SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 July 31, 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 - June 30, 2001 and
December 31, 2000........................................................................................ 1 - 2
Consolidated Statement of Income - Three Months and Six Months Ended
June 30, 2001 and 2000................................................................................... 3
Consolidated Statement of Cash Flows - Six Months
Ended June 30, 2001 and 2000............................................................................. 4
Rochester Gas and Electric Corporation
Balance Sheet - June 30, 2001 and December 31, 2000...................................................... 5 - 6
Statement of Income - Three Months and Six Months Ended
June 30, 2001 and 2000................................................................................... 7
Statement of Cash Flows - Six Months Ended
June 30, 2001 and 2000................................................................................... 8
Notes to Financial Statements............................................................................ 9 - 19
Management's Discussion and Analysis of Financial
Condition and Results of Operations...................................................................... 20 - 33
Quantitative and Qualitative Disclosures About
Market Risk.............................................................................................. 34
PART II - OTHER INFORMATION
Legal Proceedings........................................................................................ 35
Submission of Matters to a Vote of Security Holders...................................................... 36
Exhibits and Reports on Form 8-K......................................................................... 36
Signatures............................................................................................... 37
----------------
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)
June 30, December 31,
Assets 2001 2000
- -----------------------------------------------------------------------------------------------------
Utility Plant
Electric $2,494,765 $2,467,289
Gas 486,088 471,051
Common 176,613 164,872
Nuclear 292,454 292,588
---------- ----------
3,449,920 3,395,800
Less: Accumulated depreciation 1,795,933 1,750,493
Nuclear fuel amortization 263,168 254,435
---------- ----------
1,390,819 1,390,872
Construction work in progress 120,092 111,486
---------- ----------
Net Utility Plant 1,510,911 1,502,358
---------- ----------
Current Assets
Cash and cash equivalents 70,090 16,258
Accounts receivable, net of allowance for doubtful accounts:
2001 - $30,383; 2000 - $34,550 117,567 136,374
Unbilled revenue receivable 32,403 71,120
Fuels 20,980 46,868
Materials and supplies 7,696 8,187
Prepayments 25,828 26,268
Other current assets 17,604 2,292
---------- ----------
Total Current Assets 292,168 307,367
---------- ----------
Intangible Assets
Goodwill, net 26,251 27,971
Other intangible assets, net 20,719 22,614
---------- ----------
Total Intangible Assets 46,970 50,585
---------- ----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 248,540 244,514
Nine Mile Two deferred costs 26,630 27,155
Unamortized debt expense 23,753 16,602
Other deferred debits 3,533 4,673
Regulatory assets 396,042 412,790
Other assets 3,117 1,331
---------- ----------
Total Deferred Debits and Other Assets 701,615 707,065
---------- ----------
Total Assets $2,551,664 $2,567,375
---------- ----------
2
RGS ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEET
(Thousand of Dollars)
(Unaudited)
June 30, December 31,
Capitalization and Liabilities 2001 2000
- -------------------------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $ 579,711 $ 580,132
- promissory notes 209,782 211,703
Preferred stock redeemable at option of RG&E 47,000 47,000
Preferred stock subject to mandatory redemption 25,000 25,000
Common shareholders' equity
Common stock
Authorized 100,000,000 shares; 38,956,726 shares issued at
June 30, 2001 and December 31, 2000 704,304 702,807
Retained earnings 204,518 181,546
---------- ----------
908,822 884,353
Less: Treasury stock at cost (4,379,300 shares at June 30, 2001
and December 31, 2000) 117,238 117,238
---------- ----------
Total Common Shareholders' Equity 791,584 767,115
---------- ----------
Total Capitalization 1,653,077 1,630,950
---------- ----------
Long Term Liabilities
Nuclear waste disposal 99,620 97,291
Uranium enrichment decommissioning 9,885 9,649
Other promissory notes 28,149 32,025
Site remediation 24,605 24,420
---------- ----------
162,259 163,385
---------- ----------
Current Liabilities
Long term debt due within one year 112,094 12,095
Short term debt - 122,400
Accounts payable 91,772 108,618
Dividends payable 16,485 16,515
Other 73,785 57,491
---------- ----------
Total Current Liabilities 294,136 317,119
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 267,029 277,787
Pension costs accrued 14,910 26,547
Kamine deferred credit 48,618 51,920
Post employment benefits 56,664 54,505
Other 54,971 45,162
---------- ----------
Total Deferred Credits and Other Liabilities 442,192 455,921
---------- ----------
Total Capitalization and Liabilities $2,551,664 $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 Year to Date
Ended June 30, June 30,
2001 2000 2001 2000
-------- -------- -------- --------
OPERATING REVENUES
Electric $177,875 $174,021 $368,631 $353,805
Gas 58,237 57,253 224,662 176,821
Liquid fuels and other 112,325 79,430 262,923 165,929
======== ======== ======== ========
Total Operating Revenues 348,437 310,704 856,216 696,555
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 13,455 11,073 26,004 22,037
Purchased electricity 20,929 18,223 42,441 36,438
Gas purchased for resale 39,346 32,327 152,832 96,264
Unregulated fuel expenses 101,308 73,225 231,065 149,013
-------- -------- -------- --------
Total Fuel Expenses 175,038 134,848 452,342 303,752
-------- -------- -------- --------
Operating Revenues Less Fuel Expenses 173,399 175,856 403,874 392,803
Other Operating Expenses
Operations and maintenance excluding fuel 70,975 67,965 137,242 138,482
Unregulated operating and maintenance expenses excluding fuel 10,558 6,822 22,332 14,208
Depreciation and amortization 30,609 29,220 61,096 58,215
Taxes - state, local and other 21,878 19,862 49,554 49,688
Income taxes 9,650 16,834 40,301 43,401
-------- -------- -------- --------
Total Other Operating Expenses 143,670 140,703 310,525 303,994
-------- -------- -------- --------
Operating Income 29,729 35,153 93,349 88,809
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds used during construction (238) (188) (476) (379)
Income taxes 1,337 535 (55) 979
RGS/Energy East Merger Expenses 4,905 - 8,312 -
Other - net (2,955) 1,322 (3,076) 243
-------- -------- -------- --------
Total Other (Income) and Deductions 3,049 1,669 4,705 843
INTEREST CHARGES
Long term debt 16,101 14,617 30,258 29,082
Other - net 1,287 874 3,173 1,855
Allowance for borrowed funds used during construction (381) (302) (763) (608)
-------- -------- -------- --------
Total Interest Charges 17,007 15,189 32,668 30,329
-------- -------- -------- --------
Net Income 9,673 18,295 55,976 57,637
-------- -------- -------- --------
Preferred Stock Dividend Requirements 925 925 1,850 1,850
-------- -------- -------- --------
Net Income Applicable to Common Stock 8,748 17,370 54,126 55,787
-------- -------- -------- --------
Average Number of Common Shares (000's)
Common Stock 34,577 35,379 34,577 35,583
Common Stock and Equivalents 34,956 35,439 34,925 35,648
Earnings per Common Share - Basic $0.25 $0.49 $1.57 $1.57
Earnings per Common Share - Diluted $0.25 $0.49 $1.55 $1.56
Cash Dividends Paid per Common Share $0.45 $0.45 $0.90 $0.90
The accompanying notes are an integral part of the financial statements.
