UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
---------------
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended................................... December 31, 2003
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 IRS Employer
File Number Address and Telephone Number Identification No.
- ----------- ---------------------------- ------------------
0-30512 CH Energy Group, Inc. 14-1804460
(Incorporated in New York)
284 South Avenue
Poughkeepsie, New York 12601-4879
(845) 452-2000
1-3268 Central Hudson Gas & Electric Corporation 14-0555980
(Incorporated in New York)
284 South Avenue
Poughkeepsie, New York 12601-4879
(845) 452-2000
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- ----------------------
CH Energy Group, Inc.
Common Stock, $0.10 par value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Central Hudson Gas & Electric Corporation Cumulative Preferred Stock
4 1/2% Series
4.75% Series
Indicate by check mark whether the Registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Act during the preceding 12
months (or for such shorter period that the Registrants were required to file
such reports), and (2) have been subject to such filing requirements for the
past 90 days.
Yes |X| No |_|
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether CH Energy Group, Inc. ("Energy Group") is
an accelerated filer (as defined in Rule 12b-2 of the Act).
Yes |X| No |_|
The aggregate market value of the voting and non-voting common equity held
by non-affiliates of Energy Group as of January 30, 2004, was $728,519,640 based
upon the lowest price at which Energy Group's Common Stock was traded on that
date, as reported on the New York Stock Exchange listing of composite
transactions.
The aggregate market value of the voting and non-voting common equity held
by non-affiliates of Energy Group as of June 30, 2003, the last business day of
Energy Group's most recently completed second fiscal quarter, was $710,001,000
computed by reference to the price at which Energy Group's Common Stock was last
traded on that date, as reported on the New York Stock Exchange listing of
composite transactions.
Indicate by check mark whether Central Hudson Gas & Electric Corporation
("Central Hudson") is an accelerated filer (as defined in Rule 12b-2 of the
Act).
Yes |_| No |X|
The aggregate market value of the voting and non-voting common equity of
Central Hudson held by non-affiliates as of June 30, 2003, was zero.
The number of shares outstanding of Energy Group's Common Stock, as of
January 30, 2004, was 15,762,000.
The number of shares outstanding of Central Hudson's Common Stock, as of
January 30, 2004, was 16,862,087. All such shares are owned by Energy Group.
CENTRAL HUDSON MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (I)
(1) (a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM WITH THE REDUCED
DISCLOSURE FORMAT PURSUANT TO GENERAL INSTRUCTION (I) (2).
DOCUMENTS INCORPORATED BY REFERENCE
Energy Group's definitive Proxy Statement, dated March 3, 2004, and to be
used in connection with its Annual Meeting of Shareholders to be held on April
27, 2004, is incorporated by reference in Part III hereof. Information required
by Part III hereof with respect to Central Hudson has been omitted pursuant to
General Instruction (I) (2) (c) of Form 10-K of the Act.
TABLE OF CONTENTS
Page
----
PART I
ITEM 1 BUSINESS 2
ITEM 2 PROPERTIES 11
ITEM 3 LEGAL PROCEEDINGS 15
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS 15
PART II
ITEM 5 MARKET FOR ENERGY GROUP'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS 16
ITEM 6 SELECTED FINANCIAL DATA OF ENERGY GROUP AND
ITS SUBSIDIARIES 17
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS 21
ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT
MARKET RISK 46
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 48
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE 127
ITEM 9A CONTROLS AND PROCEDURES 127
PART III
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF ENERGY GROUP 127
ITEM 11 EXECUTIVE COMPENSATION 129
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 129
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 130
ITEM 14 PRINCIPAL ACCOUNTANT FEES AND SERVICES 130
PART IV
ITEM 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K 130
SIGNATURES 132-134
(i)
TABLE OF CONTENTS
(NOTES TO CONSOLIDATED FINANCIAL STATEMENTS)
Page
----
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 67
NOTE 2 REGULATORY MATTERS 78
NOTE 3 NINE MILE 2 PLANT 84
NOTE 4 INCOME TAX 85
NOTE 5 ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS 90
NOTE 6 GOODWILL AND OTHER INTANGIBLE ASSETS 91
NOTE 7 SHORT-TERM BORROWING ARRANGEMENTS 93
NOTE 8 CAPITALIZATION - ENERGY GROUP CAPITAL STOCK
CAPITALIZATION - CENTRAL HUDSON CAPITAL STOCK 94
NOTE 9 CAPITALIZATION - LONG-TERM DEBT 96
NOTE 10 POST-EMPLOYMENT BENEFITS 98
NOTE 11 STOCK-BASED COMPENSATION INCENTIVE PLANS 105
NOTE 12 OTHER INVESTMENTS 107
NOTE 13 COMMITMENTS AND CONTINGENCIES 108
NOTE 14 SEGMENTS AND RELATED INFORMATION 117
NOTE 15 FINANCIAL INSTRUMENTS 121
(ii)
PART I
FILING FORMAT
This Annual Report on Form 10-K for the fiscal year ended December 31,
2003 ("10-K Annual Report"), is a combined report being filed by two different
registrants: CH Energy Group, Inc. ("Energy Group") and Central Hudson Gas &
Electric Corporation ("Central Hudson"). Except where the content clearly
indicates otherwise, any references in this 10-K Annual Report to Energy Group
include all subsidiaries of Energy Group, including Central Hudson. Energy
Group's subsidiaries are each directly or indirectly wholly owned by Energy
Group. Central Hudson makes no representation as to the information contained in
this 10-K Annual Report in relation to Energy Group and its subsidiaries other
than Central Hudson. When this 10-K Annual Report is incorporated by reference
into any filing with the Securities and Exchange Commission ("SEC") made by
Central Hudson, the portions of this 10-K Annual Report that relate to Energy
Group and its subsidiaries, other than Central Hudson, are not incorporated by
reference therein.
FORWARD-LOOKING STATEMENTS
Statements included in this 10-K Annual Report and the documents
incorporated by reference which are not historical in nature are intended to be
and are hereby identified as "forward-looking statements" for purposes of the
safe harbor provided by Section 21E of the Securities Exchange Act of 1934, as
amended ("Exchange Act"). Forward-looking statements may be identified by words
including "anticipates," "believes," "projects," "intends," "estimates,"
"expects," "plans," "assumes," "seeks," and similar expressions. Forward-looking
statements including, without limitation, those relating to Registrants' future
business prospects, revenues, proceeds, working capital, liquidity, income, and
margins, are subject to certain risks and uncertainties that could cause actual
results to differ materially from those indicated in the forward-looking
statements, due to several important factors including those identified from
time to time in the forward-looking statements. Those factors include, but are
not limited to: weather; energy supply and demand; fuel prices; interest rates;
potential future acquisitions; developments in the legislative, regulatory and
competitive environment; market risks; electric and natural gas industry
restructuring and cost recovery; the ability to obtain adequate and timely rate
relief; changes in fuel supply or costs; the success of strategies to satisfy
electricity requirements following the sale of Central Hudson's major generating
assets; future market prices for energy, capacity, and ancillary services; the
outcome of pending litigation and certain environmental matters, particularly
the status of inactive hazardous waste disposal sites and waste site remediation
requirements; and certain presently unknown or unforeseen factors, including,
but not limited to, acts of terrorism. Registrants undertake no obligation to
update publicly any forward-looking statements, whether as a result of new
information, future events, or otherwise.
Given these uncertainties, undue reliance should not be placed on the
forward-looking statements.
1
ITEM 1 - BUSINESS
CORPORATE STRUCTURE
On December 15, 1999, Energy Group became the holding company parent
corporation of Central Hudson and Central Hudson Energy Services, Inc. ("CH
Services") (the "Holding Company Restructuring").
For further information regarding the Holding Company Restructuring and
the Amended and Restated Settlement Agreement dated January 2, 1998, and
thereafter amended ("Agreement"), among Central Hudson, the Staff of the Public
Service Commission of the State of New York ("PSC"), and certain others which,
among other things, permitted the Holding Company Restructuring, see the
captions "Competitive Opportunities Proceeding Settlement Agreement" and "Rate
Proceedings - Electric and Natural Gas" in Note 2 to the Financial Statements
contained in Item 8 of this Form 10-K Annual Report (each Note being hereinafter
called a "Note"). Surviving provisions of the Agreement discussed herein may
affect future operations of Energy Group and its subsidiaries.
Effective December 31, 2002, Energy Group reorganized its competitive
business subsidiaries to streamline administration and improve managerial
effectiveness. As a result of this reorganization, CH Services was merged into
Energy Group; Greene Point Development Corporation ("Greene Point") and Prime
Industrial Energy Services, Inc. were merged into Central Hudson Enterprises
Corporation ("CHEC"); and CHEC replaced CH Services as the parent of the
remaining competitive business subsidiaries. Griffith Energy Services, Inc.
("Griffith") and SCASCO, Inc. ("SCASCO") remain direct subsidiaries of CHEC.
CHEC, Griffith, and SCASCO are collectively referred to herein as the
"competitive business subsidiaries." Energy Group's other subsidiary, Central
Hudson, wholly owns Phoenix Development Company, Inc. ("Phoenix"). Another
subsidiary of CH Services, CH Resources, Inc. ("CH Resources") and its
subsidiary companies, CH Syracuse Properties, Inc. and CH Niagara Properties,
Inc., were sold in May 2002. For further information on the sale of CH
Resources, see Note 5 - "Acquisitions, Divestitures, and Discontinued
Operations."
Central Hudson's preferred stock and debt remain securities of Central
Hudson.
Because of its ownership of Central Hudson, Energy Group is a "public
utility holding company" under the Public Utility Holding Company Act of 1935
("PUHCA"). However, Energy Group is exempt from the provisions of PUHCA under
the intrastate exemption provisions of ss.3(a)(1) of PUHCA except that, under
ss.9(a)(2) of PUHCA, the approval of the SEC is required for a direct or
indirect acquisition by a public utility holding company of 5% or more of the
voting securities of any electric or natural gas utility company subject to
PUHCA.
For a discussion of Energy Group's and its subsidiaries' financing
program, capital structure, and short-term debt, see Item 7 of this 10-K Annual
Report under the subcaptions "Capital Structure," "Financing Program of Energy
Group and Its Subsidiaries," and "Short-Term Debt" under the caption "Capital
Resources and Liquidity." For a discussion of short-term borrowing,
capitalization, and long-term debt, see Notes 7, 8, and 9, respectively. For
information concerning revenues, certain expenses, earnings per share, and
information regarding assets for Central Hudson's electric and natural gas
segments, and the competitive business subsidiaries' segments, see Note 14 -
"Segments and Related Information."
2
SUBSIDIARIES OF ENERGY GROUP
CENTRAL HUDSON
Central Hudson is a New York natural gas and electric corporation formed
on December 31, 1926, as a consolidation of several operating utilities that had
been accumulated under one management during the previous 26 years. Central
Hudson purchases, sells at wholesale, and distributes electricity and natural
gas in portions of New York State. Central Hudson also generates a small portion
of its electricity requirements.
Central Hudson has, with minor exceptions, valid, non-exclusive
franchises, unlimited in duration, to serve a territory extending about 85 miles
along the Hudson River and about 25 to 40 miles east and west of the Hudson
River. The southern end of the territory is about 25 miles north of New York
City, and the northern end is about 10 miles south of the city of Albany. The
territory, comprising approximately 2,600 square miles, has a population
estimated at 672,800. Electric service is available throughout the territory and
natural gas service is provided in and about the cities of Poughkeepsie, Beacon,
Newburgh, and Kingston, New York, and in certain outlying and intervening
territories.
Central Hudson's territory reflects a diversified economy, including
manufacturing industries, research firms, farms, governmental agencies, public
and private institutions, resorts, and wholesale and retail trade operations.
The competitive marketplace continues to develop for electric and natural
gas utilities, and Central Hudson electric and natural gas customers may
purchase energy and related services from other sources.
The number of Central Hudson employees at December 31, 2003, was 868.
Sales of Major Generating Assets
For information with respect to the sales of Central Hudson's interests in
the Danskammer Point Steam Electric Generating Station ("Danskammer Plant"), the
Roseton Electric Generating Plant ("Roseton Plant"), and Unit No. 2 of the Nine
Mile Point Nuclear Generating Station ("Nine Mile 2 Plant") during 2001, see the
caption "Sales of Major Generating Assets" in Note 2 - "Regulatory Matters." The
Danskammer Plant, the Roseton Plant, and the Nine Mile 2 Plant are collectively
referred to herein as the "major generating assets."
Regulation
Central Hudson is subject to regulation by the PSC regarding, among other
things, services rendered (including the rates charged), major transmission
facility siting, accounting procedures, and issuance of securities. For certain
restrictions on Central Hudson's activities imposed by the Agreement, see Note 2
- - "Regulatory Matters" under the caption "Competitive Opportunities Proceeding
Settlement Agreement."
3
Certain activities of Central Hudson, including accounting and the
acquisition and disposition of property, are subject to regulation by the
Federal Energy Regulatory Commission ("FERC") under the Federal Power Act.
Central Hudson is not subject to the provisions of the Natural Gas Act.
With the exception of the Groveville Hydroelectric Facility in Beacon, New
York, Central Hudson's hydroelectric facilities are not required to be licensed
under the Federal Power Act. The Groveville Hydroelectric Facility is subject to
an Emergency Action Plan approved by the FERC.
Rates
Generally: The electric and natural gas rates collected by Central Hudson
applicable to service supplied to retail customers within New York State are
regulated by the PSC. Transmission rates and rates for electricity sold for
resale in interstate commerce by Central Hudson are regulated by the FERC. In
Central Hudson's most recent rate proceeding, rates for delivery and supply were
unbundled to facilitate competition.
Central Hudson's present retail electricity rate structure consists of
various service classifications covering delivery service and full service
(which includes electricity supply) for residential, commercial, and industrial
customers. During 2003, the average price of electricity, for full service
customers was 8.83 cents per kilowatt-hour ("kWh") as compared to an average of
7.89 cents per kWh for 2002. The average delivery price for 2003 was 2.16 cents
per kWh and 2.62 cents per kWh for 2002.
Rate Proceedings - Electric and Natural Gas: For information regarding
Central Hudson's most recent electric and natural gas proceedings filed with the
PSC, see Note 2 under the caption "Rate Proceedings - Electric and Natural Gas."
Cost Adjustment Clauses: For information regarding Central Hudson's
electric and natural gas cost adjustment clauses, see Note 1 - "Summary of
Significant Accounting Policies," under the caption "Rates, Revenues and Cost
Adjustment Clauses."
Construction Program and Financing
For estimates of 2004 construction expenditures and internal funds
available for Central Hudson, see the subcaption "Construction Program - Central
Hudson" in Item 7 of this 10-K Annual Report under the caption "Capital
Resources and Liquidity."
Central Hudson's Certificate of Incorporation and its various debt
instruments do not contain any limitations upon the issuance of authorized, but
unissued, preferred stock or unsecured short-term debt.
Central Hudson has in place a $75 million credit facility which limits the
amount of additional funded indebtedness Central Hudson may incur. Central
Hudson believes these limitations will not impair its ability to issue any or
all of the debt described under the subcaption "Financing Program of Energy
Group and Its Subsidiaries" in Item 7 of this 10-K Annual Report under the
caption "Capital Resources and Liquidity."
4
Purchased Power and Generation Costs
For the 12-month period ended December 31, 2003, the sources and related
costs of purchased electricity and generation for Central Hudson were as
follows:
Aggregate
Sources of Percentage of Costs in 2003
Generation Energy Requirements ($000)
---------- ------------------- -------------
Purchased Electricity 96.3% $260,514
Hydroelectric and Other 3.7% 841
------
100.0%
======
Deferred Electricity Cost 7,402
--------
Total $268,757
========
Other Central Hudson Matters
Labor Relations: Central Hudson has an agreement with Local 320 of the
International Brotherhood of Electrical Workers for its 577 unionized employees,
representing construction and maintenance employees, customer representatives,
service workers, and clerical employees (excluding persons in managerial,
professional, or supervisory positions). This agreement became effective on May
1, 2003, and remains effective through April 30, 2008. It provides for an
average annual general wage increase of 3.5% and certain additional fringe
benefits.
Subsidiary of Central Hudson - Phoenix Development Company, Inc.: Phoenix,
a New York corporation, is a wholly owned subsidiary of Central Hudson. Phoenix
was incorporated in 1950 to hold or lease real property for future use by
Central Hudson and to participate in energy-related ventures. Currently,
Phoenix's assets are not significant.
COMPETITIVE BUSINESS SUBSIDIARIES
As of December 31, 2002, the effective date of the restructuring described
under the caption "Corporate Structure" of this Item 1, CHEC became the holding
company parent of the competitive business subsidiaries.
CHEC and its Subsidiaries
Central Hudson Enterprises Corporation: CHEC, a New York corporation, is a
wholly owned subsidiary of Energy Group. CHEC has been engaged in the business
of marketing electricity, natural gas, petroleum products, and related services
to retail and wholesale customers; conducting energy audits; and providing
services including, but not limited to, the design, financing, installation and
maintenance of energy conservation measures and generation systems for private
businesses, institutions, and government entities. CHEC has also participated in
cogeneration, small hydroelectric, alternate fuel, and energy production
projects in Connecticut, New Jersey, New Hampshire, and New York.
5
Griffith Energy Services, Inc.: Griffith, a New York corporation, is a
wholly owned subsidiary of CHEC. Griffith is an energy services company engaged
in the distribution of heating oil, gasoline, diesel fuel, kerosene, and
propane, and the installation and maintenance of heating, ventilating, and air
conditioning ("HVAC") equipment in Virginia, West Virginia, Maryland, Delaware,
Pennsylvania, and in Washington, D.C. Since being acquired by CHEC in November
2000, Griffith has acquired assets of ten regional fuel oil, propane, and
related services companies.
SCASCO, Inc.: SCASCO, a Connecticut corporation, is a wholly owned
subsidiary of CHEC. SCASCO is an energy services company engaged in the
distribution of heating oil, gasoline, diesel fuel, kerosene, and propane, and
the installation and maintenance of electrical services and HVAC equipment in
the states of Connecticut, Massachusetts, and New York. On October 31, 2003,
SCASCO completed the sale of certain assets and liabilities of its natural gas
unit. See Note 5 - "Acquisitions, Divestitures and Discontinued Operations."
Environmental Quality Regulation
Central Hudson and certain of the competitive business subsidiaries are
subject to regulation by federal, state and, to some extent, local authorities
with respect to the environmental effects of their operations, including
regulations relating to air and water quality, noise, hazardous wastes, toxic
substances, protection of vegetation and wildlife, and limitations on land use.
Environmental matters may expose both Central Hudson and these competitive
business subsidiaries to potential liability that, in certain instances, may be
imposed without regard to fault or may be premised on historical activities that
were lawful at the time they occurred. Central Hudson and the competitive
business subsidiaries monitor their activities in order to determine the impact
of their activities on the environment and to comply with applicable
environmental laws and regulations.
The principal environmental areas to which Central Hudson and certain of
the competitive business subsidiaries are subject are generally as follows:
Air: Central Hudson's South Cairo and Coxsackie combustion turbines are
subject to the Clean Air Act Amendments of 1990 ("Clean Air Act Amendments"),
which address attainment and maintenance of national air quality standards,
including control of particulate emissions from fossil-fueled electric
generating plants and emissions that affect "acid rain" and ozone. Both of the
facilities complied with the Clean Air Act Amendments during 2003. See Note 13 -
"Commitments and Contingencies," under the caption "Environmental Matters"
regarding the investigation by the U. S. Environmental Protection Agency ("EPA")
into the compliance of electric generating plants formerly owned by Central
Hudson.
Water: Central Hudson and certain of the competitive business subsidiaries
are required to comply with applicable federal and state laws and regulations
governing the discharge of pollutants into waterways and ground water.
The discharge of any pollutants into waters of the United States is
prohibited except in compliance with a permit issued by the EPA under the
National Pollutant Discharge Elimination System ("NPDES") established under the
Clean Water Act. Likewise, under the New York Environmental Conservation Law,
pollutants cannot be discharged into state waters without a
6
State Pollutant Discharge Elimination System ("SPDES") permit, issued with
regard to activities in New York by the New York State Department of
Environmental Conservation ("DEC") and for activities in other states by the
relevant state's environmental regulatory agency. Issuance of a SPDES permit
satisfies the NPDES permit requirement.
Central Hudson has SPDES permits for its Eltings Corners maintenance and
warehouse facility and for its Rifton Recreation and Training Center, both in
New York. No other SPDES permits are required for Central Hudson's operations.
Griffith has SPDES permits for its Frederick Bulk Plant, its Westminster Bulk
Plant, its S. L. Bare Bulk Plant, its R. S. Leitch Bulk Plant, and its Cheverly,
Maryland office. Griffith also has storm water discharge permits for its
Charlestown, West Virginia bulk storage plant and its Martinsburg, West Virginia
bulk storage plant. SCASCO does not require SPDES permits for its operations.
See Note 13 under the caption "Environmental Matters" regarding Central
Hudson's application to the DEC for a SPDES permit for its Neversink
Hydroelectric Station.
Toxic Substances and Hazardous Wastes: Central Hudson and certain of the
competitive business subsidiaries are subject to federal and state laws and
regulations relating to the use, handling, storage, treatment, transportation,
and disposal of industrial, hazardous, and toxic wastes. See Note 13 -
"Commitments and Contingencies," under the caption "Environmental Matters"
regarding, among other things, former manufactured gas plants, the Orange County
Landfill, and Consolidated Iron Works.
Other: Central Hudson expenditures attributable, in whole or in
substantial part, to environmental considerations totaled $4.4 million in 2003,
of which approximately $2.0 million was capitalized and $2.4 million was charged
to expense. It is estimated that these expenditures will total approximately
$4.5 million in 2004.
Expenditures attributable, in whole or in substantial part, to
environmental considerations for the competitive business subsidiaries totaled
$169,000 in 2003, all of which was applied to capital projects. It is estimated
that these expenditures will total less than $50,000 in 2004.
Regarding environmental matters, except as described in Note 13 -
"Commitments and Contingencies," under the subcaption "Environmental Matters,"
neither Energy Group, Central Hudson, nor the competitive business subsidiaries
are involved as defendants in any material litigation, administrative
proceeding, or investigation and, to the best of their knowledge, no such
matters are threatened against any of them.
AVAILABLE INFORMATION
Energy Group files annual, quarterly, and special reports, proxy
statements, and other information with the SEC. Central Hudson files annual,
quarterly, and special reports and other information with the SEC. The public
may read and copy any documents each company files at the SEC's Public Reference
Room at 450 Fifth Street N.W., Washington, D.C. 20549. The public may obtain
information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. SEC filings are also available to the public from the SEC's
Internet website at http://www.sec.gov.
7
Energy Group makes available free of charge on or through its Internet
website at www.chenergygroup.com its annual reports on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K, and amendments to those
reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange
Act as soon as reasonably practicable after it electronically files such
material with, or furnishes it to, the SEC. Energy Group's governance
guidelines, Code of Business Conduct and Ethics and the charters of its Audit,
Compensation, Governance and Nominating, and Strategy and Finance Committees are
available on Energy Group's Internet site at www.chenergygroup.com. The
governance guidelines, the Code of Business Conduct and Ethics, and the charters
may be obtained by writing to the Corporate Secretary, CH Energy Group, Inc.,
284 South Avenue, Poughkeepsie, New York 12601-4879.
8
Executive Officers
All executive officers of Energy Group are elected or appointed annually
by its Board of Directors. There are no family relationships among any of the
executive officers of Energy Group or its subsidiaries. The names of the current
executive officers of Energy Group, their positions held and business experience
during the past five years and ages (at December 31, 2003) are as follows:
Executive Age Current and Prior Positions Date Commenced
- -----------------------------------------------------------------------------------------------------------------------------------
Executive Officers of Energy Group
Paul J. Ganci(1) 65 Director, Chairman of the Board (a) (b) (c) July 1, 2003
Director, Chairman of the Board, President, and Chief
Executive Officer (c) April 2002
Chairman of the Board and Chief Executive Officer (a) (b) (c) November 2000
Director, Chairman of the Board, President and Chief
Executive Officer (a) (b) (c) November 1999
Chairman of the Board and Chief Executive Officer (a) April 1999
President and Chief Executive Officer (a) August 1998
Director (a) January 1989
Steven V. Lant (1) 46 Director, President, and Chief Executive Officer (b) (c) July 1, 2003
Director and Chief Executive Officer (a) July 1, 2003
Director, Chief Operating Officer (c) February 2002
and Chief Financial Officer (a) (b) (c) June 2001
Director (a) (b) December 1999
Chief Financial Officer and Treasurer (a) (b) November 1999
Chief Financial Officer, Treasurer and Corporate Secretary (a) November 1998
Carl E. Meyer (2) 56 Director, President and Chief Operating Officer (a) December 1999
Executive Vice President (c) November 1999
President and Chief Operating Officer (a) April 1999
Executive Vice President (a) April 1998
9
Age at
Executive 12/31/03 Current and Prior Positions Date Commenced
- ------------------------------------------------------------------------------------------------------------------------------------
Executive Officers of Energy Group (Cont'd)
Arthur R. Upright(2) 60 Director(a) December 1999
Director(b) November 1999
Senior Vice President(a) (c) November 1999
Senior Vice President - Regulatory Affairs, Financial
Planning & Accounting(a) November 1998
Joseph J. DeVirgilio, Jr.(1) 52 Executive Vice President(b) January 2003
Senior Vice President(a) (b) (c) October 2002
Senior Vice President(a) November 1998
Christopher M. Capone (1) 41 Chief Financial Officer and Treasurer (a) (b) (c) September 2003
Treasurer (a) (c) April 2003
Managing Director, Furman Selz / ING March 2002
Treasurer(a) (b) (c) June 2001
Assistant Treasurer - Investor Relations(a) (c) March 2000
Vice President/Division Head, Personal Fixed
Income Division, Bank of New York December 1998
Donna S. Doyle(2) 55 Director(b) June 2002
Vice President - Accounting and Controller(a) (c) November 1999
Controller(a) April 1995
Denise D. VanBuren(2) 42 Vice President - Corporate Communications and Community
Relations(a) (c) November 2000
Assistant Vice President - Corporate Communications(a) November 1999
Manager - Corporate Communications(a) October 1998
Lincoln E. Bleveans (1) 36 Secretary and Assistant Treasurer (a) (c) January 2003
Secretary (b) January 2003
Vice President - Greene Point September 2000
Senior Director - Structured Investments, Dynegy
Marketing and Trade, Inc. February 2000
Managing Director - Development, Illinova Generating Company December 1998
10
(1) Executive is an officer of Energy Group, Central Hudson, and CHEC.
(2) Executive is an officer of Energy Group and Central Hudson.
(a) For Central Hudson
(b) For CHEC
(c) For Energy Group
ITEM 2 - PROPERTIES
Energy Group has no significant properties other than those of Central
Hudson and the competitive business subsidiaries.
CENTRAL HUDSON
Electric: Central Hudson owns electric generating facilities (described in
the table below) and substations having an aggregate transformer capacity of
4.47 million kilovolt amps. Central Hudson's electric transmission system
consists of 586 pole miles of line and the electric distribution system consists
of 7,679 pole miles of overhead lines and 1,124 trench miles of underground
lines.
The aggregate net capability of Central Hudson's electric generating
plants as of December 31, 2003, the net output of each plant for the year ended
December 31, 2003, and the year each plant was placed in service or
rehabilitated are as set forth below:
11
MW* 2003 Unit
Electric Year Placed Net Capability Net Output
Generating In Service/ (2003) (2002-2003) Megawatthour
Plant Type of Fuel Rehabilitated Summer Winter ("MWh")
- ------------ ------------ ------------- ------ ----------- ------------
Neversink** Water 1953 20.5 20.0 62,835
Hydro Station
Dashville Water 1920 5.3 5.5 24,630
Hydro Station
Sturgeon Pool Water 1924 15.8 15.5 84,131
Hydro Station
High Falls Water 1986 3.3 3.0 11,427
Hydro Station
Coxsackie Gas Kerosene or 1969 19.6 24.4 1,232
Turbine ("GT") Natural Gas
So. Cairo GT Kerosene 1970 15.6 22.4 2,411
Groveville
Hydro Station Water 2000 0.8 0.8 2,020
---- ---- -------
Total 80.9 91.6 188,686
==== ==== =======
* Reflects maximum one-hour net capability of Central Hudson's electric
generating plants and therefore does not include firm purchases or sales.
** Central Hudson's ownership interest in the Neversink Hydro Station
("Neversink") is governed by an agreement between Central Hudson and the
New York City ("NYC") Board of Water Supply ("BWS") dated April 21, 1948.
This agreement provides for the transfer of Central Hudson's ownership
interest in Neversink, which has a book value of zero, to the BWS on
December 31, 2003. The parties are discussing the transfer of Central
Hudson's ownership interest in Neversink and are negotiating the terms of
an interim agreement with respect to the ownership and operation of
Neversink subsequent to December 31, 2003. There can be no assurance that
such an agreement will be reached.
12
Load and Capacity: Central Hudson's maximum one-hour demand within its own
territory for the year ended December 31, 2003, occurred on June 26, 2003, and
amounted to 1,078 megawatts ("MW"). Central Hudson's maximum one-hour demand
within its own territory for that part of the 2003-2004 winter capability period
through January 31, 2004, occurred on January 15, 2004, and amounted to 974 MW.
As a result of the sales of Central Hudson's interests in its major
generating assets in 2001, Central Hudson owns minimal generating capacity and
relies on purchased capacity and energy from third-party providers to meet the
demands of its full service customers. To partially supply its full service
customers, Central Hudson entered into a transition power agreement with an
affiliate of Dynegy Power Corporation, Inc. ("Dynegy") for the period from
January 30, 2001, to and including October 31, 2003, for the purchase of
capacity and energy. Central Hudson exercised its option to extend this contract
to and including October 31, 2004. This contract is "financially firm" in that
Dynegy is required to supply electricity under the terms of the contract
regardless of the operational status of its Danskammer Plant and its Roseton
Plant, both sold by Central Hudson to Dynegy in 2001. For more information, see
Note 2 - "Regulatory Matters."
Central Hudson also entered into an agreement with Constellation, Inc.
("Constellation") to purchase capacity and energy from the Nine Mile 2 Plant for
a ten-year period beginning November 7, 2001, and ending November 30, 2011. The
agreement is "unit contingent" in that Constellation is only required to supply
electricity if the Nine Mile 2 Plant is operating. Central Hudson sold its
interest in the Nine Mile 2 Plant to Constellation in 2001.
In the case of both contracts, capacity and energy will be purchased at
defined prices that escalate over the lives of the respective contracts.
On November 12, 2002, Central Hudson entered into agreements with Entergy
Nuclear Indian Point 2 LLC and Entergy Nuclear Indian Point 3 LLC to purchase
energy (but not capacity) on a unit contingent basis at defined prices for a
period from January 1, 2005, to and including December 31, 2007. On April 23,
2003, Central Hudson entered into an agreement with Entergy Nuclear Fitzpatrick
LLC to purchase energy (but not capacity) on a unit contingent basis at defined
prices from January 1, 2004, to and including December 31, 2004.
The following table compares required capacity with currently existing
resources of Central Hudson by summer and winter capability periods for 2004 and
2005. Central Hudson intends to eliminate any capacity shortfalls through
additional purchases.
13
Forecasted UCAP
Peak - Reqmts. Available Excess of
Total for Peak UCAP UCAP Over
Delivery Loads Capacity NYISO (6)
Capability Rqts. (MW) (MW) (MW) Rqts.
Period (1) (2) (3) (4) (5) (MW)(3) Percent (3)
----------- ----------- ---------- ---------- ---------- -----------
2004 Summer 1,140.1 1,101 1,105 4 .01%
2004-5 Winter 974 1,101 543 (558) (50.7%)
(1) Total delivery requirements include requirements for both full service
(delivery and energy) and retail access (delivery only) customers.
(2) Unforced capacity ("UCAP") is generation capacity adjusted for forced
outages. Summer period UCAP requirements carry over to the following
winter period.
(3) Based on full service requirements.
(4) Owned capacity of 23.9 MW plus firm contract capacity of 18 MW as of
January 31, 2004, for the summer 2004 period.
(5) Owned capacity of 68.7 MW plus firm contract capacity of 18 MW as of
January 31, 2004, for the winter 2004-2005 period.
(6) "NYISO" is the New York Independent System Operator, which oversees the
bulk electricity transmission system in New York State.
Natural Gas: Central Hudson's natural gas system consists of 161 miles of
transmission pipelines and 1,051 miles of distribution pipelines.
For the year ended December 31, 2003, the total amount of natural gas
purchased by Central Hudson from all sources was 11,081,776 thousand cubic feet
("Mcf").
Central Hudson also owns two propane-air mixing facilities for emergency
and peak-shaving purposes, one located in Poughkeepsie, New York, and the other
in Newburgh, New York. These facilities, in aggregate, are capable of supplying
8,000 Mcf per day with propane storage capability adequate to provide maximum
facility output for up to three consecutive days.
The peak daily demand for natural gas of Central Hudson's customers for
the year ended December 31, 2003, and for that part of the 2003-2004 heating
season through January 31, 2004, occurred on January 15, 2004, and amounted to
123,918 Mcf Central Hudson's firm peak day natural gas capability in the
2003-2004 heating season was 122,033 Mcf, which excludes approximately 15,000
Mcf of transport customer deliveries.
Other Central Hudson Matters: Central Hudson's electric generating plants
and important property units are generally held by it in fee simple, except
certain rights-of-way and a portion of the property used in connection with
hydroelectric plants consisting of flowage or other riparian rights. Certain of
the Central Hudson properties are subject to rights-of-way and easements that do
not interfere with Central Hudson's operations. In the case of certain
distribution lines, Central Hudson owns only a partial interest in the poles
upon which its wires are installed, and the remaining interest is owned by
various telecommunications companies. In addition, certain electric and natural
gas transmission facilities owned by others are used by Central Hudson under
long-term contract.
14
All of the physical properties of Central Hudson, other than property such
as material and supplies and Central Hudson franchises, are from time to time
subject to liens for current taxes and assessments which Central Hudson pays
regularly and when due.
During the three-year period ended December 31, 2003, Central Hudson made
gross property additions of $179.7 million and property retirements and
adjustments of $802.7 million, resulting in a net decrease (including
Construction Work in Progress) in utility plant of $623.0 million, or 38%. This
reduction is due to the sale of Central Hudson's interests in its major
generating assets.
CHEC
Griffith
As of December 31, 2003, Griffith owned or leased several office and bulk
storage locations. These locations are located throughout Maryland, Delaware,
Virginia, West Virginia and Pennsylvania. Bulk storage tanks have typical
capacities from 106,000 gallons up to in excess of 1.2 million gallons. Griffith
leases its corporate headquarters in Cheverly, Maryland.
SCASCO
As of December 31, 2003, SCASCO owned or leased several office, warehouse
and bulk storage facilities located throughout Connecticut. The bulk storage
tanks have typical capacities of between 107,000 and 400,000 gallons. SCASCO
owns its corporate headquarters in Winsted, Connecticut.
ITEM 3 - LEGAL PROCEEDINGS
For a discussion of certain legal proceedings and certain administrative
matters involving Central Hudson and the competitive business subsidiaries, see
Note 13 - "Commitments and Contingencies," which discussion is incorporated
herein by reference.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
fourth quarter of the fiscal year ended December 31, 2003.
15
PART II
ITEM 5 - MARKET FOR ENERGY GROUP'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
For information regarding the market for Energy Group's Common Stock and
related stockholder matters, see Item 7 of this 10-K Annual Report under the
captions "Capital Resources and Liquidity - Financing Program of Energy Group
and Its Subsidiaries" and "Common Stock Dividends and Price Ranges" and Note 8 -
"Capitalization."
Under applicable statutes and their respective Certificates of
Incorporation, Energy Group may pay dividends on shares of its common stock and
Central Hudson may pay dividends on its common stock and its preferred stock, in
each case only out of surplus.
16
ITEM 6 - SELECTED FINANCIAL DATA OF ENERGY GROUP AND ITS SUBSIDIARIES
FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA*
(ENERGY GROUP)
(In Thousands)
2003 2002 2001 2000 1999**
---- ---- ---- ---- ----
Operating Revenues
Electric .......................................... $ 457,395 $ 427,978 $428,346 $ 531,732 $ 427,729
Natural gas ....................................... 123,306 105,343 110,296 105,353 93,099
Competitive business subsidiaries ................. 225,983 162,520 192,061 111,027 45,157
--------- --------- -------- --------- ---------
Total .......................................... 806,684 695,841 730,703 748,112 565,985
--------- --------- -------- --------- ---------
Operating Expenses
Operations ........................................ 664,816 562,322 573,178 526,816 354,940
Depreciation and amortization ..................... 33,611 31,230 35,637 51,453 48,246
Taxes other than income tax ....................... 31,956 38,606 50,402 54,151 64,510
Federal and State income tax ...................... 27,279 20,746 17,779 37,229 27,772
--------- --------- -------- --------- ---------
Total .......................................... 757,662 652,904 676,996 669,649 495,468
--------- --------- -------- --------- ---------
Operating Income ................................... 49,022 42,937 53,707 78,463 70,517
--------- --------- -------- --------- ---------
Other Income
Allowance for equity funds used during construction 436 591 429 -- --
Federal and State income tax ...................... (3,156) (1,548) 21,117 (986) (371)
Other - net ....................................... 21,035 21,249 8,337 10,626 12,051
--------- --------- -------- --------- ---------
Total .......................................... 18,315 20,292 29,883 9,640 11,680
--------- --------- -------- --------- ---------
Income before Interest and Other Charges ........... 67,337 63,229 83,590 88,103 82,197
Interest Charges ................................... 21,965 24,615 29,525 33,900 30,394
Preferred Stock Dividends of Central Hudson ........ 1,387 2,161 3,230 3,230 3,230
--------- --------- -------- --------- ---------
Net income from continuing operations .............. 43,985 36,453 50,835 50,973 48,573
Net Gain on Discontinued Operations ................ -- 4,828 -- -- --
--------- --------- -------- --------- ---------
17
FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA*
(ENERGY GROUP CONT'D)
(In Thousands)
2003 2002 2001 2000 1999**
---- ---- ---- ---- ------
Net Income .................................. $ 43,985 $ 41,281 $ 50,835 $ 50,973 $ 48,573
Dividends Declared on Common Stock .......... 34,093 35,095 35,342 35,945 36,422
---------- ---------- ---------- ---------- -----------
Amount Retained in the Business ............. 9,892 6,186 15,493 15,028 12,151
Common Stock Retirement ..................... -- -- -- -- (12,642)
Retained Earnings - beginning of year ....... 169,503 163,317 147,824 132,796 133,287
---------- ---------- ---------- ---------- -----------
Retained Earnings - end of year ............. $ 179,395 $ 169,503 $ 163,317 $ 147,824 $ 132,796
========== ========== ========== ========== ===========
Common Stock
Average shares outstanding - basic (000's) . 15,831 16,302 16,362 16,716 16,862
Average shares outstanding - diluted (000's) 15,835 16,316 16,370 16,725 16,862
Earnings per share on average shares
outstanding - basic ....................... $ 2.78 $ 2.53 $ 3.11 $ 3.05 $ 2.88
Earnings per share on average shares
outstanding - diluted ..................... $ 2.77 $ 2.51 $ 3.09 $ 3.04 $ 2.88
Dividends declared per share ............... $ 2.16 $ 2.16 $ 2.16 $ 2.16 $ 2.16
Book value per share (at year-end) ......... $ 30.80 $ 30.31 $ 30.33 $ 29.38 $ 28.80
Total Assets (000's) ........................ $1,300,492 $1,282,907 $1,257,298 $1,593,373 $ 1,393,499
Long-term Debt (000's) ...................... 278,880 269,877 216,124 320,370 335,451
Cumulative Preferred Stock (000's) .......... 21,030 33,530 56,030 56,030 56,030
Common Equity (000's) ....................... 485,424 486,915 496,309 480,742 484,406
* For additional information related to the impact of acquisitions and
dispositions on the above, this summary should be read in conjunction with
Item 7 - "Management Discussion and Analysis of Financial Condition and
Results of Operations" and Item 8 - Note 6 "Acquisitions, Divestitures and
Discontinued Operations" in each case of this 10-K Annual Report.
