric transmission and
distribution facilities and gas mains and services as well as nuclear fuel,
electric production, the repayment of existing debt and the repurchase of
outstanding shares of Common Stock. RG&E has no further plans to install
additional baseload generation.
Capital requirements for the Company in 2001 are currently estimated at
$164 million, which is primarily designated for construction. RG&E's portion of
total construction requirements is $161 million. Approximately $31.2 million
had been expended for construction as of March 31, 2001, reflecting primarily
RG&E's expenditures for nuclear fuel and upgrading electric transmission and
distribution facilities and gas mains.
FINANCING
On April 6, 2001, RG&E issued $200 million of 6.95% First Mortgage Bonds,
Series TT, due 2011. The net proceeds from this financing are being used to
redeem RG&E's Series PP First Mortgage Bonds as described below and to retire
outstanding short term debt.
RG&E generally utilizes its credit agreements and unsecured lines of credit
to meet any interim external financing needs prior to issuing any long-term debt
securities. For information with respect to RGS's and RG&E's short-term
borrowing arrangements and limitations, see the combined 2000 Form 10-K of RGS
and RG&E, Item 8 under Note 10 of the Notes to Financial Statements. As
financial market conditions warrant, RG&E may also, from time to time, redeem
higher-cost senior securities.
REDEMPTION OF SECURITIES
On May 10, 2001, RG&E redeemed $100 million principal amount of 9 3/8%
First Mortgage Bonds, Series PP at a price of $104.47 plus accrued interest from
April 1, 2001 through the redemption date.
30
EARNINGS SUMMARY
- -----------------
RGS :
RGS reported higher earnings of $1.31 per common share for the first
quarter ended March 31, 2001, as compared to $1.07 per common share for the same
period in 2000. First quarter 2001 results were better than a year ago due
primarily to increased wholesale electric revenues and a positive earnings
contribution from its unregulated subsidiary, Energetix. First quarter positive
results were partially offset by electric and gas rate reductions, increased
purchase power expenses and costs associated with the proposed merger of RGS and
Energy East. The Company completed its share buy-back program in the fourth
quarter of 2000, which resulted in a reduction of average shares outstanding.
RGS continues to grow its unregulated business through its subsidiary,
Energetix, which provides electric, natural gas, and petroleum based energy
products and services throughout the Upstate New York region. Energetix's
operating revenues were $214 million in the first quarter of 2001, of which
sales from Griffith and its subsidiaries contributed approximately $150 million.
These Griffith revenues are included under "Other Revenues" on RGS's Income
Statement and primarily consists of the sale of liquid fuels. Energetix's
revenues for 2001 are expected to increase over 2000 levels as Energetix expands
its customer base and the operations from businesses recently acquired are
reflected for an entire year; although no assurance may be given that Energetix
will achieve net operating income for the year 2001.
RG&E:
Earnings for RG&E reflect the same issues discussed above for RGS except
that discussions relating to Energetix and merger costs are not applicable.
RESULTS OF OPERATIONS
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The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses for RGS (regulated and
unregulated business) and RG&E (regulated business), comparing the three-month
period ended March 31, 2001 to the three-month period ended March 31, 2000. The
operating results of the regulated business reflect RG&E's electric and gas
sales and services and the operating results of the unregulated business reflect
Energetix's operations. Currently, the majority of RGS's operating results
reflect the operating results of RG&E and the factors that affect operating
results for RG&E are the significant factors that affect comparable operating
results for RGS, unless otherwise noted.
THREE MONTHS ENDED MARCH 31, 2001 COMPARED TO THREE MONTHS ENDED MARCH 31, 2000:
OPERATING REVENUES AND SALES
In the first quarter total revenues for RGS increased 31.6%, reflecting
higher wholesale electric sales and higher other revenues from Energetix due to
an aggressive expansion program during 2000 that included the acquisition of
eight petroleum companies. The increase in wholesale electric sales reflects
favorable market conditions and increased capacity to sell power in the
wholesale electric market due to the availability of RG&E's generation
facilities.
Revenues from a combination of regulated retail electric sales and sales
to energy marketers were down $2.3 million, reflecting mainly electric base rate
reductions implemented on July 1, 1999 and July 1, 2000.
Despite 8.0% colder weather on a heating degree day basis, gas revenues,
net of fuel expenses, were down for RGS and RG&E due to lower regulated gas
distribution rates and decreased customer consumption in response to higher gas
commodity prices.