4
RGS ENERGY GROUP, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Six Months Ended
June 30,
- --------------------------------------------------------------------------------------------------------
2001 2000
--------- --------
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 55,976 $ 57,637
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 70,368 67,007
Deferred recoverable fuel costs 6,974 16,532
Income taxes deferred (6,120) (29,507)
Allowance for funds used during construction (1,239) (987)
Unbilled revenue 38,717 19,067
Post employment benefit/pension costs 1,724 3,055
Provision for doubtful accounts (4,167) 103
Changes in certain current assets and liabilities; net of
assets acquired and liabilities assumed in acquisitions:
Accounts receivable 22,974 (4,253)
Materials, supplies and fuels 26,379 318
Taxes accrued 11,210 6,645
Accounts payable (16,846) 8,301
Other current assets and liabilities, net (5,786) 15,153
Other, net (2,414) 10,781
--------- --------
Total Operating 197,750 169,852
--------- --------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (66,792) (65,605)
Nuclear generating plant decommissioning fund (10,336) (10,336)
Acquisitions, net of cash - (2,571)
Other, net (3,724) -
--------- --------
Total Investing (80,852) (78,512)
--------- --------
CASH FLOW FROM FINANCING ACTIVITIES
Redemption of long term debt (100,000) (30,000)
Proceeds from issuance of long-term debt, net 199,534 -
Repayment of promissory notes (6,964) 136
Short term borrowings, net (122,400) 1,250
Payments of dividends on preferred stock (1,850) (1,850)
Payments of dividends on common stock (31,120) (32,150)
Payment for treasury stock - (17,653)
Other, net (266) 600
--------- --------
Total Financing (63,066) (79,667)
--------- --------
Increase in cash and cash equivalents 53,832 11,673
Cash and cash equivalents at beginning of period 16,258 8,288
--------- --------
Cash and cash equivalents at end of period $ 70,090 $ 19,961
--------- --------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Six Months Ended
(Thousands of Dollars) June 30,
2001 2000
Adjustment to Goodwill 1,089 -
The accompanying notes are an integral part of the financial statements.
5
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
(Unaudited)
June 30, December 31,
Assets 2001 2000
- --------------------------------------------------------------------------------------------------------------------
Utility Plant
Electric $2,494,765 $2,467,289
Gas 486,088 471,051
Common 125,767 117,473
Nuclear 292,454 292,588
---------- ----------
3,399,074 3,348,401
Less: Accumulated depreciation 1,778,952 1,735,752
Nuclear fuel amortization 263,168 254,435
---------- ----------
1,356,954 1,358,214
Construction work in progress 120,092 111,486
---------- ----------
Net Utility Plant 1,477,046 1,469,700
---------- ----------
Current Assets
Cash and cash equivalents 57,915 4,851
Accounts receivable, net of allowance for doubtful accounts:
2001 - $29,482; 2000 - $33,482 88,279 93,130
Affiliate receivable 45,999 51,558
Unbilled revenue receivable 24,201 61,838
Fuels 12,313 33,896
Materials and supplies 7,696 8,187
Prepayments 24,602 23,782
Other current assets 28,007 -
---------- ----------
Total Current Assets 289,012 277,242
---------- ----------
Deferred Debits and Other Assets
Nuclear generating plant decommissioning fund 248,540 244,514
Nine Mile Two deferred costs 26,630 27,155
Unamortized debt expense 23,753 16,602
Other deferred debits 3,533 4,673
Regulatory assets 396,042 412,789
Other assets 1,988 -
---------- ----------
Total Deferred Debits and Other Assets 700,486 705,733
---------- ----------
Total Assets $2,466,544 $2,452,675
========== ==========
6
ROCHESTER GAS AND ELECTRIC CORPORATION
BALANCE SHEET
(Thousand of Dollars)
(Unaudited)
June 30, December 31,
Capitalization and Liabilities 2001 2000
- --------------------------------------------------------------------------------------------------------------------
Capitalization
Long term debt - mortgage bonds $ 579,711 $ 580,132
- promissory notes 209,782 211,703
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
June 30, 2001 and at December 31, 2000 700,318 700,318
Retained earnings 188,156 166,184
---------- ----------
888,474 866,502
Less: Treasury stock at cost (4,379,300 shares at June 30, 2001
and December 31, 2000) 117,238 117,238
---------- ----------
Total Common Shareholder's Equity 771,236 749,264
---------- ----------
Total Capitalization 1,632,729 1,613,099
---------- ----------
Long Term Liabilities
Nuclear waste disposal 99,620 97,291
Uranium enrichment decommissioning 9,885 9,649
Site remediation 22,356 22,356
---------- ----------
131,861 129,296
---------- ----------
Current Liabilities
Long term debt due within one year 104,149 4,227
Short term debt - 98,000
Accounts payable 70,332 79,356
Affiliate payable 17,830 18,451
Dividends payable to parent 16,485 16,515
Other 54,872 41,664
---------- ----------
Total Current Liabilities 263,668 258,213
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 263,429 274,299
Pension costs accrued 14,910 26,548
Kamine deferred credit 48,618 51,920
Post employment benefits 56,664 54,505
Other 54,665 44,795
---------- ----------
Total Deferred Credits and Other Liabilities 438,286 452,067
---------- ----------
Total Capitalization and Liabilities $2,466,544 $2,452,675
========== ==========
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 Year To Date
June 30, June 30,
2001 2000 2001 2000
-------- -------- -------- --------
OPERATING REVENUES
Electric $176,558 $171,272 $365,617 $347,979
Gas 49,858 55,293 190,965 169,436
-------- -------- -------- --------
Total Operating Revenues 226,416 226,565 556,582 517,415
OPERATING EXPENSES
Fuel Expenses
Fuel for electric generation 13,455 11,073 26,004 22,037
Purchased electricity 20,277 16,432 41,069 32,595
Gas purchased for resale 30,408 30,362 119,837 89,600
-------- -------- -------- --------
Total Fuel Expenses 64,140 57,867 186,910 144,232
-------- -------- -------- --------
Operating Revenues Less Fuel Expenses 162,276 168,698 369,672 373,183