** Holding company was formed December 1999; 1999 has therefore been
reclassified to reflect fully consolidated results for comparative
purposes.
Certain 1999-2002 amounts reclassified for comparative purposes.
18
FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA*
(CENTRAL HUDSON)
(In Thousands)
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
Operating Revenues
Electric .................... $ 457,395 $ 427,978 $ 428,346 $ 531,732 $ 427,729
Natural gas ................. 123,306 105,343 110,296 105,353 93,099
--------- --------- --------- --------- ---------
Total ..................... 580,701 533,321 538,642 637,085 520,828
--------- --------- --------- --------- ---------
Operating Expenses
Operations .................. 452,314 406,705 394,581 423,545 311,165
Depreciation and amortization 27,275 25,350 26,813 47,914 46,913
Taxes, other than income tax 31,725 38,396 50,170 53,993 63,986
Federal and State income tax 25,478 21,056 17,743 36,374 27,852
--------- --------- --------- --------- ---------
Total ..................... 536,792 491,507 489,307 561,826 449,916
--------- --------- --------- --------- ---------
Operating Income ............. 43,909 41,814 49,335 75,259 70,912
--------- --------- --------- --------- ---------
Other Income
Allowance for equity funds
used during construction ... 436 591 429 -- --
Federal and State income tax (1,503) (634) 25,380 (776) (292)
Other - net ................. 17,998 15,481 (2,458) 8,960 10,875
--------- --------- --------- --------- ---------
Total ..................... 16,931 15,438 23,351 8,184 10,583
--------- --------- --------- --------- ---------
Income before Interest Charges 60,840 57,252 72,686 83,443 81,495
Interest Charges ............. 21,965 24,728 28,508 30,848 29,614
--------- --------- --------- --------- ---------
19
FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA,*
(CENTRAL HUDSON CONT'D)
(In Thousands)
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
Net Income ................................. $ 38,875 $ 32,524 $ 44,178 $ 52,595 $ 51,881
Dividends Declared on Cumulative Pref. Stock 1,387 2,161 3,230 3,230 3,230
---------- ---------- --------- ----------- -----------
Income Available for Common Stock .......... 37,488 30,363 40,948 49,365 48,651
Dividend Declared on Common Stock .......... -- -- -- -- 27,317
Dividends Declared to Parent-Energy Group .. 34,162 30,000 145,642 27,600 7,000
---------- ---------- --------- ----------- -----------
Amount Retained in the Business ............ 3,326 363 (104,694) 21,765 14,334
Reverse Equity Transfer .................... -- -- -- 26,000 --
Common Stock Retirement .................... -- -- -- -- (12,642)
Transfer of Competitive Business
Subsidiaries to Energy Group .............. -- -- -- (2,500) (65,698)
Transfer of Property to Energy Group ....... -- -- (75) -- --
Retained Earnings - beginning of year ...... 10,140 9,777 114,546 69,281 133,287
---------- ---------- --------- ----------- -----------
Retained Earnings - end of year ............ $ 13,466 $ 10,140 $ 9,777 $ 114,546 $ 69,281
========== ========== ========= =========== ===========
Total Assets ............................... $1,043,375 $1,018,766 $ 983,359 $ 1,394,698 $ 1,316,990
Long-term Debt ............................. 278,880 269,877 215,874 320,370 335,451
Cumulative Preferred Stock ................. 21,030 33,530 56,030 56,030 56,030
Common Equity .............................. 267,796 264,143 263,277 466,230 420,891
* This summary should be read in conjunction with the Consolidated Financial
Statements and Notes thereto included in Item 8 of this 10-K Annual
Report.
Certain 1999-2002 amounts reclassified for comparative purposes.
20
ITEM 7 - 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 Energy Group and its
subsidiaries over the past three years. The Consolidated Financial Statements
and the Notes thereto contain additional data. For the twelve months ended
December 31, 2003, 57% of Energy Group's operating revenues were derived from
Central Hudson's electric service, 15% from Central Hudson's natural gas
service, and 28% from the competitive business subsidiaries.
EXECUTIVE SUMMARY
The past five years have been turbulent times for the electric and natural
gas utility industries. Although there was some recovery in 2003, numerous
utilities experienced declining credit quality, and many utility investors
experienced large losses in the market value of their securities. Even today,
there is uncertainty regarding the direction of deregulation and how regulators
will respond to customer expectations for regulated utilities to deliver higher
levels of reliability and customer service.
From the very beginning of deregulation in 1999, Energy Group has remained
focused on considering all options for sustaining and increasing shareholder
value in today's fiercely competitive capital markets. In all of its endeavors,
Energy Group is committed to maintaining strong credit quality by carefully
assessing and managing risk.
Although each succeeding year has been filled with surprises, Energy Group
has stayed on a steady course and provided its shareholders with an attractive,
total return, consisting of stock price appreciation and dividends paid. In
fact:
o Energy Group's total return during the last three years, a period of
market instability, placed it in the top 36% of the Edison Electric
Institute's Index of Electric Utilities.
o Central Hudson's delivery prices for all classes of customers are the
lowest in New York State, and household prices are at least 50% below the
statewide average.
o Electric service reliability has steadily improved, as has the number of
highly satisfied customers.
o Energy Group's credit rating is among the highest in the industry.
A Strategic Assessment
Energy Group and its stock have outperformed the industry by staying away
from risky ventures and, when required to do so, responding incisively and
decisively to changing markets. As a result, cash of $100 million and borrowing
capacity of at least another $125 million is available to deploy in businesses
that will increase shareholder value over time.
21
As reported at the Annual Shareholders Meeting in April 2003, major
planning initiatives are being undertaken on three fronts to grow earnings, to
increase cash flow, and to maintain the dividend at the current level in the
foreseeable future.
o First, management is seeking to utilize available cash
reserves and debt capacity to selectively acquire electric
generating and/or natural gas pipeline assets and passive
investments that meet its criteria for profitability, risk,
and diversification.
o Secondly, the goal is to grow earnings internally at Energy
Group's fuel oil delivery companies, Griffith and SCASCO, by
expanding profitable product lines. At Central Hudson,
increased revenues, which are tied to the growing economy of
the region, will be fully taken advantage of.
o Lastly, as has been done so effectively over the last five
years, Energy Group will invest in technology, in improved
internal processes, and in the training and development of its
employees to continuously maintain competitive prices, higher
profit margins, and customer satisfaction.
Central Hudson Gas & Electric Corporation -
A Challenge to Invest to Meet Customer Expectations
Central Hudson's contribution to earnings in 2003 totaled $2.37 per share,
compared to $1.86 per share in 2002.
The increased frequency and severity of storms in 2003 resulted in
restoration expenses of $7.1 million, or 29 cents per share, which was twice the
average of the last ten years. In each case, however, investments made in
more-extensive tree trimming and the rebuilding of selected portions of the
system reduced the impact and the duration of interruptions on Central Hudson's
customers.
Customer satisfaction increased in 2003 due largely to efforts to enhance
reliability in those areas experiencing above-average interruptions; improved
call center performance; and an increased awareness by Central Hudson's
customers that, on average, households in New York State pay 75% more for
electric delivery service than the prices paid by Central Hudson customers. An
outage management system, which enables better predictability of restoration
times during storms, has also been well received by customers, who are
increasingly expressing their willingness to pay more to raise the standard of
reliability.
Importantly, the Hudson Valley is one of the fastest-growing regions in
New York State, and it maintains an exceptionally favorable trend in employment.
Population growth has been boosted by an ever-increasing migration of
residential customers from the New York City metropolitan area. These new
residents are attracted by the opportunities and desirable living choices in
pleasant surroundings that are available in the Hudson River Valley within
commuting distance of New York City.
Central Hudson's extremely favorable electric delivery pricing is a
competitive advantage, and one of the important amenities that attract high-tech
business customers to locate in the region.
22
The new computer-age electronic economy has dramatically increased
customer expectations for higher levels of electric service reliability. The
blackout of August 14, 2003, which affected 50 million people, further
highlighted a compelling need to increase the capacity of the regional electric
transmission grid.
So far, Central Hudson's electric delivery system has met the challenge.
During the last five years, Central Hudson has invested more than $193 million
to upgrade and expand the wires, cables and systems that deliver electricity to
its customers' homes and businesses. But, the system is being strained for one
basic reason: The demands for service reliability and quality increase daily, as
electronic devices proliferate in homes, hospitals, offices, security systems,
and information networks - just to name a few.
The standards of yesterday are simply not enough, as growing demands are
placed on the electric delivery grid to meet the needs of an increasingly
high-technology economy and lifestyle.
In focused surveys, Central Hudson customers have expressed their
willingness to pay more for enhanced reliability. Equally important, electric
service reliability is an essential need for prospective high-technology
customers who are considering expanding or locating their businesses in this
region.
Additional capital will be invested to meet the expectations of current
and future customers for higher standards of reliability, provided that state
and federal regulators provide Central Hudson with a reasonable opportunity to
earn a competitive return on its investment.
Clearly, investments made in the transmission and distribution wire
networks that deliver electricity will benefit customers in three ways: First,
they provide the capacity to meet the needs of a growing economy, secondly, they
improve reliability. And, lastly, they are likely to stabilize supply prices of
electricity by reinforcing the transmission lines that connect this region to
the lower-cost sources of electricity in upstate New York, as well as
neighboring power regions in the United States and Canada.
Central Hudson Enterprises Corporation - Restructured
CHEC, Energy Group's competitive business subsidiary, was restructured to
focus on delivery of fuel oil, propane and related services to its 85,000 retail
customers in the Baltimore/Washington, D.C. metro area and in southern New
England.
In 2003, earnings from fuel delivery and services were 18 cents per share,
compared to 4 cents per share in 2002.
As part of the restructuring, expenses were reduced through consolidation,
process redesign, and more effective fuel purchases. Product and service
offerings are also being reevaluated to create increased margin and customer
value parameters that all brands must
23
meet in their respective markets. Business lines and service locations that do
not meet these thresholds will be reformed, consolidated, or shut down.
As CHEC increases its effectiveness in its markets, consideration will be
given to acquisitions that can be consolidated into CHEC's existing structure.
By 2006, the goal is to achieve a return on shareholder equity of 10% or more,
compared to the current 5.3%.
COMPETITION/DEREGULATION
Holding Company
Energy Group is the holding company parent corporation of Central Hudson
and CHEC, as described under the caption "Subsidiaries of Energy Group" in Item
1 of this 10-K Annual Report. Energy Group's operations are conducted through
Central Hudson, CHEC, and the other competitive business subsidiaries. Energy
Group's common stock trades on the New York Stock Exchange under the symbol
"CHG."
The holding company structure was instituted to permit quick response to
changes in the evolving competitive energy industry. The structure permits the
use of financing techniques that are better suited to the particular
requirements, characteristics, and risks of competitive operations without
affecting the capital structure or creditworthiness of Central Hudson. This
increases Energy Group's financial flexibility by allowing it to establish
different capital structures for each of its individual lines of business.
CHEC's Business Plan
CHEC's primary focus is fuel distribution and related services, and CHEC
expects such focus to continue. CHEC's fuel distribution subsidiaries, Griffith
and SCASCO, continue to explore opportunities to expand through both internal
growth and acquisitions, depending on financial performance and opportunities
available. There can be no assurance that such expansion opportunities will
exist, or if consummated, that they will be profitable.
Competitive Opportunities Proceeding Settlement Agreement
For a discussion of the Agreement approved by the PSC in its Competitive
Opportunities Proceeding and a discussion of the impact of the Agreement on
Energy Group's accounting policies, see the caption "Competitive Opportunities
Proceeding Settlement Agreement" in Note 2.
Sales of Major Generating Assets
For information on the sales of Central Hudson's major generating assets
in 2001, see Note 2 - "Regulatory Matters," under the caption "Sales of Major
Generating Assets." For information on the sale of CH Resources in 2002, see
Note 5 - "Acquisitions, Divestitures, and Discontinued Operations."
24
FERC Restructuring and Independent System Operator
For information with respect to the NYISO, the New York State Reliability
Council ("Reliability Council"), and FERC rulings relating to electric industry
restructuring, see Note 2 - "Regulatory Matters," under the caption "FERC
Restructuring and Independent System Operator."
Rate Proceedings - Electric and Natural Gas
For information regarding Central Hudson's most recent electric and
natural gas rate filings and the Order of the PSC issued in the proceedings
related to those filings, see Note 2 - "Regulatory Matters," under the caption
"Rate Proceedings - Electric and Natural Gas."
RESULTS OF OPERATIONS
The following discussion and analyses include explanations of significant
changes in revenues and expenses between 2002 results and 2003 results and
between 2001 results and 2002 results for both Energy Group and Central Hudson.
Additional information relating to changes between these years is provided in
the Notes.
Earnings
Earnings per share (basic) of Energy Group's common stock are shown after
provision for dividends on Central Hudson's preferred stock and are computed on
the basis of the average number of common shares outstanding during the subject
year. The number of average shares outstanding of Energy Group common stock, the
earnings per share (basic), and the rate of return earned on average common
equity are as follows:
2003 2002 2001
---- ---- ----
Average shares outstanding (000) .. 15,831 16,302 16,362
Earnings per share (basic) ........ $ 2.78 $ 2.53 $ 3.11
Return earned on common equity .... 9.0% 8.2% 10.4%
Consolidated basic earnings per share for Energy Group, were $2.78 for
2003 as compared to $2.53 in 2002, an increase of $.25 per share. The increase
in earnings reflects a $.51 per share increase from Central Hudson operations
due largely to increases in electric and natural gas net operating revenue, (net
of the cost of purchased electricity, natural gas and revenue taxes); an
increase in the amortization of shareholder benefits relating to the sale of
Central Hudson's interests in its major generating assets; the favorable effect
of the recording of regulatory carrying charges; a reduction of interest charges
and preferred stock dividends; and the positive impact of Energy Group's
repurchases of its common stock, further described in Note 8 - "Capitalization."
The increase in net revenues results from an increase in sales due to the colder
weather experienced in the early part of 2003 and customer growth, a reduction
in shared earnings, and the recording of previously deferred electric and
natural gas delivery revenues to income over the 12 months ended June 30, 2004.
The increase in net revenues was partially offset by an increase in operating
expenses, increased depreciation on utility plant
25
assets, and the effect of non-recurring income recorded in 2002 from the sale of
insurance stock. The stock was received due to the demutualization of certain
insurance companies through which Central Hudson provided employee benefits.
Earnings for CHEC decreased by $0.07 per share resulting largely from a
$0.29 per share reduction relating to the net gain recorded in 2002 from the
sale of CH Resources. The decrease in earnings was largely offset by an increase
in earnings from operations due to increased fuel oil distribution sales
attributable to the colder weather in 2003; and the acquisition of fuel oil
distribution companies in the fourth quarter of 2002 and in January 2003; and
increases in productivity and a related reduction in operating expenses. The
earnings from Griffith and SCASCO increased from $.04 per share in 2002 to $.18
per share in 2003. A nominal gain on the sale of CHEC's natural gas business
unit in October 2003 and the favorable impact of Energy Group's common stock
repurchase program also partially offset the reduction in earnings.
The increase in consolidated earnings was also partially offset by a $.19
per share reduction in earnings mainly from the liquidation of Energy Group's
Investment Program by July 2003, and the absence of favorable state income tax
adjustments recorded in 2002 related to the sale of the major generating assets
that took place in 2001. Proceeds from the liquidation of approximately $90
million were reinvested in lower yield money market instruments with lower
principal risk.
Consolidated basic earnings per share decreased $0.58 per share in 2002
when compared to 2001. This decrease resulted largely from the effect of
regulatory actions taken in 2001 in conjunction with the sale of Central
Hudson's interests in its major generating assets. These actions included the
recognition of tax benefits in 2001; a reduction in rate base related to the
sale of Central Hudson's interests in these assets; and an after-tax
contribution to Central Hudson's Customer Benefit Fund in 2001 (described in
Note 2 - "Regulatory Matters," under the captions "Summary of Regulatory Assets
and Liabilities" and "Rate Proceedings - Electric and Natural Gas"). The
reduction in earnings also reflects a decrease in interest and investment income
due to lower cash balances and rates of return; an increase in other operating
expenses for Central Hudson, primarily storm restoration costs due to increased
storm activity in 2002; and a decrease in Central Hudson's natural gas net
operating revenues (net of the cost of natural gas and revenue taxes) resulting
from lower sales due to milder weather.
The reduction in earnings per share from 2001 to 2002 was partially offset
by an increase in Central Hudson's electric net operating revenues (net of the
cost of purchased electricity, fuel used in the generation of electricity, and
revenue taxes); reductions in Central Hudson's interest charges and preferred
stock dividends; and an enhancement in earnings from a non-recurring item
recorded by Central Hudson. The increase in electric net operating revenues
results primarily from increased sales, due in part to hotter weather during the
summer months in 2002. Interest charges and preferred stock dividends were
reduced due to the redemption or repurchase of various long-term debt and
preferred stock issues in 2002 and 2001 using proceeds from the sale of Central
Hudson's interests in its major generating assets. The non-recurring item is
income that was recorded by Central Hudson in 2002 for the receipt
26
and subsequent sale of stock related to the demutualization of certain insurance
companies through which Central Hudson provided employee benefits.
Energy Group's earnings in 2002 were also enhanced by an increase in
earnings from CHEC, largely attributable to discontinued operations (described
in Note 5 - "Acquisitions, Divestitures, and Discontinued Operations"). A net
gain was realized for the May 2002 sale of CH Resources. This gain was partially
offset by one-time charges related to restructuring certain energy efficiency
contracts and lower earnings from sales by its fuel distribution subsidiaries
due to milder weather.
27
Operating Revenues
Total operating revenues of Energy Group increased $110.8 million, or 16%,
in 2003 as compared to 2002, and decreased $34.9 million, or 5%, in 2002 as
compared to 2001.
See the table below for details of the variations:
Increase or (Decrease) from Prior Year
-------------------------------------------------------------------------------------------
2003 2002
------------------------------------------- --------------------------------------------
Electric Gas Other Total Electric Gas Other Total
-------- -------- ------- --------- -------- -------- -------- --------
Operating Revenues (In Thousands)
Customer sales ......... $ 2,342 $ 2,465 $ -- $ 4,807 $(50,483) $(27,493) $ -- $(77,976)
Sales to other utilities (834) (4,213) -- (5,047) (4,983) 3,855 -- (1,128)
Energy cost adjustment . 14,796 19,767 -- 34,563 53,963 20,099 -- 74,062
Deferred revenues ...... 12,974 509 -- 13,483 1,495 (1,395) -- 100
Miscellaneous .......... 139 (565) -- (426) (360) (19) -- (379)
-------- -------- ------- --------- -------- -------- -------- --------
Subtotal .............. 29,417 17,963 -- 47,380 (368) (4,953) -- (5,321)
-------- -------- ------- --------- -------- -------- -------- --------
Competitive business
subsidiary sales ...... -- -- 63,463 63,463 -- -- (29,541) (29,541)
-------- -------- ------- --------- -------- -------- -------- --------
Total .............. $ 29,417 $ 17,963 $63,463 $ 110,843 $ (368) $ (4,953) $(29,541) $(34,862)
======== ======== ======= ========= ======== ======== ======== ========
28
Sales - Central Hudson
Central Hudson's revenues vary seasonally in response to weather. In
particular, electric revenues peak in the summer while natural gas revenues peak
in the winter.
Utility sales of electricity to full service customers within Central
Hudson's service territory, plus delivery of electricity supplied by others,
increased 3% in 2003 as compared to 2002. Sales to residential customers
increased 6%, sales to commercial customers increased 1% and sales to industrial
customers increased 3%. The across-the-board increase in delivery sales was due
largely to colder weather and a modest increase in the average number of
residential and commercial customers. Billing heating degree-days were 17%
higher than last year and 6% higher than normal.
Utility sales of natural gas to firm Central Hudson customers, plus
transportation of gas supplied by others, increased 19% in 2003 as compared to
the prior year. Residential and commercial sales, primarily space heating sales,
both increased by 21% due to the colder weather experienced in 2003 and modest
growth in the average number of customers. Industrial sales, representing
approximately 5% of total firm sales in 2003 and 6% in 2002, decreased slightly
by 1%. Interruptible sales decreased 37% due to a reduction in the sale of
natural gas for electric generation and to the curtailment of interruptible
service to meet increased demand from firm customers.
For 2002, sales of electricity to full service customers, plus delivery of
electricity supplied by others, increased 4% as compared to 2001. Sales to
residential customers increased 3% and sales to commercial customers increased
2% reflecting, in part, an increase in electricity usage due to hotter summer
weather in 2002. Cooling degree-days in 2002 were 12% higher than in 2001. Sales
to industrial customers increased 6%, reflecting, in substantial part, a
significant increase in usage by a single large industrial customer.
For 2002, sales of firm natural gas, plus transportation of natural gas
supplied by others, decreased 5% as compared to the prior year. Residential
sales decreased 7% while sales to commercial customers decreased 4%. Such sales,
comprised largely of sales for heating, decreased primarily as a result of
milder weather as billing heating degree-days in 2002 were 8% lower than in
2001. Industrial sales, representing approximately 6% of total firm sales in
2001 and 2002, decreased 10% while interruptible sales increased 20%.
Changes in sales from the prior year by major customer classification,
including interruptible natural gas sales, are set forth below. Also included
are the changes related to electricity delivery.
29
% Increase (Decrease) from Prior Year
----------------------------------------------
Electric (MWh(1)) Natural Gas (Mcf.(2))
------------------- ----------------------
2003 2002 2003 2002
---- ---- ---- ----
Residential .................. 6 3 21 (7)
Commercial ................... 1 2 21 (4)
Industrial ................... 3 6 (1) (10)
Interruptible ................ N/A N/A (37) 20
(1) "MWh" means megawatt-hour.
(2) "Mcf" Means thousand cubic feet of natural gas.
Because of sharing arrangements established for interruptible natural gas
sales and interruptible transportation of customer-owned natural gas, as
described under the caption "Incentive Arrangements" below, variations in these
sales from year to year typically have a minimal impact on earnings.
Incentive Arrangements
Under certain earnings sharing formulas approved by the PSC, Central
Hudson either shares with its customers certain revenues and/or cost savings
exceeding predetermined levels, or is penalized in some cases for shortfalls
from certain performance standards.
Earnings sharing formulas are currently effective for interruptible
natural gas sales, natural gas capacity release transactions, natural gas
reliability, electric service reliability, certain aspects of customer service
and satisfaction, and certain aspects of market participant satisfaction.
See Note 2 - "Regulatory Matters," under the caption "Rate Proceedings -
Electric and Natural Gas" for a description of earnings sharing formulas
approved by the PSC for Central Hudson.
The net results of these and previous earnings sharing formulas also had
the effect of increasing pretax earnings by $1.0 million, $0.1 million, and $0.2
million during 2003, 2002, and 2001, respectively, above the applicable sharing
thresholds.
30
Sales and Revenues - Competitive Business Subsidiaries
Sales
CHEC's sales of petroleum products increased by 27.0 million gallons, or
21%, to 153.9 million gallons in 2003 from 126.9 million gallons during 2002.
This increase was primarily due to colder weather as evidenced by a 12% average
increase in heating degree-days for 2003 as compared to 2002, and increased
sales as a result of acquisitions made in the fourth quarter of 2002 and in
January 2003.
In 2003, CHEC's sales of natural gas decreased by approximately 424,000
Mcf, or 19%, to 1,841,000 Mcf, as compared to 2,265,000 Mcf in 2002. This
decrease was primarily due to the sale of certain assets and liabilities of
SCASCO's natural gas business unit on October 31, 2003.
In 2002, sales of petroleum products increased by 4.8 million gallons, or
3.9%, to 126.9 million gallons from 122.1 million gallons in 2001. This increase
was the result of acquisitions. In 2002, sales of natural gas increased by
400,000 Mcf, or 21.1%, to 2.3 million Mcf from 1.9 million Mcf in 2001. This
increase was due to customer growth.
Revenues
Total revenues net of weather derivative contracts increased $64.4 million
from $161.6 million in 2002 to $226.0 million in 2003. Revenues from petroleum
products increased by $64.0 million, or 49.3%, to $194.0 million from $130.0
million in 2002. This increase was the result of increased sales volumes as a
result of acquisitions in the fourth quarter of 2002 and January 2003 and colder
weather in 2003 as compared to 2002. In 2003, natural gas revenues increased by
$2.2 million, or 19.1%, to $13.7 million from $11.5 million in 2002. This
increase was due primarily to higher wholesale prices for natural gas in 2003.
Partially offsetting the increase was a $2.1 million reduction in revenues from
CHEC's retail electric program which CHEC terminated in 2002.
Total revenues for CHEC decreased from $191.0 million in 2001 to $161.6
million in 2002. The reduction in revenues reflects, in substantial part, the
impact of the sale of CH Resources, which was sold in May 2002. Revenues and
expenses for CH Resources were eliminated from the results of continuing
operations beginning December 2001 in accordance with accounting principles
relating to discontinued operations. CH Resources' cumulative net operating loss
and the gain on its sale are reported separately from the results of continuing
operations in Energy Group's Consolidated Income Statement. The overall decrease
in revenues was partially offset by revenues from increased sales of petroleum
products due to acquisitions of fuel distribution businesses in the latter part
of 2001.
In 2002, revenues from petroleum products increased by $3.9 million, or
3.1%, to $130.0 million from $126.1 million in 2001. This increase was the
result of increased sales volumes as a result of acquisitions. In 2002, natural
gas revenues increased by $1.9 million, or 19.8%, to $11.5 million from $9.6
million in 2001. This increase was due to increased sales volume.
31
Operating Expenses - Central Hudson
The most significant elements of Central Hudson's operating expenses are
purchased electricity and purchased natural gas. In 2003, approximately 59% of
every revenue dollar related to sales of electricity was expended for the
combined cost of fuel used in electric generation and purchased electricity. The
corresponding percentage for the cost of purchased natural gas related to sales
of natural gas was 62%.
Approximately 59% in 2002 and 52% in 2001 of every revenue dollar related
to sales of electricity was expended for the combined cost of fuel used in
electric generation and purchased electricity. The corresponding figures for the
cost of purchased natural gas related to sales of natural gas were 59% and 57%,
respectively.
Central Hudson negotiated multi-year electricity purchase contracts with
the new owners of the major generating assets it divested. These purchases are
supplemented by purchases from the NYISO and other parties. For information
regarding these electricity purchase contracts, see Item 2 of this 10-K Annual
Report under the subcaption "Load and Capacity," Note 2 - "Regulatory Matters,"
under the caption "Sales of Major Generating Assets" and Note 3 - "Nine Mile 2
Plant."
Total utility operating expenses increased $45.3 million, or 9.2%, from
$491.5 million in 2002 to $536.8 million in 2003. Purchased electricity and
purchased natural gas increased by a total of $30.7 million due primarily to
increases in the wholesale cost of these commodities. The balance of operating
expenses, including income taxes, increased $14.6 million, reflecting a
significant increase in costs related to Central Hudson's Reliability and
Economic Development programs that are funded by the Customer Benefit Fund (see
Note 2 - "Regulatory Matters" for discussion on Customer Benefit Fund). The rise
in operating expenses also reflects increases in storm restoration and other
electric distribution and maintenance costs, uncollectible accounts, property
and other insurance costs, property taxes, and employee compensation and welfare
costs.
Operating expenses increased $2.2 million, or 0.4%, from $489.3 million in
2001 to $491.5 million in 2002. Purchased electricity and fuel used in electric
generation increased by $28.3 million, primarily as a result of the sale of
Central Hudson's interests in its major generating assets in January and
November of 2001. Purchased electricity costs for 2002 reflect the purchase of
substantially all of Central Hudson's energy requirements, compared to 79% of
these requirements in 2001. The increase in electric sales also contributed to
the increase in these costs. Partially offsetting the increase in operating
expenses is the elimination of operating costs for Central Hudson's major
generating assets and a reduction in purchased natural gas costs reflecting both
lower commodity prices and a reduction in sales.
Operating Expenses - CHEC
CHEC's operating expenses for 2003 increased $59.5 million, or 36.9%, from
$161.4 million in 2002 to $220.9 million in 2003. Operating expenses are
primarily the cost of petroleum and natural gas, which increased $53.9 million
for 2003 compared to 2002, due primarily to higher sales by Griffith and SCASCO
as a result of colder
32
weather in the first quarter of 2003 and acquisitions made in the fourth quarter
of 2002 and in January 2003. The cost of petroleum and natural gas also
increased due to higher wholesale market prices. Other operating expenses
increased primarily as a result of increased distribution costs and income taxes
due to these increased sales and acquisitions.
Operating expenses for CHEC decreased $26.3 million, from $187.7 million
in 2001 to $161.4 million in 2002, largely as a result of the sale of CH
Resources. This decrease was partially offset by increased operating expenses
due to additional acquisitions of fuel oil distribution companies. The cost of
purchased petroleum products increased by $3.0 million, or 3.3%, to $92.1
million from $89.1 million in 2001 from increased sales due to acquisitions of
fuel oil distribution companies. The cost of natural gas increased by $1.8
million, or 21.2%, to $10.3 million from $8.5 million in 2001 due to an increase
in sales.
Other Income
Other Income for Energy Group for 2003 decreased $2.0 million due
primarily to the liquidation of its Alternate Investment Program portfolio of
securities by July 2003 and the reinvestment of approximately $90 million into
lower yield, but lower risk, money market instruments. For discussion of the
Alternate Investment Program, see "Financing Program of Energy Group and its
Subsidiaries" in Item 6 of this 10-K Annual Report. The reduction is also
attributable to favorable New York State income tax adjustments recorded in
2002.
For Central Hudson, Other Income increased $1.5 million in 2003 mainly
reflecting increases in the amortization of shareholder benefits relating to the
sale of Central Hudson's interest in its major generating assets and the accrual
of regulatory carrying charges on accumulated balances related to pension
credits in customer rates. The increases were partially offset by a reduction in
interest income resulting primarily from a decrease in temporary cash
investments and the early settlement of a balance due to Central Hudson from the
sale of its interest in the Nine Mile 2 Plant. Also offsetting the increase was
the effect of non-recurring income recorded in 2002 that related to the sale of
the stock of certain insurance companies through which Central Hudson provided
employee benefits.
Expiring Amortization: Under a prior PSC regulatory settlement related to
the sales of Central Hudson's interests in its major generating assets, a
portion of the gain recognized on the sales is being recorded as net income over
a four-year period which commenced in 2001. Amounts recorded or to be recorded
by year, net of tax, are as follows: 2001 - $3.2 million, 2002 - $2.9 million,
2003 - $5.9 million, and 2004 - $5.9 million. Energy Group is seeking to use its
cash reserves and debt capacity to make investments with a view to produce new
earnings intended to replace, in whole or in part, the income from the sales of
Central Hudson's major generating assets. In this connection, Energy Group is
actively seeking new energy-related investments that provide diversification and
offer attractive returns with acceptable risks. Such opportunities may include,
but are not limited to, currently operating assets that use proven technology
and have a relatively stable customer base such as electric generating plants
and natural gas pipelines, in either case with a significant portion of
33
their output under long-term contract. Energy Group also may use its cash
reserves to repurchase shares of its common stock. Such repurchases, depending
on the number and average price of shares repurchased, could have the effect of
offsetting a substantial portion of the earnings per share impact of the
expiring amortization noted above.
In 2003, Interest Charges and Preferred Stock Dividends for Energy Group
and Central Hudson decreased $3.4 million and $3.5 million, respectively, due
primarily to a decrease in regulatory carrying charges accrued on a declining
Customer Benefit Fund balance and the redemption and repurchases of higher cost
long-term debt and preferred stock issues by Central Hudson in 2002 and 2003.
In 2002, Other Income for Central Hudson decreased $7.9 million as
compared to 2001 primarily reflecting the net effect of favorable tax benefits
related to the sale of Central Hudson's interests in its major generating assets
and the after-tax contribution to Central Hudson's Customer Benefit Fund, both
recorded in 2001. The reduction also reflects a decrease in interest and
investment income.
Other Income for Energy Group decreased $9.6 million in 2002 reflecting
the above and an additional reduction in interest and investment income due
primarily to lower balances available for investment.
Interest Charges and Preferred Stock Dividends for Energy Group and
Central Hudson decreased $6.0 million and $4.8 million, respectively, in 2002
due primarily to redemptions and repurchases of various long-term debt and
preferred stock issues by Central Hudson in 2001 and 2002 utilizing proceeds
from the sale of Central Hudson's interests in its major generating assets. The
reduction of Energy Group's interest charges also reflects the repayment of debt
in 2001.
The following table sets forth some of the pertinent data on Energy
Group's outstanding debt (unless noted otherwise, this debt relates to Central
Hudson):
2003 2002 2001
---- ---- ----
(In Thousands)
Long-Term Debt:
Debt retired ........................ $ 15,000 $ 20,000 $147,630
Outstanding at year-end:
Amount (including current
portion) .......................... $293,880 $284,877 $235,874
Estimated effective interest rate .. 3.91% 3.92% 4.64%
Short-Term Debt:
Average daily amount
outstanding ........................ $ 7,151 $ 1,534 $ 1,922
Weighted average interest rate ...... 1.41% 2.15% 6.56%
In 2001, Central Hudson redeemed, repurchased, or defeased a significant
percentage of its long-term debt and experienced a reduction in interest expense
and its effective interest rate.
34
See Notes 7 - "Short-Term Borrowing Arrangements" and 9 - "Capitalization
- - Long-Term Debt" for additional information on short-term and long-term debt of
Energy Group and/or Central Hudson.
Nuclear Operations
Nine Mile 2 Plant: For information regarding Central Hudson's sale of its
9% ownership interest in the Nine Mile 2 Plant on November 7, 2001, see Note 3.
During 2001, Central Hudson's share of operating expenses, taxes, and
depreciation pertaining to the operation of the Nine Mile 2 Plant were included
in Energy Group's financial results. Under runs in costs of operations and
maintenance expenses for the Nine Mile 2 Plant, compared to the amount allowed
in rates, were deferred for the future benefit of customers. Carrying charges
are being accrued on the regulatory liability balance. For further information
regarding the deferred Nine Mile 2 Plant costs, see Note 2 - "Regulatory
Matters."
Other Matters
Changes in Accounting Standards: See Note 1 - "Summary of Significant
Accounting Policies," under the caption "New Accounting Standards and Other FASB
Projects" for discussion on other relevant Financial Accounting Standards Board
("FASB") proposals.
35
FINANCIAL INDICES - ENERGY GROUP
Selected financial indices for the last five years are set forth in the
following table:
2003 2002 2001(1) 2000 1999(2)
---- ---- ---- ---- -----
Pretax coverage of total interest charges:
Including Allowance for Funds Used During
Construction ("AFDC") ............... 4.25x 3.38x 2.66x 3.37x 3.59x
Excluding AFDC ............................ 3.78x 3.10x 2.46x 3.11x 3.30x
Funds from Operations ..................... 5.24x 4.66x 3.99x 3.98x 4.34x
Pretax coverage of total interest
charges and preferred stock dividends ......... 3.90x 2.98x 2.41x 2.96x 3.09x
Effective tax rate - federal ................. 35.7% 36.1% (6.7%) 36.6% 35.2%
Effective tax rate - state ................... 4.4% 1.5% .1% 4.8% --%
----- ----- ----- ----- -----
Effective tax rate - combined ................ 40.1% 37.6% (6.6%) 41.4% 35.2%
===== ===== ===== ===== =====
(1) The effective tax rate in 2001 consisted of a (6.7%) effective rate for
federal income taxes and a 0.1% rate for state income taxes. The effective
rate in 2001 was primarily due to the recognition of investment tax
credits in the amount of $18.8 million upon the sale of Central Hudson's
interests in its major generating assets and $2.3 million of tax-exempt
interest income. The effective tax rates for 1999 reflect solely the
effective tax rates for federal income tax. Prior to 2000, when the New
York State tax law was changed, Central Hudson and other New York State
utilities were not subject to an income-based state tax.
(2) Holding company restructuring became effective December 15, 1999, and 1999
indices were restated to reflect fully consolidated results for
comparative purposes.
36
FINANCIAL INDICES - CENTRAL HUDSON GAS & ELECTRIC CORPORATION
Selected financial indices for the last five years are set forth in the
following table:
2003 2002 2001(1) 2000 1999(2)
---- ---- ---- ---- ----
Pretax coverage of total interest charges:
Including AFDC ......................... 3.86x 3.11x 2.23x 3.75x 3.58x
Excluding AFDC ......................... 3.43x 2.91x 2.04x 3.60x 3.48x
Funds from operations .................. 4.22x 3.99x 3.37x 4.22x 4.34x
Pretax coverage of total interest
charges and preferred stock dividends ...... 3.50x 2.72x 2.04x 3.20x 3.08x
Effective tax rate - federal .............. 36.7% 36.0% (18.9%) 36.6% 35.2%
Effective tax rate - state ................ 4.3% 4.0% (2.0%) 4.8% --%
----- ----- ----- ----- -----
Effective tax rate - combined ............. 41.0% 40.0% (20.9%) 41.4% 35.2%
===== ===== ===== ===== =====
(1) The effective tax rate for 2001 consisted of an (18.9%) rate for federal
income taxes and a (2.0%) effective rate for state income taxes. The
effective tax rate in 2001 was primarily due to the recognition of
investment tax credits in the amount of $18.8 million upon the sale of
Central Hudson's interests in its major generating assets and $2.3 million
of tax-exempt interest income. The effective tax rates for 1999 reflects
solely the effective tax rates for federal income tax. Prior to 2000, when
the New York State tax law was changed, Central Hudson and other New York
State utilities were not subject to an income-based state tax.
(2) Holding company restructuring became effective December 15, 1999, and 1999
indices were restated to reflect fully consolidated results for
comparative purposes.
37
CAPITAL RESOURCES AND LIQUIDITY
Construction Program - Central Hudson
As shown in the Consolidated Statement of Cash Flows, expenditures related
to Central Hudson's construction program amounted to $53.4 million in 2003, a
$12.4 million decrease from the $65.8 million expended in 2002. Construction
program expenditures for 2004 are estimated to be $50.9 million, a decrease of
$2.5 million from 2003 expenditures.
Central Hudson's construction program expenditures include the non-cash
components of AFDC and capitalized overheads and exclude construction removal
expenditures and special programs. After adjusting for estimates of these items,
cash construction expenditures are expected to be funded in full by cash from
operations in 2004.
Central Hudson's 2004 cash requirements also include the mandatory
redemption of $15 million of long-term debt and $10.6 million for working
capital and other requirements. Estimated cash requirements for 2004 are
summarized in the table below:
2004
(In Thousands)
Construction Program Expenditures ......................... $ 50,900
Adjustment for non-cash construction expenditures
and other construction-related cash outlays ..... (2,800)
--------
Cash Construction Expenditures ............................ $ 48,100
Internal Funds From Operations(1) ......................... 51,300
--------
Excess of Internal Funds over Construction Expenditures ... $ 3,200
Mandatory Redemption of Long-term Debt .................... 15,000
Other Cash Requirements ................................... 10,600
--------
Estimated Cash Requirements ............................... $ 22,400
========
(1) Includes $14.5 million of Income Tax and Utility Service Tax refunds from
New York State and the Internal Revenue Service that Central Hudson
expects to receive in 2004. These funds are not expected to repeat in
subsequent years.
Central Hudson plans to fund its cash requirements in 2004 through the
issuance of medium-term notes and the use of short-term borrowings. Estimates of
construction expenditures, internal funds, and cash requirements are subject to
continuous review and adjustment, and actual amounts may vary from these
estimates.