Unregulated revenues, net of fuel, from the sale of liquid fuels by
Energetix, increased $10.1 million from the first quarter of 2000. Unregulated
first quarter income is generally driven by the seasonal nature of its heating
oil business. Compared to the first quarter of 2000, the liquid fuels volume
increased 40%. Seventy percent of Energetix's total operating revenues for the
first quarter 2001 were from the sale of fuel oil, propane and
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gasoline (see discussion under "Earnings Summary"). For heating oil and propane,
Energetix experiences seasonal fluctuations due to the dependence on
spaceheating sales during the heating season. However, the first quarter of 2001
also reflects the first full quarter of operations after completing an
aggressive expansion program in 2000 that included the acquisition of eight
petroleum companies, the largest of which were Burnwell and certain assets of
the New York Fuels division of AllEnergy, that closed in November of 2000.
Unregulated sales also reflect the migration of electric and gas customers from
the regulated to the unregulated business.
OPERATING EXPENSES.
Higher regulated fuel expenses reflect mainly higher unit cost for gas and
electricity purchased. The higher purchased electricity unit costs were
partially offset by the reduction in energy purchased due to the greater
availability of the RG&E generating units due mainly to the Nine Mile 2
refueling outage that occurred in the first quarter of 2000.
Higher unregulated fuel costs for RGS reflect mainly the increase in the
cost of fuel oil and gasoline in the first quarter of 2001 as compared to a year
ago.
The decrease in non-fuel regulated operating and maintenance expense for
both RGS and RG&E in the first quarter of 2001 reflects mainly a decrease in
electric transmission and wheeling charges by the NYISO (see discussion under
"New York Independent System Operator").
Unregulated non-fuel operating and maintenance expenses increased in the
current quarter compared to a year ago driven by the business acquisitions as
discussed earlier.
Local, State and other taxes for RGS and RG&E decreased reflecting mainly a
lower gross receipts tax and the elimination of the excess dividends tax.
The difference in income tax expense for RGS and RG&E is attributable to
pre-tax earnings and the inclusion of state income tax expense in 2001.
OTHER STATEMENT OF INCOME ITEMS.
The changes in RGS's Other Income and Deductions, Other-net reflect mainly
the costs associated with the proposed merger of RGS and Energy East (see
"Merger Agreement" under "Liquidity and Capital Resources").
Interest expense for both RGS and RG&E reflects higher interest costs on
short term debt due to increased borrowings in the first quarter of 2001
compared to a year ago. These interest charges were nearly offset by a
reduction of interest expense for certain radwaste obligations. Interest
expense for RGS also reflects the cost of a promissory note issued in November
2000 associated with the acquisition of Burnwell.
DIVIDENDS
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On March 21, 2001, the Board of Directors of RGS authorized a common stock
dividend of $.45 per share, which was paid on April 25, 2001 to shareholders of
record on April 2, 2001. Also on March 21, 2001, the Board of Directors of RG&E
declared dividends on its Preferred Stock at the regular rates per share payable
on June 1, 2001 to stockholders of record on May 1, 2001.
The ability of RGS to pay common stock dividends is governed by the ability
of RGS's subsidiaries to pay dividends to RGS. Because RG&E is by far the
largest of RGS's subsidiaries, it is expected that for the foreseeable future
the funds required by RGS to enable it to pay dividends will be derived
predominantly from the dividends paid to RGS by RG&E. In the future, dividends
from subsidiaries other than RG&E may also contribute to RGS's ability to pay
dividends. RG&E's ability to make dividend payments to RGS will depend upon the
availability of retained earnings and the needs of its utility business. RG&E's
Certificate of
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Incorporation provides for the payment of dividends on its common stock out of
the surplus net profits (retained earnings) of RG&E. In addition, pursuant to
the PSC order approving the formation of RGS, RG&E may pay dividends to RGS of
no more than 100% of RG&E's net income calculated on a two-year rolling basis.
The calculation of net income for this purpose excludes non-cash charges to
income resulting from accounting changes or certain PSC required charges as well
as charges that may arise from significant unanticipated events. This condition
does not apply to dividends that would be used to fund the remaining portion of
RG&E's $100 million authorization for unregulated operations (approximately $24
million at March 31, 2001)
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.
RG&E is exposed to interest rate and commodity price risks.
The interest rate risk relates to new debt financing needed to fund capital
requirements, including maturing debt securities, and to variable rate debt.