Other Operating Expenses
Operations and maintenance excluding fuel 70,975 67,965 137,242 138,482
Depreciation and amortization 28,590 28,250 56,969 56,310
Taxes - state, local and other 21,230 18,901 47,253 47,485
Income taxes 10,956 17,488 38,491 42,633
-------- -------- -------- --------
Total Other Operating Expenses 131,751 132,604 279,955 284,910
-------- -------- -------- --------
Operating Income 30,525 36,094 89,717 88,273
OTHER (INCOME) AND DEDUCTIONS
Allowance for other funds used during construction (238) (188) (476) (379)
Income taxes 1,272 396 (299) 813
RGS/Energy East Merger Expenses 4,768 - 8,079 -
Other - net (3,030) 1,567 (2,751) 522
-------- -------- -------- --------
Total Other (Income) and Deductions 2,772 1,775 4,553 956
INTEREST CHARGES
Long term debt 15,794 14,249 29,644 28,345
Other - net 825 1,093 1,880 1,958
Allowance for borrowed funds used during construction (381) (302) (763) (608)
-------- -------- -------- --------
Total Interest Charges 16,238 15,040 30,761 29,695
-------- -------- -------- --------
Net Income 11,515 19,279 54,403 57,622
-------- -------- -------- --------
Dividends on Preferred Stock 925 925 1,850 1,850
-------- -------- -------- --------
Net Income Applicable to Common Stock 10,590 18,354 52,553 55,772
-------- -------- -------- --------
Average Number of Common Shares (000's)
Common Stock 34,577 35,379 34,577 35,583
The accompanying notes are an integral part of the financial statements.
8
ROCHESTER GAS AND ELECTRIC CORPORATION
STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Six Months Ended
June 30,
- ------------------------------------------------------------------------------------------------------
2001 2000
--------- --------
CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 54,403 57,622
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation & amortization 65,960 65,129
Deferred recoverable fuel costs 6,974 16,532
Income taxes deferred (6,231) (28,328)
Allowance for funds used during construction (1,239) (987)
Unbilled revenue 37,637 22,404
Post employment benefit/pension costs 1,724 3,055
Provision for doubtful accounts (4,000) 117
Changes in certain current assets and liabilities:
Accounts receivable 14,410 (6,081)
Materials, supplies and fuels 22,074 260
Taxes accrued 10,063 7,280
Accounts payable 2,317 12,253
Other current assets and liabilities, net (9,557) 10,397
Other, net (6,778) 10,750
--------- --------
Total Operating 187,757 170,403
--------- --------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (63,345) (64,618)
Nuclear generating plant decommissioning fund (10,336) (10,336)
Other, net (15,745) (776)
--------- --------
Total Investing (89,426) (75,730)
--------- --------
CASH FLOW FROM FINANCING ACTIVITIES
Redemption of long term debt (100,000) (30,000)
Proceeds from issuance of long-term debt, net 199,534 -
Repayment of promissory notes (1,999) (1,856)
Short term borrowings, net (98,000) -
Payments of dividends on preferred stock (1,850) (1,850)
Payment of dividends on common stock (31,120) (32,150)
Payment for treasury stock - (17,653)
Other, net (11,832) 270
--------- --------
Total Financing (45,267) (83,239)
--------- --------
Increase in cash and cash equivalents 53,064 11,434
Cash and cash equivalents at beginning of period 4,851 6,443
--------- --------
Cash and cash equivalents at end of period $ 57,915 $ 17,877
========= ========
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, RG&E was reorganized into a holding company structure in
accordance with the Agreement and Plan of Exchange between RG&E and 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 and 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 Corporation ("Energy East"), a New York corporation, and Eagle
Merger Corp., a New York corporation that will be a wholly owned subsidiary of
Energy East ("Merger Sub") at the effective time of the merger, 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.
At the 2001 Annual Meetings of RGS and Energy East, the shareholders of
RGS approved the Merger Agreement and the shareholders of Energy East approved
the issuance of Energy East shares in connection with the merger. The Merger is
still subject to, among other things, the approvals of various
10
regulatory agencies, including the PSC, FERC, NRC and the SEC. A Joint Petition
by the parties to the Merger Agreement, seeking approval of the PSC pursuant to
Section 70 of the Public Service Law, was filed on March 23, 2001. On May 9,
2001, Energy East and RGS, on behalf of their jurisdictional subsidiaries, filed
a joint application with FERC pursuant to Section 203 of the Federal Power Act
for authorization of the disposition of jurisdictional facilities. On June 22,
2001, RG&E applied for the approval of the NRC of the indirect transfer of the
NRC licenses held by RG&E for the Ginna Plant. On June 20, 2001, RGS and Energy
East filed an application on Form U-1 with the SEC seeking the SEC's approval of
the Merger pursuant to Sections 9(a)(2) and 10 of the Public Utilities Holding
Company Act of 1935. RGS and Energy East anticipate that all regulatory
approvals can be obtained during or before the first quarter of 2002.
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, of $16.7 million, that has been deferred for future rate treatment in
accordance with the Electric Settlement.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") finalized
their deliberations and issued Statement of Financial Accounting Standards
("SFAS") No. 141, "Business Combinations", and SFAS 142, "Goodwill and Other
Intangible Assets". The new pronouncements eliminate the pooling-of-interests
method to accounts for business combinations, and take a non-amortization
approach to goodwill. Instead of amortizing goodwill, an entity will have to
assess goodwill for impairment on at least an annual basis, as well as when
circumstances indicate a possible impairment. Goodwill would be considered
impaired if the fair value of the reporting unit's goodwill is less than its
carrying amount.