38
Capital Expenditures, Acquisitions, and Divestitures by CHEC
At December 31, 2003, CHEC had a credit facility that provided up to $25
million to be used for working capital purposes, acquisitions, and capital
expenditures, and in addition could borrow funds from Energy Group. CHEC's
capital expenditures for 2003 were approximately $13.8 million, which included
acquisitions of $7.5 million. CHEC's capital expenditures for 2004 are estimated
to be $3.2 million. There are no projected acquisitions for 2004. However,
CHEC's fuel distribution subsidiaries, Griffith and SCASCO, continue to explore
opportunities to expand through both internal growth and acquisitions, depending
on financial performance and opportunities available. The actual amount expended
for and the financing of any future acquisitions will depend on the
opportunities that develop.
On October 31, 2003, SCASCO completed the sale of certain assets and
liabilities related to its natural gas business unit. Energy Group recognized an
after-tax gain on the sale of approximately $181,000. This disposition was not
significant to the historical financials of Energy Group and is not expected to
materially impact the future financial condition, results of operations, or cash
flows of Energy Group or its subsidiaries.
Capital Structure
As provided in the PSC's Order Establishing Rates (see Note 2 under the
caption "Rate Proceedings - Electric and Natural Gas"), Central Hudson's common
equity ratio was capped, for the purposes of the PSC's return on equity ("ROE")
calculation, at 47% for the twelve months ended June 30, 2002, and at 46% and
45%, respectively, for the two subsequent twelve-month periods. Central Hudson
intends to maintain a common equity ratio of approximately 45% in fiscal year
2004. Central Hudson's current senior debt ratings are "A2" by Moody's Investors
Service and "A" by Standard and Poor's Corporation and by FitchRatings.
Year-end capital structure for Energy Group and its subsidiaries is set
forth below as of the end of 2003, 2002, and 2001:
Energy Group Year-end Capital Structure
- ------------ -------------------------------
2003 2002 2001
---- ---- ----
Long-term debt ............................. 36.0% 35.4% 30.0%
Short-term debt ............................ 2.0 -- --
Preferred stock ............................ 2.6 4.2 7.1
Common equity .............................. 59.4 60.4 62.9
----- ----- -----
100.0% 100.0% 100.0%
===== ===== =====
Central Hudson Year-end Capital Structure
- -------------- -----------------------------
2003 2002 2001
---- ---- ----
Long-term debt ............................. 49.1% 48.9% 42.5%
Short-term debt ............................ 2.7 -- --
Preferred stock ............................ 3.5 5.8 10.1
Common equity .............................. 44.7 45.3 47.4
----- ----- -----
100.0% 100.0% 100.0%
===== ===== =====
39
Competitive Business Subsidiaries Year-end Capital Structure*
- --------------------------------- -------------------------------
2003 2002 2001
---- ---- ----
Long-term debt ............................. 48.3% 48.5% 50.5%
Short-term debt ............................ -- -- --
Preferred stock ............................ -- -- --
Common equity .............................. 51.7 51.5 49.5
----- ----- -----
100.0% 100.0% 100.0%
===== ===== =====
* Based on stand-alone financial statements and includes intercompany
balances which are eliminated in consolidation.
Financing Program of Energy Group and Its Subsidiaries
Effective August 1, 2002, Energy Group authorized a common stock
repurchase program ("Repurchase Program") for the purchase of up to 25% of its
then-outstanding common stock over a five-year period, and projected that
800,000 shares would be repurchased during the first twelve months of this
program. Between August 2002 and December 2003, the number of shares repurchased
under this program were 600,087 at a cost of $27.5 million. Energy Group intends
to set repurchase targets, if any, each year based on circumstances then
prevailing. Repurchases have been temporarily suspended while Energy Group
assesses opportunities to redeploy its cash reserves in energy-related
investments as discussed in Note 2 - "Regulatory Matters," under "Rate
Proceedings - Electric and Natural Gas". Energy Group reserves the right to
modify, suspend, or terminate the Repurchase Program at any time without notice.
At January 1, 2003, investments in Energy Group's Alternate Investment
Program ("Investment Program") consisted of electric utility common stocks,
preferred stocks, and an intermediate-term bond fund. As of December 31, 2003,
all holdings in the Investment Program had been liquidated and the proceeds
invested in short-term investments with lower principal risk. Since its
inception in mid-2002, the Investment Program produced a return of $0.15 per
share over a period of about one year. Money market alternatives were estimated
to have returned $0.055 per share over the same period, resulting in a net
benefit of $0.095 per share from the Investment Program.
Proceeds from sales of securities during the year ended December 31, 2003,
were $111.5 million. Realized gains associated with sales of securities were
$2.9 million, offset by realized losses of $3.0 million. The cost basis of these
securities was determined on a specific identification basis.
Central Hudson received authority from the PSC to issue up to $100 million
of unsecured medium-term notes during the three years ending June 30, 2004.
During 2002 and 2003 respectively, $69 million and $24 million of such notes
were issued, and $7 million of such notes remain authorized but unissued.
Central Hudson has filed a financing petition with the PSC for authorization of
a new medium-term notes program. There can be no assurance that the PSC will
grant this authorization or, if it does, on what terms.
For more information with respect to the financing program of Energy
Group, see Note 8 - "Capitalization - Energy Group Capital Stock" and Note 9 -
"Capitalization - Long-Term Debt."
Griffith funded its acquisitions in 2003 with funds received from Energy
Group.
40
Short-Term Debt
As more fully discussed in Note 7, Central Hudson, pursuant to authority
from the PSC, entered into a $75 million revolving credit facility in October
2001 to replace its then-existing $50 million revolving credit facility. In
addition, Central Hudson maintains a confirmed line of credit of $1 million with
a regional bank and certain uncommitted lines of credit with various banks.
These agreements give Central Hudson competitive options to minimize the cost of
its short-term borrowing. Authorization from the PSC limits the amount Central
Hudson may have outstanding at any time under all of its short-term borrowing
arrangements to $77 million in the aggregate. This authorization expires on June
30, 2004. Central Hudson currently has a financing petition filed with the PSC
to renew its financing authorization. For additional discussion, see Note 9 -
"Capitalization - Long-Term Debt."
As of December 31, 2003, the competitive business subsidiaries also have a
short-term line of credit totaling $25 million.
Contractual Obligations
A review of capital resources and liquidity should also consider other
contractual obligations and commitments, which are further disclosed in Note 13
- - "Commitments and Contingencies".
41
The following is a summary of the contractual obligations for Energy Group
and its affiliates as of December 31, 2003:
- -------------------------------------------------------------------------------------------------------
Payments Due By Period (In Thousands)
- -------------------------------------------------------------------------------------------------------
Years Years
Ending Ending Years
Less than 2005- 2008- Beyond
1 year 2007 2009 2009 Total
- -------------------------------------------------------------------------------------------------------
Long-Term Debt $ 15,000 $ 33,000 $ 20,000 $ 225,950 $ 293,950
- -------------------------------------------------------------------------------------------------------
Operating Leases 1,354 2,067 153 106 3,680
- -------------------------------------------------------------------------------------------------------
Construction/Maintenance & Other Projects(1) 17,508 4,538 635 -- 22,681
- -------------------------------------------------------------------------------------------------------
Purchased Electric Contracts(2) 121,462 207,642 74,452 99,830 503,386
- -------------------------------------------------------------------------------------------------------
Purchased Natural Gas Contracts(2) 64,821 105,721 11,956 8,725 191,223
- -------------------------------------------------------------------------------------------------------
Purchased Fixed Liquid Petroleum Contracts(3) 12,589 -- -- -- 12,589
- -------------------------------------------------------------------------------------------------------
Purchased Variable Liquid Petroleum
Contracts(3) 27,603 -- -- -- 27,603
- -------------------------------------------------------------------------------------------------------
Total Contractual Obligations $260,337 $352,968 $107,196 $ 334,611 $1,055,112
- -------------------------------------------------------------------------------------------------------
(1) Including Specific, Term & Service Contracts, briefly defined as follows:
Specific Contracts consist of work orders for construction. Term Contracts
consist of maintenance contracts. Service Contracts include consulting,
educational, and professional service contracts.
(2) Purchased electric and natural gas costs for Central Hudson are fully
recovered via their respective regulatory cost adjustment mechanisms.
(3) Estimated based on pricing at January 14, 2004.
42
The following is a summary of the contractual obligations for Central
Hudson as of December 31, 2003:
- --------------------------------------------------------------------------------------------------------
Payments Due By Period (In Thousands)
- --------------------------------------------------------------------------------------------------------
Years Years Years
Less than Ending Ending Beyond
1 year 2005-2007 2008-2009 2009 Total
- --------------------------------------------------------------------------------------------------------
Long-Term Debt $ 15,000 $ 33,000 $ 20,000 $ 225,950 $ 293,950
- --------------------------------------------------------------------------------------------------------
Operating Leases 626 1,035 18 -- 1,679
- --------------------------------------------------------------------------------------------------------
Construction/Maintenance & Other Projects(1) 17,508 4,538 635 -- 22,681
- --------------------------------------------------------------------------------------------------------
Purchased Electric Contracts(2) 121,462 207,642 74,452 99,830 503,386
- --------------------------------------------------------------------------------------------------------
Purchased Natural Gas Contracts(2) 64,821 105,721 11,956 8,725 191,223
- --------------------------------------------------------------------------------------------------------
Total Contractual Obligations $219,417 $351,936 $107,061 $ 334,505 $1,012,919
- --------------------------------------------------------------------------------------------------------
(1) Including Specific, Term & Service Contracts, briefly defined as follows:
Specific Contracts consist of work orders for construction. Term Contracts
consist of maintenance contracts. Service Contracts include consulting,
educational, and professional service contracts.
(2) Purchased electric and natural gas costs for Central Hudson are fully
recovered via their respective regulatory cost adjustment mechanisms.
Parental Guarantees
For information on parental guarantees issued by Energy Group and certain
of its competitive subsidiaries, see Note 1 - "Summary of Significant Accounting
Policies," under the caption "Parental Guarantees."
Product Warranties
For information on product warranties issued by certain of Energy Group's
competitive subsidiaries, see Note 1 - "Summary of Significant Accounting
Policies," under the caption "Product Warranties."
43
COMMON STOCK DIVIDENDS AND PRICE RANGES
Energy Group and its principal predecessors (including Central Hudson)
have paid dividends on their respective common stock in each year commencing in
1903, which common stock has been listed on the New York Stock Exchange since
1945. The price ranges and the dividends paid for each quarterly period during
the last two fiscal years are as follows:
2003 2002
------------------------- -------------------------
High Low Dividend High Low Dividend
---- --- -------- ---- --- --------
1st Quarter $49.69 $40.21 $ 0.54 $48.58 $42.91 $ 0.54
2nd Quarter 45.70 41.31 0.54 52.38 46.17 0.54
3rd Quarter 46.00 42.26 0.54 51.69 39.93 0.54
4th Quarter 47.00 42.54 0.54 50.83 44.15 0.54
In 2003, Energy Group maintained the quarterly dividend rate at $0.54 per
share. In making future dividend decisions, Energy Group will evaluate all
circumstances at the time of making such decisions, including business,
financial, and regulatory considerations.
The Agreement contains certain dividend payment restrictions on Central
Hudson, including limitations on the amount of dividends payable if Central
Hudson's senior debt ratings are downgraded by more than one major rating agency
due to performance or concerns about the financial condition of Energy Group or
any Energy Group subsidiary other than Central Hudson. These limitations would
result in the average annual income available for dividends on a two-year
rolling average basis being reduced to: (i) 75%, if the downgrade were below
"BBB+," (ii) 50% if the senior debt were placed on "Credit Watch" (or the
equivalent) because of a rating below "BBB," or (iii) no dividends payable if
the downgrade were below "BBB-." These restrictions survived the June 30, 2001,
expiration of the Agreement. Central Hudson is currently rated "A" or, the
equivalent, and therefore the restrictions noted above do not apply.
Central Hudson anticipates paying up to its entire earnings in 2004 as a
dividend to Energy Group. The number of registered holders of common stock of
Energy Group as of December 31, 2003, was 17,549. Of these, 16,694 were accounts
in the names of individuals with total holdings of 3,962,714 shares, or an
average of 237 shares per account. The 855 other accounts, in the names of
institutional or other non-individual holders, for the most part hold shares of
common stock for the benefit of individuals.
All of the outstanding common stock of Central Hudson and all of the
outstanding common stock of CHEC is held by Energy Group.
Critical Accounting Policies
The following accounting policies have been identified that could result
in material changes to the financial condition or results of operations of
Energy Group and its subsidiaries under different conditions or using different
assumptions.
Accounting for Regulated Operations - Central Hudson follows generally
accepted accounting principles, including the provisions of Statement of
Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of
Certain Types of Regulation ("SFAS 71"). The application of SFAS 71 may cause
the allocation of costs to accounting periods to differ from accounting methods
generally applied to non-regulated companies. See Note 2 - "Regulatory
44
Matters," under the caption "Regulatory Accounting Policies" for additional
discussion.
Post -Employment Benefits - Central Hudson's reported costs of providing
non-contributory defined pension benefits as well as certain health care and
life insurance benefits for retired employees are dependent upon numerous
factors resulting from actual plan experience and assumptions of future plan
performance. A change in assumptions regarding discount rates and expected
long-term rate of return on plan assets, as well as current market conditions,
could cause a significant change in the level of costs to be recorded. See Note
10 - "Post-Employment Benefits" for additional discussion.
Use of Estimates - Preparation of the Consolidated Financial Statements in
accordance with Generally Accepted Accounting Principles includes the use of
estimates and assumptions by Management that affect financial results and actual
results may differ from those estimated. See Note 1 - "Summary of Significant
Accounting Policies," under the caption "Use of Estimates" for additional
discussion.
Accounting for Derivatives - Energy Group and its subsidiaries use
derivatives to manage their commodity and financial market risks. The accounting
requirements for derivatives and hedging activities are complex and still
evolving. All derivatives, other than those specifically excepted, are reported
on the Consolidated Balance Sheet at fair value. For discussions relating to
market risk and derivative instruments, see Item 7A - "Quantitative and
Qualitative Disclosure About Market Risk" and Note 1 - "Summary of Significant
Accounting Policies," under the caption "Accounting for Derivative Instruments
and Hedging Activities."
Goodwill and Other Intangible Assets - As required by SFAS No. 142,
Goodwill and Other Intangible Assets ("SFAS 142"), effective January 1, 2002,
Energy Group no longer amortizes goodwill and does not amortize intangible
assets with indefinite lives, known as unamortized intangible assets. Both
goodwill and unamortized intangible assets are tested at least annually for
impairment. Intangible assets with finite lives are amortized and are reviewed
at least annually for impairment. Impairment testing compares fair value of the
reporting units (Griffith and SCASCO) to the carrying amount of their goodwill.
Fair value is estimated using a multiple of earnings measurement. For Central
Hudson's determination of an impairment, see Note 6 - "Goodwill and Other
Intangible Assets."
Accounting for Deferred Taxes - Central Hudson provides for income taxes
based on the asset and liability method required by SFAS No. 109, "Accounting
for Income Taxes" ("SFAS 109"). Under SFAS 109, deferred tax assets and
liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases, as well as net operating loss
and credit carryforwards. See Note 4 - "Income Tax" for additional discussion.
45
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The primary market risks for Energy Group and its subsidiaries are
commodity price risk and interest rate risk. Commodity price risk, related
primarily to purchases of natural gas, electricity, and petroleum products for
resale is mitigated in several different ways. Central Hudson, under the
Agreement, collects its actual purchased electricity and natural gas costs
through automatic adjustment clauses in its rates. These adjustment clauses
provide for the collection of costs, including risk management costs, from
customers to reflect the actual costs incurred in obtaining supply. Risk
management costs are defined by the PSC as "costs associated with transactions
that are intended to reduce price volatility or reduce overall costs to
customers. These costs include transaction costs, and gains and losses
associated with risk management instruments." Griffith and SCASCO may increase
the prices charged for the commodities they sell in response to changes in
costs; however, the ability to raise prices is limited by the competitive
market. Depending on market conditions, Central Hudson, Griffith, and SCASCO
enter into long-term fixed supply and long-term forward supply contracts for the
purchase of these commodities. Central Hudson also uses natural gas storage
facilities, which enable it to purchase and hold quantities of natural gas at
pre-heating season prices for use during the heating season.
Central Hudson and the competitive business subsidiaries have in place an
energy risk management program to manage, through the use of defined risk
management practices, various risks associated with their respective operations,
namely commodity price risk and sales volatility due to weather. This risk
management program permits the use of derivative financial instruments for
hedging purposes and does not permit their use for trading or speculative
purposes. Central Hudson, Griffith, and SCASCO have entered into either
exchange-traded futures contracts or over-the-counter ("OTC") contracts with
third parties to hedge commodity price risk associated with the purchase of
natural gas, electricity, and petroleum products and also, to hedge the effect
on earnings due to significant variances in weather conditions from normal
patterns. The types of derivative instruments used include natural gas futures
and basis swaps to hedge natural gas purchases; contracts for differences to
hedge electricity purchases; put and call options to hedge oil purchases; and
weather derivatives. OTC derivative transactions are entered into only with
counter-parties that meet certain credit criteria. The creditworthiness of these
counter-parties is determined primarily by reference to published credit
ratings.
At December 31, 2003, Central Hudson had open derivative contracts to
hedge natural gas prices through October 2004, covering approximately 13.1% of
Central Hudson's projected total natural gas requirements during this period. In
2003, derivative transactions were used to hedge 18.2% of Central Hudson's total
natural gas supply requirements as compared to 4.3% in 2002. In its electric
operations, Central Hudson had open derivatives at December 31, 2003, hedging
approximately 2.5% of its required electricity supply through August 2004. In
2003, Central Hudson hedged approximately 13.7% of its total electricity supply
requirements with OTC derivative contracts as compared to 29.9% in 2002. In
addition, Central Hudson has in place a number of agreements, of varying terms,
to purchase electricity produced by its former major generating assets and other
generating facilities at fixed prices. The notional amounts hedged by the
derivatives and the purchase electricity agreements for 2004 and 2005 represent
approximately 59% and 36%, respectively, of its total electricity supply
requirements.
46
At December 31, 2003, Griffith and SCASCO had open OTC put and call option
positions covering approximately 18.1% of their combined anticipated fuel oil
supply requirements for the period January 2004 through June 2004. In 2003,
derivatives were used to hedge 12.3% of these requirements as compared to 6.4%
in 2002.
Derivative contracts are discussed in more detail in Note 1 - "Summary of
Significant Accounting Policies," under the sub caption "Accounting for
Derivative Instruments and Hedging Activities."
Interest rate risk largely affects Central Hudson and is managed through
the issuance of fixed-rate debt with varying maturities and variable rate debt
for which interest is reset on a periodic basis to reflect current market
conditions. The difference between costs associated with actual variable
interest rates related to Central Hudson's bonds issued by the New York State
Energy Research Development Authority ("NYSERDA") and costs embedded in customer
rates is deferred for eventual refund to, or recovery from, customers. The
variability in interest rates is also managed with the use of a derivative
financial instrument, known as an interest rate cap agreement, for which the
premium cost and any realized benefits also pass through the aforementioned
regulatory recovery mechanism. Central Hudson also repurchases or redeems
existing debt at a lower cost when market conditions permit. Please refer to
Note 9 - "Capitalization - Long-Term Debt" and Note 15 - "Financial Instruments"
for additional disclosure related to long-term debt.
47
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
I - Index to Financial Statements: Page
----
Report of Independent Auditors 49
Statement of Management's Responsibility 50
ENERGY GROUP
Energy Group Consolidated Statement of Income for the three
years ended December 31, 2003 51
Energy Group Consolidated Statement of Comprehensive
Income for the three years ended December 31, 2003 53
Energy Group Consolidated Statement of Cash Flows for the
three years ended December 31, 2003 54
Energy Group Consolidated Balance Sheet at December 31, 2003
and 2002 56
Energy Group Consolidated Statement of Retained Earnings and
Comprehensive Income (Net of Taxes) for the three years
ended December 31, 2003 58
CENTRAL HUDSON
Central Hudson Consolidated Statement of Income for the three
years ended December 31, 2003 59
Central Hudson Consolidated Statement of Comprehensive Income
for the three years ended December 31, 2003 61
Central Hudson Consolidated Statement of Retained Earnings and
Comprehensive Income (Net of Taxes) for the three years
ended December 31, 2003 62
Central Hudson Consolidated Balance Sheet at December 31, 2003
and 2002 63
Central Hudson Consolidated Statement of Cash Flows for the
three years ended December 31, 2003 65
Notes to Consolidated Financial Statements 67
Selected Quarterly Financial Data (Unaudited) 123
FINANCIAL STATEMENT SCHEDULES
Schedule II - Reserves - Energy Group 125
Schedule II - Reserves - Central Hudson 126
All other schedules are omitted because they are not applicable or the
required information is shown in the Consolidated Financial Statements or the
Notes thereto.
II - Supplementary Data
Supplementary data are included in "Selected Quarterly Financial Data
(Unaudited)" referred to in "I" above, and reference is made thereto.
48
Report of Independent Auditors
To the Board of Directors and Shareholders of CH Energy Group, Inc. and
Central Hudson Gas & Electric Corporation
In our opinion, the consolidated financial statements present fairly, in
all material respects, the financial position of CH Energy Group, Inc. and its
subsidiaries and Central Hudson Gas & Electric Corporation and its subsidiary at
December 31, 2003 and 2002, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2003, in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement schedules in Item
8 "Financial Statements and Supplementary Data" of this Form 10-K Annual Report
present fairly, in all material respects, the information set forth therein when
read in conjunction with the related consolidated financial statements. These
financial statements and financial statement schedules are the responsibility of
CH Energy Group, Inc.'s and Central Hudson Gas & Electric Corporation's
management; our responsibility is to express an opinion on these financial
statements and financial statement schedules based on our audits. We conducted
our audits of these financial statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the financial statements, CH Energy Group, Inc.
has revised the 2002 and 2001 reporting of cumulative preferred stock dividends
in the consolidated statements of income.
As discussed in Note 6 to the financial statements, CH Energy Group, Inc.
and its subsidiaries and Central Hudson Gas & Electric Corporation and its
subsidiary, as required under accounting principles generally accepted in the
United States of America, changed the manner in which they account for goodwill
and other intangible assets as of the required implementation date, January 1,
2002.
As discussed in Note 1 to the financial statements, CH Energy Group, Inc.
and its subsidiaries and Central Hudson Gas & Electric Corporation and its
subsidiary, as required under accounting principles generally accepted in the
United States of America, changed the manner in which they account for
derivative instruments and hedging activities as of the required implementation
date, January 1, 2001.
/s/ PRICEWATERHOUSECOOPERS LLP
New York, New York
January 29, 2004
49
STATEMENT OF MANAGEMENT'S RESPONSIBILITY
The management personnel of CH Energy Group, Inc. ("Management") are
responsible for the preparation, integrity, and objectivity of the Consolidated
Financial Statements of CH Energy Group, Inc., its subsidiary Central Hudson Gas
& Electric Corporation, and its competitive business subsidiaries (for the
purposes of this statement of Management's responsibility, collectively the
"Corporation"), as well as all other information contained in this Annual Report
on Form 10-K ("10-K Annual Report") for the fiscal year ended December 31, 2003.
The Consolidated Financial Statements have been prepared in conformity with
generally accepted accounting principles and, in some cases, reflect amounts
based on the best estimates and judgments of Management, giving due
consideration to materiality.
The Corporation maintains adequate systems of internal control to provide
reasonable assurance that, among other things, transactions are executed in
accordance with Management's authorizations, that the Consolidated Financial
Statements are prepared in accordance with generally accepted accounting
principles, and that the assets of the Corporation are properly safeguarded. The
systems of internal control are documented, evaluated, and tested by the
Corporation's internal auditors on a continuing basis. Due to the inherent
limitations of the effectiveness of internal controls, no such system can
provide absolute assurance that errors will not occur. Management believes that
the Corporation has maintained an effective system of internal control over the
preparation of its financial information, including the Consolidated Financial
Statements of the Corporation for the year ended December 31, 2003.
Independent accountants were engaged to audit the Consolidated Financial
Statements of the Corporation and issue their report thereon. The Report of
Independent Auditors, which is presented herein, does not limit the
responsibility of Management for information contained in the Consolidated
Financial Statements and elsewhere in this 10-K Annual Report.
The Corporation's Board of Directors maintains an Audit Committee which is
composed of Directors who have been determined to be independent in accordance
with applicable rules and laws and the Audit Committee has a member who is an
"audit committee financial expert" as defined by the Securities and Exchange
Commission. The Audit Committee meets with Management, the Corporation's
Internal Auditing Manager, and the Corporation's independent accountants several
times a year to discuss internal controls and accounting matters, the
Corporation's Consolidated Financial Statements, and the scope and results of
the audits performed by both the independent accountants and the Corporation's
Internal Auditing Department.
The independent accountants and the Corporation's Internal Auditing
Manager have direct access to the Audit Committee.
PAUL J. GANCI STEVEN V. LANT DONNA S. DOYLE
Chairman of the Board President and Vice President - Accounting
Chief Executive Officer and Controller
January 29, 2004
50
ENERGY GROUP CONSOLIDATED STATEMENT OF INCOME
(In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Operating Revenues
Electric ............................. $ 457,395 $ 427,978 $ 428,346
Natural gas .......................... 123,306 105,343 110,296
Competitive business subsidiaries .... 225,983 162,520 192,061
--------- --------- ---------
Total Operating Revenues ........... 806,684 695,841 730,703
--------- --------- ---------
Operating Expenses
Operation:
Purchased electricity and fuel
used in electric generation ......... 268,757 254,249 248,879
Purchased natural gas ................ 88,767 71,991 71,893
Purchased petroleum .................. 143,992 92,125 89,173
Other expenses of operation -
regulated activities ............... 107,105 92,245 106,751
Other expenses of operation -
competitive business subsidiaries .. 56,195 51,712 56,482
Depreciation and amortization
(Note 1) ........................... 33,611 31,230 35,637
Taxes, other than income tax ......... 31,956 38,606 50,402
Federal and State income tax
(Note 4) ........................... 27,279 20,746 17,779
--------- --------- ---------
Total Operating Expenses ........... 757,662 652,904 676,996
--------- --------- ---------
Operating Income ....................... 49,022 42,937 53,707
--------- --------- ---------
Other Income
Allowance for equity funds
used during construction
(Note 1) ............................ 436 591 429
Federal and State income tax
(Note 4) ............................ (3,156) (1,548) 21,117
Interest on regulatory assets and
investment income .................. 12,225 13,780 20,338
Other - net .......................... 8,810 7,469 (12,001)
--------- --------- ---------
Total Other Income ................. 18,315 20,292 29,883
--------- --------- ---------
Income before Interest and other
Charges .............................. 67,337 63,229 83,590
--------- --------- ---------
The Notes to Consolidated Financial Statements are an integral part hereof.
51
ENERGY GROUP CONSOLIDATED STATEMENT OF INCOME (CONT'D)
(In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Interest and Other Charges
Interest on mortgage bonds ............ $ 570 $ 2,136 $ 5,211
Interest on other long-term debt ...... 10,699 9,819 10,446
Other interest ........................ 10,987 12,908 14,187
Allowance for borrowed
funds used during
construction (Note 1) ................ (291) (248) (319)
Cumulative Preferred Stock Dividends
of Central Hudson ..................... 1,387 2,161 3,230
--------- --------- ---------
Total Interest and Other Charges .... 23,352 26,776 32,755
--------- --------- ---------
Net income from continuing
operations ........................... 43,985 36,453 50,835
Net loss from discontinued
operations, net of income tax
benefit of $1,377 .................... -- (2,237) --
Gain on disposal of discontinued
operations, net of income tax
of ($5,239) .......................... -- 7,065 --
Net Income ............................. $ 43,985 $ 41,281 $ 50,835
========= ========= =========
Dividends Declared on Common
Stock ................................ 34,093 35,095 35,342
Balance Retained in the Business ....... $ 9,892 $ 6,186 $ 15,493
========= ========= =========
Average number of common stock
shares outstanding:
Basic .............................. 15,831 16,302 16,362
Diluted ............................ 15,835 16,316 16,370
Earnings per share - Basic:
Income from continuing operations .. $ 2.78 $ 2.24 $ 3.11
Discontinued operations ............ -- $ 0.29 --
--------- --------- ---------
Net Income ......................... $ 2.78 $ 2.53 $ 3.11
Earnings per share - Diluted:
Income from continuing operations . $ 2.77 $ 2.22 $ 3.09
Discontinued operations ........... -- $ 0.29 --
--------- --------- ---------
Net Income ........................ $ 2.77 $ 2.51 $ 3.09
Dividends Declared per Share ........... $ 2.16 $ 2.16 $ 2.16
The Notes to Consolidated Financial Statements are an integral part hereof.
52
ENERGY GROUP CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Net Income ......................................... $ 43,985 $ 41,281 $ 50,835
Other Comprehensive Income, net of tax:
FAS 133 transition adjustment -
cumulative effect of unrealized
losses at implementation date of
January 1, 2001 .............................. -- -- (1,896)
Less: reclassification adjustment
for gains realized in net
income .............................. -- -- (795)
Plus: change in fair value for transition
adjustment amounts .................. -- -- 2,691
--------- --------- ---------
Balance of FAS 133 transition
adjustment at December 31,
2001 ..................................... -- -- --
--------- --------- ---------
Fair value of cash flow hedges - FAS 133:
Unrealized gain, net of tax of ($59)
and ($13) ................................... 88 19 --
Reclassification for gains realized in net
income, net of tax of $13 .................. (19) -- --
Investment Securities:
Net unrealized losses on investment
securities, net of tax of $896 ............. -- (1,394) --
Change in fair value, net of tax of ($880) ... 1,320 -- --
Reclassification adjustment for losses
(gains) included in net income, net of tax
of ($49) and $26 ........................... 74 (38) --
Net unrealized losses on
investment in partnerships, net of
tax of $26 and $219, respectively ........... (38) (319) --
--------- --------- ---------
Other comprehensive income (loss) .............. 1,425 (1,732) --
--------- --------- ---------
Comprehensive Income ............................... $ 45,410 $ 39,549 $ 50,835
========= ========= =========
The Notes to Consolidated Financial Statements are an integral part hereof.
53
ENERGY GROUP CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Operating Activities
Net Income ....................................... $ 43,985 $ 41,281 $ 50,835
Adjustments to reconcile net
income to net cash provided
by (used in) operating activities:
Depreciation and amortization .................. 35,199 32,687 36,843
Nuclear fuel amortization ...................... -- -- 2,295
Deferred income taxes - net .................... 35,281 25,639 2,545
Deferred taxes related to sale of major
generating assets and Nine Mile 2
Plant ......................................... -- -- (259,494)
Gain on disposal of subsidiary ................. 302 (18,985) --
Loss on sale of temporary investments .......... 123 960 --
Provision for uncollectibles ................... 5,862 3,582 3,913
Amortization of fossil plant incentive ......... (9,887) (4,794) (5,393)
Other - net .................................... 6,558 10,978 21,458
Changes in operating assets and Liabilities - net:
Accounts receivable, unbilled utility
revenues and other receivables .............. (16,145) 3,986 53,652
Fuel, materials and supplies .................. (3,814) (820) (6,034)
Special deposits and
prepayments ................................. 14,601 1,155 (12,652)
Contribution - prefunded pension costs ........ (10,000) (32,000) --
Fair value of derivative instruments .......... 1,878 -- --
Accounts payable .............................. (5,333) (1,357) 12,764
Accrued taxes and interest .................... 6,193 8,586 (61,628)
Accrued/deferred pension
costs ....................................... (19,698) (19,561) (17,304)
Deferred natural gas and electric costs ....... 10,927 3,014 (3,388)
Customer benefit and carrying
charge - net ................................ (38,844) (23,859) (8,509)
Other - net ................................... (1,725) 3,454 12,175
-------- -------- ---------
Net cash provided by (used in) operating
activities ...................................... 55,463 33,946 (177,922)
-------- -------- ---------
The Notes to Consolidated Financial Statements are an integral part hereof.
54
ENERGY GROUP CONSOLIDATED STATEMENT OF CASH FLOWS (CONT'D)
(In Thousands)
2003 2002 2001
---- ---- ----
Investing Activities
Proceeds from sale of subsidiary ............................. 567 58,373 --
Purchase of temporary investments ............................ (22,221) (124,062) --
Proceeds from sale of temporary
investments ................................................ 111,539 33,616 --
Mortgage receivable - sale of
Nine Mile 2 Plant .......................................... 1,289 28,885 (29,688)
Proceeds from sale of major generating
assets ..................................................... -- -- 770,835
Additions to utility and other property
and plant .................................................. (59,681) (72,287) (67,818)
Acquisitions made by competitive
business subsidiary ......................................... (7,624) (1,461) (17,908)
Nine Mile 2 Plant decommissioning
trust fund (Note 3) ......................................... -- -- (737)
Other - net .................................................. (2,070) (974) 17,409
--------- --------- ---------
Net cash provided by (used in) investing
activities .................................................. 21,799 (77,910) 672,093
--------- --------- ---------
Financing Activities
Proceeds from issuance of
long-term debt ............................................. 24,000 69,000 --
Retirement of preferred stock ................................ (12,500) (22,500) --
Borrowings (repayments) of short-term
debt, net .................................................. 16,000 -- (164,250)
Retirement and redemption of
long-term debt ............................................ (15,000) -- (147,880)
Dividends paid on common
stock ....................................................... (34,080) (35,095) (35,342)
Defeasance of long-term debt ................................. -- -- (39,281)
Repurchase of common stock ................................... (13,135) (14,351) --
Issuance and redemption costs ................................ (236) (1,962) (3,341)
--------- --------- ---------
Net cash used in financing activities ........................ (34,951) (4,908) (390,094)
--------- --------- ---------
Net Change in Cash and Cash
Equivalents ................................................... 42,311 (48,872) 104,077
Cash and Cash Equivalents at
Beginning of Year ............................................. 83,523 132,395 28,318
--------- --------- ---------
Cash and Cash Equivalents at End
of Year....................................................... $ 125,834 $ 83,523 $ 132,395
========= ========= =========
Supplemental Disclosure of Cash
Flow Information
Interest paid ............................................... $ 14,229 $ 12,498 $ 22,144
Federal and State income taxes paid ......................... 1,532 2,370 263,005
The Notes to Consolidated Financial Statements are an integral part hereof.
55
ENERGY GROUP CONSOLIDATED BALANCE SHEET
(In Thousands)
December 31,
2003 2002
ASSETS ---- ----
Utility Plant
Electric ..................................... $ 656,192 $ 605,989
Natural gas .................................. 199,221 189,143
Common ....................................... 104,532 100,476
---------- ----------
959,945 895,608
Less: Accumulated depreciation ............... 309,208 297,549
---------- ----------
650,737 598,059
Construction work in progress ................ 56,764 76,398
---------- ----------
Net Utility Plant ............................ 707,501 674,457
---------- ----------
Other Property and Plant, net .................. 21,589 18,337
---------- ----------
Current Assets
Cash and cash equivalents .................... 125,834 83,523
Investments in marketable securities ......... -- 89,441
Accounts receivable from customers - net of
allowance for doubtful accounts; $4.6 million
in 2003 and $4.2 million in 2002 ............ 61,223 60,978
Accrued unbilled utility revenues ............ 7,618 7,894
Other receivables ............................ 12,216 1,998
Fuel, materials and supplies, at average
cost ....................................... 19,847 16,033
Fair value of derivative instruments ......... 869 2,747
Bond defeasance escrow ....................... -- 16,275
Special deposits and prepayments ............. 23,315 28,466
---------- ----------
Total Current Assets ....................... 250,922 307,355
---------- ----------
Deferred Charges and Other Assets
Prefunded pension costs (Note 10) ............ -- 108,242
Regulatory assets-pension plan
(Notes 2 and 10) ........................... 124,210 15,943
Intangible asset-pension plan (Note 10) ...... 24,447 --
Goodwill and other intangible assets ......... 81,980 77,972
Regulatory assets (Note 2) ................... 67,474 58,057
Unamortized debt expense ..................... 3,901 3,623
Other ........................................ 18,468 18,921
---------- ----------
Total Deferred Charges and Other Assets .... 320,480 282,758
---------- ----------
TOTAL ASSETS ................................... $1,300,492 $1,282,907
========== ==========
The Notes to Consolidated Financial Statements are an integral part hereof.
56
ENERGY GROUP CONSOLIDATED BALANCE SHEET (CONT'D)
(In Thousands)
CAPITALIZATION AND LIABILITIES December 31,
2003 2002
---- ----
Capitalization
Common Stock Equity
Common stock, $.10 par value (Note 8) ........ $ 1,686 $ 1,686
Paid-in capital (Note 8) ..................... 351,230 351,230
Retained earnings ............................ 179,395 169,503
Treasury stock (Note 8) ...................... (46,252) (33,117)
Accumulated other comprehensive loss ......... (307) (1,732)
Capital stock expense ........................ (328) (655)
----------- -----------
Total Common Stock Equity ................... 485,424 486,915
----------- -----------
Cumulative Preferred Stock (Note 8)
Not subject to mandatory redemption .......... 21,030 21,030
Subject to mandatory redemption .............. -- 12,500
----------- -----------
Total Cumulative Preferred Stock ............ 21,030 33,530
----------- -----------
Long-term Debt net of current portion (Note 9) . 278,880 269,877
----------- -----------
Total Capitalization ........................ 785,334 790,322
----------- -----------
Current Liabilities
Current maturities of long-term debt ........... 15,000 15,000
Notes payable .................................. 16,000 --
Accounts payable ............................... 40,602 45,649
Accrued interest ............................... 4,274 4,273
Dividends payable .............................. 8,754 9,113
Accrued vacation and payroll ................... 5,289 4,891
Customer deposits .............................. 5,690 5,268
Deferred revenues .............................. 8,197 8,498
Other .......................................... 16,214 19,413
----------- -----------
Total Current Liabilities ................... 120,020 112,105
----------- -----------
Deferred Credits and Other Liabilities
Regulatory liabilities (Note 2) ................ 228,058 264,874
Operating reserves ............................. 5,043 4,912
Deferred gain-sale of major generating assets .. 9,887 19,774
Accrued environmental remediation costs ........ 19,500 18,304
Accrued OPEB costs ............................. 10,561 4,514
Accrued pension costs .......................... 9,775 4,244
Other .......................................... 16,266 8,088
----------- -----------
Total Deferred Credits and
Other Liabilities ............................ 299,090 324,710
----------- -----------
Accumulated Deferred Income Tax (Note 4) ........ 96,048 55,770
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES ........... $ 1,300,492 $ 1,282,907
=========== ===========
The Notes to Consolidated Financial Statements are an integral part hereof.
57
ENERGY GROUP CONSOLIDATED STATEMENTS OF RETAINED EARNINGS AND COMPREHENSIVE
INCOME (NET OF TAXES)
(In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Retained Earnings:
Balance at beginning of year .......... $ 169,503 $ 163,317 $ 147,824
Net Income ............................ 43,985 41,281 50,835
Dividends declared:
On common stock ($2.16 per
share in 2003, 2002, and 2001) ...... (34,093) (35,095) (35,342)
--------- --------- ---------
Balance at end of year ................ $ 179,395 $ 169,503 $ 163,317
========= ========= =========
Comprehensive Income:
Balance at beginning of year .......... (1,732) -- --
FAS 133 transition adjustment ......... -- -- (1,896)
Change in fair value:
Derivative instruments .............. 88 19 2,691
Investments ......................... 1,282 (1,394) --
Reclassification adjustments for losses
(gains) recognized in net income .... 55 (357) (795)
--------- --------- ---------
Balance end of year ................... $ (307) $ (1,732) $ --
========= ========= =========
The Notes to Consolidated Financial Statements are an integral part hereof.