RG&E manages its interest rate risk through the issuance of fixed rate debt with
varying maturities and through economic refundings of debt through optional
redemptions. A portion of RG&E's long-term debt consists of long-term
Promissory Notes, the interest component of which resets on a periodic basis
reflecting current market conditions. See combined 2000 10-K of RGS and RG&E
"Note 6 - Long Term Debt". RG&E was not participating in any derivative
financial instruments to manage interest rate risk as of March 31, 2001.
The commodity price risk relates to market fluctuations in the price of
natural gas, electricity, and other petroleum-related products used for resale.
Commodity purchases and electric generation are based on projected demand for
power generation and customer delivery of electricity, natural gas and petroleum
products. RG&E enters into forward contracts for natural gas to hedge the
effect of price increases and reduce volatility on gas purchased for resale.
Owned electric generation significantly reduces RG&E's exposure to market
fluctuations in electric prices. RG&E does not hold open speculative positions
in any commodity for trading purposes.
RG&E's exposure to market price fluctuations of the cost of natural gas is
further limited as the result of the Gas Cost Adjustment, a regulatory mechanism
that transfers substantially all gas commodity price risk to the customer.
Nonetheless, RG&E hedges approximately 70% of its gas supply price through the
purchase of derivative contracts and the use of storage assets. The balance of
RG&E's natural gas requirements is procured through spot market purchases and is
subject to market price fluctuations.
Under the Electric Settlement, RG&E's electric rates are capped at
specified levels through June 30, 2002. As a result of owned generation and
long-term fixed rate supply contracts, RG&E is largely insulated from market
price fluctuations for procurement of its electric supply. In the event that
RG&E's generation assets fail to perform as planned, RG&E is exposed to market
price fluctuations. RG&E has hedging contracts in place to mitigate this risk.
Energetix has entered into electric and natural gas purchase commitments
with numerous suppliers. These commitments support fixed price offerings to
retail electric and gas customers.
Energetix, through its subsidiary Griffith, is in the business of
purchasing petroleum-related commodities for resale to its customers. To manage
the resulting market price risk, Griffith enters into various exchange-traded
futures and option contracts and over-the-counter contracts with third parties.
These contracts are closely monitored on a daily basis to manage the price risk
associated with inventory and future sales commitments.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to Notes 3, 4 and 5 of the Notes to Financial
Statements.
ITEM 5. OTHER INFORMATION
This year's annual meeting has been delayed so that the proposed merger
between RGS and Energy East can be acted upon at this year's annual meeting.
Because this year's annual meeting will be held more than 30 days after the
anniversary of last year's annual meeting, the date for submission of proposals
for inclusion in this year's proxy statement pursuant to Rule 14a-8 of the
Securities Exchange Act, as amended, was extended beyond the date specified in
last year's proxy statement. Proposals would have been eligible to have been
included in this year's proxy statement if they were received by RGS a
reasonable period of time prior to the printing and mailing of this year's proxy
statement. Because this year's proxy statement has already been printed and
mailed, the period for submission has already passed.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: See Exhibit Index below.
(b) Reports on Form 8-K:
RGS Energy Group, Inc.
A report was filed dated February 20, 2001, including under Item 5, other
events, an announcement that RGS had entered into an agreement and Plan of
Merger, dated as of February 16, 2001 between RGS, Merger Sub and Energy East.
Rochester Gas and Electric Corporation
A report was filed dated April 4, 2001 including under Item 7, Financial
Statements and Exhibits, certain exhibits relating to the issuance of RG&E's
6.95% First Mortgage Bonds, due 2011, Series TT.
EXHIBIT INDEX
Exhibit 10-1 (A) Agreement, effective February 21, 2001, between RGS, RG&E
and Paul C. Wilkens.
Exhibit 10-2 (A) Agreement, effective February 21, 2001, between RGS, RG&E
and Michael J. Bovalino.
Exhibit 10-3 (A) Agreement, effective February 21, 2001, between RGS, RG&E
and Michael T. Tomaino.
(A) Denotes executive compensation plans and agreements.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each of
the Registrants have duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
RGS ENERGY GROUP, INC.
----------------------
(Registrant)
Date: May 10, 2001 By /s/ Mark Keogh
------------------------------------
Mark Keogh
Treasurer
Date: May 10, 2001 By /s/ William J. Reddy
-----------------------------------
William J. Reddy
Controller
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: May 10, 2001 By /s/ Mark Keogh
------------------------------------
Mark Keogh
Vice President and Treasurer
Date: May 10, 2001 By /s/ William J. Reddy
------------------------------------
William J. Reddy
Vice President and Controller