The Company is required to adopt SFAS 141 for all acquisitions that occur
subsequent to July 1, 2001, while SFAS 142 is effective January 1, 2002. The
Company's management is currently in the process of evaluating the impact that
the two pronouncements will have on the Company.
11
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 2. 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 had 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.
At July 1, 2001 the purchase price for RG&E's 14% ownership interest in
Nine Mile Two was $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 adjustments, including a daily price adjustment, at the time of
closing.
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.
12
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. 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
expected to close prior to December 31, 2001. The necessary FERC and NRC
approvals have been received. At June 30, 2001, the net book value of RG&E's 14
percent interest in the Nine Mile Two generating facility was approximately $360
million. RG&E also had investments in fuel of approximately $6.9 million,
transmission and distribution facilities of $3.3 million and construction work
in progress of $6.2 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 included 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. Subsequent to the filing of
testimony on the rate-making treatment associated with the proposed sale of the
Nine Mile Two units to Constellation Nuclear, RG&E has engaged in settlement
negotiations aimed at resolving all rate-making issues affecting RG&E. As a
result of those settlement negotiations, RG&E and the Staff of the PSC have
entered into a joint proposed settlement that addresses the rate-making
treatment associated with RG&E's recovery of its remaining investment in Nine
Mile Two and related costs. The proposed settlement is still subject to
approval by the PSC. Under the settlement, RG&E will be authorized to establish
a regulatory asset calculated in accordance with the provisions of the
settlement that is currently estimated to be approximately $329 million. RG&E
has agreed to a one-time write-off of $20 million of this regulatory asset,
approximately 5% of the Company's pre-sale investment in Nine Mile Two. RG&E
has also agreed to amortize during the period from the closing of the sale of
Nine Mile Two until RG&E's base electric rates are re-set (estimated to be July
1, 2002) an additional amount of this regulatory asset to reflect the projected
reduction in RG&E's expenses of owning and operating Nine Mile Two prior to the
sale compared to the estimated expenses that will be incurred in purchasing the
equivalent amount of electricity after the sale. The amortization during this
period will be calculated using an amortization rate of $30 million per year.
The terms associated with the recovery of the remaining regulatory asset will be
established in future RG&E rate proceedings. The proposed settlement further
provides that, upon PSC approval, it constitutes a final and irrevocable
resolution of all RG&E rate-making issues associated with the sale of Nine Mile
Two and RG&E's ability to recover costs associated with its investment in Nine
Mile Two through its rates.
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 was unconstitutional and should be null, void and
enjoined. Specifically, the utilities
13
alleged that DOE violated their due process rights in levying the assessment and
that such action constituted an unlawful taking of private property without just
compensation. 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 to
either transfer the case to the Court of Federal Claims, where cases seeking
assessment refunds on similar facts have been dismissed, or to dismiss the
complaint. Proceedings continue in the lower court.
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 June 30, 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 June 30, 2001 was
$11.7 million ($9.9 million as a long-term liability and $1.8 million as a
current liability). RG&E is recovering these costs in rates.
Note 3. 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 June 30, 2001 and
December 31, 2000:
Millions of Dollars
June 30, 2001 Dec. 31, 2000
Kamine Settlement $174.4 $179.1
Income Taxes 97.3 101.9
Oswego Plant Sale 71.1 74.4
Deferred Environmental SIR costs 13.3 16.6
Uranium Enrichment Decommissioning Deferral 12.1 12.7
Labor Day 1998 Storm Costs 9.7 9.3
Other, net 18.1 18.8
Total - Regulatory Assets $396.0 $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 June 30, 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
14
the carrying amount of a long-lived asset may not be
recoverable.
At June 30, 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 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 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
15
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 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 will implement 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.
16
(12) RG&E will implement a customer education plan to increase customer
awareness and understanding of competitive choice.
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.
As of early August, the Company is working on internal infrastructure
changes for the two aspects of the settlement that take effect on September 1,
2001. This includes changes to the billing system to separately state commodity
and delivery charges, and identifying the HEAP-eligible, non-heating population
in order to apply a reduced monthly customer charge.
The Service Quality Performance Program which was previously reported under
the Electric Settlement Agreement has been superceded by the indicators approved
in the Gas Restructuring Settlement. This was made effective January 1, 2001
for both gas and electric operations, and consists of the same six measures from
the Electric Settlement (see PSC Electric Settlement), but with new targets and
potential penalties: adjusted bills, PSC complaint rate, estimated meter reads,
calls answered within 30 seconds, appointments kept, and a customer transaction
survey. The maximum annual penalty for each measure is $118,000. The Company's
performance for the first two quarters of 2001 indicates that all six measures
are within an acceptable range and would incur no penalty.
17
Note 4. 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 June 30,
Regulated Electric Regulated Gas Unregulated
------------------ ------------------ -------------------
(thousands of dollars) 2001 2000 2001 2000 2001 2000
-------- -------- -------- -------- -------- --------
Operating Income/(Loss) $ 30,055 $ 33,835 $ 470 $ 2,259 $ (805) $ (960)
Revenues - External Customers 152,839 153,861 43,393 55,293 152,205 101,550
Revenues - Intersegment Transactions 23,719 17,411 6,465 - - -
For the Six Months Ended June 30,
Regulated Electric Regulated Gas Unregulated
------------------ ------------------ -------------------
(thousands of dollars) 2001 2000 2001 2000 2001 2000
-------- -------- -------- -------- -------- --------
Operating Income $ 72,359 $ 68,132 $ 17,358 $ 20,141 $ 3,617 $ 490
Revenues - External Customers 314,597 313,677 174,841 169,436 366,778 213,442
Revenues - Intersegment Transactions 51,020 34,302 16,124 - - -
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 For the Six Months
Ended June 30, Ended June 30,
(thousands of dollars)
Revenues 2001 2000 2001 2000
-------- -------- -------- --------
Regulated Electric $176,558 $171,272 $365,617 $347,979
Regulated Gas 49,858 55,293 190,965 169,436
Unregulated 152,205 101,550 366,778 213,442
-------- -------- -------- --------
Total $378,621 $328,115 $923,360 $730,857
Reported on RGS Consolidated
Income Statement 348,437 310,704 856,216 696,555
Difference to reconcile 30,184 17,411 67,144 34,302
Intersegment Revenue
Regulated Electric from Unregulated 23,719 17,411 51,020 34,302
Regulated Gas from Unregulated 6,465 - 16,124 -
-------- -------- -------- --------
Total Intersegment $ 30,184 $ 17,411 $ 67,144 $ 34,302
18
Note 5. COMMITMENTS AND OTHER MATTERS
ENVIRONMENTAL MATTERS
RGS
NEW YORK INITIATIVES
In May 2000, the 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 oxides 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 emissions below the
existing Acid Rain Phase II limits. The state emission reductions would be
phased-in beginning in 2004. These are draft regulations subject to review,
comment, and modification, RG&E is in the process of estimating their economic
impact on the station.