58
CENTRAL HUDSON CONSOLIDATED STATEMENT OF INCOME
(In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Operating Revenues
Electric ........................ $ 457,395 $ 427,978 $ 428,346
Natural gas ..................... 123,306 105,343 110,296
--------- --------- ---------
Total Operating Revenues .... 580,701 533,321 538,642
Operating Expenses
Operation:
Purchased electricity ........... 267,916 252,030 209,033
Fuel used in electric generation 841 757 15,406
Purchased natural gas ........... 76,452 61,672 63,330
Other expenses of operation ..... 107,105 92,246 106,812
Depreciation and amortization
(Note 1) ........................ 27,275 25,350 26,813
Taxes, other than income tax .... 31,725 38,396 50,170
Federal and State income tax
(Note 4) ........................ 25,478 21,056 17,743
--------- --------- ---------
Total Operating Expenses ...... 536,792 491,507 489,307
--------- --------- ---------
Operating Income .................. 43,909 41,814 49,335
--------- --------- ---------
Other Income
Allowance for equity funds
used during construction
(Note 1) ....................... 436 591 429
Federal and State income tax
(Note 4) ....................... (1,503) (634) 25,380
Interest on regulatory assets and
other interest income .......... 9,974 9,102 11,517
Other - net ..................... 8,024 6,379 (13,975)
--------- --------- ---------
Total Other Income ............ 16,931 15,438 23,351
--------- --------- ---------
Income before Interest
Charges ......................... 60,840 57,252 72,686
--------- --------- ---------
The Notes to Consolidated Financial Statements are an integral part hereof.
59
CENTRAL HUDSON CONSOLIDATED STATEMENT OF INCOME (CONT'D)
(In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Interest Charges
Interest on mortgage bonds ................ 570 2,136 5,211
Interest on other long-term debt .......... 10,699 9,819 10,446
Interest on regulatory liabilities and
other interest ........................... 10,987 13,021 13,170
Allowance for borrowed
funds used during
construction (Note 1) .................... (291) (248) (319)
-------- -------- --------
Total Interest Charges ................... 21,965 24,728 28,508
-------- -------- --------
Net Income ................................. $ 38,875 $ 32,524 $ 44,178
======== ======== ========
Dividends Declared on Cumulative
Preferred Stock .......................... 1,387 2,161 3,230
-------- -------- --------
Income Available for Common
Stock .................................... $ 37,488 $ 30,363 $ 40,948
======== ======== ========
The Notes to Consolidated Financial Statements are an integral part hereof.
60
CENTRAL HUDSON CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Net Income ..................................... $38,875 $ 32,524 $44,178
Net unrealized gains on Marketable securities:
Unrealized gain, net of tax
of $(26) ................................... -- 38 --
Less: reclassification adjustment
for gain included in net
income, net of tax of
of $26 ............................... -- (38) --
------- -------- -------
Subtotal .................. -- -- --
Comprehensive Income ........................... $38,875 $ 32,524 $44,178
======= ======== =======
The Notes to Consolidated Financial Statements are an integral part hereof.
61
CENTRAL HUDSON CONSOLIDATED STATEMENT OF RETAINED EARNINGS AND COMPREHENSIVE
INCOME (NET OF TAX)
(In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Retained Earnings:
Balance at beginning of year ............. $ 10,140 $ 9,777 $ 114,546
Net Income ................................ 38,875 32,524 44,178
Transfer of property to Energy
Group .................................. -- -- (75)
Dividends declared:
On cumulative preferred
stock ................................... (1,387) (2,161) (3,230)
To parent - Energy Group ............... (34,162) (30,000) (145,642)
-------- -------- ---------
Total Dividends Declared ............... (35,549) (32,161) (148,872)
-------- -------- ---------
Balance at end of year .................... $ 13,466 $ 10,140 $ 9,777
======== ======== =========
Comprehensive Income:
Balance at beginning of year .............. -- -- --
Change in fair value of investments ....... -- 38 --
Reclassification adjustments for (gains)
losses recognized in net income ......... -- (38) --
-------- -------- ---------
Balance end of year ....................... $ -- $ -- $ --
======== ======== =========
The Notes to Consolidated Financial Statements are an integral part hereof.
62
CENTRAL HUDSON CONSOLIDATED BALANCE SHEET
(In Thousands)
December 31,
2003 2002
ASSETS ---- ----
Utility Plant
Electric ......................................... $ 656,192 $ 605,989
Natural gas ...................................... 199,221 189,143
Common ........................................... 104,532 100,476
---------- ----------
959,945 895,608
Less: Accumulated depreciation ................... 309,208 297,549
---------- ----------
650,737 598,059
Construction work in progress .................... 56,764 76,398
---------- ----------
Net Utility Plant .............................. 707,501 674,457
---------- ----------
Other Property and Plant ........................... 968 968
---------- ----------
Current Assets
Cash and cash equivalents ........................ 12,720 54,989
Accounts receivable from customers - net of
allowance for doubtful accounts; $3.0 million
in 2003 and $2.7 million in 2002 ................ 37,487 35,216
Accrued unbilled utility revenues ................ 7,618 7,894
Other receivables ................................ 9,566 2,407
Fuel, materials and supplies - at average
cost ........................................... 16,158 12,459
Fair value of derivative instruments ............. 722 2,715
Bond defeasance escrow ........................... -- 16,275
Special deposits and prepayments ................. 22,503 17,656
---------- ----------
Total Current Assets ........................... 106,774 149,611
---------- ----------
Deferred Charges and Other Assets
Prefunded pension costs (Note 10) ................ -- 108,242
Regulatory assets-pension plan (Note 10) ......... 124,210 15,943
Intangible asset-pension plan (Note 10) .......... 24,447 --
Regulatory assets (Note 2) ....................... 67,474 58,057
Unamortized debt expense ......................... 3,901 3,623
Other ............................................ 8,100 7,865
---------- ----------
Total Deferred Charges and Other Assets ........ 228,132 193,730
---------- ----------
TOTAL ASSETS ....................................... $1,043,375 $1,018,766
========== ==========
The Notes to Consolidated Financial Statements are an integral part hereof.
63
CENTRAL HUDSON CONSOLIDATED BALANCE SHEET (CONT'D)
(In Thousands)
CAPITALIZATION AND LIABILITIES December 31,
2003 2002
---- ----
Capitalization
Common Stock Equity
Common stock, $5 par value (Note 8) ........... $ 84,311 $ 84,311
Paid-in capital (Note 8) ...................... 174,980 174,980
Retained earnings ............................. 13,466 10,140
Capital stock expense ......................... (4,961) (5,288)
----------- -----------
Total Common Stock Equity .................... 267,796 264,143
----------- -----------
Cumulative Preferred Stock (Note 8)
Not subject to mandatory redemption ........... 21,030 21,030
Subject to mandatory redemption ............... -- 12,500
----------- -----------
Total Cumulative Preferred Stock ............. 21,030 33,530
----------- -----------
Long-term Debt net of current portion (Note 9) .. 278,880 269,877
----------- -----------
Total Capitalization ......................... 567,706 567,550
----------- -----------
Current Liabilities
Current maturities of long-term debt ............ 15,000 15,000
Notes payable ................................... 16,000 --
Accounts payable ................................ 33,084 37,066
Accrued interest ................................ 4,274 4,273
Dividends payable ............................... 242 451
Accrued vacation and payroll .................... 5,289 4,891
Customer deposits ............................... 5,690 5,268
Other ........................................... 6,622 8,688
----------- -----------
Total Current Liabilities .................... 86,201 75,637
----------- -----------
Deferred Credits and Other Liabilities
Regulatory liabilities (Note 2) ................. 228,058 264,874
Operating reserves .............................. 5,043 4,912
Deferred gain-sale of major generating assets ... 9,887 19,774
Accrued environmental remediation costs ......... 19,500 18,304
Accrued OPEB costs .............................. 10,561 4,514
Accrued pension costs ........................... 9,775 4,244
Other ........................................... 12,524 4,003
----------- -----------
Total Deferred Credits and Other Liabilities ... 295,348 320,625
----------- -----------
Accumulated Deferred Income Tax (Note 4) ......... 94,120 54,954
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES ............. $ 1,043,375 $ 1,018,766
=========== ===========
The Notes to Consolidated Financial Statements are an integral part hereof.
64
CENTRAL HUDSON CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands)
Year ended December 31,
2003 2002 2001
---- ---- ----
Operating Activities
Net Income ................................... $ 38,875 $ 32,524 $ 44,178
Adjustments to reconcile net income to net
cash provided by (used in) operating
activities:
Depreciation and amortization ............. 28,861 26,808 28,020
Nuclear fuel amortization ................. -- -- 2,295
Deferred income taxes - net ............... 34,169 25,984 1,765
Deferred taxes related to sale of major
generating assets and Nine Mile 2
Plant write-off .......................... -- -- (259,494)
Provision for uncollectibles .............. 4,741 3,062 2,614
Amortization of fossil plant incentive .... (9,887) (4,794) (5,393)
Other - net ............................... 5,605 (783) 23,346
Changes in operating assets and
liabilities, net:
Accounts receivable, unbilled
revenues and other receivables .......... (13,895) 3,536 39,003
Fuel, materials and supplies .............. (3,699) 1,408 (4,668)
Special deposits and prepayments .......... 14,239 (931) 1,334
Contribution - prefunded pension costs .... (10,000) (32,000) --
Accrued/deferred pension costs ............ (19,698) (19,561) (17,304)
Fair value of derivative instruments ...... 1,993 -- --
Accounts payable .......................... (3,982) 4,941 (4,594)
Accrued taxes and interest ................ (2,812) 9,004 (57,857)
Deferred natural gas and electric costs ... 10,927 9,596 (3,388)
Customer benefit and carrying charge -
net ....................................... (38,844) (23,859) (8,509)
Other - net ............................... (1,247) (2,011) 12,175
Net cash provided by (used in) operating -------- -------- ---------
activities .................................. 35,346 32,924 (206,477)
-------- -------- ---------
The Notes to Consolidated Financial Statements are an integral part hereof.
65
CENTRAL HUDSON CONSOLIDATED STATEMENT OF CASH FLOWS (CONT'D)
(In Thousands)
2003 2002 2001
---- ---- ----
Investing Activities
Proceeds from sale of major generating
assets ............................... -- -- 770,835
Mortgage receivable - sale of
Nine Mile 2 Plant ..................... 1,289 28,885 (29,688)
Additions to plant ..................... (53,361) (65,830) (60,469)
Net return of equity from subsidiaries . -- -- (76)
Nine Mile 2 Plant decommissioning
trust fund (Note 3) ................... -- -- (737)
Other - net ............................ (2,050) (875) 19,579
--------- --------- ---------
Net cash (used in) provided by investing
activities ............................ (54,122) (37,820) 699,444
--------- --------- ---------
Financing Activities
Proceeds from issuance of
long-term debt ....................... 24,000 69,000 --
Retirement of preferred stock .......... (12,500) (22,500) --
Repayments of short-term debt .......... -- -- (25,000)
Retirement and redemption of
long-term debt ....................... (15,000) -- (147,630)
Net borrowings of short-term debt ...... 16,000 -- --
Dividends paid on cumulative preferred
and common stock ...................... (35,758) (32,517) (35,130)
Defeasance of long-term debt ........... -- -- (39,281)
Special dividend to parent ............. -- -- (212,000)
Issuance and redemption costs .......... (235) (1,962) (3,341)
--------- --------- ---------
Net cash (used in) provided by financing
activities ........................... (23,493) 12,021 (462,382)
--------- --------- ---------
Net Change in Cash and Cash
Equivalents ............................. (42,269) 7,125 30,585
Cash and Cash Equivalents at
Beginning of Year ....................... 54,989 47,864 17,279
--------- --------- ---------
Cash and Cash Equivalents at End
of Year ................................. $ 12,720 $ 54,989 $ 47,864
========= ========= =========
Supplemental Disclosure of Cash
Flow Information
Interest paid ........................ $ 11,867 $ 10,740 $ 19,817
Federal and State income taxes paid .. 2,917 5,068 269,567
The Notes to Consolidated Financial Statements are an integral part hereof.
66
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
This is a combined report of CH Energy Group, Inc. ("Energy Group") and
Central Hudson Gas & Electric Corporation ("Central Hudson"), a wholly owned
subsidiary of Energy Group. The Notes to the Consolidated Financial Statements
apply to the Consolidated Financial Statements of both Energy Group and Central
Hudson. Energy Group's Consolidated Financial Statements include the accounts of
Energy Group and its wholly owned subsidiaries, including Central Hudson. Energy
Group's Consolidated Financial Statements, following a one-for-one common stock
share exchange with Central Hudson effective on December 15, 1999 (the "Holding
Company Restructuring"), have been prepared from Central Hudson's prior period
consolidated financial statements.
Central Hudson and the competitive business subsidiaries (as hereinafter
defined) are each wholly owned, directly or indirectly, by Energy Group. Their
businesses are comprised of an electric and natural gas utility, cogeneration,
fuel distribution, energy management, and electric and natural gas sales.
Principles of Consolidation
The consolidated statement of income of CH Energy Group and its
subsidiaries for each of the two years ended December 31, 2002 and 2001, have
been revised to present the cumulative preferred stock dividends of its
subsidiary of $2.1 million and $3.2 million, respectively, as a deduction in
arriving at net income from continuing operations. Net income from continuing
operations, for 2002 and 2001, prior to the change in classification of such
dividends, was $38.6 million ($2.37 per share) and $54.1 million ($3.30 per
share), respectively. This revision had no effect on previously reported net
income as such dividends were considered in arriving at net income and related
per share amounts.
Upon the Holding Company Restructuring, Central Hudson became a wholly
owned subsidiary of Energy Group. Phoenix Development Company, Inc. is a wholly
owned subsidiary of Central Hudson. In addition, Central Hudson Energy Services,
Inc. ("CH Services") became a wholly owned subsidiary of Energy Group for the
purpose of becoming the holding company parent of Central Hudson Enterprises
Corporation ("CHEC"), SCASCO, Inc. ("SCASCO"), Prime Industrial Energy Services,
Inc. ("Prime Industrial"), CH Syracuse Properties, Inc. ("CH Syracuse"), CH
Niagara Properties, Inc. ("CH Niagara"), CH Resources, Inc. ("CH Resources"),
and Greene Point Development Corporation ("Greene Point").
In November 2002, the Boards of Directors of Energy Group and the
competitive business subsidiaries approved a reorganization of the competitive
business subsidiaries, effective December 31, 2002. CH Services, which had been
the holding company parent of all competitive business subsidiaries of Energy
Group, was merged into Energy Group, CHEC replaced CH Services as the holding
company parent of Griffith Energy Services, Inc. ("Griffith") and SCASCO. In
addition, Greene Point and Prime Industrial were merged into CHEC, effective the
same date. CHEC, Griffith, and SCASCO are hereinafter referred to collectively
as the "competitive business subsidiaries."
67
See Note 2 - "Regulatory Matters" under the caption "Competitive
Opportunities Proceeding Settlement Agreement" for further details regarding the
Holding Company Restructuring.
Energy Group's Consolidated Financial Statements include the accounts of
Energy Group, Central Hudson, and the competitive business subsidiaries.
Intercompany balances and transactions have been eliminated.
Rates, Revenues and Cost Adjustment Clauses
Central Hudson's electric and natural gas retail rates are regulated by
the Public Service Commission of the State of New York ("PSC"). Transmission
rates, facilities charges, and rates for electricity sold for resale in
interstate commerce are regulated by the Federal Energy Regulatory Commission
("FERC").
Central Hudson's tariff for retail electric service includes a purchased
electricity cost adjustment clause by which electric rates are adjusted to
collect actual purchased electricity costs incurred in providing service.
Central Hudson's tariff for natural gas service contains a comparable clause to
collect actual costs incurred in purchasing natural gas.
Revenue Recognition
Central Hudson records revenue on the basis of meters read. In addition,
Central Hudson records an estimate of unbilled revenue for service rendered to
bimonthly customers whose meters are read in the prior month. The estimate
covers the 30 days subsequent to the meter-read date.
Revenues are recognized by the competitive business subsidiaries when
products are delivered to customers or services have been rendered. Deferred
revenues include unamortized payments from fuel oil burner maintenance
contracts. These contracts require a one-time payment at inception of the
contract. Also included in deferred revenues are payments received from
customers who participate in budget billing programs, whose balance represents
the amount paid in excess of fuel oil deliveries received at December 31. At the
conclusion of the heating season, each such customer's budget billings are
reconciled with their actual purchases and the accounts are settled.
Utility Plant - Central Hudson
The costs of additions to utility plant and replacements of retired units
of property are capitalized at original cost. Capitalized costs include labor,
materials and supplies, indirect charges for such items as transportation,
certain taxes, pension and other employee benefits, and an Allowance for the
Funds Used During Construction ("AFDC"), as defined below. Replacement of minor
items of property is included in operating expenses.
The original cost of property, together with removal cost less salvage, is
charged to accumulated depreciation at the time the property is retired and
removed from service as required by the PSC.
68
Allowance For Funds Used During Construction
Central Hudson's regulated utility plant includes AFDC, which is defined
in applicable regulatory systems as the net cost of borrowed funds used for
construction purposes and a reasonable rate on other funds when so used. The
concurrent credit for the amount so capitalized is reported in the Consolidated
Statement of Income as follows: the portion applicable to borrowed funds is
reported as a reduction of interest charges while the portion applicable to
other funds (the equity component, a noncash item) is reported as other income.
The AFDC rate was 4.50% in 2003, 6.75% in 2002, and 8.25% in 2001.
Depreciation and Amortization
For financial statement purposes, Central Hudson's depreciation provisions
are computed on the straight-line method using rates based on studies of the
estimated useful lives and estimated net salvage values of properties. The
anticipated costs of removing assets upon retirement are provided for over the
life of those assets as a component of depreciation expense. This depreciation
method is consistent with industry practice and the applicable depreciation
rates have been approved by the PSC.
In 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 143, Accounting for
Asset Retirement Obligations ("SFAS 143"). One of the provisions of SFAS 143
precludes the recognition of expected future retirement obligations as a
component of depreciation expense or accumulated depreciation. Central Hudson is
required to use depreciation methods and rates that the PSC has approved under
regulatory accounting. In accordance with SFAS 71, Accounting for the Effects of
Certain Types of Regulation ("SFAS 71"), Central Hudson continues to accrue for
the future cost of removal for its rate regulated gas and electric utility
assets. For financial reporting purposes, Central Hudson has reclassified $79.3
million and $72.3 million of net cost of removal from accumulated depreciation
to a regulatory liability as of December 31, 2003, and 2002, respectively.
Central Hudson performs depreciation studies on a continuing basis and,
upon approval by the PSC, periodically adjusts the depreciation rates of its
various classes of depreciable property. Central Hudson's composite rates for
depreciation were 3.25% in 2003, 3.20% in 2002, and 3.17% in 2001, in each case
of the original cost of average depreciable property. The ratio of the amount of
accumulated depreciation to the original cost of depreciable property at
December 31 was 32.9% in 2003, 33.4% in 2002, and 41.2% in 2001.
For financial statement purposes, the competitive business subsidiaries'
depreciation provisions are computed on the straight-line method using
depreciation rates based on the estimated useful lives of the depreciable
property and equipment. Expenditures for major renewals and betterments, which
extend the useful lives of property and equipment, are capitalized. Expenditures
for maintenance and repairs are charged to expense when incurred. Retirements,
sales, and disposals of assets are recorded by removing the cost and accumulated
depreciation from the asset and accumulated depreciation accounts with any
resulting gain or loss reflected in earnings.
Amortization of intangibles (other than goodwill) is computed on the
straight-line method over the assets' expected useful lives. See Note 6 -
"Goodwill and other Intangible Assets" for further discussion.
69
Cash and Cash Equivalents
For purposes of the Consolidated Statement of Cash Flows, Energy Group and
Central Hudson consider temporary cash investments with a maturity, when
purchased, of three months or less to be cash equivalents.
Inventory
Inventory is valued at average cost and is comprised of the following:
Energy Group Central Hudson
------------ --------------
As of December 31, 2003 2002 2003 2002
- ------------------ ---- ---- ---- ----
(In Thousands)
Natural Gas $ 9,802 $ 5,977 $ 9,802 $ 5,977
Petroleum Products and Propane 2,779 2,633 505 467
Materials and Supplies 7,266 7,423 5,851 6,015
------- ------- ------- -------
Total $19,847 $16,033 $16,158 $12,459
------- ------- ------- -------
Investments in Marketable Securities
Marketable securities held in 2002 and liquidated in 2003 included debt
and equity instruments. Debt securities and publicly traded equity securities
were classified as available-for-sale and were marked to market using the
specific identification method; unrealized gains and losses were reflected in
Other Comprehensive Income. The company realized a net loss of $123,000 in 2003
from the sale of these investments, and a net loss of $960,000 in 2002.
Investments in Limited Partnerships
These investments are accounted for under the equity method. Unrealized
gains and losses on these investments are recognized in Other Comprehensive
Income.
70
Earnings Per Share
The following table presents Energy Group's basic and diluted earnings per share
(EPS) included on the consolidated income statement:
Year ended December 31,
2003 2002 2001
---- ---- ----
(In Thousands)
Avg. Net Avg. Net Avg. Net
Shares Income $/Share Shares Income $/Share Shares Income $/Share
------- ------- ------- ------- ------- ------- ------- ------- -------
Earnings applicable to Common
Stock - Continuing Operations (1) $43,985 $36,453 $50,835
Average number of common
shares outstanding - basic 15,831 -- $ 2.78 16,302 -- $ 2.24 16,362 -- $ 3.11
Average dilutive effect of:
Stock Options (2) (3) 3 (41) (0.01) 13 (373) (0.02) 7 (184) (0.02)
Performance Shares (3) 1 -- -- 1 -- -- 1 -- --
--------------------------------------------------------------------------------------------
Average number of common
shares outstanding - diluted 15,835 $43,944 $ 2.77 16,316 $36,080 $ 2.22 16,370 $50,651 $ 3.09
============================================================================================
(1) Total earnings (basic) for 2002 of $41.3 million include $4.8 million or
$.29 per share from discontinued operations. These earnings were not
affected by the dilutive effect related to the above stock options and
performance shares. In addition, the earnings for Energy Group reflect the
inclusion of preferred stock dividends of Central Hudson as part of
Interest and Other Charges.
(2) For 2003 and 2001, there are stock options excluded from the computation
of diluted earnings per share because the exercise prices were greater
than the average market price of the common stock shares for each of the
years presented. The number of common stock shares represented by the
options excluded from the above calculation were 94,400 and 59,100 shares,
respectively.
(3) See Note 11 - Stock-Based Compensation Incentive Plans for additional
information regarding stock options and performance shares.
71
Stock-Based Compensation
At December 31, 2003, Energy Group had a stock-based employee compensation
plan that is described more fully in Note 11 - "Stock-Based Compensation
Incentive Plans." As permitted by SFAS 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"), Energy Group had previously accounted for this plan
under the recognition and measurement provisions of Accounting Practices
Bulletin ("APB") No. 25, Accounting for Stock Issued to Employees, and related
Interpretations. No stock-based employee compensation cost was reflected in 2001
or 2002 net income, as all options granted under those plans had an exercise
price equal to the market value of the underlying common stock on the date of
grant. Effective January 1, 2003, Energy Group adopted the fair value
recognition provisions of FASB 123, utilizing the modified prospective method
under the provisions of SFAS 148, Accounting for Stock-Based Compensation -
Transition and Disclosure. Compensation cost recognized in 2003 is what would
have been recognized had the recognition provisions of SFAS 123 been applied
from its original effective date. Accordingly, a total compensation cost of
$85,000 was recorded in 2003.
The following table illustrates the effect on net income and earnings per
share if the fair value method had been applied to all outstanding and unvested
awards in each period:
Year Ended December 31
(In Thousands) 2003 2002 2001
---- ---- ----
Net income, as reported $ 43,985 $ 41,281 $ 50,835
Deduct: Total stock-based employee
compensation expense determined under
fair value based method for all awards,
net of related tax effects -- (41) (107)
-------- -------- --------
Pro forma net income $ 43,985 $ 41,240 $ 50,728
======== ======== ========
Earnings per share:
Basic - as reported $ 2.78 $ 2.53 $ 3.11
======== ======== ========
Basic - pro forma $ 2.78 $ 2.53 $ 3.10
======== ======== ========
Income Tax
Energy Group and its subsidiaries file consolidated federal and New York
State income tax returns. Federal and state income taxes are allocated to
operating expenses and to other income and deductions in the Consolidated
Statement of Income. Income taxes are deferred under the liability method in
accordance with SFAS 109, Accounting for Income Taxes ("SFAS 109"). Under the
liability method, deferred income taxes are provided for all differences between
the financial statement and the tax basis of assets and liabilities. Additional
deferred income taxes and offsetting regulatory assets or liabilities are
recorded by Central Hudson to recognize that income taxes will be recovered or
refunded through future revenues. For federal and state income tax purposes,
Energy Group and its subsidiaries use an accelerated method of depreciation and
generally use the shortest life permitted for each class of assets. For state
income tax purposes, Central Hudson uses book depreciation for property placed
in service in 1999 or earlier in accordance with transition property rules under
Article 9-A of the New York State Tax Law. For more information, see Note 4 -
"Income Tax."
72
Use of Estimates
Preparation of the financial statements in accordance with generally
accepted accounting principles includes the use of estimates and assumptions by
Management that affect the reported amounts of assets and liabilities and
disclosures of contingent assets and liabilities at the date of the financial
statements and reported amount of revenues and expenses during the reporting
period. Actual results may differ from those estimated. Expense items most
affected by the use of estimates are depreciation and amortization (including
amortization of intangible assets), the reserve for uncollectible accounts,
other operating reserves, and unbilled revenues. Depreciation and amortization
is based on estimates of the useful lives and estimated net salvage value of
properties (as described in this note under the caption "Depreciation and
Amortization"). Amortizable intangible assets include the amortization of
customer lists related to CHEC's operations, which is based on an assessment of
customer turnover as described in Note 6 - "Goodwill and Other Intangible
Assets". Depreciation and amortization amounts included in Energy Group income
for years 2003, 2002 and 2001 are $33.6 million, $31.2 million and $35.6
million, respectively.
Estimates for uncollectible accounts are based on customer accounts
receivable aging data as well as consideration for special collection issues.
The estimates for other operating reserves are based on assessments of future
obligations as it relates to injuries and damages and workers compensation
claims. A summary of the activity in these reserves, including charges to
expense, for years 2001 through 2003 can be found on Schedule II - Reserves for
both Energy Group and Central Hudson. Unbilled revenues are determined based on
the estimated sales for accounts that have not yet been billed by Central
Hudson. The estimation methods used in determining the sales are the same
methods used for billing customers when actual meter readings cannot be
obtained. Revenues for 2003 include an estimate of $5.2 million for unbilled
revenues and 2002 includes an estimate of $5.3 million.
Estimates are also reflected for certain commitments and contingencies,
where there is sufficient basis to project a future obligation. Disclosures
related to same can be found in Note 13 - "Commitments and Contingencies."
Related Party Transactions
Thompson Hine LLP (formerly Gould & Wilkie LLP) serves as general counsel
to Energy Group and Central Hudson. A partner in that firm serves as Assistant
Secretary of each corporation. This Assistant Secretary appointment serves to
assist in closure of specified transactions in the ordinary course of business.
While this partner receives no additional compensation for his role as Assistant
Secretary, time spent performing the duties of Assistant Secretary is charged to
Energy Group and Central Hudson on an hourly basis. The combined fees paid by
Energy Group and Central Hudson to Thompson Hine LLP were $3.4 million in 2003,
$2.5 million in 2002, and $3.2 million in 2001.
73
Parental Guarantees
Energy Group and certain of the competitive business subsidiaries have
issued guarantees in conjunction with certain commodity and derivative contracts
that provide financial or performance assurance to third parties on behalf of a
subsidiary. The guarantees are entered into primarily to support or enhance the
creditworthiness otherwise attributed to a subsidiary on a stand-alone basis,
thereby facilitating the extension of sufficient credit to accomplish the
relevant subsidiary's intended commercial purposes. In addition, Energy Group
has agreed to guarantee the post-closing obligations of CH Services under the
agreement related to the sale of CH Resources, which guarantee now applies to
CHEC. See Note 13 - "Commitments and Contingencies," under the caption "CHEC."
The guarantees described have been issued to counter-parties to assure the
payment, when due, of certain obligations incurred by the Energy Group
subsidiaries in physical and financial transactions related to natural gas,
heating oil, propane, other petroleum products, weather and commodity hedges,
and certain obligations related to the sale of CH Resources. At December 31,
2003, the aggregate amount of subsidiary obligations (excluding obligations
related to CH Resources) covered by these guarantees was $7.7 million. Where
liabilities exist under the commodity-related contracts subject to these
guarantees, these liabilities are included in the Consolidated Balance Sheet.
Product Warranties
Griffith and SCASCO offer a multi-year warranty on heating system
installations and multi-year service contracts as an incentive to new heating
oil delivery customers, and have recorded liabilities for the estimated costs of
fulfilling their respective obligations under these warranty and service
contracts. The aggregate amounts of these liabilities were approximately
$830,000 and $1 million at December 31, 2003, and 2002, respectively. The
accounting policy and methodology used to determine each subsidiary's liability
for these product warranties is to accrue the present value of future warranty
expense based on the number and type of contracts outstanding and historical
costs for these contracts.
Accounting for Derivative Instruments and Hedging Activities
In June 1998, the FASB issued Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS 133"), which was subsequently amended
in June 2000 and April 2003 by FASB Statement No. 138, Accounting for Certain
Derivative Instruments and Certain Hedging Activities, and by FASB Statement
149, Amendment of Statement 133 on Derivative Instruments and Hedging
Activities, respectively. As amended, SFAS 133 established accounting and
reporting requirements for derivative instruments and hedging activities. SFAS
133 requires that an entity recognize the fair value of all derivative
instruments as either assets or liabilities in the balance sheet with the
corresponding unrealized gains or losses recognized in earnings. SFAS 133
permits the deferral of unrealized hedge gains and losses, under stringent hedge
accounting provisions, until the hedged transaction is realized. SFAS 133 also
provides an exception for certain derivative transactions that qualify as
"normal purchases and normal sales." These are transactions that are exempt from
SFAS 133 if they provide for the purchase or sale of something other than a
financial or derivative instrument to be delivered in quantities for probable
use or sale by the reporting entity in the normal course of business within a
reasonable period of time.
74
As part of its adoption of SFAS 133, Energy Group recognized a net of tax
transition adjustment of $(1.9) million in Other Comprehensive Income on January
1, 2001. This amount represents the cumulative effect of a change in accounting
principle for unrealized losses when certain derivatives owned by CHEC were
redesignated as cash flow hedges. This adjustment was reversed by December 31,
2001, as the actual related gains and losses were realized during the period
from January 2001 to December 2001. The actual gains and losses served to offset
the variability in cash flows related to the transactions hedged.
Energy Group and its subsidiaries do not enter into derivative instruments
for speculative purposes.
Central Hudson uses derivative instruments to hedge exposure to
variability in the prices of natural gas and electricity and to hedge exposure
to variability in interest rates for its variable rate long-term debt. The types
of derivative instruments used by Central Hudson are natural gas futures and
basis swaps to hedge natural gas purchases, contracts for differences to hedge
electricity purchases, and interest rate caps to hedge interest payments on
variable rate debt. These derivatives are not designated as hedges under the
provisions of SFAS 133, and derivatives existing at January 1, 2001, were not
redesignated as hedges as the related gains and losses were included as part of
Central Hudson's commodity cost and/or price-reconciled in its natural gas and
electricity cost adjustment charge clauses. The premium related to interest rate
hedges, as well as any related actual gains, is also subject to a true-up
mechanism authorized by the PSC for the variable long-term debt. The earnings
impact from these derivatives is, therefore, deferred for refund to, or recovery
from, customers under their respective regulatory adjustment mechanisms.
At December 31, 2003, Central Hudson had open derivative contracts to
hedge natural gas prices through October 2004, covering approximately 13.1% of
Central Hudson's projected total natural gas requirements during this period. In
2003, derivative transactions were used to hedge 18.2% of Central Hudson's total
natural gas supply requirements as compared to 4.3% in 2002. In its electric
operations, Central Hudson had open derivatives at December 31, 2003, hedging
approximately 2.5% of its required electricity supply through August 2004. In
2003, Central Hudson hedged approximately 13.7% of its total electricity supply
requirements with over-the-counter ("OTC") derivative contracts as compared to
29.9% in 2002. In addition, Central Hudson has in place a number of agreements
of varying terms to purchase electricity produced by its former major generating
assets and other generating facilities at fixed prices. The notional amounts
hedged by the derivatives and the electricity purchase agreements for 2004 and
2005 represent approximately 59% and 36%, respectively, of Central Hudson's
total electricity supply requirements.
The total fair value (net unrealized gain) of Central Hudson's derivatives
at December 31, 2003, was $722,000 as compared to a fair value of $2.7 million
at December 31, 2002. Fair value is determined based on market quotes for
exchange traded derivatives and broker quotes for OTC derivatives. Actual net
losses of $1.04 million were recorded as additional energy costs in 2003, which
were recovered through Central Hudson's electric and natural gas cost adjustment
clauses. This compares to a total net gain of $635,000 recorded in 2002, which
served to reduce energy costs.
The competitive business subsidiaries use derivative instruments to hedge
variability in the price of heating oil purchased for resale. Griffith and
SCASCO generally enter into heating oil put option contracts to hedge firm
heating oil purchase commitments and also enter into call option contracts to
cover forecasted heating oil supply requirements for fixed and capped price
programs not hedged by firm contracts. The call options hedge commodity price
increases
75
and/or supply restrictions resulting from colder than normal weather. These
derivatives are designated as either fair value hedges or cash flow hedges under
the provisions of SFAS 133 and are accounted for under the deferral method with
actual gains and losses from the hedging activity included in the cost of sales
as the hedged transaction occurs. The put and call options entered into have
been effective with no gains or losses from ineffectiveness recorded in 2003 or
2002. The assessment of hedge effectiveness for these hedges excludes the change
in the fair value of the premium paid for these derivative instruments. These
premiums, which are not material, are expensed based on the change in their
respective fair value. The fair values of open derivative instruments at
December 31, 2003, and at December 31, 2002, were not material. Including
premium costs, a net loss was recorded in 2003 and a net gain was recorded in
2002 as part of the cost or price of the related commodity transactions. The
amounts recorded were not material, representing less than 1% of total petroleum
costs for each of the respective years. The fair values of put and call options
are determined based on the market value of the underlying commodity.
At December 31, 2003, Griffith and SCASCO had open OTC put and call option
positions covering approximately 18.1% of their combined anticipated fuel oil
supply requirements for the period January 2004 through June 2004. In 2003,
derivative transactions were used to hedge 12.3% of total fuel oil requirements
as compared to 6.4% in 2002.
In addition to the above, Central Hudson, Griffith, and SCASCO have
entered into weather derivative contracts, beginning with the 2001-2002 heating
season, to hedge the effect on earnings of significant variances in weather
conditions from normal patterns. These weather derivatives are entered into for
the heating season, which runs from November through March. In addition, Central
Hudson has entered into similar contracts for the cooling season, which runs
from June through August. Weather derivative contracts are not subject to the
provisions of SFAS 133 and are accounted for in accordance with Emerging Issues
Task Force ("EITF") Statement 99-2, Accounting for Weather Derivatives. In 2003,
due to the colder than normal weather, payments were made to counter-parties by
Central Hudson, Griffith, and SCASCO totaling $3.6 million and in 2002 a total
net payment of $363,000 was made to counter-parties. In each case these amounts
partially offset variations in revenues experienced due to the actual weather
patterns that occurred in each period. Weather derivative contracts are
currently in place to cover the months of January, February, and March 2004,
with an aggregate settlement cap of $5.3 million.
New Accounting Standards and Other FASB Projects - Standards Implemented
Asset Retirement Obligations
SFAS 143 was initiated in 1994 as a project to account for the costs of
nuclear decommissioning and the FASB later expanded its scope to include similar
closure or removal-related costs in other industries that are incurred at any
time during the life of an asset. SFAS 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred. When the liability is initially recorded, the entity capitalizes
the cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is shown at its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement. SFAS 143 is effective
for the calendar year that began January 1, 2003. Its implementation has not had
a material impact on Energy Group or Central Hudson's financial condition,
results of operations, or cash flows. See this note under the caption
"Depreciation and
76
Amortization" for additional discussion of SFAS 143. As described therein, as
required by SFAS 143, Central Hudson has reclassified $79.3 million from
accumulated depreciation to a regulatory liability account for the year ended
December 31, 2003, and $72.3 million for the year ended December 31, 2002.
Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity - SFAS 150
On May 30, 2003, the FASB issued Statement No. 150, Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity ("SFAS
150"). It requires that an issuer classify a financial instrument that is within
the scope of SFAS 150 as a liability or asset, in some circumstances, including
financial instruments issued in the form of shares that are mandatorily
redeemable - that is, placing an unconditional obligation on its issuer to
redeem it by a transfer of assets by its issuer at a specified or determined
date(s) or upon an event that is certain to occur.
SFAS 150 is effective for financial instruments entered into or modified
after May 31, 2003, and otherwise is effective at the beginning of the first
interim period beginning after June 15, 2003, except for mandatorily redeemable
financial instruments of non-public entities.
Central Hudson had two issues of mandatorily redeemable preferred stock,
and Central Hudson adopted SFAS 150 effective July 1, 2003. Therefore, dividends
related to this preferred stock for the quarter ended September 30, 2003, were
recorded as interest charges. On October 1, 2003, Central Hudson redeemed the
$12.5 million balance of this mandatorily redeemable preferred stock. These
changes did not have a material impact on Energy Group's or Central Hudson's
financial condition, results of operations, or cash flows.
Lease Arrangements
In May 2003, the EITF reached consensus on Issue No. 01-8, Determining
Whether an Arrangement Contains a Lease ("EITF 01-8"). Under the provisions of
EITF 01-8, arrangements conveying the right to control the use of specific
property, plant, or equipment must be evaluated to determine whether they
contain a lease. For Energy Group, the new rules went into effect July 1, 2003,
and are applicable to contracts entered into or modified after that date. Energy
contracts entered into by Central Hudson and CHEC, depending on the facts and
circumstances, could be subject to the accounting guidance set forth by EITF
01-8. However, its implementation has not and is not expected to materially
impact the financial condition, results of operations, or cash flows of Energy
Group or its subsidiaries at this time.
Pension and Other Postretirement Benefits
On December 23, 2003, the FASB issued its revised version of Statement No.
132, Employees' Disclosures About Pensions and Other Postretirement Benefits
("SFAS 132"), providing new disclosure requirements for pensions and other
postretirement benefits. The objective of SFAS 132 is to provide additional
disclosure information that is useful in evaluating plan assets, obligations,
and pension costs, including associated risks that may impact future earnings
and cash flows, so that users can develop a clearer picture regarding the status
and health of a company's plan. SFAS 132 contains requirements to provide
reconciliation of beginning and ending balances of the fair value of plan assets
and benefit obligations. In addition, key elements such as target allocations,
investment strategies, measurement dates,
77
actual return on assets, benefit payments, employer contributions and
participant contributions, and assumed discount rates are now required to be
disclosed. The provisions of SFAS 132 are effective for the fiscal years ending
on or after December 15, 2003, and have been adopted by Energy Group. (See Note
10 - "Post-Employment Benefits").
New Accounting Standards and Other FASB Projects - Standards to be Implemented
Property, Plant and Equipment
During the second quarter of 2001, the FASB issued an Exposure Draft
entitled Accounting in Interim and Annual Financial Statements for Certain Costs
and Activities Related to Property, Plant, and Equipment. This Exposure Draft
would amend certain APB Opinions and FASB Statements to incorporate changes
resulting from the issuance of a proposed American Institute of Certified Public
Accountants ("AICPA") Statement of Position ("SOP"), Accounting for Certain
Costs and Activities Related to Property, Plant, and Equipment. This project
would amend certain APB Opinions and FASB Statements to incorporate changes that
would result from the final issuance of the proposed AICPA SOP, Accounting for
Certain Costs and Activities Related to Property, Plant, and Equipment. This
project also would amend APB Opinion No. 28, Interim Financial Reporting so that
the provision of the proposed SOP that would require certain costs to be charged
to expense as incurred also would apply to interim periods. The Accounting
Standards Executive Committee ("AcSEC"), at its September 2003 meeting, approved
for final issuance the SOP, Accounting for Certain Costs and Activities Related
to Property, Plant, and Equipment, subject to AcSEC's positive clearance and
FASB clearance. AcSEC expects to issue the SOP in the first quarter of 2004. Its
implementation is not expected to have a material impact on Energy Group or
Central Hudson's financial condition, results of operations, or cash flows.