RG&E-OWNED WASTE SITE ACTIVITIES
RG&E is conducting proactive Site Investigation and/or Remediation ("SIR")
efforts at eight RG&E-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 RG&E 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 RG&E-owned sites. Through
June 30, 2001, RG&E has incurred aggregate costs of $7.9 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 be as much as
$14.5 million. These properties are in various stages of investigation and
remediation and, in some instances, 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 for
SIR efforts at nine sites not owned by it. 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 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 defending the legal action but cannot predict its eventual
outcome. There is insufficient information available at this time to predict the
economic impact of the claim on RG&E.
19
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 $1.6 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
June 30, 2001 approximately $1.4 million has been spent and it is estimated $1.6
million will be spent on these facilities.
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 $1.4 million accrual (on a
discounted basis) has been established for AllEnergy and Burnwell. As of June
30, 2001 no environmental expenses have been incurred for AllEnergy and
Burnwell.
20
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 and six month
periods. The Consolidated Financial Statements and the Notes thereto contain
additional data. For the quarter ended June 30, 2001, 50.7 percent of the
Company's operating revenues were derived from regulated electric service, 14.3
percent from regulated natural gas service, and 35.0 percent from unregulated
businesses.
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
21
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.
Shown below is a listing of the principal items discussed:
RGS ENERGY GROUP, INC. Page 22
Unregulated Subsidiaries
ROCHESTER GAS AND ELECTRIC CORPORATION
Competition Pages 23- 28
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 28- 30
PSC Gas Restructuring Policy Statement
FERC Gas Market Proposals
FERC Electric Restructuring Order
LIQUIDITY AND CAPITAL RESOURCES Pages 30- 31
Merger Agreement
Capital and Other Requirements
Financing
Redemption of Securities
EARNINGS SUMMARY Page 31
RESULTS OF OPERATIONS Pages 31 - 33
Operating Revenues and Sales
Operating Expenses
Other Statement of Income Items
DIVIDENDS Page 33
22
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 businesses and RGS
has invested $92.0 million (including loan guarantees) as of June 30, 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 and
Central New York. Energetix has approximately 84,000 customers for natural gas
and electricity service.
In August 1998, Energetix acquired Griffith Oil Co., 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 added
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 added 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 585
employees and operated 27 customer service centers as of June 30, 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
June 30, 2001, RGS Development's operations have not been material to RGS's
results of operations or its financial condition.
23
ROCHESTER GAS AND ELECTRIC CORPORATION
COMPETITION
Gas Retail Access Settlements
On January 25, 2001, RG&E reached agreement with the 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 3 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 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 3 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 July 31, 2001, eighteen energy service companies, including
Energetix, were 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.
24
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 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. In accordance with a
Joint Proposal filed with the PSC on March 13, 2001 and approved on March 29,
2001, RG&E implemented a market-based backout credit for Energy Service
Companies ("ESCOs") serving customers on its system who choose not to continue
with the full requirements option, effective May 1, 2001. One ESCO with a total
retail customer load of approximately 3 MW has elected the market-based backout
credit. All other ESCOs have chosen to remain on full requirements.
The Electric Settlement agreement established a Service Quality Performance
Program ("SQPP") and an Electric Reliability Program, specifying goals, targets,
and potential penalties for RG&E's performance of retail customer services and
reliability. The SQPP measures the Company's performance under six distinct
performance criteria: (1) percentage of service appointments kept by RG&E
personnel, (2) percentage of customer calls answered within 30 seconds, (3)
percentage of bills adjusted, (4) estimated bills-unscheduled, (5) customer
satisfaction survey, and (6) PSC complaints. The Electric Reliability program
consists of two measures: System Average Interruption Frequency Index and
Customer Average Interruption Indicator Index. For each rate year of the
settlement, average annual RG&E performance for each of the measures is
calculated and compared to targets established in the Settlement. If actual
performance is below the target level of performance, a penalty is assessed.
On May 9, 2001, the PSC imposed a penalty on the Company in the amount of
$249,000 for alleged non-compliance during a three year period ending June 30,
2000, regarding one of the SQPP provisions - conducting a customer transaction
survey. The Company dropped the survey instrument agreed to in the Electric
Settlement in favor of another instrument. RG&E collaborated with PSC staff as
this was taking place; however, the Commission imposed a penalty on the basis of
RG&E's omission to conduct a customer survey in the manner required by the
Electric Settlement. On June 7, 2001 RG&E filed a petition for a rehearing of
the Commission's May 9, 2001 decision including withdrawal of the $249,000
penalty.
25
The Company cannot predict the outcome of the petition at this time.
The electric reliability performance indicators remain in place in
accordance with the Electric Settlement. The maximum annual penalty for each
measure is $375,000.
The customer service performance indicators in the Electric Settlement have
been superseded by a Service Quality Performance Program approved in the gas
restructuring settlement (see Gas Retail Access Settlements).
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 are 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 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.
26
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 June 30, 2001, five energy service companies, including Energetix,
were qualified by RG&E to serve retail customers under Energy Choice.
RG&E's Energy Choice program began on July 1, 1998 with an "Energy-Only"
stage, during which energy service companies were responsible only for providing
the energy requirements of the customers they acquired. The program moved to an
"Energy and Capacity" stage on November 1, 1999. From that point, energy
service companies were required to provide for the energy and installed capacity
requirements of their customers.