Reclassification
Certain amounts in the 2002 and 2001 Consolidated Financial Statements
have been reclassified to conform to the 2003 presentation.
NOTE 2 - REGULATORY MATTERS
Competitive Opportunities Proceeding Settlement Agreement
In response to the May 1996 Order of the PSC issued in its generic
Competitive Opportunities Proceeding, Central Hudson, the PSC Staff and certain
other parties entered into an Amended and Restated Settlement Agreement, dated
January 2, 1998. The PSC approved the Amended and Restated Settlement Agreement
by its final Order issued and effective June 30, 1998, for which a final
amendment was issued and approved as of March 7, 2000 (hereinafter called the
"Agreement").
The Agreement, which expired on June 30, 2001, included the following
major provisions which survive its expiration date: (i) certain limitations on
ownership of electric generation facilities by Central Hudson and its affiliates
in Central Hudson's franchise territory; (ii) standards of conduct in
transactions between Central Hudson, Energy Group, and the competitive business
subsidiaries; (iii) prohibitions against Central Hudson making loans to Energy
Group or any other subsidiary of Energy Group and on Central Hudson guaranteeing
debt of Energy Group or any other subsidiary of Energy Group; (iv) limitations
on the transfer of Central Hudson employees to Energy Group or other Energy
Group subsidiaries, and the use of
78
Central Hudson officers in common with Energy Group or other Energy Group
subsidiaries; (v) certain dividend payment restrictions on Central Hudson, and
(vi) treatment of savings up to the amount of an acquisition's or merger's
premium or costs flowing from a merger with another utility company.
Regulatory Accounting Policies
Central Hudson follows generally accepted accounting principles which, for
regulated public utilities, include SFAS 71, Accounting for the Effects of
Certain Types of Regulation. Under SFAS 71, regulated companies apply AFDC to
the cost of construction projects and defer costs and credits on the balance
sheet as regulatory assets and liabilities (see Note 2 under the caption
"Summary of Regulatory Assets and Liabilities") when it is probable that those
costs and credits will be recoverable through the rate-making process in a
period different from when they otherwise would have been reflected in income.
These deferred regulatory assets and liabilities are then either eliminated by
offset or reflected in the income statement in the period in which the same
amounts are reflected in rates. In addition, current accounting practices
reflect the regulatory accounting authorized in the most recent Settlement
Agreement or Rate Order.
Sales of Major Generating Assets
Pursuant to the Agreement, on January 30, 2001, Central Hudson, after a
competitive bidding process, sold its Danskammer Point Steam Electric Generating
Station ("Danskammer Plant") and its interest in the Roseton Electric Generating
Station ("Roseton Plant") to affiliates of Dynegy Power Corp. (collectively,
"Dynegy") for $713 million. By Order issued and effective October 26, 2001
("Nine Mile 2 Order"), the PSC authorized the sale of Central Hudson's interest
in the Nine Mile 2 Nuclear Generating Plant ("Nine Mile 2 Plant"). The
Danskammer Plant, the Roseton Plant, and the Nine Mile 2 Plant are referred to
collectively herein as the "major generating assets." On November 7, 2001,
Central Hudson sold its interest in the Nine Mile 2 Plant to an affiliate of
Constellation Nuclear LLC ("Constellation") for approximately $58.2 million, of
which $28.4 million was paid in cash with the remaining principal to be paid
under a five-year, 11% promissory note, all subject to certain post-closing
adjustments. On April 12, 2002, Constellation elected to pay the then remaining
balance of $29.8 million on the promissory note. Central Hudson's net gain,
after-tax, from these sales was used to recover the book value and the net
regulatory assets related to Central Hudson's interests in its major generating
assets.
Despite these sales, Central Hudson remains obligated to supply
electricity to its retail electric customers. Under the Agreement, Central
Hudson's retail customers may elect to procure electricity from third party
suppliers, or may continue to rely on Central Hudson. No prediction can be made
as to the amount of service that Central Hudson will be obligated to provide or
the cost or availability of electricity to satisfy Central Hudson's retail
customers' requirements. To partially supply these customers, Central Hudson
entered into a Transition Power Agreement ("TPA") with Dynegy to purchase
capacity and energy from January 30, 2001, through October 31, 2003. On August
2, 2002, Central Hudson exercised an option to extend the TPA through October
31, 2004. Central Hudson also entered into an agreement with Constellation to
purchase capacity and energy from the Nine Mile 2 Plant during the ten-year
period beginning on the sale of Central Hudson's interest in the Nine Mile 2
Plant on November 7, 2001. In the case of each of the TPA and the Constellation
agreements, electricity will be purchased at defined prices that escalate over
the lives of the respective contracts. The capacity and energy supplied under
these two agreements in 2003 was
79
sufficient to supply approximately 44% of Central Hudson's retail customer
requirements. On November 12, 2002, Central Hudson entered into an agreement
with Entergy Nuclear Indian Point 2 LLC and Entergy Nuclear Indian Point 3 LLC
to purchase electricity (but not capacity) on a unit-contingent basis at defined
prices from January 1, 2005, to and including December 31, 2007. On April 23,
2003, Central Hudson entered into an agreement with Entergy Nuclear Fitzpatrick,
LLC to purchase electricity (but not capacity) on a unit-contingent basis at
defined prices from January 1, 2004, to and including December 31, 2004.
Summary of Regulatory Assets and Liabilities
The following table sets forth Central Hudson's regulatory assets and
liabilities:
At December 31, 2003 2002
- --------------------------------------------------------------------------
Regulatory Assets (Debits): (In Thousands)
Deferred pension costs undercollection
(Note 10) ...................................... $ 124,210 $ 15,943
Carrying charges - pension reserve (Note 10) .... 18,026 8,863
Deferred manufactured gas sites (Note 13) ....... 14,360 12,760
Deferred OPEB costs undercollection
(Note 10) ...................................... 9,226 2,617
Deferred debt expense on reacquired debt
(Note 9) ....................................... 8,603 9,489
Income taxes recoverable
through future rates ........................... 5,410 1,519
Deferred purchased electric and natural gas costs
(Note 1) ....................................... 4,432 15,359
Other ........................................... 7,417 7,450
--------- ---------
Total Regulatory Assets ........................ $ 191,684 $ 74,000
--------- ---------
Regulatory Liabilities (Credits):
Customer benefit fund ........................... $ 133,043 $ 171,887
SFAS 143 - accumulated cost of removal .......... 79,300 72,800
Deferred Nine Mile 2 Plant costs overcollection . 1,960 1,508
SFAS 133 - deferred change in fair value
(Note 1) ....................................... 722 $ 2,715
Income taxes refundable ......................... 463 1,568
Other ........................................... 12,570 14,396
--------- ---------
Total Regulatory Liabilities ................... $ 228,058 $ 264,874
--------- ---------
Net Regulatory Liabilities ................... $ (36,374) $(190,874)
========= =========
The significant regulatory assets and liabilities include:
Deferred Pension Costs Undercollection: As discussed further in Note 10,
the amount for 2003 includes $83.6 million related to the accounting required
under SFAS 87 for recording a minimum pension liability. The remaining $40.6
million is the cumulative undercollected pension costs owed by customers.
Carrying Charges - Pension Reserves: Under the policy of the PSC regarding
pension costs, carrying charges are accrued on cash differences between rate
allowances and cash contributions to the Retirement Plan.
80
Income Taxes Recoverable/Refundable: The adoption of SFAS 109 in 1993
increased Central Hudson's net deferred taxes. As it is probable that the
related balances will be either recoverable from or refundable to customers,
Central Hudson established a net regulatory asset for the recoverable future
taxes and a net regulatory liability for balances refundable to customers. The
SFAS 109 amounts related to the major generating assets were eliminated at the
time of the sales of Central Hudson's interests in the respective plants, with
no impact on earnings.
Customer Benefit Fund: The Agreement required that Central Hudson make
available $10 million per calendar year of the Agreement in a Customer Benefit
Fund to fund rate reductions and retail access options. Funding sources included
$3 million from shareholder sources, $3.5 million from fuel cost savings
generated by the installation of a coal dock unloading facility at the
Danskammer Plant, and $3.5 million from deferred credits related to the
reconciliation of rate allowances compared to actual costs for pension and other
post-employment benefit costs. The Agreement also stipulated that unused funds
accumulated to the end of the Agreement's term be used to offset strandable
costs or to provide other benefits to ratepayers. The terms of the Customer
Benefit Fund were later supplemented as described under the caption "Rate
Proceedings - Electric and Natural Gas."
SFAS 143 - Accumulated Cost of Removal: The adoption of SFAS 143 resulted
in a reclassification of $79.3 million and $72.8 million for 2003 and 2002,
respectively, from accumulated depreciation. This amount represents the future
cost of removing assets upon retirement and was reclassified from the
accumulated depreciation account to a regulatory liability account.
Deferred Nine Mile 2 Plant Costs: The PSC Order on Nine Mile 2 Plant
Operating and Capital Forecast for 1996 ("Supplement No. 5") provided for the
deferral of the difference between actual and authorized operating and
maintenance expenses for the Nine Mile 2 Plant. Central Hudson's interest in the
Nine Mile 2 Plant was sold in November 2001. The regulatory liability recorded
represents the residual overcollection balance and related carrying charges due
to customers.
Rate Proceedings - Electric and Natural Gas
On August 1, 2000, Central Hudson filed an electric and natural gas case
with the PSC. On August 21, 2001, after full evidentiary hearings, several
public hearings, and numerous negotiation sessions, a joint proposal ("Joint
Proposal") was filed by Central Hudson, the Staff of the PSC, and other parties
to the case.
On October 25, 2001, the PSC issued its Order Establishing Rates in the
proceeding ("Rate Order") incorporating the provisions of the Joint Proposal.
New rates became effective November 1, 2001. All accounting related to the rate
proceeding and any offsetting balances, which would have resulted as if the new
rates had been in effect on July 1, 2001, were reconciled.
Significant terms and conditions of the Joint Proposal and the Rate Order
are: (i) a three year term, beginning July 1, 2001, with a Central Hudson option
to extend the Rate Order for up to two additional years; (ii) electric delivery
rates were reduced by 1.2% and then frozen at rates in effect on June 30, 2001,
for the remainder of the term of the Rate Order and natural gas delivery rates
were frozen for the term of the Rate Order; (iii) Central Hudson will continue
to purchase electricity and natural gas for its full service customers and will
recover these costs
81
from customers through energy adjustment mechanisms; (iv) customer charges were
and will be increased and volumetric delivery charges were reduced; (v) customer
bills will be formatted to show the market price of electricity in order to
encourage competition and enhance customer migration to third party energy
suppliers; (vi) electric customers will receive refunds of $25 million in
aggregate for each of the first three years the Rate Order is effective; (vii)
Central Hudson will be allowed a base return on equity ("ROE") of 10.3% on the
equity portion of its rate base (approximately $250 million); (viii) the common
equity ratio will be capped, for purposes of the PSC's ROE calculation, at 47%
in the first year of the Rate Order and decline 1% per year in each of the
following two years; (ix) earnings above the 10.3% base ROE will be retained by
Central Hudson up to 11.3%, with an equal sharing of earnings between customers
and Central Hudson, between 11.3% and 14%, and earnings above 14% will be added
to the Customer Benefit Fund; (x) the establishment of customer service
standards with associated penalties if standards are not met and enhanced low
income and customer education programs; and (xi) excess proceeds from the sales
of Central Hudson's interests in its major generating assets and net deferred
regulatory accounts approximating $169 million (net of tax) were made available
for the Customer Benefit Fund and a portion of such Fund was directed to be used
as follows:
1) Customer refunds $45.0 million (net of tax)
2) Rate base reduction $42.5 million (net of tax)
3) Enhanced electric
reliability program $13.0 million (net of tax)
4) Offset of manufactured gas
plant site remediation costs $12.6 million (net of tax)
Also included in the Rate Order and the Nine Mile 2 Order were approval
for Central Hudson to recognize $19.8 million of tax benefits related to the
sales of its interests in its major generating assets, offset by $11.4 million
of after-tax contributions by Central Hudson to the Customer Benefit Fund, or a
net benefit to shareholders of $8.4 million, which amount was recorded in the
fourth quarter of 2001. Central Hudson has or will additionally recognize net
income for shareholders under a prior PSC regulatory settlement as follows: $2.9
million in 2002, $5.9 million in 2003, and $5.9 million in 2004. These tax
benefits and prior settlement-related amounts are excluded from the earnings
that are subject to the ROE sharing formula described above.
Expiring Amortization: Under a prior PSC regulatory settlement related to
the sales of Central Hudson's interests in its major generating assets, a
portion of the gain recognized on the sales is being recorded as net income over
a four-year period which commenced in 2001. Amounts recorded or to be recorded
by year, net of tax, are as follows: 2001 - $3.2 million, 2002 - $2.9 million,
2003 - $5.9 million, and 2004 - $5.9 million. Energy Group is seeking to use its
cash reserves and debt capacity to make investments with a view to produce new
earnings intended to replace, in whole or in part, the income from the sales of
Central Hudson's major generating assets. In this connection, Energy Group is
actively seeking new energy-related investments that provide diversification and
offer attractive returns with acceptable risks. Such opportunities may include,
but are not limited to, currently operating assets that use proven technology
and have a relatively stable customer base such as electric generating plants
and natural gas pipelines, in either case with a significant portion of their
output under long-term contract. Energy Group also may use its cash reserves to
repurchase shares of its common stock. Such repurchases, depending on the number
and average price of shares repurchased, could have the effect of offsetting a
82
substantial portion of the earnings per share impact of the expiring
amortization noted above.
On October 3, 2002, the PSC issued two additional orders in the electric
rate proceeding. The first such order authorized and directed Central Hudson to
refund to its electric customers an additional $10 million in aggregate from the
Customer Benefit Fund over the period November 1, 2002, through June 30, 2004.
The second such order authorized the implementation of an $11 million Economic
Development Program to be funded from the Customer Benefit Fund over a period of
five years.
On October 23, 2003, the PSC issued an order establishing further
procedures in the electric rate proceeding. The order directed Central Hudson to
participate in a collaborative proceeding beginning November 1, 2003, to (i)
address the uses of the Customer Benefit Fund credits after June 30, 2004, and
(ii) address the continuation of programs to promote retail competition and
service quality. Central Hudson was directed to make a filing by March 1, 2004,
detailing proposals where consensus was reached among the parties and
identifying areas where consensus was not reached. Central Hudson has
participated in a number of meetings pursuant to this order but cannot predict
the outcome of these discussions.
FERC Restructuring and Independent System Operator
In its Order No. 888 ("Order 888"), the FERC directed jurisdictional
transmission owners to restructure their operations to promote open transmission
access. As proposed in response to Order 888 and as approved by the FERC, on
December 1, 1999, the New York State Independent System Operator ("NYISO") was
created and given responsibility for the operation of the New York State
transmission system.
The NYISO is a not-for-profit New York corporation open to buyers,
sellers, consumers, and transmission owners, each of which are represented on
its Management Committee. As part of the restructuring, a New York State
Reliability Council ("Reliability Council") was also established. The
Reliability Council is governed by a committee comprised of transmission owners
and representatives of buyers, sellers, and consumer and environmental groups.
The Reliability Council promotes and preserves the reliability of the bulk power
system within New York State through its promulgation of reliability rules; the
NYISO develops the procedures necessary to operate the system within those
reliability rules. Central Hudson is a member of the NYISO and the Reliability
Council.
In its Order No. 2000 ("Order 2000"), the FERC directed all utilities
subject to its jurisdiction under the Federal Power Act that belong to an
Independent System Operator ("ISO") to make a filing on or before January 15,
2001, addressing the extent to which that ISO conforms to the minimum
characteristics and functions of a Regional Transmission Organization ("RTO"), a
plan for such conformation, and any obstacles to full compliance with the FERC's
RTO requirements. A compliance filing was made by the six jurisdictional New
York State transmission owners (including Central Hudson) and the NYISO which
demonstrated that the NYISO would satisfy all of FERC's RTO requirements. Upon
review of this compliance filing, the FERC issued an order determining that the
NYISO does not satisfy the RTO requirements set forth in Order 2000.
On November 7, 2001, the FERC issued an "Order Providing Guidance on
Continued Processing of RTO Filings" under which the FERC intends to complete
the RTO effort using two
83
parallel tracks to resolve business and process issues relating to: (i)
geographic scope and governance of qualifying RTOs across the nation, and (ii)
transmission tariff and market design rulemaking for public utilities, including
RTOs, to accomplish the objectives of Order 2000.
On July 31, 2002, the FERC released its third major restructuring
initiative by issuing a Notice of Proposed Rulemaking on Remedying Undue
Discrimination through Open Access Transmission Service and Standard Electricity
Market Design ("SMD NOPR"). A significant requirement of the SMD NOPR is that
all public utilities become Independent Transmission Providers ("ITP"), turn
over their transmission facilities to an ITP, or contract with an ITP to operate
their transmission facilities.
In order to address concerns raised by various parties, on April 28, 2003,
the FERC issued a white paper entitled "Wholesale Power Market Platform" ("White
Paper") identifying changes to its proposed market design rules. In addition,
the White Paper announced a series of regional technical conferences to further
discuss market design issues with the states and market participants. The
technical conference for New York was held on October 20, 2003.
At this time the FERC has not identified a date for issuance of a final
rule on Standard Market Design ("SMD"). Legislation currently before Congress
includes a provision delaying implementation of SMD until at least 2007.
Recently the NYISO has undertaken an initiative to develop a more
comprehensive electric system planning process for New York State. The PSC and
market participants, including Central Hudson, are participating in this effort.
No prediction can be made as to the outcome of the FERC electric
restructuring effort or the NYISO planning process initiative.
NOTE 3 - NINE MILE 2 PLANT
General
The Nine Mile 2 Plant, formerly owned as tenants-in-common by Central
Hudson (9% interest), Niagara Mohawk Power Corporation ("Niagara Mohawk") (41%
interest), New York State Electric and Gas Corporation ("NYSEG") (18% interest),
Long Island Lighting Company, d/b/a Long Island Power Authority (18% interest),
and Rochester Gas and Electric Corporation ("Rochester") (14% interest), is
located in Oswego County, New York and has a rated net capability of 1,143
megawatts. As described in Note 2 herein, Central Hudson, together with Niagara
Mohawk, NYSEG, and Rochester, sold its interest in the Nine Mile 2 Plant to an
affiliate of Constellation on November 7, 2001.
The output of the Nine Mile 2 Plant was shared among, and its operating
expenses allocated among, the cotenants in the same proportions as the
cotenants' respective ownership interests. Central Hudson's share of direct
operating expense for the Nine Mile 2 Plant was included in the appropriate
expense classifications in the Consolidated Statement of Income.
As part of an agreement with Constellation, Central Hudson will buy, at
negotiated prices, approximately 8% of the output of the Nine Mile 2 Plant over
the period beginning November 7, 2001, and ending November 30, 2011. Following
the expiration of this purchase agreement, a Revenue Sharing Agreement with
Constellation begins, which will provide Central Hudson with a hedge against
electricity price increases and could provide additional future
84
revenue for Central Hudson through 2021.
Nuclear Plant Decommissioning Costs
Prior to the sale of Central Hudson's interest in the Nine Mile 2 Plant,
Central Hudson made annual contributions of $868,000 to a qualified external
nuclear decommissioning trust fund relating to the Nine Mile 2 Plant. The total
annual amount allowed in rates was $999,000, but the maximum annual tax
deduction allowed was $868,000. The difference between the rate allowance and
the amount contributed to the external qualified fund was recorded as an
internal reserve, and the funds were held by Central Hudson.
As part of the sale of the Nine Mile 2 Plant, the external decommissioning
fund amounting to $14.7 million and the obligation of the selling owners for
decommissioning were transferred to Constellation on November 7, 2001, subject
to possible post-closing adjustments, which were finalized for immaterial
amounts in 2003.
NOTE 4 - INCOME TAX
Energy Group and its subsidiaries file a consolidated federal and New York
State income tax return. The subsidiaries also file state income tax returns in
those states in which they conduct business.
In 2000, New York State law was changed such that Central Hudson and other
New York State utilities became subject to an income-based state income tax. The
tax law repealed the three-quarter percent (0.75%) tax on gross earnings and the
excess dividends tax under Section 186 of the New York State Tax Law and
replaced it with an income-based tax under Article 9-A of the New York State Tax
Law. The Article 9-A state income tax obligation is recovered from Central
Hudson customers as a revenue tax, and this treatment will continue until such
time that the PSC includes this obligation in the base rates of Central Hudson
in the same manner as Central Hudson's federal income tax obligation is already
included.
See Note 2 - "Regulatory Matters - Summary of Regulatory Assets and
Liabilities" for additional information regarding Energy Group and its
subsidiaries' income taxes.
85
Components of Income Tax
The following is a summary of the components of state and federal income
taxes for Energy Group as reported in its Consolidated Statement of Income:
2003 2002 2001
---- ---- ----
(In Thousands)
Charged to operating expense:
Federal income tax .............................. $ (4,139) $ (4,687) $ 225,061
State income tax ................................ (5) (1,242) 22,250
Federal income tax from
discontinued operations ....................... -- 2,939 --
State income tax from
discontinued operations ....................... -- 923 --
Deferred federal income tax ..................... 28,345 23,385 (207,867)
Deferred state income tax ....................... 3,078 3,290 (21,665)
-------- -------- ---------
Income tax charged to
operating expense ............................. 27,279 24,608 17,779
-------- -------- ---------
Charged (credited) to other income and deductions:
Federal income tax .............................. 606 4,372 6,349
State income tax ................................ (124) (1,855) 549
Deferred federal income tax ..................... 2,283 (911) (26,963)
Deferred state income tax ....................... 391 (58) (1,052)
-------- -------- ---------
Income tax charged (credited) to
other income and deductions ................... 3,156 1,548 (21,117)
-------- -------- ---------
Total income tax ............................... $ 30,435 $ 26,156 $ (3,338)
======== ======== =========
The 2001 deferred federal income tax credited to other income includes
recognition of investment tax credits in the amount of $18.8 million upon the
sales of Central Hudson's interests in its major generating assets. In 2003,
federal and state income taxes applicable to Energy Group are reported in other
income instead of operating expense. Certain 2002 and 2001 amounts have been
reclassified to conform to the 2003 presentation.
86
Reconciliation: The following is a reconciliation between the amount of
federal income tax computed on income before taxes at the statutory rate and the
amount reported in the Energy Group Consolidated Statement of Income:
2003 2002 2001
---- ---- ----
(In Thousands)
Net income ........................ $ 43,985 $ 41,281 $ 50,835
Preferred stock dividend of Central
Hudson ........................... 1,387 2,161 3,230
Federal income tax ................ (3,533) 2,624 231,410
State income tax ("SIT") .......... (129) (2,174) 22,799
Deferred federal income tax ....... 30,628 22,474 (234,830)
Deferred state income tax ......... 3,469 3,232 (22,717)
-------- -------- ---------
Income before taxes .............. $ 75,807 $ 69,598 $ 50,727
======== ======== =========
Computed federal tax @ 35%
statutory rate ................... $ 26,532 $ 24,359 $ 17,754
SIT net of federal tax benefit .... 3,696 3,393 2,638
Tax depreciation ................. 3,736 2,907 1,986
Amortized investment tax credits . (363) (415) (19,244)
Other ............................ (3,166) (4,088) (6,472)
-------- -------- ---------
Total income tax ................. $ 30,435 $ 26,156 $ (3,338)
======== ======== =========
Effective tax rate - federal ..... 35.7% 36.1% (6.7%)
Effective tax rate - state ....... 4.4% 1.5% .1%
-------- -------- ---------
Effective tax rate - combined .... 40.1% 37.6% (6.6%)
======== ======== =========
87
The following is a summary of the components of deferred taxes at December
31, 2003, and December 31, 2002, as reported in Energy Group's Consolidated
Balance Sheet:
2003 2002
---- ----
Accumulated Deferred Income (In Thousands)
Tax Assets:
Customer Benefit Fund .......................... $ 43,332 $ 62,232
Future tax benefits on investment
tax credit basis difference .................. 1,794 1,990
Unbilled revenues .............................. 8,541 7,927
Other .......................................... 34,885 30,208
-------- --------
Accumulated Deferred Income
Tax Assets ...................................... $ 88,552 $102,357
-------- --------
Accumulated Deferred Income
Tax Liabilities:
Tax depreciation .............................. $ 92,241 $ 79,453
Accumulated deferred investment
tax credit ................................... 3,332 3,695
Future revenues - recovery of plant
basis differences ............................. 5,703 2,967
Nondeductible pension expense .................... 39,062 41,149
Other .......................................... 44,262 30,863
-------- --------
Accumulated Deferred Income
Tax Liabilities ................................ $184,600 $158,127
-------- --------
Net Accumulated Deferred Income
Tax Liability .................................. $ 96,048 $ 55,770
======== ========
The following is a summary of the components of state and federal income
taxes for Central Hudson as reported in its Consolidated Statement of Income:
2003 2002 2001
---- ---- ----
(In Thousands)
Charged to operating expense:
Federal income tax .............................. $ (5,522) $ (4,440) $ 225,240
State income tax ................................ (423) (1,179) 22,035
Deferred federal income tax ..................... 28,345 23,385 (207,867)
Deferred state income tax ....................... 3,078 3,290 (21,665)
-------- -------- ---------
Income tax charged to
operating expense ............................. 25,478 21,056 17,743
-------- -------- ---------
Charged (credited) to other income and deductions:
Federal income tax .............................. (1,016) 1,470 2,679
State income tax ................................ (227) 133 (44)
Deferred federal income tax ..................... 2,355 (911) (26,963)
Deferred state income tax ....................... 391 (58) (1,052)
-------- -------- ---------
Income tax charged (credited) to
other income and deductions ................... 1,503 634 (25,380)
-------- -------- ---------
Total income tax ............................... $ 26,981 $ 21,690 $ (7,637)
======== ======== =========
The 2001 deferred federal income tax credited to other income includes
recognition of investment tax credits in the amount of $18.8 million upon the
sales of Central Hudson's interests in its major generating assets.
88
Reconciliation: The following is a reconciliation between the amount of federal
income tax computed on income before taxes at the statutory rate and the amount
reported in the Central Hudson Consolidated Statement of Income:
2003 2002 2001
---- ---- ----
(In Thousands)
Net income ............................. $ 38,875 $ 32,524 $ 44,178
Federal income tax ..................... (6,538) (2,970) 227,919
State income tax ....................... (650) (1,046) 21,991
Deferred federal income tax ............ 30,700 22,474 (234,830)
Deferred state income tax .............. 3,469 3,232 (22,717)
-------- -------- ---------
Income before taxes ................... $ 65,856 $ 54,214 $ 36,541
======== ======== =========
Computed federal tax @ 35%
statutory rate ........................ $ 23,050 $ 18,975 $ 12,789
SIT net of federal tax benefit ......... 3,210 2,643 1,900
Tax depreciation ...................... 3,736 2,907 1,986
Amortized investment tax credits ...... (363) (415) (19,244)
Other ................................. (2,652) (2,420) (5,068)
-------- -------- ---------
Total income tax ...................... $ 26,981 $ 21,690 $ (7,637)
======== ======== =========
Effective tax rate - federal .......... 36.7% 36.0% (18.9%)
Effective tax rate - state ............ 4.3% 4.0% (2.0%)
-------- -------- ---------
Effective tax rate - combined ......... 41.0% 40.0% (20.9%)
======== ======== =========
89
The following is a summary of the components of deferred taxes at December
31, 2003, and December 31, 2002, as reported in Central Hudson's Consolidated
Balance Sheet:
2003 2002
---- ----
Accumulated Deferred Income (In Thousands)
Tax Assets:
Customer Benefit Fund ......................... $ 43,332 $ 62,232
Future tax benefits on investment
tax credit basis difference .................. 1,794 1,990
Unbilled revenues .............................. 8,541 7,927
Other .......................................... 34,885 30,208
-------- --------
Accumulated Deferred Income
Tax Assets ...................................... $ 88,552 $102,357
-------- --------
Accumulated Deferred Income
Tax Liabilities:
Tax depreciation .............................. $ 92,241 $ 79,453
Accumulated deferred investment
tax credit ................................... 3,332 3,695
Future revenues - recovery of plant
basis differences ............................. 5,703 2,967
Nondeductible pension expense .................... 39,062 41,149
Other ............................................ 42,334 30,047
-------- --------
Accumulated Deferred Income
Tax Liabilities ................................ $182,672 $157,311
-------- --------
Net Accumulated Deferred Income
Tax Liability .................................. $ 94,120 $ 54,954
======== ========
NOTE 5 - ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS
In January 2003, Griffith acquired certain assets of two companies for
$7.5 million. The amount charged to intangible assets (including goodwill) was
$6.9 million, of which $3.7 million was charged to goodwill. During 2002,
Griffith acquired the operating assets of two companies. The total amount paid
for these assets was $1.5 million. These acquisitions were accounted for using
the purchase method of accounting. The amount charged to intangible assets
(including goodwill) was $1.4 million, of which $0.7 million was charged to
goodwill. The principal tangible assets acquired were vehicles, petroleum
products, and spare parts.
On October 31, 2003, SCASCO completed the sale of certain assets and
liabilities related to its natural gas business unit. Energy Group recognized an
after-tax gain on the sale of approximately $181,000. This disposition is not
expected to materially impact the future financial condition, results of
operations, or cash flows of Energy Group or its subsidiaries.
On December 21, 2001, CH Services entered into an agreement to sell all of
its stock ownership interest in CH Resources and its subsidiaries, CH Syracuse
and CH Niagara (together "CH Resources"), to WPS Power Development, Inc., a
Wisconsin corporation. The sale closed on May 31, 2002.
The CH Resources sale was accounted for in accordance with APB Opinion No.
30, Reporting the Results of Operations - Reporting the Effects of Disposal of a
Segment, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions, and EITF Abstract 85-36, Discontinued Operations with Expected
Gain and Interim Operating Losses. CH
90
Resources' principal assets at the sale closing date were long-term leasehold
interests in three electric generating facilities and ownership interests in
various fuel, spare parts, and other inventories, consisting in aggregate fixed
assets of $32.3 million, inventory of $3.2 million, and other assets of $7.1
million. The sale proceeds of $58.4 million resulted in a gain of $7.0 million
(net of income taxes of $5.2 million). A net operating loss of $2.2 million (net
of an income tax benefit of $1.4 million) was recorded in 2002. Therefore, the
net income from discontinued operations in 2002 was $4.8 million, or $.29 per
share.
In December 2001, CH Resources, in accordance with the accounting
pronouncements noted above, deferred a net operating loss of $293,000 for offset
against the expected gain on the date of disposal. This operating loss is
included in the $2.2 million loss from discontinued operations recognized in
2002. The Consolidated Income Statement for Energy Group for the year ended
December 31, 2001, does not include the December 2001 operating results of CH
Resources.
NOTE 6 - GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill, customer lists, and covenants not to compete associated with
acquisitions are included in intangible assets. Goodwill represents the excess
of cost over the fair value of the net tangible and identifiable intangible
assets of businesses acquired as of the date of acquisition. In July 2001, the
FASB issued Statement No. 142, Goodwill and Other Intangible Assets ("SFAS
142"). SFAS 142 requires that goodwill and other intangible assets that have
indefinite useful lives no longer be amortized against earnings, but instead be
periodically reviewed for impairment. The amortization of goodwill related to
all acquisitions made by the competitive business subsidiaries ceased upon
adoption of SFAS 142 by Energy Group on January 1, 2002, which favorably
impacted Energy Group's results of operations by $2.2 million for the year ended
December 31, 2003. Upon implementation of SFAS 142, and annually thereafter, the
competitive business subsidiaries tested the intangible assets remaining on the
balance sheet for impairment and confirmed that no impairment existed.
In accordance with SFAS 142, intangible assets that have finite useful
lives continue to be amortized over their useful lives. The estimated useful
life for customer lists is 15 years, which is believed to be appropriate in view
of currently experienced customer turnover. However, if customer turnover were
to substantially increase, a shorter amortization period would be used,
resulting in an increase in amortization expense. For example, if a 10-year
amortization period were used, annual amortization expense would increase by
approximately $780,000. The useful life of a covenant not to compete is based on
the term of each covenant, generally between two to ten years.
91
The components of amortizable intangible assets of Energy Group are
summarized as follows (thousands of dollars):
December 31, 2003 December 31, 2002
----------------- -----------------
Gross Carrying Accumulated Gross Carrying Accumulated
Amount Amortization Amount Amortization
-------------- ------------ -------------- ------------
Customer Lists ............. $38,371 $7,609 $36,287 $5,932
Covenants Not To Compete ... 1,439 683 1,439 506
------- ------ ------- ------
Total Amortizable
Intangibles ................ $39,810 $8,292 $37,726 $6,438
======= ====== ======= ======
Amortization expense was $2.9 million for both years ended December 31,
2003, and 2002 and $5.1 million for 2001. The estimated amortization expense for
each of the next five years, assuming no new acquisitions, is as follows
(thousands of dollars):
2004 $2,704
2005 $2,696
2006 $2,676
2007 $2,662
2008 $2,646
The carrying amount for goodwill not subject to amortization was $50.5
million and $46.7 million, as of December 31, 2003, and December 31, 2002,
respectively. During 2002, the competitive business subsidiaries recognized an
impairment loss on goodwill of $92,000 associated with assets purchased from an
energy services company specializing in energy efficiency projects; this loss is
included in Other Expenses of Operations - Competitive Business Subsidiaries.
The impairment was caused by negative cash flows and the loss of key employees
relating to the assets acquired. The competitive business subsidiaries retested
the intangible balance at December 31, 2003, and found no further impairment.
Pro forma earnings of Energy Group as a result of the changes associated
with SFAS 142 were as follows:
For the Year
Ended December 31
-----------------
2003 2002 2001
---- ---- ----
Net Income:
As reported .................... $ 43,985 $ 41,281 $ 50,835
Add back goodwill amortization . -- -- 1,598
-------- -------- --------
Pro forma net income ........... $ 43,985 $ 41,281 $ 52,433
Earnings per Share (basic):
As reported .................... $ 2.78 $ 2.53 $ 3.11
Add back goodwill amortization . -- -- .09
-------- -------- --------
Pro forma earnings per share ... $ 2.78 $ 2.53 $ 3.20
92
NOTE 7 - SHORT-TERM BORROWING ARRANGEMENTS
In November 2003, Energy Group entered into a $75 million revolving credit
agreement with several commercial banks. The credit facility and available cash
are currently earmarked for the acquisition of energy-related assets as further
described in Note 2 - "Regulatory Matters," in the discussion regarding Rate
Case Proceedings.
Pursuant to PSC authorization, Central Hudson entered into a $75 million
revolving credit facility with several commercial banks through June 30, 2004
("Borrowing Agreement"). Compensating balances are not required under the
Borrowing Agreement. In addition, Central Hudson maintains a confirmed line of
credit of $1 million with a regional bank. There were no outstanding loans under
the Borrowing Agreement or the line of credit at December 31, 2003, or 2002. In
order to diversify its sources of short-term financing, Central Hudson has
entered into short-term credit facility agreements with several commercial
banks. At December 31, 2003, Central Hudson had $16.0 million in short-term debt
outstanding and had cash and cash equivalents, including investments in
short-term securities, of $12.7 million. The PSC limits the amount Central
Hudson may have outstanding, at any time, under all of its short-term borrowing
arrangements to $77 million in the aggregate. This PSC authorization expires
June 30, 2004. Central Hudson currently has a financing petition filed with the
PSC to provide for future financing authorization.
For years ended 2003 and 2002, Central Hudson had an average daily amount
of short-term debt outstanding of $7.2 million and $1.5 million, respectively.
The weighted-average interest rate for borrowing was 1.41% for 2003 and 2.15%
for 2002.
The competitive business subsidiaries have a line of credit totaling $25
million. There were no borrowings against this line of credit at December 31,
2003.
At December 31, 2003, Energy Group had $16.0 million in short-term debt
outstanding. Cash and cash equivalents for Energy Group, including investments
in short-term securities, were $125.8 million at December 31, 2003.
93
NOTE 8 - CAPITALIZATION - ENERGY GROUP CAPITAL STOCK
Common Stock, $.10 par value; 30,000,000 shares authorized:
Common Stock
------------------------- Paid-In Treasury Capital Stock
Shares Amount Capital Stock Expense
Outstanding ($000) ($000) ($000) ($000)
----------- --------- --------- --------- -------------
January 1, 2001 ......................... 16,362,087 $ 1,686 $ 351,230 $ (18,766) $ (1,232)
Amortization ............................ -- -- -- -- 74
----------- --------- --------- --------- ---------
December 31, 2001 ....................... 16,362,087 1,686 351,230 (18,766) (1,158)
----------- --------- --------- --------- ---------
Repurchased under Repurchase Program .... (297,487) -- -- (14,351) --
Amortization ............................ -- -- -- -- 42
Transfer to Regulatory Asset ............ -- -- -- -- 461
----------- --------- --------- --------- ---------
December 31, 2002 ....................... 16,064,600 1,686 351,230 (33,117) (655)
----------- --------- --------- --------- ---------
Repurchased under Repurchase Program .... (302,600) -- -- (13,135) --
Amortization ............................ -- -- -- -- 15
Transfer to Regulatory Asset ............ -- -- -- -- 312
----------- --------- --------- --------- ---------
December 31, 2003 ....................... 15,762,000 $ 1,686 $ 351,230 $ (46,252) $ (328)
=========== ========= ========= ========= =========
CAPITALIZATION - CENTRAL HUDSON CAPITAL STOCK
Common Stock, $5.00 par value; 30,000,000 shares authorized:
Common Stock
------------------------ Paid-In Capital Stock
Shares Amount Capital Expense
Outstanding ($000) ($000) ($000)
----------- --------- --------- -------------
January 1, 2001 ................... 16,862,087 $ 84,311 $ 273,238 $ (1,232)
Dividend to Parent - Energy Group . -- -- (98,258) --
Amortization ...................... -- -- -- 74
---------- --------- --------- ---------
December 31, 2001 ................. 16,862,087 84,311 174,980 (1,158)
---------- --------- --------- ---------
Amortization ...................... -- -- -- 42
Transfer to Regulatory Asset ...... -- -- -- 461
---------- --------- --------- ---------
December 31, 2002 ................. 16,862,087 84,311 174,980 (655)
---------- --------- --------- ---------
Amortization ...................... -- -- -- 15
Transfer to Regulatory Asset ...... -- -- -- 312
---------- --------- --------- ---------
December 31, 2003 ................. 16,862,087 $ 84,311 $ 174,980 $ (328)
========== ========= ========= =========
94
Cumulative Preferred Stock, Central Hudson, $100 par value; 1,200,000 shares
authorized:
Shares Outstanding
Final Redemption ------------------
Redemption Price December 31,
Series Date 12/31/03 2003 2002
------ ---- -------- ---- ----
Not Subject to Mandatory
Redemption:
41/2% -- $107.00 70,300 70,300
4.75% -- 106.75 20,000 20,000
4.35% -- 102.00 60,000 60,000
4.96% -- 101.00 60,000 60,000
------- -------
210,300 210,300
------- -------
Subject to Mandatory
Redemption:
6.20% 10/1/08 -- 25,000
6.80% 10/1/27 -- 100,000
------- -------
-- 125,000
------- -------
Total 210,300 335,300
======= =======
In October 2003, Central Hudson redeemed $2.5 million of its mandatorily
redeemable 6.20% cumulative preferred stock and $10.0 million of its 6.80%
cumulative preferred stock. For additional discussion, see Note 1 - "Significant
Accounting Policies," under the caption "New Accounting Standards and Other FASB
Projects."