Energy service companies have had and continue to have the option to serve
a portion or all of their load by buying power directly from RG&E, at a price
equal to the backout credit for energy and capacity. This is the "full
requirements" option. To the extent that energy service companies choose not to
take advantage of the full requirements option, they must acquire power from the
competitive wholesale market. Energy service companies may make this choice on
a service point by service point basis. Once they elect to acquire power from
the market for a particular service point, they are not allowed to return that
service point to full requirements service. To the extent that energy service
companies choose to procure power from the market, RG&E will experience a
revenue decrease. This will be offset by decreased costs resulting from reduced
requirements to purchase energy and capacity for sale to the energy service
companies and by increased revenues from the sale in the wholesale market of
energy produced by the company. Throughout the remaining term of the Electric
Settlement, through June 30, 2002, the full requirements option will continue to
be available to energy service companies.
From the beginning of the Energy and Capacity stage through the
implementation of the market-based backout credit (described below), RG&E's
distribution rates were set to be equal to rates for standard retail service
less two separate credits. The first was a fixed "backout" credit for energy
and capacity. The second was a fixed "retailing" credit to represent the avoided
costs of retailing services assumed by energy service companies. From November
1, 1998 through June 30, 2000, the energy and capacity backout credit was set at
2.67 cents per kilowatt-hour (an estimate of the wholesale market price of
electric energy and capacity, adjusted for gross receipts taxes). The retailing
credit was set at 0.40 cents per kilowatt-hour. Beginning July 1, 2000, the
energy and capacity backout credit was updated to 2.68 cents per kilowatt-hour
to reflect the implementation of reduced gross receipts taxes. The retailing
credit was unchanged.
On March 29, 2001 the PSC approved a joint proposal among RG&E and several
other parties, including the Staff of the PSC, which replaces 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 "market-based" backout credit became
effective May 1, 2001. The market-based credit is initially based on projected
prices for energy, capacity, ancillary services and NTAC and is trued-up to
actual prices after they are known. The joint proposal called for the retailing
credit to remain at a level of 0.40 cents per kilowatt-hour.
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
27
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 eligibility to participate in the electric retail access program was
subject to increasing caps 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. Moreover, in the opinion
of the Company, the adoption of the market-based backout credit, described
above, and the elimination of the cap on eligibility to participate in the
electric retail access program on July 1 2001, as provided by the Electric
Settlement, effectively moots most aspects of these petitions. 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 potential changes on its operations as
retail access continues to evolve.
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 2 to the Financial Statements under the
heading "Nine Mile Nuclear Plants".
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
28
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.
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 3 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 3 of the Notes to Financial Statements under the heading "Regulatory
Assets".
At June 30, 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 2 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
29
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 preceeding discussion under "Gas Retail Access
Settlements" under the heading "Competition").
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;
(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 ("DTI") became the first pipeline upon
which RG&E holds capacity to file a FERC Order No. 637 settlement with the FERC.
On May 31, 2001 FERC issued an order accepting DTI's settlement, as filed. This
was the first of the FERC Order No. 637 filings to be accepted. There are
continuing negotiations with the other pipelines upon which RG&E holds capacity.
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
30
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 made a joint
filing with NYSEG supporting the January 16th filing, but asking FERC to explore
the functional and structural integration of the three existing Northeastern
ISOs. On July 12, 2001, FERC issued orders in the four dockets relating to the
creation of RTO's in the Northeast. They also issued a mediation order calling
for the formation of one RTO for the whole northeast instead of the three as
proposed by the market participants. The Commission ordered that the
Pennsylvania-New Jersey-Maryland ISO was to be the platform upon which the
northeastern RTO would be based, but that best practice rules from the three
pre-existing ISOs would be used to guide the project. The mediation order called
for a business plan for creating an RTO out of the three ISOs to be achieved in
45 days of mediation under the supervision of an Administrative Law Judge. At
the end of the mediation period, the Judge is to file a report with the
Commission on the implementation process chosen, including milestones and a
timeline. RG&E cannot predict what effect the ultimate action by FERC with
respect to the rule will have on future operations or on the financial condition
of the Company.
LIQUIDITY AND CAPITAL RESOURCES
During the first six months of 2001, RGS's and RG&E's cash flow from
operations, and the issuance by RG&E of First Mortgage Bonds in April 2001 (see
Statements of Cash Flows) provided the funds for utility plant construction
expenditures, the payment of dividends, repayment of short term borrowings, and
the redemption of $100 million of First Mortgage Bonds in the second quarter of
2001 (see "Financing and Redemption of Securities" below). Capital requirements
of the Company for the remaining six months of 2001 are anticipated to be
satisfied from the combination of internally generated funds and short-term
credit arrangements. In addition, completion of the Nine Mile Two sale would
also provide additional funds as previously discussed in Note 2 to the Financial
Statements under the heading "Nine Mile Nuclear Plants".
MERGER AGREEMENT
On February 16, 2001, RGS entered into a Merger Agreement with Energy East
pursuant to which RGS will be merged with and into a subsidiary of Energy East
and will become a wholly owned subsidiary of Energy East. See Note 1 to the
Financial Statements under the heading "Merger Agreement" for additional
information about the Merger.
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. The Company completed its share repurchase
program in the fourth quarter of 2000. RG&E has no further plans to install
additional baseload generation.
Construction requirements for the Company in 2001 are currently estimated
at $157 million. RG&E's portion of total estimated construction requirements is
$154 million. Approximately $63.2 million had been expended for construction as
of June 30, 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 principal amount of 6.95% First
Mortgage Bonds, Series TT, due 2011. The net proceeds from this financing were
used to redeem RG&E's Series PP First Mortgage Bonds as described below and to
repay $39 million of outstanding short-term debt.
31
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 its 9 3/8%
First Mortgage Bonds, Series PP, at a price of 104.47 percent of the principal
amount plus accrued interest from April 1, 2001 through the redemption date.
RG&E does not anticipate redeeming any other securities for the remainder of
2001.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") finalized
their deliberations and issued Statement of Financial Accounting Standards
("SFAS") No. 141, "Business Combinations", and SFAS 142, "Goodwill and Other
Intangible Assets". The new pronouncements eliminate the pooling-of-interests
method to accounts for business combinations, and take a non-amortization
approach to goodwill. Instead of amortizing goodwill, an entity will have to
assess goodwill for impairment on at least an annual basis, as well as when
circumstances indicate a possible impairment. Goodwill would be considered
impaired if the fair value of the reporting unit's goodwill is less than its
carrying amount.
The Company is required to adopt SFAS 141 for all acquisitions that occur
subsequent to July 1, 2001, while SFAS 142 is effective January 1, 2002. The
Company's management is currently in the process of evaluating the impact that
the two pronouncements will have on the Company.
EARNINGS SUMMARY
RGS :
RGS reported earnings of $0.25 per common share for the quarter ended June
30, 2001, down from $0.49 per common share for the same period in 2000. Earnings
for the six-month period ended June 30, 2001 were $1.57 per share, unchanged
from the per share earnings reported for the same period in 2000. These results
for the second quarter and year to date reflect one-time after-tax expenses of
$4.9 million ($0.14 per share effect) and $8.3 million ($0.24 per share effect),
respectively, related to the pending merger with Energy East. Partially
offsetting these one-time costs were increased sales of electricity into the
wholesale market due to the increased availability of the Company's generating
facilities.
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 $152.2 million in the second quarter of 2001, compared
to $101.6 million for the second quarter 2000.
RG&E:
Earnings for RG&E were impacted by the same factors discussed above for
RGS except that discussions relating to Energetix and merger costs are not
applicable.
RESULTS OF OPERATIONS
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
and six-month periods ended June 30, 2001 to the three-month and six-month
periods ended June 30, 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,
32
unless otherwise noted.
THREE MONTHS ENDED JUNE 30, 2001 COMPARED TO THREE MONTHS ENDED JUNE 30, 2000:
OPERATING REVENUES AND SALES
In the second quarter total revenues for RGS increased $37.7 million or
12.1%, reflecting mainly higher wholesale electric sales and higher other
revenues from Energetix due to an aggressive expansion program during 2000 that
included the acquisition of eight liquid-fuels companies. The increase in
wholesale electric sales reflect increased capacity to sell power in the
wholesale electric market due to the availability of RG&E's generation
facilities.
Revenues from regulated retail electric sales were up $.9 million from the
second quarter of 2000, driven by increased sales to energy marketers, partially
offset by lower retail electric base rates that became effective in July 2000.
Electric sales to other utilities were up $4.3 million, which reflects the
higher electric output from the RG&E generation facilities.
Gas revenues, net of fuel expenses, were down $5.5 million for 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 expense, increased $4.0 million from the
second quarter of 2000. This performance reflects a full quarter of operations
after the completion by Energetix of an aggressive expansion program in 2000
that included the acquisition of eight liquid-fuels companies, the largest of
which was Burnwell and certain assets of the New York Fuels division of
AllEnergy, both of which 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 the increased consumption due
to the higher availability of RG&E's nuclear generation facilities due to the
timing of scheduled maintenance shutdowns. Purchased power expense for RG&E was
up $3.8 million driven by more megawatt hours purchased.
Higher unregulated fuel costs for RGS reflect mainly the increase in the
liquid-fuels commodity costs and the higher volumes of fuel sold in the second
quarter of 2001 as compared to a year ago.
The increase in non-fuel regulated operating and maintenance expense for
both RGS and RG&E in the second quarter of 2001 reflects mainly a $7 million
increase in electric transmission and wheeling charges by the NYISO, compared to
a year ago when the Company recognized certain one-time credits for these
expenses. These higher electric transmission and wheeling charges were
partially offset by a $4 million decrease in the Company's reserve for
uncollectible accounts due to improved collection experience.
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 are up $2.0 million from second
quarter 2000. The 2000 amount included a $4.3 million credit adjustment for new
state income taxes in 2000, so the 2001 taxes are actually $2.0 million lower
than the second quarter 2001 before the adjustment. This decrease reflects
lower state revenue taxes.
The difference in income tax expense for RGS and RG&E is attributable to
lower pre-tax earnings, and the effect of merger costs in 2001, which are non-
deductible..
OTHER STATEMENT OF INCOME ITEMS
The change in RGS's Other Income and Deductions, Other-net reflects mainly
additional income in
33
the current period compared to a year when in May 2000 the Company recognized
a charge for certain prior period purchase power expenses.
Interest expense for both RGS and RG&E is driven by the $200 million bond
financing in April 2001 and the $100 million redemption of bonds in May 2001 as
discussed in "Financing" and "Redemption of Securities" above. Interest expense
for RGS also increased due to interest payments on the promissory note issued in
November 2000 in connection with the acquisition of Burnwell.
SIX MONTHS ENDED JUNE 30, 2001 COMPARED TO SIX MONTHS ENDED JUNE 30, 2000:
OPERATING REVENUES AND SALES
In the first six months of 2001, total revenues for RGS increased $159.7
million from the same period a year ago principally as a result of increased
unregulated revenues. Compared to last year, revenues from the sale of energy
to other electric utilities were up $18.9 million, reflecting increased output
of the RG&E generation facilities and higher average market prices. Partially
offsetting these favorable results was a drop of $1.3 million from a decline in
retail electric rates. Regulated gas revenues, net of fuel expenses, were down
$8.7 million due mainly to reduced consumption in response to higher commodity
costs for natural gas.
Unregulated revenues were $366.8 million for the first six months of 2001,
as compared to $213.4 million last year for the same reasons discussed for the
second quarter.
OPERATING EXPENSES
Higher regulated fuel and purchased power expenses increased for the same
reasons discussed for the second quarter.
The decrease in regulated non-fuel operating and maintenance expenses was
driven by the decrease in the company's uncollectible accounts reserve discussed
above, partially offset by higher electric transmission and wheeling charges of
$2.8 million compared to a year ago. There was a decrease in the NYISO charges
in the first quarter, followed by the $7 million increase as discussed for the
second quarter.
The factors affecting variances in regulated state, local and other taxes
and income taxes for the quarterly period are also applicable for the six-month
comparison period.
The increase in unregulated non-fuel operating and maintenance expenses for
RGS reflects primarily operating expenses for Griffith, driven by the business
acquisitions as discussed earlier.