Capital Stock Expense: Expenses incurred on issuance of capital stock are
accumulated and reported as a reduction in common stock equity. These expenses
are generally not amortized; however, as directed by the PSC, certain issuance
and redemption costs and unamortized expenses associated with certain issues of
preferred stock that were redeemed have been deferred and are being amortized
over the remaining lives of the issues subject to mandatory redemptions.
Repurchase Program: On July 25, 2002, the Board of Directors of Energy
Group authorized a Common Stock Repurchase Program ("Repurchase Program") to
repurchase up to 4 million shares, or approximately 25% of its outstanding
common stock, over the five years beginning August 1, 2002. The Board of
Directors had targeted 800,000 shares for repurchase in the first year of the
Repurchase Program, but had authorized the repurchase of up to 1.2 million
shares during the first year. Between August 1, 2002, and December 31, 2003, the
number of shares repurchased under this Repurchase Program was 600,087 at a cost
of $27.5 million. Energy Group intends to set repurchase targets, if any, each
year based on circumstances then prevailing. Repurchases have been temporarily
suspended while Energy Group assesses opportunities to redeploy its cash
reserves in energy-related investments. Energy Group reserves the right to
modify, suspend, or terminate the Repurchase Program at any time without notice.
95
NOTE 9 - CAPITALIZATION - LONG-TERM DEBT
Details of Central Hudson's long-term debt are as follows:
Series Maturity Date December 31,
------ ------------- ------------------------
First Mortgage Bonds: 2003 2002
---- ----
(In Thousands)
7.97% (a)(b)(d) June 11, 2003 $ -- $ 5,000
7.97% (a)(b)(d) June 13, 2003 -- 500
6.46% (a)(b)(d) Aug. 11, 2003 -- 9,500
--------- ---------
-- 15,000
Promissory Notes:
1998 Series A (3.00%)(c) Dec. 1, 2028 16,700 16,700
7.85% (b) July 2, 2004 15,000 15,000
1999 Series C (6%)(b) Jan. 15, 2009 20,000 20,000
1999 Series A (5.45%)(c) Aug. 1, 2027 33,400 33,400
1999 Series B (Var. rate)(c) July 1, 2034 33,700 33,700
1999 Series C (Var. rate)(c) Aug. 1, 2028 41,150 41,150
1999 Series D (Var. rate)(c) Aug. 1, 2028 41,000 41,000
2002 Series D (5.87%)(b) Mar. 28, 2007 33,000 33,000
2002 Series D (6.64%)(b) Mar. 28, 2012 36,000 36,000
2003 Series D (4.33%)(b) Sep. 23, 2010 24,000 --
--------- ---------
293,950 269,950
Unamortized Discount on Debt (70) (73)
--------- ---------
$ 293,880 $ 284,877
Less: Current Portion (15,000) (15,000)
--------- ---------
Total $ 278,880 $ 269,877
========= =========
(a) Central Hudson's First Mortgage Bond Indenture was defeased on November 6,
2001.
(b) Issued under Central Hudson's Medium-Term Note Program.
(c) First Mortgage Bonds or Promissory Notes issued in connection with the
sale by NYSERDA of tax-exempt pollution control revenue bonds.
(d) Redeemed in 2003 using defeasance funds held by the Mortgage Trustee.
In June 2003, Central Hudson redeemed $5.5 million of its 7.97% First
Mortgage Bonds. In August 2003, the remaining $9.5 million of its 6.46% First
Mortgage Bonds were redeemed, leaving Central Hudson with no outstanding First
Mortgage Bonds. The First Mortgage Bond Indenture was defeased on November 6,
2001.
In October 2001, the PSC approved the issuance by Central Hudson of up to
$100 million of unsecured medium-term notes prior to June 30, 2004. On March 28,
2002, $33 million of five-year, Series D Notes were issued at 5.87% and $36
million of ten-year, Series D Notes were issued at 6.64%. On September 17, 2003,
$24 million of seven-year Series D Notes were issued at 4.33%. As a result, the
amount remaining under current PSC authorization is $7 million. Central Hudson
currently has a financing request pending with the PSC for authorization of a
new Medium-Term Notes program.
96
The competitive business subsidiaries had no long-term debt outstanding as
of December 31, 2003, or December 31, 2002.
Central Hudson's authorization for short-term borrowing arrangements up to
$77 million and a Medium-Term Notes program of up to $100 million expires on
June 30, 2004. In October 2003, Central Hudson filed a petition with the PSC to
renew its authorization for financing. The petition seeks authorization, through
December 31, 2006, for up to $77 million of short-term borrowing arrangements
and a new Medium-Term Notes program up to $115 million. Central Hudson is
currently participating in meetings with the PSC in support of its petition, but
cannot predict the final result of its petition at this time.
Long-Term Debt Maturities
See Note 15 - "Financial Instruments" for a schedule of long-term debt
maturing or to be redeemed during the next five years and thereafter.
NYSERDA
On December 1, 2003, Central Hudson completed the reoffering of its $16.7
million promissory notes issued in conjunction with the sale of tax-exempt
pollution control revenue bonds by New York State Energy Research and
Development Authority ("NYSERDA"). The new rate which will be in place for five
years is 3.0%, down from the previous rate of 4.2%.
Central Hudson's 1999 NYSERDA Bonds Series B, C, D are unsecured, variable
rate bonds and are insured as to payment of principal and interest as they
become due by a municipal bond insurance policy issued by AMBAC Assurance
Corporation. In its rate orders, the PSC has authorized deferred accounting for
the interest costs of these bonds. This authorization provides for full recovery
of the actual interest costs supporting utility operations. Interest costs
supporting utility operations represent approximately 94% of the total costs.
The deferred balances under this accounting were $3.3 million and $1.5 million
at December 31, 2003, and at December 31, 2002, respectively, and are included
in "Regulatory Liabilities" in Energy Group's and Central Hudson's Consolidated
Balance Sheets. The deferred balances at June 30, 2001, were eliminated in
accordance with a Rate Order from the PSC. The ongoing deferred balances are to
be addressed in future rate cases. To further mitigate the risk of rising
interest rates, Central Hudson purchased derivative instruments known as
interest rate caps to limit its exposure to a defined 5.5% interest rate ceiling
for the period from April 1, 2002, to April 1, 2004.
Debt Expense
Expenses incurred in connection with Central Hudson's debt issuance and
any discount or premium on debt are deferred and amortized over the lives of the
related issues. Expenses incurred on debt redemptions prior to maturity have
been deferred and are usually amortized over the shorter of the remaining lives
of the related extinguished issues or the new issues, as directed by the PSC.
97
Debt Covenants
Central Hudson's $75 million credit facility requires that Central Hudson
maintain certain financial ratios and contains other restrictive covenants.
Currently, Central Hudson is in compliance with all of its debt covenants. The
only debt outstanding at CHEC is amounts borrowed from Energy Group. As of
December 31, 2003, no amounts were outstanding on CHEC's line of credit with its
commercial bank and, accordingly, it is in compliance with all of its debt
covenants.
NOTE 10 - POST-EMPLOYMENT BENEFITS
Pension Benefits
Central Hudson has a non-contributory Retirement Income Plan ("Retirement
Plan") covering substantially all of its employees. The Retirement Plan is a
defined benefit plan, which provides pension benefits that are based on the
employee's compensation and years of service. It has been Central Hudson's
practice to provide periodic updates to the benefit formula stated in the
Retirement Plan.
In September 2003, Central Hudson contributed $10 million to the Trust
Fund for the Retirement Plan to reduce the difference between the Accumulated
Benefit Obligation ("ABO") for the Retirement Plan and the market value of
related pension assets. In accordance with SFAS No. 87, Employers Accounting for
Pensions ("SFAS 87"), Central Hudson was required to show a minimum pension
liability of $3.9 million on its balance sheet for the difference between the
ABO and the market value of the pension assets. In order to reflect this minimum
pension liability of $3.9 million, Central Hudson was required to record a
pension accrual of $106.9 million that additionally offsets the prefunded
pension costs balance of $103 million at December 31, 2003. The offsetting
charge on the balance sheet was recorded as an intangible asset in the amount of
$24.4 million representing unrecognized prior service costs and the remainder of
$82.5 million as a regulatory asset as authorized by the PSC.
For the balance sheet presentation, the prefunded pension costs of $103
million were offset against total accrued pension costs of $112.8 million. The
resulting pension liability of $9.8 million at December 31, 2003, also includes
$5.9 million for non-qualified executive plans. The balance of the pension
related requlatory asset of $124.2 million reflects a $1.1 million SFAS 87
adjustment for non-qualified executive plans and undercollected pension costs of
$40.6 million to be recovered from customers.
Under the policy of the PSC regarding pension costs, differences between
pension expense and rate allowances covering pension expenses are deferred for
future recovery from or return to customers and carrying charges accrued on cash
differences. The $10 million contribution is subject to such carrying charges.
98
It should be noted that the valuation of the ABO was determined as of the
measurement date of September 30, 2003, using a 6.0% discount rate (as
determined with reference to interest rates applicable to domestic long-term
corporate bonds rated "AA" by Moody's Investors Services, Inc.) and that each
0.25% change in the discount rate would affect the projection of ABO by
approximately $8.0 million. The discount rate on the prior measurement date of
September 30, 2002, was 6.75%.
Declines in the market value of the Trust Fund's investment portfolio and
a reduction in the discount rate used to determine the ABO have resulted in a
significant increase in annual pension expense as compared to the level upon
which current rates were set. This difference is deferred under the PSC's policy
for recovery of pension expense and post-retirement benefits. This deferral,
which Central Hudson anticipates will continue in the future, could result in
the accumulation of a significant regulatory asset which Central Hudson will
seek to recover from customers as provided for under the PSC's policy.
Central Hudson accounts for pension activity in accordance with
PSC-prescribed provisions which, among other things, require ten-year
amortization of actuarial gains and losses. The pension assets and liabilities
transferred to Dynegy as a result of the sale of Central Hudson's interests in
the Danskammer Plant and the Roseton Plant were reflected in the amount recorded
in 2001 for net periodic pension cost.
In addition to the Retirement Plan, Central Hudson's and Energy Group's
officers and executives are covered under a non-qualified Directors and
Executives Deferred Compensation Plan and a non-qualified Supplementary
Retirement Plan. Central Hudson also sponsors a non-qualified Retirement Benefit
Restoration Plan.
Other Post-Retirement Benefits
Central Hudson provides certain health care and life insurance benefits
for retired employees through its post-retirement benefit plans. Substantially
all of Central Hudson's employees may become eligible for these benefits if they
reach retirement age while employed by Central Hudson. These and similar
benefits for active employees are provided through insurance companies whose
premiums are based on the benefits paid during the year. In order to reduce the
total costs of these benefits, Central Hudson requires employees who retired on
or after October 1, 1994, to contribute toward the cost of these benefits.
Central Hudson is fully recovering its net periodic post-retirement costs
in accordance with PSC guidelines. Under these guidelines, the difference
between the amounts of post-retirement benefits recoverable in rates and the
amounts of post-retirement benefits determined by an actuary under SFAS 106,
Employers Accounting for Post-retirement Benefits Other Than Pensions, is
deferred as either a regulatory asset or liability, as appropriate.
99
Estimates of Long-Run Rates of Return
An equal weighted average of three methods was used to estimate the
long-run expected returns of each equity asset class. The three methods were: 1)
the building block method, based on the Capital Asset Pricing Model, which
states that the return of an asset class is a function of the risk-free rate and
a risk based return premium; 2) the historical return method, which uses the
historical average return for each market index as a proxy for future average
returns; and 3) the economic growth method, which is based on long-run averages
on estimates for economic growth, dividend yield, and expected inflation.
For the fixed income asset class, three methods were used. The historical
return and building block methods, described above, and the market observable
rate of return, represented by the average yield to maturity of representative
market indexes.
For the real estate asset class, the historical return and building block
method, described above, were used to estimate the long-run expected return.
Retirement Plan Policy and Strategy
Central Hudson's Retirement Plan seeks to match the long-term nature of
its funding obligations with investment objectives for long-term growth and
income. Retirement Plan assets are invested in accordance with sound investment
practices that emphasize long-term investment fundamentals. The Retirement Plan
recognizes that assets are exposed to risk and the market value of assets may
vary from year to year. Potential short-term volatility, mitigated through a
well-diversified portfolio structure, is acceptable in accordance with the
objective of capital appreciation over the long-term.
It is desired that the Retirement Plan earn returns higher than the
market, as represented by a benchmark index comprised of 30% Standard & Poor's
500 Stock Index, 10% Russell 2000 Stock Index, 20% Morgan Stanley Capital
International Europe, Australasia, and Far East (MSCI EAFE) International Stock
Index, 5% NCREIF Real Estate Composite Index, and 35% Merrill Lynch Domestic
Master Bond Index. The Retirement Plan is expected to exceed the average annual
return of this benchmark on a risk-adjusted basis over a three-to-five-year
rolling time period and a full market cycle. It is understood that there can be
no guarantees about the attainment of the Retirement Plan's return objectives.
100
The asset allocation strategy employed in the Retirement Plan reflects
Central Hudson's return objectives and risk tolerance. Asset mix targets,
expressed as a percentage of the market value of the Retirement Plan, are
summarized in the table below:
- -----------------------------------------------------------------------------------------------
Target
Asset Class Minimum Average Maximum
- -----------------------------------------------------------------------------------------------
Domestic Large/Medium Capitalization Stocks 28% 33% 38%
- -----------------------------------------------------------------------------------------------
Domestic Small/Medium Capitalization Stocks 9% 12% 15%
- -----------------------------------------------------------------------------------------------
International Equity 10% 15% 20%
- -----------------------------------------------------------------------------------------------
Real Estate 0% 5% 7%
- -----------------------------------------------------------------------------------------------
Fixed Income 30% 35% 40%
- -----------------------------------------------------------------------------------------------
Cash and Cash Equivalents 0% 0% 10%
- -----------------------------------------------------------------------------------------------
Due to the dynamic nature of market value fluctuations, Retirement Plan
assets will require rebalancing from time to time to maintain the target asset
mix. The Retirement Plan recognizes the importance of maintaining a long-term
strategic mix and does not intend any tactical asset allocation or market timing
asset mix shifts.
The Retirement Plan will utilize multiple managers and funds of
complementary investment styles and asset classes to invest plan assets.
101
As of December 31, 2003, the only post-retirement benefit plans provided
to employees of any of the competitive business subsidiaries were Griffith's
401(k) Savings and Profit Sharing plan and SCASCO's 401(k) Savings and Profit
Sharing plan.
Reconciliations of Central Hudson's pension and other post-retirement
plans' benefit obligations, plan assets, and funded status, as well as the
components of net periodic pension cost and the weighted average assumptions
(excluding competitive business subsidiary employees not covered by these plans)
are as follows:
- ------------------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
- ------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------
(In Thousands) (In Thousands)
- ------------------------------------------------------------------------------------------------------
Change in Benefit Obligation:
Benefit obligation at beginning of year $ 314,467 $ 273,381 $ 111,177 $ 85,081
Service cost 5,942 5,404 2,860 2,242
Interest cost 20,961 20,553 8,643 7,041
Participant contributions -- -- 259 238
Plan amendments 6,017 -- -- --
Benefits paid (18,342) (17,967) (5,099) (4,609)
Actuarial loss 33,398 33,096 38,098 21,184
- ------------------------------------------------------------------------------------------------------
Benefit Obligation at End of Year $ 362,443 $ 314,467 $ 155,938 $ 111,177
- ------------------------------------------------------------------------------------------------------
Change in Plan Assets:
Fair value of plan assets at beginning of year $ 287,354 $ 291,288 $ 58,833 $ 64,588
Actual return on plan assets 39,433 (15,787) 10,950 (6,720)
Employer contributions 10,289 32,283 5,700 5,700
Participant contributions -- -- 259 238
Benefits paid (18,342) (17,967) (5,099) (4,609)
Administrative expenses (2,017) (2,463) (320) (364)
- ------------------------------------------------------------------------------------------------------
Fair Value of Plan Assets at end of Year $ 316,717 $ 287,354 $ 70,323 $ 58,833
- ------------------------------------------------------------------------------------------------------
102
- --------------------------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
- --------------------------------------------------------------------------------------------------------------
(In Thousands) 2003 2002 2003 2002
- --------------------------------------------------------------------------------------------------------------
Reconciliation of Funded Status:
Funded Status $ (45,727) $ (27,114) $(85,616) $(52,344)
Unrecognized actuarial loss 119,755 111,146 52,042 22,260
Unrecognized transition obligation -- -- 23,079 25,644
Unamortized prior service cost 24,279 19,966 (66) (74)
- --------------------------------------------------------------------------------------------------------------
Accrued Benefit Cost $ 98,307 $ 103,998 $(10,561) $ (4,514)
- --------------------------------------------------------------------------------------------------------------
Amounts Recognized on Consolidated Balance Sheet:
Prepaid benefit cost $ -- $ 108,242 $ -- $ --
Accrued benefit liability (9,775) (4,244) (10,561) (4,514)
Intangible asset 24,447 -- -- --
Regulatory asset 83,635 -- -- --
- --------------------------------------------------------------------------------------------------------------
Net Amount Recognized at End of Year $ 98,307 $ 103,998 $(10,561) $ (4,514)
- --------------------------------------------------------------------------------------------------------------
Components of Net Periodic Benefit Cost:
Service cost $ 5,942 $ 5,404 $ 2,860 $ 2,242
Interest cost 20,961 20,553 8,643 7,041
Expected return on plan assets (21,410) (22,698) (4,596) (4,200)
Amortization of prior service cost 1,706 1,716 (9) (9)
Amortization of transitional (asset) or obligation -- (152) 2,566 2,566
Recognized actuarial loss or (gain) 8,780 (1,599) 2,693 (1,068)
- --------------------------------------------------------------------------------------------------------------
Net Periodic Benefit Cost $ 15,979 $ 3,224 $ 12,157 $ 6,572
- --------------------------------------------------------------------------------------------------------------
Weighted-average assumptions used to determine
benefit obligations at December 31:
Discount rate
Expected long-term rate of return on plan assets 6.00% 6.75% 6.00% 6.75%
Rate of compensation increase 8.00% 8.50% 7.75% 8.25%
Weighted-average assumptions used to determine net
periodic benefit cost for years 4.50% 4.50% 4.50% 4.50%
ended December 31:
Discount rate
Expected long-term rate of return on plan assets 6.75% 7.25% 6.75% 7.25%
Rate of compensation increase 8.50% 8.50% 8.25% 6.80%
4.50% 4.50% 4.50% 4.50%
- --------------------------------------------------------------------------------------------------------------
103
- --------------------------------------------------------------------------------------------------------------
Pension plans with accumulated benefit obligations in
excess of plan assets:
Projected benefit obligation
Accumulated benefit obligation $ 362,443 $ 5,398 $ -- $ --
Fair Value of plan assets 326,413 4,624 -- --
316,717 -- -- --
- --------------------------------------------------------------------------------------------------------------
The accumulated benefit obligation for defined benefit pension plans was
$326.4 million and $287.2 million at December 31, 2003 and December 31, 2002,
respectively.
Central Hudson's pension and other post-retirement plans' weighted average
asset allocations at December 31, 2003, and 2002 by asset category are as
follows:
- -------------------------------------------------------------------------------
Pension Benefits Other Benefits
- -------------------------------------------------------------------------------
2003 2002 2003 2002
- -------------------------------------------------------------------------------
Equity Securities 61.6% 59.8% 62.0% 57.3%
Debt Securities 30.5% 32.3% 35.1% 40.5%
Real Estate 6.7% 7.0% -- --
Other 1.2% 0.9% 2.9% 2.2%
- -------------------------------------------------------------------------------
Total: 100% 100% 100% 100%
- -------------------------------------------------------------------------------
For the pension plan and other benefit plan, equity securities include no Energy
Group common stock at December 31, 2003 and 2002, respectively.
Central Hudson does not expect to make a contribution to the pension plan in
2004, and expects to make a contribution of approximately $5.6 million to its
other post-retirement plan. The non-qualified supplementary Retirement Plan and
Retirement Benefit Restoration Plan are not pre-funded. Cash required to pay
benefits for participants in these plans during 2004 is expected to total $0.4
million.
- -------------------------------------------------------------------------------
104
For measurement purposes, an 11.5% (12.0% for participants over age 65)
annual rate of increase in the per capita cost of covered health benefits was
assumed for 2004. The rate is assumed to decrease gradually to 5.0% for 2013 and
remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plan. A one percentage point (1%) change in
assumed health care cost trend rates would have the following effects:
One Percentage One Percentage
Point Increase Point Decrease
-------------- --------------
Effect on total of service
and interest cost components
for 2003 $ 1,687,000 $ (1,466,000)
Effect on year-end 2003
post-retirement benefit obligation $20,428,000 $(18,062,000)
NOTE 11 - STOCK-BASED COMPENSATION INCENTIVE PLANS
Energy Group's Long-Term Performance-Based Incentive Plan ("Incentive
Plan"), adopted in 2000 and amended in 2001 and 2003, reserves 500,000 shares of
the Energy Group's common stock for awards to be granted under the Incentive
Plan. The Incentive Plan provides for the granting of stock options, stock
appreciation rights, restricted stock awards, performance shares, and
performance units. No participant may be granted total awards in excess of
150,000 shares over the life of the Incentive Plan. Stock options granted to
officers of Energy Group and its subsidiaries are exercisable over a period of
ten years, with 40% of the options vesting after two years and 20% each year
thereafter for the following three years; however, stock options granted to
executives retiring prior to June 30, 2006, are immediately exercisable upon
retirement. Additionally, stock options granted to non-employee directors are
immediately exercisable.
In the third quarter of 2003, the Incentive Plan was amended. The
amendment allows executives to defer receipt of performance shares and
performance units. Also, an amendment to the Stock Plan for Outside Directors
provides for shares of stock previously accrued for retired directors to be paid
in the form of cash, and provided that active directors could elect to transfer
previously accrued shares payable to them to Energy Group's Directors and
Executives Deferred Compensation Plan.
Effective January 1, 2000, stock options covering 30,300 shares were
granted with an exercise price per share of $31.94. Further, effective January
1, 2001, stock options covering 59,900 shares were granted with an exercise
price per share of $44.06. There were no options granted in 2002. Effective
January 1, 2003, stock options covering a total of 36,900 shares were granted
with an exercise price per share of $48.62.
105
The fair market values per share of Energy Group stock options granted in
2003 and 2001 are $6.51 and $4.46, respectively. These fair market values were
estimated as of the date of grant using the Black-Scholes option pricing model
with the following weighted average assumptions:
2003 2002 2001
---- ---- ----
Risk-free interest rate 4.40% -- 4.78%
Expected lives - in years 10 -- 5
Expected stock volatility 17.50% -- 20.06%
Dividend yield 4.40% -- 5.40%
A summary of the status of stock options awarded to executives and
non-employee Directors of Energy Group under the Incentive Plan as of December
31, 2003, and changes since inception are as follows:
Weighted
Average
Stock Exercise Remaining
Options Price Contractual Life
- -------------------------------------------------------------------------------
Outstanding at 1/1/01 30,300 $31.94
Granted 1/1/01 59,900 $44.06 7 years
Exercised -- --
Forfeited (800) $44.06
- -------------------------------------------------------------------------------
Outstanding at 12/31/01 89,400 $39.95
Granted 1/1/02 -- -- --
Exercised (3,600) $31.94
Forfeited (800) $44.06
- -------------------------------------------------------------------------------
Outstanding at 12/31/02 85,000 $40.25
Granted 1/1/03 36,900 $48.62 9 years
Exercised (13,740) $31.94
Forfeited (800) $44.06
- -------------------------------------------------------------------------------
Total Outstanding at 12/31/03 107,360 $44.16 7.567 years
- -------------------------------------------------------------------------------
A total of 13,740 non-qualified stock options were exercised during the
year ended December 31, 2003. These options had an exercise price of $31.94 and
resulted in recognition of compensation expense that was not material.
In addition, effective January 1, 2003, Energy Group adopted the fair
value method of recording stock-based compensation utilizing the "modified
prospective" approach, whereby existing options are expensed prospectively over
their respective vesting periods. Under the fair value method, all future
employee stock option grants and other stock-based compensation will be expensed
over their respective vesting periods based on their fair value at the date on
which the stock-based compensation is granted. Compensation expense, recorded
for the year ended December 31, 2003, and pro forma expense for the years ended
December 31, 2002, and 2001, resulting from the implementation of fair value
accounting for stock options was not material.
106
On January 1, 2001, the number of performance shares granted was 7,570, in
aggregate, to executives covered under the Incentive Plan. No performance shares
were granted in 2002. On January 1, 2003, the number of performance shares
granted was 14,800, in aggregate, to executives covered under the Incentive
Plan. As of December 31, 2003, the number of these performance shares that
remain outstanding were 5,850 and 14,800, respectively. The ultimate number of
shares awarded was based on the performance of Energy Group's common stock over
the three years following the date of the relevant grant, but shall not exceed
150% of the number of shares granted. Compensation expense is recorded as
performance shares are earned over the three-year life of the relevant
performance share grant prior to this award. Compensation expense recorded
related to these performance shares was $331,931, $458,402, and $211,282 for
2003, 2002, and 2001, respectively. Energy Group anticipates less use of stock
options in the future, and more use of performance shares in connection with
executive compensation.
For additional discussion regarding the dilutive and pro forma effects of
stock based compensation, see Note 1 under the captions - "Earnings Per Share"
and "Stock-Based Compensation".
NOTE 12 - OTHER INVESTMENTS
Energy Group initiated an investment program ("Alternate Investment
Program") in the third quarter of 2002. The Alternate Investment Program
involved investing approximately $100 million of Energy Group's cash reserves
made available from the sales of Central Hudson's interests in its major
generating assets with the objective of realizing higher after-tax yields than
are available through money market instruments, while avoiding undue risk to
principal and maintaining adequate liquidity.
At December 31, 2002, the investments held by Energy Group included
marketable debt and equity securities classified as available-for-sale; debt
securities included corporate and government notes and bonds. These investments
were reported at fair value with unrealized gains and losses reported as a
component of Other Comprehensive Income, net of tax. As of December 31, 2003,
all holdings in the Alternate Investment Program had been liquidated and the
proceeds invested in short-term investments with lower principal risk.
Proceeds from sales of available-for-sale securities during the year ended
December 31, 2003, were $111.5 million. Realized gains associated with sales of
available-for-sale securities were $2.9 million and realized losses were $3
million. The cost of these securities was determined on a specific
identification basis.
Since its inception in mid-2002, the Alternate Investment Program produced
a return of $0.15 per share over a period of approximately one year. Money
market alternatives were estimated to have returned $0.055 per share over that
same period, resulting in a net benefit of $0.095 per share for the Alternate
Investment Program.
107
NOTE 13 - COMMITMENTS AND CONTINGENCIES
Electricity Purchase Commitments
Under federal and New York State laws and regulations, Central Hudson is
required to purchase the electrical output of unregulated cogeneration
facilities which meet certain criteria for Qualifying Facilities ("QF"), as the
term is defined in the applicable legislation. Purchases are made under
long-term contracts which require payment at rates often higher than those
prevailing in the wholesale market. These costs are currently fully recoverable
through Central Hudson's energy adjustment mechanism, which provides for
recovery from customers of certain costs of fuels used to generate electricity.
Central Hudson had contracts with QFs in 2003 which represented approximately
1.7% of Central Hudson's energy purchases. These contracts are physical
contracts that do not meet the definition of a derivative instrument under SFAS
133 and, accordingly, are not recorded at their fair value.
Other Commitments
Energy Group and its affiliates have entered into agreements with various
companies, which provide products and services to be used in its normal
operations.
108
The following is a summary of these commitments for Energy Group and its
affiliates as of December 31, 2003:
- -----------------------------------------------------------------------------------------------------
Payments Due By Period (In Thousands)
- -----------------------------------------------------------------------------------------------------
Years Years
Ending Ending Years
Less than 2005- 2008- Beyond
1 year 2007 2009 2009 Total
- -----------------------------------------------------------------------------------------------------
Long-Term Debt $ 15,000 $ 33,000 $ 20,000 $225,950 $ 293,950
- -----------------------------------------------------------------------------------------------------
Operating Leases 1,354 2,067 153 106 3,680
- -----------------------------------------------------------------------------------------------------
Construction/Maintenance & Other Projects(1) 17,508 4,538 635 -- 22,681
- -----------------------------------------------------------------------------------------------------
Purchased Electric Contracts(2) 121,462 207,642 74,452 99,830 503,386
- -----------------------------------------------------------------------------------------------------
Purchased Natural Gas Contracts(2) 64,821 105,721 11,956 8,725 191,223
- -----------------------------------------------------------------------------------------------------
Purchased Fixed Liquid Petroleum
Contracts(3) 12,589 -- -- -- 12,589
- -----------------------------------------------------------------------------------------------------
Purchased Variable Liquid Petroleum
Contracts(3) 27,603 -- -- -- 27,603
- -----------------------------------------------------------------------------------------------------
Total Contractual Obligations $260,337 $352,968 $107,196 $334,611 $1,055,112
- -----------------------------------------------------------------------------------------------------
(1) Including Specific, Term & Service Contracts, briefly defined as follows:
Specific Contracts consist of work orders for construction; Term Contracts
consist of maintenance contracts; and Service Contracts include
consulting, educational, and professional service contracts.
(2) Purchased electric and natural gas costs for Central Hudson are fully
recovered via their respective regulatory cost adjustment mechanisms.
(3) Estimated based on pricing at January 14, 2004.
109
The following is a summary of the contractual obligations for Central
Hudson as of December 31, 2003:
- -----------------------------------------------------------------------------------------------------
Payments Due By Period (In Thousands)
- -----------------------------------------------------------------------------------------------------
Years Years
Ending Ending Years
Less than 2005- 2008- Beyond
1 year 2007 2009 2009 Total
- -----------------------------------------------------------------------------------------------------
Long-Term Debt $ 15,000 $ 33,000 $ 20,000 $225,950 $ 293,950
- ------------------------------------------------------------------------------------------------------
Operating Leases 626 1,035 18 -- 1,679
- ------------------------------------------------------------------------------------------------------
Construction/Maintenance & Other Projects(1) 17,508 4,538 635 -- 22,681
- ------------------------------------------------------------------------------------------------------
Purchased Electric Contracts(2) 121,462 207,642 74,452 99,830 503,386
- ------------------------------------------------------------------------------------------------------
Purchased Natural Gas Contracts(2) 64,821 105,721 11,956 8,725 191,223
- ------------------------------------------------------------------------------------------------------
Total Contractual Obligations $219,417 $351,936 $107,061 $334,505 $1,012,919
- ------------------------------------------------------------------------------------------------------
(1) Including Specific, Term & Service Contracts, briefly defined as follows:
Specific Contracts consist of work orders for construction; Term Contracts
consist of maintenance contracts; and Service Contracts include
consulting, educational, and professional service contracts.
(2) Purchased electric and natural gas costs for Central Hudson are fully
recovered via their respective regulatory cost adjustment mechanisms.
CONTINGENCIES
City of Poughkeepsie
On January 1, 2001, a fire destroyed a multi-family residence on Taylor
Avenue in the City of Poughkeepsie, New York, resulting in several deaths and
damage to nearby residences. Seven separate lawsuits arising out of this
incident have been commenced in New York State Supreme Court, County of
Dutchess, by approximately 23 plaintiffs against Central Hudson and other
defendants, each lawsuit alleging that Central Hudson supplied the Taylor Avenue
residence with natural gas service for cooking purposes at the time of the fire.
The basis for Central Hudson's alleged liability in these actions is that it was
negligent in the supply of such natural gas. The suits seek an aggregate of $528
million in compensatory damages for alleged property damage, personal injuries,
wrongful death, and loss of consortium or services. Central Hudson notified its
insurance carrier, has denied liability, and is defending the lawsuits. It
presently has insufficient information on which to predict the outcome of these
lawsuits.
110
Environmental Matters
Central Hudson and certain of the competitive business subsidiaries are
subject to regulation by federal, state and, to some extent, local authorities
with respect to the environmental effects of their operations, including
regulations relating to air and water quality, levels of noise, hazardous
wastes, toxic substances, protection of vegetation and wildlife, and limitations
on land use. Environmental matters may expose both Central Hudson and certain of
the competitive business subsidiaries to potential liability, which in certain
instances may be imposed without regard to fault or may be premised on
historical activities that were lawful at the time they occurred. Both Central
Hudson and these competitive business subsidiaries monitor their activities in
order to determine the impact of their activities on the environment and to
comply with applicable environmental laws and regulations.
CENTRAL HUDSON:
Water: In February 2001, Central Hudson received a letter from the New
York State Department of Environmental Conservation ("DEC") indicating that it
must terminate the discharge from an internal sump at its Neversink
Hydroelectric Facility into a regulated stream or obtain a State Pollutant
Discharge Elimination System ("SPDES") permit for it. Central Hudson filed for a
draft permit in May 2001; the DEC subsequently issued a draft permit on January
15, 2003, and is reviewing Central Hudson's comments on that draft permit.
Air: In October 1999, Central Hudson was informed by the New York State
Attorney General ("Attorney General") that the Danskammer Plant was included in
an investigation by the Attorney General's Office into the compliance of eight
older New York State coal-fired power plants with federal and state air
emissions rules. Specifically, the Attorney General alleged that Central Hudson
"may have constructed, and continues to operate, major modifications to the
Danskammer Plant without obtaining certain requisite preconstruction permits."
As part of this investigation, Central Hudson has received several requests for
information from the Attorney General, the DEC, and the U.S. Environmental
Protection Agency ("EPA") seeking information about the operation and
maintenance of the Danskammer Plant during the period from 1980 to 2000,
including specific information regarding approximately 45 projects conducted
during that period. In March 2000, the EPA assumed responsibility for the
investigation. Central Hudson has concluded its production of documents in
connection with the information requests, and believes any permits required for
these projects were obtained in a timely manner. Notwithstanding Central
Hudson's sale of the Danskammer Plant on January 30, 2001, Central Hudson could
retain liability depending on the type of remedy, if any, imposed in connection
with this matter.
Former Manufactured Gas Plant Facilities
In 1986, the DEC added six locations to the New York State Registry of
Inactive Hazardous Waste Disposal Sites ("Registry"), including a site in
Newburgh, New York, discussed below, at which manufactured gas plants ("MGP")
owned or operated by Central Hudson or its predecessors were once located. Two
additional former MGP sites were identified by Central Hudson but not placed on
the Registry by the DEC.
111
Three of the eight sites identified are in Poughkeepsie, New York (at Laurel
Street, North Water Street, and North Perry Street); the remaining five sites
are in Newburgh, Beacon, Saugerties, Kingston, and Catskill, New York. Central
Hudson studied all eight sites to determine whether or not they contain any
hazardous wastes which could pose a threat to the environment or public health
and, if wastes were located at the sites, to determine whether or not remedial
actions should be considered. The DEC subsequently removed the six sites it had
previously placed on the Registry, subject to future revisions of its testing
methods.
Central Hudson has also become aware of information contained in a DEC
Internet website indicating that, in addition to the eight sites referenced
above, Central Hudson is attributed with responsibility for three additional MGP
sites. The Internet website states that the additional sites are located on
Broadway in Kingston, at Vassar College in Poughkeepsie, and on Water Street in
Newburgh. No former MGP is believed to have been present at the Broadway,
Kingston location. Rather, the location is likely to have been used for an
office associated with the MGP site at East Strand Street, Kingston. Central
Hudson does not believe that it ever owned or operated the site at Vassar
College. The site identified as the Water Street, Newburgh site is, to Central
Hudson's knowledge, an MGP site that ceased operations in the 1880's. The land
upon which the plant was located was sold in 1891. The stock of the MGP site's
former operator, Consumers Gas Company of Newburgh, New York, was acquired in
1900-01 by Newburgh Light, Heat and Power Company, which was later consolidated
with several other companies to form Central Hudson.
City of Newburgh: In October 1995, Central Hudson and the DEC entered into
an Order on Consent regarding the development and implementation of an
investigation and remediation program for Central Hudson's former MGP site in
Newburgh, New York ("Central Hudson Site"), the City of Newburgh's ("City")
adjacent and nearby property, and the adjoining areas of the Hudson River. The
City subsequently filed a lawsuit against Central Hudson in the United States
District Court for the Southern District of New York alleging violation by
Central Hudson of, among others, federal environmental laws and seeking damages
of at least $70 million.
Subsequent to a 1998 jury award of $16 million in that lawsuit, reflecting
the estimated cost of environmental remediation and damages, Central Hudson and
the City entered into a court-approved Settlement Agreement in 1999 under which,
among others, (i) Central Hudson agreed to remediate the City's property at
Central Hudson's cost pursuant to the DEC's October 1995 Order on Consent and
(ii) if the total cost of the remediation were less than $16 million, Central
Hudson would pay the City an additional amount up to $500,000 depending on the
extent to which the cost of remediation was less than $16 million.
Further studies of the City's property by Central Hudson were provided to
the DEC, which determined that the contaminants found may pose a significant
threat to human health or the environment. As a result, Central Hudson developed
a draft Feasibility Study Report ("Feasibility Report") which was filed with the
DEC and provided to the City in December 1999. Following their review of the
Feasibility Report, the DEC and the New York State Department of Health ("DOH")
requested additional sampling. Central Hudson performed the requested work and
reported its results to the
112
DEC, the DOH, and the City in revised risk assessments that were submitted in
June 2001 (which also encompassed additional clean-up of Hudson River sediments
and property owned by the City).
The DEC and the DOH approved the revised risk assessments. The Feasibility
Report was revised based on the revised assessments and filed with the DEC for
its approval on October 29, 2003.
After approving a Feasibility Report, the DEC will issue a Proposed
Remedial Action Plan for public review and comment. After the public review, the
DEC will issue a Record of Decision that will specify a remediation plan for
Central Hudson's implementation. It is presently anticipated that the DEC will
issue the Record of Decision in the first or second quarter of 2004.
As of January 31, 2004, approximately $12 million has been spent on the
City of Newburgh matter, including the defense of the litigation described
above. It is not possible to predict the extent of additional remediation costs
that will be incurred in connection with this matter, but Central Hudson
believes that such costs could be in excess of $17 million. As of December 31,
2003, liabilities of $17 million were recorded regarding this matter which are
included in "Deferred Credits and Other Liabilities - Accrued Environmental
Remediation Costs" in Energy Group's and Central Hudson's Consolidated Balance
Sheets.
Neither Energy Group nor Central Hudson can make any prediction as to the
full financial effect of this matter on either Energy Group or Central Hudson,
including the extent, if any, of insurance reimbursement and including
implementation of environmental clean-up under the Order on Consent. However,
Central Hudson has put its insurers on notice of this matter and intends to seek
reimbursement from its insurers for the cost of any liability. Two of the
insurers have denied coverage.
Other MGP Sites: In February 1999, the DEC informed Central Hudson of its
intention to perform site assessments at three of the other previously
identified MGP sites; namely, the Poughkeepsie Laurel Street and North Water
Street sites and the Beacon site. Central Hudson conducted these site
assessments under agreements negotiated with the DEC to determine if there are
any significant quantities of residues from the MGP operations on the sites.
In October 2000, Central Hudson was notified by the DEC that it had
determined that the Poughkeepsie North Perry Street site and the Catskill site
posed little or no significant threat to the public and that no additional
investigation or action was necessary at the present time. During the fourth
quarter of 2001, Central Hudson was advised that the DEC and the DOH found that
no further remedial action is presently necessary at the Beacon site.
In March 2002, the DEC informed Central Hudson that both it and the DOH
had approved Central Hudson's Supplemental Preliminary Site Assessment for the
North Water Street site, which had concluded that the contamination at the site
"does not appear to pose a significant threat to public health and the
environment." At that time, the DEC and Central Hudson agreed that further
investigation at the site would be given
113
a lower priority than work at the other Central Hudson MGP sites. In August
2002, however, an oily sheen was reported to the DEC on the Hudson River
adjacent to this site. As a result, the DEC has reversed its priority
determination with respect to the North Water Street site, and has now given it
a high priority for action. Central Hudson has provided the DEC with a report of
an investigation of subsurface conditions near the Hudson River. This work was
begun on November 3, 2003, and was completed on December 15, 2003. Additional
investigation and/or remediation is expected following a review by the DEC of
the data supplied by Central Hudson. Neither Energy Group nor Central Hudson can
predict the outcome of the investigative work at this time.