OTHER STATEMENT OF INCOME ITEMS
The factors affecting variances in Regulated Other Income and Deductions-
net, and interest charges for the quarterly period are also applicable for the
six-month comparison period. One time after-tax merger expenses of $8.3 million
were partially offset by lower expenses due to recognition in June 2000 of
certain non-recurring prior period purchase power expenses.
DIVIDENDS
On June 15, 2001, the Board of Directors of RGS authorized a common stock
dividend of $.45 per share, which was paid on July 25, 2001 to shareholders of
record on July 2, 2001. Also on June 15, 2001, the Board of Directors of RG&E
declared dividends on its Preferred Stock at the regular rates per share payable
on September 1, 2001 to shareholders of record on August 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. RG&E is the largest of RGS's
subsidiaries, therefore 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
34
upon the availability of retained earnings and the needs of its utility
business. RG&E's Certificate of 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 $8 million at June 30, 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 June 30, 2001.
The commodity price risk relates to market fluctuations in the price of
natural gas, electricity, and other liquid-fuel-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 liquid-fuel 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 mitigates this risk through generation insurance on a
significant percentage of its owned generation during its peak summer months and
through hedging contracts.
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. Additionally, Energetix enters into exchange-
traded option contracts for natural gas. These contracts are closely monitored
on a daily basis to manage the price risk associated with future sales
commitments.
Energetix, through its subsidiary Griffith, is in the business of
purchasing liquid-fuel-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.
35
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to Notes 2, 3 and 5 of the Notes to Financial Statements.
GRIFFITH OWNED SITES
In connection with its Big Flats, New York terminal, Griffith has been
complying with the Unilateral Administrative Order issued by the EPA. Pursuant
to a cost sharing agreement with Sun Pipe Line Company, Griffith continues to
undertake one-half of the costs necessary to comply with the order. To date
Griffith has spent $1.8 million on this compliance. Griffith has reserved the
right to claim contribution and/or indemnification from Sun Pipe Line Company,
and compliance with the order is proceeding on this basis accordingly.
Since February 1996, Griffith has been involved in a legal proceeding in
New York State Supreme Court for Steuben County, related to the environmental
matter in the above paragraph. In Steuben Contracting v. Sun Pipe Line Company,
Griffith Oil Co., Inc. and Chevron, USA, the plaintiff is seeking compensation
for property damage associated with petroleum discharge at Big Flats. In a
decision by the Court entered June 28, 2000, the trial court (i) granted summary
judgment against the defendant Sun Pipe Line, (ii) dismissed the complaint
against Chevron, USA, (iii) determined that a question of fact existed as to the
liability of Griffith as an operator of the failed spur, and (iv) denied Sun's
motion for indemnification pursuant to an Access Agreement signed by Griffith
upon discovery of the incident. The Court also determined in its bench decision
that Griffith did not own the failed spur. This Order was appealed by all
defendants, including Griffith. Most significantly, if the Order regarding
indemnification is reversed, Griffith could be held liable for Sun's defense and
response costs. In April 2001, the Appellate Division for the Fourth Department
of Supreme Court determined that both Griffith Oil and Sun Pipe Line were
dischargers within the meaning of the New York State Navigation Law, and
responsible for the property damages which may be proved by Steuben Contracting,
the owner of lands adjoining Griffith's Big Flats Petroleum Bulk Storage
Terminal and through which the failed spur line traversed. Certain causes of
action against Chevron, USA, successor by merger to Gulf Oil, were reinstated.
Trial of the plaintiff's damages as well as the respective claims between the
defendants for contribution and indemnification, have yet to be tried. With the
exception of the cost-sharing agreement with Sun Pipe Line, an estimate of the
possible cost to Griffith cannot be made at this time.
In June of 2000, Griffith received notification that it is considered a
responsible party in connection with petroleum contamination at its Phelps, New
York facility. Griffith leases an office and garage at this facility. From
approximately 1996 through 1998, it stored distillate fuels at the bulk
petroleum storage facility at the site, which was owned by Jeffrey Fuels, Inc.
Early in 2000, NYSDEC received complaints of gasoline contamination affecting
the water wells of local residents. While no action has been commenced, it is
anticipated that Griffith will be named in any future cost recovery suit or
other action regarding this facility. The Phelps-Clifton Springs School
District, as well as Jeffrey Fuels, Inc. have also been identified as
responsible parties. Since Griffith stored only distillate fuels at this site,
and not gasoline, it will continue to disclaim responsibility. Griffith is
unable to estimate the cost of these possible actions at this time.
36
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's Annual Meeting of Shareholders was held on June 15, 2001. The
following matters were voted upon:
(a) Approval and adoption of the Agreement and Plan of Merger between RGS and
Energy East
For Against Abstain Total
--------------------------------------------------------------------------
23,123,264 2,137,680 468,957 25,729,901
Since a majority of the 34,577, 426 outstanding share of RGS common stock voted
for the Agreement and Plan of Merger, the merger was approved.
(b) The election of the following Directors for three year terms expiring at
the Annual Meeting of Shareholders in 2004:
Nominees Shares For Shares Withheld
--------------------- ---------- ---------------
Angelo J. Chiarella 28,927,047 969,756
Mark B. Grier 28,957,509 939,294
Jay T. Holmes 28,960,375 936,428
Since each Nominee received a plurality of the votes cast, the Nominees were
elected Directors for three year terms expiring at the 2004 Annual Meeting of
Shareholders.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: None
(b) Reports on Form 8-K:
RGS Energy Group, Inc.
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
A report was filed August 10, 2001, including under Item 5, Other Events, that
RG&E has reached an agreement with the Staff of the New York State Public
Service Commission on a joint settlement proposal with respect to the regulatory
and ratemaking aspects of the sale of RG&E's interest in the Nine Mile Two
generating facility. This proposal is subject to PSC approval.
37
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: August 9, 2001 By /s/ Mark Keogh
-----------------------------
Mark Keogh
Treasurer
Date: August 9, 2001 By /s/ William J. Reddy
-----------------------------
William J. Reddy
Controller
ROCHESTER GAS AND ELECTRIC CORPORATION
--------------------------------------
(Registrant)
Date: August 9, 2001 By /s/ Mark Keogh
-----------------------------
Mark Keogh
Vice President and Treasurer
Date: August 9, 2001 By /s/ William J. Reddy
-----------------------------
William J. Reddy
Vice President and Controller