The DEC has not yet approved the cleanup plan for the Laurel Street site,
delaying the initiation of cleanup. The current estimate for cleanup at Laurel
Street is $2.5 million. Additional work at the Kingston and Saugerties sites has
been deferred pending completion of work at the other sites.
The $2.5 million estimate for the Laurel Street site cleanup was recorded
as a liability in June 2002, and the expense will be deferred, subject to the
provisions of a PSC order issued on October 25, 2002, that granted permission
for the deferral of these and other costs relating to the MGP sites. Recovery of
the deferred costs, net of any insurance recoveries, will be subject to the
following three conditions at the time the expenditures are made on an annual
basis: 1) the expenditures are incremental to current rates; 2) the expenditures
are material; and 3) Central Hudson is not earning above its allowed rate of
return on equity. Central Hudson cannot predict whether it will meet these three
conditions.
Remedial actions ultimately required at any of the four sites
(Poughkeepsie North Water Street and Laurel Street, Kingston and Saugerties) for
which additional information has been requested by the DEC could cause a
material adverse effect (the extent of which cannot be reasonably estimated) on
the financial condition of Energy Group and Central Hudson if Central Hudson
were unable to recover all or a substantial portion of these costs through
insurance and rates. Central Hudson has put its insurers on notice regarding
this matter and intends to seek reimbursement from its carriers for amounts, if
any, for which it may become liable.
Orange County Landfill
In June 2000, the DEC sent a letter to Central Hudson requesting that it
provide information about disposal of wastes at the Orange County Landfill
("Orange County Site") located in the Township of Goshen, New York, which is
listed on the Registry.
The DEC stated that its records indicate Central Hudson, or a predecessor
entity, disposed or may have disposed of wastes at the Orange County Site or
that Central Hudson transported wastes to the Orange County Site for disposal.
Central Hudson has put its insurers on notice regarding this matter and intends
to seek reimbursement from its insurers for amounts for which it may become
liable.
Documents submitted by Central Hudson in response to the request of the
DEC indicate that at least three shipments of wastes may have been disposed of
by Central Hudson at the Orange County Site: one of construction waste, one of
office and
114
commercial waste, and one of asbestos waste. Central Hudson entered into a
Tolling Agreement (i.e., an agreement extending the applicable statute of
limitations) dated September 7, 2001, with the DEC and other state agencies
whereby Central Hudson agreed to toll the applicable statute of limitations by
the state agencies against Central Hudson for certain alleged causes of action
until February 28, 2002. The tolling agreement has been renewed through March
31, 2004.
Neither Energy Group nor Central Hudson can predict the outcome of this
investigation at this time.
Newburgh Consolidated Iron Works
By letter from the EPA, dated November 28, 2001, Central Hudson, among
others, was served with a Request For Information pursuant to the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA") regarding any
shipments of scrap or waste materials that Central Hudson may have made to the
Consolidated Iron and Metal Co., Inc. ("Consolidated Iron"), a Superfund site
located in Newburgh, New York. Sampling by the EPA has indicated that lead and
polychlorinated biphenyls (or "PCBs") are present at the site, and the EPA
expects to commence a remedial investigation and feasibility study at the site
in the future. Central Hudson responded to the EPA's information request on
January 30, 2002. In its response, Central Hudson stated that it had entered
into a contract with Consolidated Iron under which Central Hudson sold scrap to
Consolidated Iron. The term of the contract was from 1988 to 1989. Records of
eight and a possible ninth shipment of scrap to Consolidated Iron have been
identified. No records were found which indicate that the material sold to
Consolidated Iron contained or was a hazardous substance. Central Hudson has put
its insurers on notice regarding this matter and intends to seek reimbursement
from its insurers for amounts, if any, for which it may become liable.
Neither Energy Group nor Central Hudson can predict the outcome of this
investigation at the present time.
Asbestos Litigation
Since 1987, Central Hudson, along with many other parties, has been joined
as a defendant or third-party defendant in 3,147 asbestos lawsuits commenced in
New York State and federal courts. The plaintiffs in these lawsuits have each
sought millions of dollars in compensatory and punitive damages from all
defendants. The cases were brought by or on behalf of individuals who have
allegedly suffered injury from exposure to asbestos, including exposure which
allegedly occurred at the Roseton Plant and the Danskammer Plant.
As of January 20, 2004, of the 3,147 cases brought against Central Hudson,
1,463 remain pending. Of the 1,684 cases no longer pending against Central
Hudson, 1,547 have been dismissed or discontinued, and Central Hudson has
settled 137 cases. Central Hudson is presently unable to assess the validity of
the remaining asbestos lawsuits; accordingly, it cannot determine the ultimate
liability relating to these cases. Based on information known to Central Hudson
at this time, including Central Hudson's experience in settling asbestos cases
and in obtaining dismissals of asbestos cases, Central Hudson believes that
costs which may be incurred in connection with the
115
remaining lawsuits will not have a material adverse effect on either of Energy
Group's or Central Hudson's financial positions or results of operations.
Other Central Hudson Matters
Central Hudson is involved in various other legal and administrative
proceedings incidental to its business which are in various stages. While these
matters collectively involve substantial amounts, it is the opinion of
Management that their ultimate resolution will not have a material adverse
effect on either of Energy Group's or Central Hudson's financial positions or
results of operations.
Neversink Hydro Station
Central Hudson's ownership in the Neversink Hydro Station ("Neversink") is
governed by an agreement between Central Hudson and the New York City Board of
Water Supply. This agreement provides for the transfer of Central Hudson's
ownership interest in Neversink, which has a book value of zero, to the Board of
Water Supply on December 31, 2003. As of the date of these financial statements,
the parties are discussing the transfer of Central Hudson's ownership interest
in Neversink and are negotiating the terms of an interim agreement with respect
to the ownership and operation of Neversink subsequent to December 31, 2003.
There can be no assurance that such an agreement will be reached.
CHEC:
Griffith has received a demand, addressed to Griffith Consumers Division
("Consumers"), the entity from which Griffith had purchased the assets of its
business, from the CITGO Petroleum Corporation ("CITGO") for defense and
indemnification of CITGO in a lawsuit commenced on or about March 13, 2001, by
James and Casey Threatte against CITGO and Gordon E. Wenner in the Circuit Court
for Loudon County, Virginia. The lawsuit seeks compensatory damages of $1.4
million plus attorneys' fees, jointly and severally from CITGO and defendant
Wenner, for the alleged contamination of the plaintiffs' property in
Lovettsville, Virginia, by gasoline containing methyl tertiary butyl ether
("MTBE") emanating from the neighboring Lovettsville Garage. CITGO maintains
that Consumers owes it a defense and indemnification pursuant to a February 1,
1999 Distribution Franchise Agreement pursuant to which CITGO sold gasoline to
Consumers, which then resold the gasoline to the Lovettsville Garage. Griffith
does not believe it or Consumers is responsible to CITGO in this matter, in part
because the supply agreement with the Lovettsville Garage was transferred to
another distributor on August 1, 2001, and the transferee agreed to assume any
liabilities existing as of that date. Moreover, even if Griffith were determined
to be responsible to CITGO, Energy Group believes that CITGO itself is not a
proper party to the lawsuit and, therefore, Griffith would be liable only for
the reimbursement of defense costs.
On May 31, 2002, CH Services sold all of its stock ownership interest in
CH Resources to WPS Power Development, Inc. In connection with the sale, CH
Services has agreed for four years following the date of this sale to retain up
to $4 million of potential environmental liabilities which may have been
incurred by CH Resources prior to the closing, although no such material
liabilities have been identified. Energy Group
116
has agreed to guarantee the post-closing obligations of CH Services under the
sale agreement, which guarantee now applies to CHEC.
Griffith has a voluntary environmental program in connection with the West
Virginia Division of Environmental Protection regarding Griffith's Kable Oil
Bulk Plant, located in West Virginia. During 2003, approximately $6,000 was
spent on site remediation efforts and it is anticipated that less than $50,000
will be expended in 2004. The State of West Virginia has indicated no further
remediation of the site will be required.
During 2003, SCASCO spent approximately $163,000 on site remediation
efforts in Connecticut. SCASCO is to be reimbursed $133,000 from the State of
Connecticut under an environmental agreement and has recorded this anticipated
reimbursement as a receivable.
NOTE 14 - SEGMENTS AND RELATED INFORMATION
Energy Group
Energy Group's reportable operating segments are the regulated electric
and natural gas operations of Central Hudson and the activities of the
competitive business subsidiaries covered under the "Unregulated" segment for
Energy Group. Also included in the "Unregulated" segment is the investment
activity of Energy Group. All three segments currently operate in the Northeast
and Mid-Atlantic regions of the United States.
Certain additional information regarding these segments is set forth in
the following tables. General corporate expenses, property common to both
Central Hudson's electric and natural gas segments, and the depreciation of the
common property have been allocated to those segments in accordance with
practice established for regulatory purposes.
117
CH Energy Group, Inc.
Segment Disclosure
Year Ended December 31, 2003
- -----------------------------------------------------------------------------------------------------
(In Thousands except Natural
Earnings per Share) Electric Gas Unregulated Eliminations Total
- -----------------------------------------------------------------------------------------------------
Revenues from external $457,395 $123,306 $225,983 $ -- $ 806,684
customers
Intersegment revenues 9 346 -- (355) --
- -----------------------------------------------------------------------------------------------------
Total revenues 457,404 123,652 225,983 (355) 806,684
- -----------------------------------------------------------------------------------------------------
Depreciation and
amortization 21,280 5,995 6,336 -- 33,611
Interest expense 18,974 3,282 2,462 (2,462) 22,256
Interest and investment
income 8,547 1,427 4,713 (2,462) 12,225
Income tax expense 19,418 7,563 3,454 -- 30,435
Earnings per share - basic 1.77 .60 .41(1) -- 2.78
Segment assets 806,731 236,644 257,117 -- 1,300,492
Construction expenditures 42,954 10,407 6,973 -- 60,334
- -----------------------------------------------------------------------------------------------------
(1) The amount of Unregulated earnings per share ("EPS") attributable to the
competitive business units was $.20, with the balance of $.21 attributable
to Energy Group.
CH Energy Group, Inc.
Segment Disclosure
Year Ended December 31, 2002
- -----------------------------------------------------------------------------------------------------
(In Thousands except Natural
Earnings per Share) Electric Gas Unregulated Eliminations Total
- -----------------------------------------------------------------------------------------------------
Revenues from external
customers $427,978 $105,343 $162,520 $ -- $ 695,841
Intersegment revenues 47 490 -- (537) --
- -----------------------------------------------------------------------------------------------------
Total revenues 428,025 105,833 162,520 (537) 695,841
- -----------------------------------------------------------------------------------------------------
Depreciation and
amortization 19,652 5,698 5,880 -- 31,230
Interest expense 21,634 3,342 1,444 (1,557) 24,863
Interest and investment
Income 7,963 1,139 6,235 (1,557) 13,780
Income tax expense 16,252 5,438 604 -- 22,294
Earnings per share - basic 1.38 .48 .67(1) -- 2.53
Segment assets 797,621 221,145 264,141 -- 1,282,907
Construction expenditures 51,989 13,841 6,457 -- 72,287
- -----------------------------------------------------------------------------------------------------
(1) The amount of Unregulated EPS attributable to the competitive business
units was $.27, with the balance of $.40 resulting primarily from
investment activity.
118
CH Energy Group, Inc.
Segment Disclosure
Year Ended December 31, 2001
- -----------------------------------------------------------------------------------------------------
(In Thousands except Natural
Earnings per Share) Electric Gas Unregulated Eliminations Total
- -----------------------------------------------------------------------------------------------------
Revenues from external
customers $428,346 $110,296 $192,061 $ -- $ 730,703
Intersegment revenues 70 421 -- (491) --
- ------------------------------------------------------------------------------------------------------
Total revenues 428,416 110,717 192,061 (491) 730,703
- ------------------------------------------------------------------------------------------------------
Depreciation and
amortization 21,541 5,272 8,824 -- 35,637
Interest expense 24,752 4,075 3,994 (2,977) 29,844
Interest and investment
income 9,899 1,618 11,798 (2,977) 20,338
Income tax (credit) expense (13,383) 5,746 4,299 -- (3,338)
Earnings per share - basic 1.94 .56 .61(1) -- 3.11
Segment assets 769,325 214,034 273,939 -- 1,257,298
Construction expenditures 49,951 10,518 6,048 -- 66,517
- ------------------------------------------------------------------------------------------------------
(1) The amount of Unregulated EPS attributable to the competitive business
units was $.09, with the balance of $.52 largely attributable to
investment activity.
Central Hudson Gas & Electric Corporation
Segment Disclosure
Year Ended December 31, 2003
- --------------------------------------------------------------------------------
Natural
(In Thousands) Electric Gas Eliminations Total
- -------------------------------------------------------------------------------
Revenues from external
customers $457,395 $ 123,306 $ -- $ 580,701
Intersegment revenues 9 346 (355) --
- -------------------------------------------------------------------------------
Total revenues 457,404 123,652 (355) 580,701
- -------------------------------------------------------------------------------
Depreciation and amortization 21,280 5,995 -- 27,275
Interest expense 18,974 3,282 -- 22,256
Interest income 8,547 1,427 -- 9,974
Income tax expense 19,418 7,563 -- 26,981
Income avail. for common
stock 28,034 9,454 -- 37,488
Segment assets 806,731 236,644 -- 1,043,375
Construction expenditures 42,954 10,407 -- 53,361
- -------------------------------------------------------------------------------
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Central Hudson Gas & Electric Corporation
Segment Disclosure
Year Ended December 31, 2002
- -----------------------------------------------------------------------------------------------
Natural
(In Thousands) Electric Gas Eliminations Total
- -----------------------------------------------------------------------------------------------
Revenues from external
customers $427,978 $105,343 $ -- $ 533,321
Intersegment revenues 47 490 (537) --
- -----------------------------------------------------------------------------------------------
Total revenues 428,025 105,833 (537) 533,321
- -----------------------------------------------------------------------------------------------
Depreciation and
amortization 19,652 5,698 -- 25,350
Interest expense 21,634 3,342 -- 24,976
Interest income 7,963 1,139 -- 9,102
Income tax expense 16,252 5,438 -- 21,690
Income avail. for common
stock 22,545 7,818 -- 30,363
Segment assets 797,621 221,145 -- 1,018,766
Construction expenditures 51,989 13,841 -- 65,830
- -----------------------------------------------------------------------------------------------
Central Hudson Gas & Electric Corporation
Segment Disclosure
Year Ended December 31, 2001
- --------------------------------------------------------------------------------------------
Natural
(In Thousands) Electric Gas Eliminations Total
- --------------------------------------------------------------------------------------------
Revenues from external
customers $ 428,346 $ 110,296 $ -- $ 538,642
Intersegment revenues 70 421 (491) --
- --------------------------------------------------------------------------------------------
Total revenues 428,416 110,717 (491) 538,642
- --------------------------------------------------------------------------------------------
Depreciation and amortization 21,541 5,272 -- 26,813
Interest expense 24,752 4,075 -- 28,827
Interest income 9,899 1,618 -- 11,517
Income tax expense (13,383) 5,746 -- (7,637)
Income Avail. for Common
Stock 31,731 9,217 -- 40,948
Segment assets 769,325 214,034 -- 983,359
Construction Expenditures 49,951 10,518 -- 60,469
- --------------------------------------------------------------------------------------------
120
NOTE 15 - FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value:
Cash and Temporary Cash Investments: The carrying amount approximates fair
value because of the short maturity of those instruments.
Long-Term Debt: The fair value is estimated based on the quoted market
prices for the same or similar issues or to current rates offered to Central
Hudson for debt of the same remaining maturities and credit quality.
Notes Payable: The carrying amount approximates fair value because of the
short maturity of those instruments.
121
ENERGY GROUP / CENTRAL HUDSON
Long-Term Debt Maturities and Fair Value
December 31, 2003
Expected Maturity Date
----------------------
(In Thousands)
2004 2005 2006 2007 2008 Thereafter Total Fair Value
---- ---- ---- ---- ---- ---------- ----- ----------
Fixed Rate: $ 15,000 -- -- $ 33,000 -- $130,030 $178,030 $191,285
Estimated Effective
Interest Rate 7.950% -- -- 5.910% -- 5.343% 5.652%
Variable Rate: -- -- -- -- -- $115,850 $115,850 $115,850
Estimated Effective
Interest Rate 1.061% 1.061%
-------- --------
Total Debt Outstanding $293,880 $307,135
======== ========
Estimated Effective Interest Rate 3.91%
====
December 31, 2002
Expected Maturity Date
----------------------
(In Thousands)
2003 2004 2005 2006 2007 Thereafter Total Fair Value
---- ---- ---- ---- ---- ---------- ----- ----------
Fixed Rate: $ 15,000 $ 15,000 -- -- $ 33,000 $106,027 $169,027 $186,504
Estimated Effective
Interest Rate 7.014% 7.950% -- -- 5.910% 5.765% 5.459%
Variable Rate: -- -- -- -- -- $115,850 $115,850 $115,850
Estimated Effective
Interest Rate 1.236% 1.236%
-------- --------
Total Debt Outstanding $284,877 $302,354
======== ========
Estimated Effective Interest Rate 4.27%
====
122
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) - ENERGY GROUP
Selected financial data for each quarterly period within 2003 and 2002 are
presented below:
Earnings Per
Average
Share of
Common
Operating Operating Net Stock
Revenues Income Income Outstanding
-------- ------ ------ ------------
(In Thousands) (Dollars)
-------------------------------- ------------
Quarter Ended:
2003
March 31 ................... $265,152 $ 22,352 $ 20,193 $ 1.27
June 30 .................... 183,188 8,123 7,625 .48
September 30 ............... 169,827 6,148 4,705 .30
December 31 ................ 188,517 12,399 11,462 .73
2002
March 31 ................... $197,982 $ 18,964 $ 19,442 $ 1.19
June 30 .................... 152,805 4,510 5,098 .31
September 30 ............... 169,191 7,944 6,111 .37
December 31 ................ 175,863 10,580 10,630 .66
123
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) - CENTRAL HUDSON
Selected financial data for each quarterly period within 2003 and 2002 are
presented below:
Income
Available for
Operating Operating Common
Revenues Income Stock
-------- ------ -------------
(In Thousands)
---------------------------------------
Quarter Ended:
2003
March 31 ...................... $170,943 $ 16,592 $ 14,707
June 30 ....................... 143,469 8,479 6,741
September 30 .................. 135,285 8,433 6,684
December 31 ................... 131,004 10,405 9,356
2002
March 31 ...................... $143,205 $ 15,403 $ 14,449
June 30 ....................... 122,933 6,396 2,772
September 30 .................. 144,426 10,437 6,713
December 31 ................... 122,757 9,578 6,429
124
SCHEDULE II - Reserves - Energy Group
Payments Balance
. Balance at Charged to Charged to Charged at End
Beginning Cost and Other to of
Description of Period Expenses Accounts Reserves Period
- ----------- --------- -------- -------- -------- ------
YEAR ENDED DECEMBER 31, 2003
Operating Reserves ........... $ 4,912,084 $ 969,170 $ 142,130 $ 980,404 $ 5,042,980
=========== =========== =========== =========== ===========
Reserve for Uncollectible
Accounts ..................... $ 4,200,000 $ 5,861,382 $ -- $ 5,461,382 $ 4,600,000
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 2002
Operating Reserves ........... $ 4,852,994 $ 1,382,163 $ 579,509 $ 1,902,582 $ 4,912,084
=========== =========== =========== =========== ===========
Reserve for Uncollectible
Accounts ..................... $ 3,800,000 $ 3,582,200 $ -- $ 3,182,200 $ 4,200,000
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 2001
Operating Reserves ........... $ 4,754,783 $ 1,304,487 $ 250,542 $ 1,456,818 $ 4,852,994
=========== =========== =========== =========== ===========
Reserve for Uncollectible
Accounts ..................... $ 3,400,000 $ 3,912,893 $ -- $ 3,512,893 $ 3,800,000
=========== =========== =========== =========== ===========
125
SCHEDULE II - Reserves - Central Hudson
Payments Balance
Balance at Charged to Charged to Charged at End
Beginning Cost and Other to of
Description of Period Expenses Accounts Reserves Period
- ----------- --------- -------- -------- -------- ------
YEAR ENDED DECEMBER 31, 2003
Operating Reserves ........... $ 4,912,084 $ 969,170 $ 142,130 $ 980,404 $ 5,042,980
=========== =========== =========== =========== ===========
Reserve for Uncollectible
Accounts ..................... $ 2,700,000 $ 4,741,382 $ -- $ 4,441,382 $ 3,000,000
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 2002
Operating Reserves ........... $ 4,852,994 $ 1,382,163 $ 579,509 $ 1,902,582 $ 4,912,084
=========== =========== =========== =========== ===========
Reserve for Uncollectible
Accounts ..................... $ 2,300,000 $ 3,061,800 $ -- $ 2,661,800 $ 2,700,000
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 2001
Operating Reserves ........... $ 4,754,783 $ 1,304,487 $ 250,542 $ 1,456,818 $ 4,852,994
=========== =========== =========== =========== ===========
Reserve for Uncollectible
Accounts ..................... $ 2,500,000 $ 2,612,893 $ -- $ 2,812,893 $ 2,300,000
=========== =========== =========== =========== ===========
126
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A - CONTROLS AND PROCEDURES
At the end of the period covered by this report, Energy Group and Central
Hudson carried out an evaluation, under the supervision and with the
participation of the Chairman of the Board, the Chief Executive Officer, and the
Chief Financial Officer of Energy Group and of Central Hudson, to evaluate the
effectiveness of the disclosure controls and procedures (as defined in Rule
13a-15(e) under the Securities Exchange Act of 1934, as amended ("Exchange
Act")). Based on that evaluation, the Chairman of the Board, the Chief Executive
Officer, and Chief Financial Officer have concluded that Energy Group's and
Central Hudson's disclosure controls and procedures as of December 31, 2003, are
effective for recording, processing, summarizing, and reporting information that
is required to be disclosed in their reports under the Exchange Act, as amended,
within the time periods specified in the Securities and Exchange Commission's
("SEC") rules and forms.
There were no changes in Energy Group's or Central Hudson's internal
controls over financial reporting during the fourth quarter that have materially
affected, or are reasonably likely to materially affect, Energy Group's or
Central Hudson's internal control over financial reporting.
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF ENERGY GROUP
The directors of Energy Group are as follows:
- --------------------------------------------------------------------------------------------
Age
as of Year Joined
Name 12/31/03 The Board(6) Term of Office
- --------------------------------------------------------------------------------------------
Paul J. Ganci(3),(4),(6) 65 1989 Class III Director(8)
- --------------------------------------------------------------------------------------------
Heinz K. Fridrich(1),(3),(5),(6) 70 1988 Class III Director(8)
- --------------------------------------------------------------------------------------------
Edward F. X. Gallagher(1),(3),(4),(6) 70 1984 Class I Director(7)
- --------------------------------------------------------------------------------------------
Stanley J. Grubel(2),(3),(4) 61 1999 Class II Director(9)
- --------------------------------------------------------------------------------------------
E. Michel Kruse(1),(4),(5) 59 2002 Class III Director(8)
- --------------------------------------------------------------------------------------------
Steven M. Fetter(1),(2),(3),(5) 51 2002 Class II Director(9)
- --------------------------------------------------------------------------------------------
Steven V. Lant(4) 46 2002 Class I Director(7)
- --------------------------------------------------------------------------------------------
127
- ---------------
(1) Member, Audit Committee of the Board of Directors.
(2) Member, Compensation Committee of the Board of Directors.
(3) Member, Executive Committee of the Board of Directors.
(4) Member, Strategy and Finance Committee of the Board of Directors.
(5) Member, Governance and Nominating Committee of the Board of Directors.
(6) Years prior to 1999 reflect Directorships of Central Hudson.
(7) Messrs. Gallagher and Lant are standing for election at the Annual Meeting
of Shareholders as Class I Directors.
(8) Term expires at Annual Meeting of Shareholders in 2006.
(9) Term expires at Annual Meeting of Shareholders in 2005.
Officers of the Board:
Paul J. Ganci
Chairman of the Board and the Executive Committee
Heinz K. Fridrich
Vice Chairman of the Board and the Executive Committee
and Chairman of the Governance and Nominating Committee
Stanley J. Grubel
Chairman of the Compensation Committee
Steven M. Fetter
Chairman of the Audit Committee
E. Michel Kruse
Chairman of the Strategy and Finance Committee
The information on those directors of Energy Group standing for election
by shareholders at the Annual Meeting of Shareholders to be held on April 27,
2004, is incorporated by reference to the caption "Proposal 1 - Election of
Directors" in Energy Group's definitive proxy statement dated March 3, 2004,
("Proxy Statement"), to be used in connection with its Annual Meeting of
Shareholders to be held on April 27, 2004, which Proxy Statement will be filed
with the SEC.
The information on the executive officers of Energy Group required
hereunder is incorporated by reference to Item 1 of this 10-K Annual Report
under the caption "Executive Officers."
Other information required hereunder for directors and officers of Energy
Group is incorporated by reference to the Proxy Statement.
The Corporation has adopted a Code of Business Conduct and Ethics
("Code"). Section II of the Code, in accordance with Section 406 of the
Sarbanes-Oxley Act of 2002 and Item 406 of Regulation S-K, constitutes the
Corporation's Code of Ethics for Senior Financial Officers. This section, in
conjunction with the remainder of the Code, is
128
intended to promote honest and ethical conduct, full and accurate reporting, and
compliance with laws as well as other matters. A copy of the Code is available
on our Internet site at www.chenergygroup.com and is also included in the
Exhibit Index to this 10-K Annual Report.
If Energy Group's Board of Directors materially amends or grants any
waivers to Section II of the Code relating to issues concerning the need to
resolve ethically any actual or apparent conflicts of interest, and to comply
with all generally accepted accounting principles, laws and regulations designed
to produce full, fair, accurate, timely, and understandable disclosure in the
company's periodic reports filed with the Securities and Exchange Commission,
Energy Group will post such information on its Internet site at
www.chenergygroup.com.
Energy Group's governance guidelines, Code of Business Conduct and Ethics,
and the charters of its Audit, Compensation, Governance and Nominating, and
Strategy and Finance Committees are available on the Corporation's Internet site
at www.chenergygroup.com. The governance guidelines, the Code of Business
Conduct and Ethics, and the charters may also be obtained by writing to the
Corporate Secretary, CH Energy Group, Inc., 284 South Avenue, Poughkeepsie, New
York 12601-4879.
ITEM 11 - EXECUTIVE COMPENSATION
The information required hereunder for directors and executives of Energy
Group is incorporated by reference to the Proxy Statement.
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Equity Compensation Plan Information
The following table sets forth information concerning Energy Group's
compensation plans (including individual compensation arrangements) under which
equity securities of Energy Group are authorized for issuance:
- -----------------------------------------------------------------------------------------
Number of securities
to be issued upon Weighted average Number of
exercise of exercise price of securities remaining
outstanding options, outstanding option, available for future
warrants and rights warrants and rights issuance
Plan Category (a) (b) (c)
- -----------------------------------------------------------------------------------------
Equity compensation
plans approved by 107,360(1) $44.16 346,550(2)
security holders
- -----------------------------------------------------------------------------------------
Equity compensation
plans not approved --(3) -- --
by security holders
- -----------------------------------------------------------------------------------------
Total 107,360 $44.16 346,550
- -----------------------------------------------------------------------------------------
129
(1) This includes only stock options granted under the Long-Term Performance-
Based Incentive Plan.
(2) This excludes 11,020 performance shares granted, 1,837 performance shares
awarded and 17,340 stock options exercised through 2003 under the
Long-Term Performance Based Incentive Plan.
(3) Energy Group also has an equity compensation plan described under the
caption "Stock Plan for Outside Directors" in the Proxy Statement. No
options, warrants or rights are granted under this plan.
The information required hereunder regarding equity ownership in Energy
Group by its directors and executive officers is incorporated by reference to
the caption "Security Ownership of Directors and Officers" in the Proxy
Statement.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
See Note 1 under the caption "Related Party Transactions."
ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required hereunder regarding the Audit Committee's
policies and procedures and annual fees rendered to Energy Group's principal
accountants is incorporated by reference to the caption "Principal Accountant
Fees and Services" included in the Report of the Audit Committee in the Proxy
Statement.
PART IV
ITEM 15 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents filed as part of this Report
1. and 2. All Financial Statements and Financial Statement Schedules filed
as part of this 10-K Annual Report are included in Item 8 of this 10-K
Annual Report and reference is made thereto.
3. Exhibits
Incorporated herein by reference to the Exhibit Index for this 10-K Annual
Report. Such Exhibits include the following management contracts or
compensatory plans or arrangements required to be filed as an Exhibit
pursuant to Item 15(c) hereof:
Description in the Exhibit List and Exhibit Nos. for this Report
Energy Group's Stock Plan for Outside Directors. (Exhibits (10) (iii) 7,
30)
Energy Group's Supplementary Retirement Plan. (Exhibits (10) (iii) 11 and
23)
Central Hudson's Retirement Benefit Restoration Plan. (Exhibits (10) (iii)
12 and 24)
130
Form of Employment Agreement for all officers of Energy Group and its
subsidiary companies. (Exhibits (10) (iii) 13)
Employment Agreement between Paul J. Ganci and Energy Group. (Exhibit (10)
(iii) 16)
Energy Group's Change of Control Severance Policy. (Exhibits (10) (iii) 6
and 15)
Central Hudson's Savings Incentive Plan. (Exhibits (10) (iii) 1, 2, 3, 14,
18, 19, 21 and 27)
Energy Group's Long-Term Performance-Based Incentive Plan. (Exhibit (10)
(iii) 10, 17, 20 and 28)
Energy Group's Directors and Executives Deferred Compensation Plan.
(Exhibits (10) (iii) 8, 9, 22, 26 and 29)
Agreement between Energy Group and Allan R. Page. (Exhibit (10) (iii) 25)
(b) Reports on Form 8-K
During the last quarter of the period covered by this 10-K Annual Report
and including the period to the date hereof, the following Reports on Form
8-K were filed by Energy Group and/or Central Hudson:
1. Report dated January 31, 2004, of Energy Group relating to Energy
Group's 2003 earnings and earnings guidance for 2004.
2. Report dated January 30, 2004 of Energy Group relating to executive
succession plan.
3. Report dated October 21, 2003, of Energy Group relating to Energy
Group's third quarter 2003 earnings.
4. Report dated September 2, 2003, of Energy Group relating to the
appointment of Christopher M. Capone as Chief Financial Officer and
Treasurer of Energy Group and Central Hudson.
(c) Exhibits Required by Item 601 of Regulation S-K
Incorporated herein by reference to subpart (a)-3 of Item 15, above.
(d) Financial Statement Schedule required by Regulation S-X which is excluded
from Energy Group's Annual Report to Shareholders for the fiscal year
ended December 31, 2003
Not applicable, see Item 8 hereof.
131
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, CH Energy Group, Inc. and Central Hudson Gas & Electric
Corporation have duly caused this 10-K Annual Report to be signed on its behalf
by the undersigned, thereunto duly authorized.
CH ENERGY GROUP, INC.
By /s/ Paul J. Ganci
--------------------------------
Paul J. Ganci
Chairman of the Board
Dated: February 18, 2004
CENTRAL HUDSON GAS & ELECTRIC
CORPORATION
By /s/ Paul J. Ganci
------------------------------
Paul J. Ganci
Chairman of the Board
Dated: February 18, 2004
132
Pursuant to the requirements of the Securities Exchange Act of 1934, this
10-K Annual Report has been signed below by the following person on behalf of CH
Energy Group, Inc. and Central Hudson Gas & Electric Corporation and in the
capacities and on the date indicated:
Signature Title Date
--------- ----- ----
(a) Principal Executive
Officer or Officers:
/s/ Paul J. Ganci
- --------------------------
(Paul J. Ganci) Chairman of the Board
of CH Energy Group, Inc.
and Chairman of the Board
of Central Hudson Gas
& Electric Corporation February 18, 2004
/s/ Steven V. Lant
- --------------------------
(Steven V. Lant) President and Chief Executive Officer
of CH Energy Group, Inc.
and Chief Executive Officer
of Central Hudson Gas
& Electric Corporation February 18, 2004
(b) Principal Accounting
Officer:
/s/ Donna S. Doyle
- --------------------------
(Donna S. Doyle) Vice President -
Accounting and
Controller of
CH Energy Group, Inc.
and Central Hudson Gas
& Electric Corporation February 18, 2004
(c) Chief Financial
Officer:
/s/ Christopher M. Capone
- --------------------------
(Christopher M. Capone) Chief Financial Officer and Treasurer
of CH Energy Group, Inc.
and Central Hudson Gas
& Electric Corporation February 18, 2004
133
(d) A majority of Directors of CH Energy Group, Inc.:
Heinz K. Fridrich*,
Edward F.X. Gallagher*, Paul J. Ganci*,
Stanley J. Grubel*, Steven M. Fetter*,
E. Michel Kruse*, and Steven V. Lant*, Directors
By /s/ Paul J. Ganci
-------------------------
(Paul J. Ganci) February 18, 2004
(e) A majority of Directors of Central Hudson Gas & Electric Corporation:
Paul J. Ganci*, Carl E. Meyer*, Steven V. Lant*, Jack Effron*,
and Arthur R. Upright*, Directors
By /s/ Paul J. Ganci
-------------------------
(Paul J. Ganci) February 18, 2004
- ------------------
* Paul J. Ganci, by signing his name hereto, does thereby sign this document
for himself and on behalf of the persons named above after whose printed
name an asterisk appears, pursuant to powers of attorney duly executed by
such persons and filed with the SEC as Exhibit 24 hereof.
134
EXHIBIT INDEX
Following is the list of Exhibits, as required by Item 601 of Regulation
S-K, filed as a part of this Annual Report on Form 10-K, including Exhibits
incorporated herein by reference (1):
Exhibit No.
(Regulation S-K
Item 601
Designation) Exhibits
- ----------------- --------
(2) Plan of Acquisition, reorganization, arrangement, liquidation
or succession:
(i) Certificate of Exchange of Shares of Central Hudson Gas
& Electric Corporation, subject corporation, for shares
of CH Energy Group, Inc., acquiring corporation, under
Section 913 of the Business Corporation Law of the State
of New York. ((45); Exhibit 2(i))
(ii) Agreement and Plan of Exchange by and between Central
Hudson Gas & Electric Corporation and CH Energy Group,
Inc. ((39; Exhibit 2.1)
(3) Articles of Incorporation and Bylaws:
(i) Restated Certificate of Incorporation of CH Energy
Group, Inc. under Section 807 of the Business
Corporation Law, filed November 12, 1998. ((37); Exhibit
(3)1)
(ii) By-laws of CH Energy Group, Inc. in effect on the date
of this Report. ((50); Exhibit (3)(ii))
(iii) Restated Certificate of Incorporation of Central Hudson
Gas & Electric Corporation under Section 807 of the
Business Corporation Law. ((18); Exhibit (3)1)
- --------------
(1) Exhibits which are incorporated by reference to other filings are followed
by information contained in parentheses, as follows: The first reference
in the parenthesis is a numeral, corresponding to a numeral set forth in
the Notes which follow this Exhibit list, which identifies the prior
filing in which the Exhibit was physically filed; and the second reference
in the parenthesis is to the specific document in that prior filing in
which the Exhibit appears.
E-1
(iv) Certificate of Amendment to the Certificate of
Incorporation of Central Hudson Gas & Electric
Corporation under Section 805 of the Business
Corporation Law. ((18) Exhibit (3)2)
(v) Certificate of Amendment to the Certificate of
Incorporation of Central Hudson Gas & Electric
Corporation under Section 805 of the Business
Corporation Law. ((18); Exhibit (3)3)
(vi) By-laws of Central Hudson Gas & Electric Corporation in
effect on the date of this Report. ((49); 3(vi))
(4) Instruments defining the rights of security holders, including
indentures (see also Exhibits (3)(i)and (ii) above):
(ii) 1-- Indenture dated January 1, 1927 between Central
Hudson Gas & Electric Corporation ("Central
Hudson") and American Exchange Irving Trust
Company, as Trustee. ((2); Exhibit (4)(ii)1)
(ii) 2-- Fourth Supplemental Indenture dated March 1, 1941
between Central Hudson and Irving Trust Company,
as Trustee. ((2); Exhibit (4)(ii)5)
(ii) 3-- Fifth Supplemental Indenture dated December 1, 1950
between Central Hudson and Irving Trust Company,
as Trustee. ((2); Exhibit (4)(ii)6)
(ii) 4-- Ninth Supplemental Indenture dated December 1, 1967
between Central Hudson and Irving Trust Company,
as Trustee. ((2); Exhibit (4)(ii)10)
(ii) 5-- Twenty-Seventh Supplemental Indenture dated as of
May 15, 1992 between Central Hudson and The Bank
of New York, as Trustee. ((2); Exhibit
(4)(ii)28); and
Prospectus Supplement Dated May 28, 1992 (To
Prospectus Dated April 13, 1992) relating to
$125,000,000 principal amount of First Mortgage
Bonds, designated Secured Medium-Term Notes,
Series A, and the Prospectus Dated April 13,
1992, relating to $125,000,000 principal amount
of Central Hudson's debt
E-2
securities attached thereto, as filed pursuant
to Rule 424(b) in connection with Registration
Statement No. 33-46624. ((6)(a)), and, as
applicable to a tranche of such Secured
Medium-Term Notes, one of the following:
(a) Pricing Supplement No. 2, Dated June 4,
1992 (To Prospectus Dated April 13, 1992,
as supplemented by a Prospectus Supplement
Dated May 28, 1992) filed pursuant to Rule
424(b) in connection with Registration
Statement No. 33-46624. ((6)(b))
(b) Pricing Supplement No. 3, Dated June 4,
1992 (To Prospectus Dated April 13, 1992,
as supplemented by a Prospectus Supplement
Dated May 28, 1992) filed pursuant to Rule
424(b) in connection with Registration
Statement No. 33-46624. ((6)(c))
(c) Pricing Supplement No. 4, Dated August 20,
1992 (To Prospectus Dated April 13, 1992,
as supplemented by a Prospectus Supplement
Dated May 28, 1992) filed pursuant to Rule
424(b) in connection with Registration
Statement No. 33-46624. ((6)(d)
(d) Pricing Supplement No. 5, Dated August 20,
1992 (To Prospectus Dated April 13, 1992,
as supplemented by a Prospectus Supplement
Dated May 28, 1992) filed pursuant to Rule
424(b) in connection with Registration
Statement No. 33-46624. ((6)(e)
(e) Pricing Supplement No. 7, Dated July 26,
1993 (To Prospectus Dated April 13, 1992,
as supplemented by a Prospectus Supplement
Dated May 28, 1992) filed pursuant to Rule
424(b) in connection with Registration
Statement No. 33-46624. ((6)(f)
(ii) 6-- Discharge, release and cancellation of Indenture of
Mortgage, dated November 6, 2001, from the Bank
of New York, as Trustee. ((47)); Exhibit (4)
(ii) (6))
(ii) 7-- Indenture, dated as of April 1, 1992, between
Central Hudson and Morgan Guaranty Trust Company
of New York, as
E-3
Trustee related to unsecured Medium-Term Notes.
((7); Exhibit (4)(ii)29)
(ii) 8-- Prospectus Supplement Dated May 28, 1992 (To
Prospectus Dated April 13, 1992) relating to
$125,000,000 principal amount of Medium-Term
Notes, Series A, and the Prospectus Dated April
13, 1992, relating to $125,000,000 principal
amount of Central Hudson's debt securities
attached thereto, as filed pursuant to Rule
424(b) in connection with Registration Statement
No. 33-46624. ((8)(a)), and, as applicable to a
tranche of such Medium-Term Notes, set forth in
Pricing Supplement No. 1, Dated June 26, 1992
(To Prospectus Dated April 13, 1992, as
supplemented by a Prospectus Supplement Dated
May 28, 1992) filed pursuant to Rule 424(b) in
connection with Registration Statement No.
33-46624. ((8)(b)).
(ii) 9-- Prospectus Supplement Dated January 8, 1999 (To
Prospectus Dated January 7, 1999) relating to
$110,000,000 principal amount of Medium-Term
Notes, Series C, and the Prospectus Dated
January 7, 1999, relating to $110,000,000
principal amount of Central Hudson's debt
securities attached thereto, as filed pursuant
to Rule 424(b) in connection with Registration
Statement Nos. 333-65597 and 33-56349.
((36)(a)), and, as applicable to a tranche of
such Medium-Term Notes, set forth in Pricing
Supplement No. 1, Dated January 12, 1999 (To
Prospectus Dated January 7, 1999, as
supplemented by a Prospectus Supplement Dated
January 8, 1999) filed pursuant to Rule 424(b)
in connection with Registration Statement Nos.
333-65597 and 33-56349. ((36)(b)).
(ii) 10-- Prospectus Supplement Dated March 20, 2002 (To
Prospectus dated March 14, 2002) relating to
$100,000,000 principal amount of Medium-Term
Notes, Series D, and the Prospectus Dated March
14, 2002, relating to $100,000,000 principal
amount of Central Hudson's debt securities
attached hereto, as filed pursuant to Rule 424
(b) in connection with Registration Statement
No. 33-83542 ((13)(a)), and, as applicable to a
tranche of such Medium-Term Notes, each of the
following:
(a) Pricing Supplement No. 1, Dated March 25,
2002 (to said Prospectus dated March 14,
2002, as supplemented by said Prospectus
E-4
Supplement Dated March 20, 2002) filed
pursuant to Rule 424 (b) in connection with
Registration Statement No. 333-83542.
((13)(b))
(b) Pricing Supplement No. 2, Dated March 25,
2002 (to said Prospectus Dated March 14,
2002, as supplemented by said Prospectus
Supplement Dated March 20, 2002) filed
pursuant to Rule 424 (b) in connection with
Registration Statement No. 333-83542.
((13)(c))
(c) Pricing Supplement No. 3, Dated September
17, 2003 (to said Prospectus Dated March
14, 2002, as supplemented by said
Prospectus Supplement Dated March 20, 2002
and March 25, 2002) filed pursuant to Rule
424 (b) in connection with Registration
Statement No. 333-83542. ((13)(d))
(ii) 11-- Central Hudson and another subsidiary of Energy
Group have entered into certain other
instruments with respect to long-term debt. No
such instrument relates to securities authorized
thereunder which exceed 10% of the total assets
of Energy Group and its other subsidiaries or
Central Hudson, as the case may be, each on a
consolidated basis. Energy Group and Central
Hudson agree to provide the Commission, upon
request, copies of any instruments defining the
rights of holders of long-term debt of Central
Hudson and such other subsidiary.
(10) Material contracts:
(i) 1-- Agreement dated April 27, 1973 between
Central Hudson and the Power Authority of the
State of New York. ((11); Exhibit 5.19)
(i) 2-- Assignment and Assumption dated as of
October 24, 1975 between Central Hudson and
New York State Electric & Gas Corporation.
((12); Exhibit 5.25)
(i) 3-- Amendment to Assignment and Assumption
dated October 30, 1978 between Central Hudson
and New York State Electric & Gas
Corporation. ((3); Exhibit 5.34)
E-5
(i) 4-- Agreement dated April 2, 1980 by and
between Central Hudson and the Power
Authority of the State of New York. ((2);
Exhibit (10)(i)24)
(i) 5-- Transmission Agreement, dated October
25, 1983, between Central Hudson and Niagara
Mohawk Power Corporation. ((2); Exhibit
(10)(i)30)
(i) 6-- Underground Storage Service Agreement,
dated June 30, 1982, between Central Hudson
and Penn-York Energy Corporation. ((2);
Exhibit (10)(i)32)
(i) 7-- Interruptible Transmission Service
Agreement, dated December 20, 1983, between
Central Hudson and Power Authority of the
State of New York. ((2); Exhibit (10)(i)33)
(i) 8-- Agreement, dated December 7, 1983,
between Central Hudson and the Power
Authority of the State of New York. ((2);
Exhibit (10)(i)34)
(i) 9-- General Joint Use Pole Agreement between
Central Hudson and the New York Telephone
Company effective January 1, 1986 (not
including the Administrative and Operating
Practices provisions thereof). ((2); Exhibit
(10)(i)37)
(i) 10-- Agreement, dated June 3, 1985, between
Central Hudson, Consolidated Edison Company
of New York, Inc. and the Power Authority of
the State of New York relating to Marcy South
Real Estate - East Fishkill, New York. ((2);
Exhibit (10)(i)38)
(i) 11-- Agreement, dated June 11, 1985, between
Central Hudson and the Power Authority of the
State of New York relating to Marcy South
Substation - East Fishkill, New York. ((2);
Exhibit (10)(i)39)
(i) 12-- Memorandum of Understanding, dated as
of March 22, 1988, by and among Central
Hudson, Alberta Northeast Gas, Limited, the
Brooklyn Union Gas Company, New Jersey
Natural Gas Company and Connecticut Natural
Gas Corporation. ((17); Exhibit (10)(i)98)
E-6
(i) 13-- Agreement, effective as of November 1,
1989, between Columbia Gas Transmission
Corporation and Central Hudson. ((19);
Exhibit (10)(i)75)
(i) 14-- Agreement, dated as of November 1,
1989, between Columbia Gas Transmission
Corporation and Central Hudson. ((19);
Exhibit (10)(i)77)
(i) 15-- Agreement, dated as of November 1,
1989, between Columbia Gas Transmission
Corporation and Central Hudson. ((19);
Exhibit (10)(i)78)
(i) 16-- Agreement, dated as of November 1,
1989, between Columbia Gulf Transmission
Company and Central Hudson. ((19); Exhibit
(10)(i)79)
(i) 17-- Agreement, dated October 9, 1990,
between Texas Eastern Transmission
Corporation and Central Hudson. ((19);
Exhibit (10)(i)80)
(i) 18-- Agreement, dated July 2, 1990, between
Texas Eastern Transmission Corporation and
Central Hudson. ((19); Exhibit (10)(i)81)
(i) 19-- Agreement, dated December 28, 1989,
between Texas Eastern Transmission
Corporation and Central Hudson. ((19);
Exhibit (10)(i)82)
(i) 20-- Agreement, dated December 28, 1989,
between Texas Eastern Transmission
Corporation and Central Hudson. ((19);
Exhibit (10)(i)83)
(i) 21-- Agreement, dated November 3, 1989,
between Texas Eastern Transmission
Corporation and Central Hudson. ((19);
Exhibit (10)(i)84)
(i) 22-- Agreement, dated September 4, 1990,
between Algonquin Gas Transmission Company
and Central Hudson. ((19); Exhibit
(10)(i)87)
(i) 23-- Storage Service Agreement, dated July
1, 1989, between CNG Transmission
Corporation and Central Hudson. ((19);
Exhibit (10)(i)91)
E-7
(i) 24-- Agreement dated as of February 7, 1991
between Central Hudson and Alberta Northeast
Gas, Limited for the purchase of Canadian
natural gas from ATCOR Ltd. to be delivered
on the Iroquois Gas Transmission System.
((19); Exhibit (10)(i)92)
(i) 25-- Agreement dated as of February 7, 1991
between Central Hudson and Alberta Northeast
Gas, Limited for the purchase of Canadian
natural gas from AEC Oil and Gas Company, a
Division of Alberta Energy Company, Ltd. to
be delivered on the Iroquois Gas
Transmission System. ((19); Exhibit
(10)(i)93)
(i) 26-- Agreement dated as of February 7, 1991
between Central Hudson and Alberta Northeast
Gas, Limited for the purchase of Canadian
natural gas from ProGas Limited to be
delivered on the Iroquois Gas Transmission
System. ((19); Exhibit (10)(i)94)
(i) 27-- Agreement No. 2 dated as of February 7,
1991 between Central Hudson and Alberta
Northeast Gas, Limited for the purchase of
Canadian natural gas from TransCanada
Pipelines Limited under Precedent Agreement
No. 2 to be delivered on the Iroquois Gas
Transmission System. ((19); Exhibit
(10)(i)95)
(i) 28-- Agreement No. 1 dated as of February 7,
1991 between Central Hudson and Alberta
Northeast Gas, Limited for the purchase of
Canadian natural gas from TransCanada
Pipelines Limited under Precedent Agreement
No. 1 to be delivered on the Iroquois Gas
Transmission System. ((19); Exhibit
(10)(i)96)
(i) 29-- Agreement dated as of February 7, 1991
between Central Hudson and Iroquois Gas
Transmission System to transport gas
imported by Alberta Northeast Gas, Limited
to Central Hudson. ((19); Exhibit (10)(i)97)
(i) 30-- Service Agreement, dated September 30,
1986, between Central Hudson and Algonquin
Gas Transmission Company, for firm storage
transportation under Rate Schedule SS-III.
((20); Exhibit (10)(i)95)
E-8
(i) 31-- Service Agreement, dated March 12,
1991, between Central Hudson and Algonquin
Gas Transmission Company, for firm
transportation of 5,056 dth. of Texas
Eastern Transmission Corporation incremental
volume. ((20); Exhibit (10)(i)99)
(i) 32-- Agreement, dated December 28, 1990 and
effective February 5, 1991, between Central
Hudson and National Fuel Gas Supply
Corporation for interruptible
transportation. ((20); Exhibit (10)(i)100)
(i) 33-- Utility Services Contract, effective
October 1, 1991, between Central Hudson and
the U.S. Department of the Army, for the
provision of natural gas service to the U.S.
Military Academy at West Point and Stewart
Army Subpost, together with an Amendment
thereto, effective October 10, 1991. ((20);
Exhibit (10)(i)101)
(i) 34-- Service Agreement, effective December
1, 1990, between Central Hudson and Texas
Eastern Transmission Corporation, for firm
transportation service under Rate Schedule
FT-1. ((20); Exhibit (10)(i)103)
(i) 35-- Service Agreement, dated February 25,
1991, between Central Hudson and Texas
Eastern Transmission Corporation, for
incremental 5,056 dth. under Rate Schedule
CD-1. ((20); Exhibit (10)(i)104)
(i) 36-- Service Agreement, dated January 7,
1992, between Central Hudson and Texas
Eastern Transmission Corporation, for the
firm transportation of 6,000 dth./day under
Rate Schedule FTS-5. ((20); Exhibit
(10)(i)106)
(i) 37-- Agreement dated as of July 1, 1992
between Central Hudson and Tennessee Gas
Pipeline Company for storage of natural gas.
((21); Exhibit (10)(i)114)
(i) 38-- Agreement dated as of July 1, 1992
between Central Hudson and Tennessee Gas
Pipeline Company for firm transportation
periods. ((21); Exhibit (10)(i)115)
(i) 39-- Agreement, dated November 1, 1990,
between Tennessee Gas Pipeline and Central
Hudson for transportation of third-party gas
for injection into and withdrawal from Penn
York storage. ((2); Exhibit (10)(i)100)
E-9
(i) 40-- Agreement, dated December 1, 1991,
between Central Hudson and Iroquois Gas
Transmission System for interruptible gas
transportation service. ((2); Exhibit
(10)(i)101)
(i) 41-- Letter Agreement, dated August 24,
1992, between Central Hudson and Iroquois
Gas Transmission System amending that
certain Agreement, dated December 1, 1991
between said parties for interruptible gas
transportation service. ((19); Exhibit
(10)(i)102)
(i) 42-- Gas Transportation Agreement, dated as
of September 1, 1993, by and between
Tennessee Gas Pipeline Company and Central
Hudson. ((1); Exhibit(10)(i)108)
(i) 43-- Agreement, dated as of May 20, 1993,
between Central Hudson and New York State
Electric & Gas Corporation. ((24); Exhibit
(10)(i)93)
(i) 44-- Agreement for the Sale and Purchase of
Coal, dated as of December 1, 1996, among
Central Hudson, Inter-American Coal N.V. and
Inter-American Coal, Inc. [Certain portions
of the agreement setting forth or relating
to pricing provisions are omitted and filed
separately with the Securities and Exchange
Commission pursuant to a request for
confidential treatment under the rules of
said Commission.] ((30); Exhibit (10)(i)107)
(i) 45-- Amended and Restated Settlement
Agreement, dated January 2, 1998, among
Central Hudson, the Staff of the Public
Service Commission of the State of New York
and the New York State Department of
Economic Development. ((32); Exhibit
(10)(i)112)
(i) 46-- Amendment, dated as of November 1,
1997, to the Agreement for the Sale and
Purchase of Coal, dated December 1, 1996,
among Central Hudson, Inter-American Coal
N.V. and Inter-American Coal, Inc. [Certain
portions of said Amendment set forth and
relate to pricing provisions and will be
filed separately with the Securities and
Exchange Commission pursuant to a request
for confidential treatment under the rules
of said Commission.] ((33); Exhibit
(10)(i)113)
E-10
(i) 47-- Modification to the Amended and
Restated Settlement Agreement, dated
February 26, 1998, signed by Central Hudson,
the Staff of the Public Service Commission
of the State of New York, the New York State
Consumer Protection Board and Pace Energy
Project. ((34); Exhibit (10)(i)115)
(i) 48-- Amendment II, dated as of November 1,
1998, to the Agreement for the Sale and
Purchase of Coal, dated December 1, 1996,
among Central Hudson, Inter-American Coal
N.V. and Inter-American Coal, Inc. [Certain
portions of said Amendment setting forth or
relating to pricing provisions are omitted
and filed separately with the Securities and
Exchange Commission pursuant to a request
for confidential treatment under the rules
of said Commission.] ((40); Exhibit
(10)(i)80)
(i) 49-- Participation Agreement, dated as of
June 1, 1977 by and between New York State
Energy Research and Development Authority
and Central Hudson. ((45); Exhibit
(10)(i)67)
(i) 50-- Agreement, dated as of November 1,
1998, between Central Hudson and Glencore
Ltd., for the Sale and Purchase of Coal.
[Certain portions of said Agreement setting
forth or relating to pricing provisions are
omitted and filed separately with the
Securities and Exchange Commission pursuant
to a request for confidential treatment
under the rules of said Commission.] ((40);
Exhibit (10)(i)81)
(i) 51-- Participation Agreement, dated as of
December 1, 1998, by and between New York
State Energy Research and Development
Authority and Central Hudson. ((40); Exhibit
(10)(i)82)
(i) 52-- Participation Agreement, dated as of
July 15, 1999, by and between New York State
Energy Research and Development Authority
and Central Hudson. ((45); Exhibit
(10)(i)66)
(i) 53-- Participation Agreement, dated as of
August 1, 1999, by and between New York
State Energy Research and Development
Authority and Central Hudson. ((45); Exhibit
(10)(i)67)
E-11
(i) 54-- Agreement, dated April 1, 1999, between
Central Hudson and Arch Coal Sales Company,
Inc. for the Sale and Purchase of Coal.
[Certain portions of the Agreement setting
forth or relating to pricing provisions are
omitted and filed separately with the
Securities and Exchange Commission pursuant
to a request for confidential treatment
under the rules of said Commission.] ((38);
Exhibit (10)(i)89)
(i) 55-- Amendment No. 3, dated as of November
1, 1999, to the Agreement for the Sale and
Purchase of Coal, dated December 1, 1996,
between Central Hudson and Inter-American
Coal, Inc. [Certain portions of said
Amendment set forth and relate to pricing
provisions and will be filed separately with
the Securities and Exchange Commission
pursuant to a request for confidential
treatment under the rules of said
Commission.] ((41); Exhibit (10)(i)88)
(i) 56-- Amendment No. 1, dated as of November
1, 1999, to the Agreement for the Sale and
Purchase of Coal, dated November 1, 1998,
between Central Hudson and Glencore, Ltd.
[Certain portions of said Amendment set
forth and relate to pricing provisions and
will be filed separately with the Securities
and Exchange Commission pursuant to a
request for confidential treatment under the
rules of said Commission.] ((41); Exhibit
(10)(i)89)
(i) 57-- Amendment No. 1, dated as of November
1, 1999, to the Agreement for the Sale and
Purchase of Coal, dated April 1, 1999
between Central Hudson and Arch Coal.
[Certain portions of said Amendment set
forth and relate to pricing provisions and
will be filed separately with the Securities
and Exchange Commission pursuant to a
request for confidential treatment under the
rules of said Commission.] ((41); Exhibit
(10)(i)90)
(i) 58-- Asset Purchase and Sale Agreement,
dated August 7, 2000, by and among Central
Hudson, Consolidated Edison Company of New
York, Inc., Niagara Mohawk Power Corporation
and Dynegy Power Corp. ((44); Exhibit
(10)(i)93)
E-12
(i) 59-- Asset Purchase and Sale Agreement,
dated August 7, 2000, by and between Central
Hudson and Dynegy Power Corp. ((44); Exhibit
(10)(i)94)
(i) 60-- Purchase Price Agreement, dated August
7, 2000, among Central Hudson, Consolidated
Edison Company of New York, Inc., Niagara
Mohawk Power Corporation and Dynegy Power
Corp. ((44); Exhibit (10)(i)95)
(i) 61-- Guarantee Agreement, dated August 7,
2000, among Central Hudson, Consolidated
Edison Company of New York, Inc., Niagara
Mohawk Power Corporation and Dynegy
Holdings, Inc. ((44); Exhibit (10)(i)96)
(i) 62-- Nine Mile Point Unit 2 Nuclear
Generating Facility Asset Purchase
Agreement, dated as of December 11, 2000, by
and among Central Hudson, Niagara Mohawk
Power Corporation, New York State Electric &
Gas Corporation, Rochester Gas and Electric
Corporation, Constellation Energy Group,
Inc. and Constellation Nuclear LLC. ((45);
Exhibit (10)(i)(79))
(i) 63-- Power Purchase Agreement, dated as of
December 11, 2000, by and between
Constellation Nuclear, LLC and Central
Hudson. ((45); Exhibit (10)(i)(80))
(i) 64-- Revenue Sharing Agreement, dated as of
December 11, 2000, by and between
Constellation Nuclear LLC and Central
Hudson. ((45); Exhibit (10)(i)(84))
(i) 65-- Transition Power Agreement, dated
January 30, 2001, by and between Central
Hudson and Dynegy Power Marketing, Inc.
((45); Exhibit (10)(i)(82))
(i) 66-- Amended and Restated Credit Agreement,
dated July 10, 2000, among CH Energy Group,
Inc., ("Energy Group") certain lenders
described therein and Banc One, N.A., as
administrative Agent. ((43); Exhibit
(10)(i)92)
E-13
(i) 67-- Amendment II, dated as of December 22,
2000, to the Agreement for the Sale and
Purchase of Coal, dated April 1, 1999,
between Central Hudson and Arch Coal Sales
Company, Inc. [Certain portions of said
Amendment set forth and relate to pricing
provisions and will be filed separately with
the Securities and Exchange Commission
pursuant to a request for confidential
treatment under the rules of said
Commission.] ((45); Exhibit (10)(i)(84))
(i) 68-- Amendment IV, dated as of December 29,
2000, to the Agreement for the Sale and
Purchase of Coal made as of December 1,
1996, between Central Hudson and
Inter-American Coal N.V. and Inter-American
Coal, Inc. [Certain portions of said
Amendment set forth and relate to pricing
provisions and will be filed separately with
the Securities and Exchange Commission
pursuant to a request for confidential
treatment under the rules of said
Commission.] ((45); Exhibit (10)(i)(85))
(i) 69-- Stock Purchase Agreement, dated
December 21, 2001 between Central Hudson
Energy Services, Inc. and WPS Power
Development, Inc. ((47); Exhibit (10) (i)
(69))
(i) 70-- Letter Agreement, dated December 21,
2001, between Central Hudson Enterprises
Corporation and WPS Power Development, Inc.
((47); Exhibit (10) (i) (70))
(i) 71-- [Reserved]
(i) 72-- Letter Agreement, dated July 3, 2001
between Central Hudson and Dynegy. ((47);
Exhibit (10) (i) (72))
(iii) 1-- Agreement, made March 14, 1994, by and between
Central Hudson and Mellon Bank, N.A.,
amending and restating, effective April 1,
1994, Central Hudson's Savings Incentive
Plan and related Trust Agreement with The
Bank of New York. ((25); Exhibit
(10)(iii)18)
(iii) 2-- Amendment 1, dated July 22, 1994 (effective April 1,
1994) to the Amended and Restated Savings
Incentive Plan of Central Hudson. ((26);
Exhibit (10)(iii)19)
E-14
(iii) 3-- Amendment 2, dated December 16, 1994 (effective
January 1, 1995) to the Amended and Restated
Savings Incentive Plan of Central Hudson, as
amended. ((26); Exhibit (10)(iii)20)
(iii) 4-- Management Incentive Program of Central Hudson,
effective April 1, 1994. ((30); Exhibit
(10)(iii)23)
(iii) 5-- Amendment, dated July 25, 1997, to the Management
Incentive Program of Central Hudson,
effective August 1, 1997. ((33); Exhibit
(10)(iii)24)
(iii) 6-- CH Energy Group, Inc. Change-of-Control Severance
Policy, effective December 1, 1998. ((40);
Exhibit (10)(iii)14)
(iii) 7-- Amended and Restated Stock Plan for Outside
Directors of CH Energy Group, Inc. effective
December 15, 1999. ((41); Exhibit
(10)(iii)21)
(iii) 8-- CH Energy Group, Inc. Directors and Executives
Deferred Compensation Plan effective January
1, 2000. ((41); Exhibit (10)(iii)25)
(iii) 9-- Trust and Agency Agreement, dated December 15, 1999
and effective January 1, 2000, between the
Corporation and First America Trust Company
for the Corporation's Directors and
Executives Deferred Compensation Plan.((41);
Exhibit (10)(iii)26)
(iii) 10-- Long-Term Performance-Based Incentive Plan of CH
Energy Group, Inc. effective January 1,
2000. ((41); Exhibit (10)(iii)27)
(iii) 11-- CH Energy Group, Inc. Supplementary Retirement
Plan, effective December 15, 1999, being an
amendment and restatement of the Central
Hudson Executive Deferred Compensation Plan
as assigned to CH Energy Group, Inc. ((43);
Exhibit (10)(ii)29)
(iii) 12-- Amendment to and Restatement of Central Hudson's
Retirement Benefit Restoration Plan,
effective as of January 1, 2000. ((43);
Exhibit (10)(iii)30)
E-15
(iii) 13-- Form of Employment Agreement, for all officers of
CH Energy Group, Inc. and its subsidiary
companies. ((47); Exhibit (10) (iii) (13))
(iii) 14-- Amendment Number Three to the Central Hudson
Savings Incentive Plan, effective January 1,
2001. ((45); Exhibit (10)(iii)32)
(iii) 15-- Amendment to the CH Energy Group, Inc.
Change-of-Control Severance Policy,
effective August 1, 2000. ((45); Exhibit
(10)(iii)33)
(iii) 16-- Employment Agreement, dated September 28, 2001,
between CH Energy Group, Inc. and Paul J.
Ganci. ((47); Exhibit (10) (iii) (16))
(iii) 17-- Amendment, effective January 1, 2001, to Energy
Group's Long-Term Performance-Based
Incentive Plan. ((46); Exhibit (10)(iii)1)
(iii) 18-- Amendment and Restatement, dated October 1, 2001,
of the Central Hudson Savings Incentive
Plan.((47); Exhibit (10) (iii) (18))
(iii) 19-- Form of Trust Agreement, effective as of October 1,
2001, between Central Hudson and ING
National Trust, as successor Trustee under
the Central Hudson Savings Incentive Plan.
((47); Exhibit (10) (iii) (19))
(iii) 20-- Amendment No. 2, effective January 1, 2002, to
Energy Group's Long-Term Performance-Based
Incentive Plan. ((47); Exhibit (10) (iii)
(20))
(iii) 21-- Form of Supplemental Participation Agreement, dated
October 21, 2001, among Central Hudson
Enterprises Corporation, Central Hudson and
ING National Trust re: Central Hudson
Savings Incentive Plan. ((47); Exhibit (10)
(iii) (21))
(iii) 22-- Amendment to CH Energy Group, Inc. Directors and
Executives Deferred Compensation Plan
effective July 1, 2002. ((47); Exhibit (10)
(iii) (22))
(iii) 23-- Amendment and restatement of CH Energy Group, Inc.
Supplementary Retirement Plan, effective
July 1, 2001. ((47); Exhibit (10) (iii)
(23))
E-16
(iii) 24-- Amendment and restatement of Central Hudson Gas &
Electric Corporation Retirement Benefit
Restoration Plan effective June 22, 2001.
((47); Exhibit (10) (iii) (24))
(iii) 25-- Agreement, dated May 10, 2002, between CH Energy
Group, Inc. and Allan R. Page.((51); Exhibit
(10)(iii)(25))
(iii) 26-- Amendment and restatement of CH Energy Group, Inc.
Directors and Executives Deferred
Compensation Plan, effective September 26,
2003 ((52); Exhibit (10)(iii)(26).
(iii) 27-- Central Hudson Gas & Electric Corporation Savings
Incentive Plan, January 1, 2004
Restatement((53); Exhibit 99(a).
(iii) 28-- Amendment to CH Energy Group, Inc. Long-Term
Performance-Based Incentive Plan, dated
October 24, 2003, effective as of September
26, 2003
(iii) 29-- Amendment to CH Energy Group, Inc. Directors and
Executives Deferred Compensation Plan Trust
Agreement, dated October 24, 2003, effective
as of September 26, 2003
(iii) 30-- CH Energy Group, Inc. Amended and Restated Stock
Plan for Outside Directors, dated October
24, 2003, effective as of September 26, 2003
(12)(i)-- CH Energy Group Statement showing the computation of the ratio
of earnings to fixed charges.
(12)(ii)-- Central Hudson Statement showing the computation of the ratio
of earnings to fixed charges and ratio of earnings to fixed
charges and preferred dividends.
(14) -- CH Energy Group, Inc. Code of Business Conduct and Ethics
(21) -- Subsidiaries of Energy Group and Central Hudson as of December
31, 2003.
State or other Name under which
Jurisdiction of Subsidiary conducts
Name of Subsidiary Incorporation Business
- ----------------- -------------- ------------------
Central Hudson Gas New York Central Hudson Gas &
& Electric Corporation Electric Corporation
E-17
Phoenix Development New York Phoenix Development
Company, Inc. Company, Inc.
Central Hudson New York Central Hudson
Enterprises Corporation Enterprises Corporation
SCASCO, Inc. Connecticut SCASCO, Inc.
Griffith Energy New York Griffith Energy
Services, Inc. Services, Inc.
(23) -- Consent of Experts:
The consent of PricewaterhouseCoopers LLP.
(24) -- Powers of Attorney:
(i) 1-- Powers of Attorney for each of the directors
comprising a majority of the Board of Directors of
Energy Group authorizing execution and filing of this
Annual Report on Form 10-K by Paul J. Ganci.
(i) 2-- Powers of Attorney for each of the directors
comprising a majority of the Board of Directors of
Central Hudson authorizing execution and filing of
this Annual Report on Form 10-K by Paul J. Ganci.
(31) -- Rule 13a-14(a)/15d-14(a) Certifications.
(32) -- Section 1350 Certifications.
(99) -- Additional Exhibits:
(i) 1-- Order on Consent signed on behalf of the New York
State Department of Environmental Conservation
and Central Hudson relating to Central Hudson's
former manufactured gas site located in
Newburgh, New York. ((28); Exhibit (99)(i)5)
(i) 2-- Summary of principal terms of the Amended and Restated
Settlement Agreement, dated January 2, 1998,
among Central Hudson, the Staff of the Public
Service Commission of the State of New York and
the New York State Department of Economic
Development. ((32); Exhibit 99(1))
E-18
(i) 3-- Order of the Public Service Commission of the State of
New York, issued and effective February 19, 1998,
adopting the terms of Central Hudson's Amended
Settlement Agreement, subject to certain modifications
and conditions. ((34); Exhibit (10)(1))
(i) 4-- Order of the Public Service Commission of the State of
New York, issued and effective June 30, 1998,
explaining in greater detail and reaffirming its
Abbreviated Order, issued and effective February 19,
1998, which February 19, 1998 Order modified, and as
modified, approved the Amended and Restated Settlement
Agreement, dated January 2, 1998, entered into among
Central Hudson, the PSC Staff and others as part of
the PSC's "Competitive Opportunities" proceeding (ii)
the Order, dated June 24, 1998, of the Federal Energy
Regulatory Commission conditionally authorizing the
establishment of an Independent System Operator by the
member systems of the New York Power Pool and (iii)
disclosing, effective August 1, 1998, Paul J. Ganci's
appointment by Central Hudson's Board of Directors as
President and Chief Executive Officer and John E. Mack
III's (formerly Chairman of the Board and Chief
Executive Officer) continuation as Chairman of the
Board. (35)
(i) 5-- Order of the Public Service Commission of the State of
New York, issued and effective December 20, 2000,
authorizing the transfer of the Danskammer Plant and
the Roseton Plant. ((45); Exhibit (99)(i)8)
(i) 6-- Order of the Public Service Commission of the State of
New York, issued and effective January 25, 2001,
clarifying prior Order relating to the approval of the
transfer of the Danskammer Plant and the Roseton
Plant. ((45); Exhibit (99)(i)9)
(i) 7-- Order of the Public Service Commission of the State of
New York, issued and effective, October 26, 2001,
authorizing asset transfers of the Nine Mile 2 Plant.
((47); Exhibit (99)(i)(7))
(i) 8-- Order of the Public Service Commission of the State of
New York, issued and effective, September 27, 2001,
authorizing new revolving credit facilities and a New
Medium Term Note Program for Central Hudson. ((47);
Exhibit (99)(i)(8))
(i) 9-- Order of the Public Service Commission of the State of
New York, issued and effective October 25, 2001,
establishing new rates for Central Hudson. ((47);
Exhibit (99)(i)(9))
E-19
(i) 10-- Order of the Public Service Commission of the State
of New York, issued and effective October 3, 2002,
authorizing the implementation of the Economic
Development Program. ((51); Exhibit (99)(i)(10))
(i) 11-- Order of the Public Service Commission of the State
of New York, issued and effective October 25, 2002,
authorizing the establishment of a deferred
accounting plan for site identification and
remediation costs relating to Central Hudson's seven
former manufactured gas plants. ((51); Exhibit
(99)(i)(11))
(i) 12-- Order of the Public Service Commission of the State
of New York, issued and effective October 29, 2003,
directing the continuation of certain non-price
features of the rate plan.
The following are notes to the Exhibits listed above:
(1) Incorporated herein by reference to Central Hudson's
Quarterly report on Form 10-Q for fiscal quarter
ended September 30, 1993 (File No. 1-3268).
(2) Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K/A for the fiscal year
ended December 31, 1992 (File No. 1-3268).
(3) Incorporated herein by reference to Central Hudson's
Registration Statement No. 2-65127.
(4) [Reserved]
(5) [Reserved]
(6) (a) Incorporated herein by reference to Prospectus
Supplement Dated May 28, 1992 (To Prospectus Dated
April 13, 1992) relating to $125,000,000 principal
amount of First Mortgage Bonds, designated Secured
Medium-Term Notes, Series A, and to the Prospectus
Dated April 13, 1992 relating to $125,000,000
principal amount of Central Hudson's debt securities
attached thereto, as filed with the Securities and
Exchange Commission pursuant to Rule 424(b)(5) under
the Securities Act of 1933, in connection with
Registration Statement No. 33-46624.
E-20
(b) Incorporated herein by reference to Pricing
Supplement No. 2, Dated June 4, 1992 (To Prospectus
Dated April 13, 1992, as supplemented by a
Prospectus Supplement Dated May 28, 1992), as filed
with the Securities and Exchange Commission pursuant
to Rule 424(b)(3) under the Securities Act of 1933
in connection with Registration Statement No.
33-46624.
(c) Incorporated herein by reference to Pricing
Supplement No. 3, Dated June 4, 1992 (To Prospectus
Dated April 13, 1992, as supplemented by a
Prospectus Supplement Dated May 28, 1992), as filed
with the Securities and Exchange Commission pursuant
to Rule 424(b)(3) under the Securities Act of 1933
in connection with Registration Statement No.
33-46624.
(d) Incorporated herein by reference to Pricing
Supplement No. 4, Dated August 20, 1992 (To
Prospectus Dated April 13, 1992, as supplemented by
a Prospectus Supplement Dated May 28, 1992), as
filed with the Securities and Exchange Commission
pursuant to Rule 424(b)(3) under the Securities Act
of 1933 in connection with Registration Statement
No. 33-46624.
(e) Incorporated herein by reference to Pricing
Supplement No. 5, Dated August 20, 1992 (To
Prospectus Dated April 13, 1992, as supplemented by
a Prospectus Supplement Dated May 28, 1992), as
filed with the Securities and Exchange Commission
pursuant to Rule 424(b)(3) under the Securities Act
of 1933 in connection with Registration Statement
No. 33-46624.
(f) Incorporated herein by reference to Pricing
Supplement No. 7, Dated July 26, 1993 (To Prospectus
Dated April 13, 1992, as supplemented by a
Prospectus Supplement Dated May 28, 1992), as filed
with the Securities and Exchange Commission pursuant
to Rule 424(b)(3) under the Securities Act of 1933
in connection with Registration Statement No.
33-46624.
(7) Incorporated herein by reference to Central Hudson's
Current Report on Form 8-K, dated May 27, 1992 (File
No. 1-3268).
(8) (a) Incorporated herein by reference to Prospectus
Supplement Dated May 28, 1992 (To Prospectus Dated
April 13, 1992) relating to $125,000,000 principal
amount of Medium-Term Notes, Series A, and to the
Prospectus Dated April 13, 1992, relating to
$125,000,000 principal amount of Central Hudson's
debt securities attached thereto, as filed with the
Securities and Exchange Commission pursuant to Rule
424(b)(5) under the
E-21
Securities Act of 1933, in connection with
Registration Statement No. 33-46624.
(b) Incorporated herein by reference to Pricing
Supplement No. 1, Dated June 26, 1992 (To Prospectus
Dated April 13, 1992, as supplemented by a
Prospectus Supplement Dated May 28, 1992), as filed
with the Securities and Exchange Commission pursuant
to Rule 424(b)(3) under the Securities Act of 1933
in connection with Registration Statement No.
33-46624.
(9) [Reserved]
(10) (a) Incorporated herein by reference to Prospectus
Supplement Dated August 24, 1998 (To Prospectus Dated
April 4, 1995) relating to $80,000,000 principal
amount of Medium-Term Notes, Series B, and the
Prospectus Dated April 4, 1995, relating to (i)
$80,000,000 of Central Hudson's Debt Securities and
Common Stock, $5.00 par value, but not in excess of
$40 million aggregate initial offering price of such
Common Stock and (ii) 250,000 shares of Central
Hudson's Cumulative Preferred Stock, par value $100
per share, which may be issued as 1,000,000 shares of
Depositary Preferred Shares each representing 1/4 of
a share of such Cumulative Preferred Stock attached
thereto, as filed pursuant to Rule 424(b) in
connection with Registration Statement No. 33-56349.
(b) Incorporated herein by reference to Pricing
Supplement No. 1, Dated September 2, 1998 (To
Prospectus Dated April 4, 1995, as supplemented by a
Prospectus Supplement Dated August 24, 1998), as
filed with the Securities and Exchange Commission
pursuant to Rule 424(b)(2) under the Securities Act
of 1933 in connection with Registration Statement
No. 33-56349.
(11) Incorporated herein by reference to Central Hudson's
Registration Statement No. 2-50276.
(12) Incorporated herein by reference to Central Hudson's
Registration Statement No. 2-54690.
(13) (a) Incorporated herein by reference to Prospectus
Supplement, dated March 20, 2002 (to Prospectus dated
March 14, 2002), relating to $100,000,000 principal
amount Medium-Term Notes, Series D, of Central
Hudson, and the Prospectus, dated 14, 2002, relating
to said $100,000,000 principal amount of debt
securities, attached thereto, as filed with the
Securities and Exchange Commission pursuant to Rule
424 (b) under the Securities Act of
E-22
1933 in connection with Registration Statement No.
333-83542.
(b) Incorporated herein by reference to Pricing
Supplement No. 1, dated March 25, 2002 (to
Prospectus dated March 14, 2002, as supplemented by
a Prospectus Supplement dated March 20, 2002) filed
with the Securities and Exchange Commission pursuant
to Rule 424 (b) (2) under Securities Act of 1933 in
connection with Registration Statement No.
333-83542.
(c) Incorporated herein by reference to Pricing
Supplement No. 2 dated March 25, 2002 (to Prospectus
dated March 14, 2002, as supplemented by a
Prospectus Supplement dated March 20, 2002) filed
with the Securities and Exchange Commission pursuant
to Rule 424 (b) (2) under the Securities Act of 1933
in connection with Registration Statement No.
333-83542.
(d) Incorporated herein by reference to Pricing
Supplement No. 3 dated September 17, 2003 (to
Prospectus dated March 14, 2002, as supplemented by
a Prospectus Supplement dated March 20, 2002 and
March 25, 2002) filed with the Securities and
Exchange Commission pursuant to Rule 424 (b) (2)
under the Securities Act of 1933 in connection with
Registration Statement No. 333-83542.
(14) [Reserved]
(15) [Reserved]
(16) [Reserved]
(17) Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1987 (File No. 1-3268).
(18) Incorporated herein by reference to Central Hudson's
Quarterly Report on Form 10-Q for the fiscal quarter
ended September 30, 1993 (File No. 1-3268).
(19) Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1990 (File No. 1-3268).
(20) Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1991 (File No. 1-3268).
E-23
(21) Incorporated herein by reference to Central Hudson's
Quarterly Report on Form 10-Q for the fiscal quarter
ended September 30, 1992 (File No. 1-3268).
(22) [Reserved]
(23) Incorporated herein by reference to Central Hudson's
Current Report on Form 8-K, dated May 15, 1987 (File
No. 1-3268).
(24) Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1993 (File No. 1-3268).
(25) Incorporated herein by reference to Central Hudson's
Quarterly Report on Form 10-Q for the fiscal quarter
ended June 30, 1994 (File No. 1-3268).
(26) Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1994 (File No. 1-3268).
(27) [Reserved]
(28) Incorporated herein by reference to Central Hudson's
Quarterly Report on Form 10-Q for the fiscal quarter
ended September 30, 1995 (File No. 1-3268).
(29) [Reserved]
(30) Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1996 (File No. 1-3268).
(31) [Reserved]
(32) Incorporated herein by reference to Central Hudson's
Current Report on Form 8-K, dated January 7, 1998
(File No. 1-3268).
(33) Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1997, as amended December 8, 1998 (File
No. 1-3268).
(34) Incorporated herein by reference to Central Hudson's
Current Report on Form 8-K, dated February 10, 1998
(File No. 1-3268).
E-24
(35) Incorporated herein by reference to Central Hudson's
Current Report on Form 8-K, dated July 24, 1998 (File
No. 1-3268).
(36) (a) Incorporated herein by reference to Prospectus
Supplement Dated January 8, 1999 (To Prospectus Dated
January 7, 1999) relating to $110,000,000 principal
amount of Medium-Term Notes, Series C, and to the
Prospectus Dated January 7, 1999, relating to
$110,000,000 principal amount of Central Hudson's
debt securities attached thereto, as filed with the
Securities and Exchange Commission pursuant to Rule
424(b)(2) under the Securities Act of 1933, in
connection with Registration Statement Nos. 333-65597
and 33-56349.
(b) Incorporated herein by reference to Pricing
Supplement No. 1, Dated January 12, 1999 (To
Prospectus Dated January 7, 1999, as supplemented by
a Prospectus Supplement Dated January 8, 1999), as
filed with the Securities and Exchange Commission
pursuant to Rule 424(b)(3) under the Securities Act
of 1933 in connection with Registration Statement
Nos. 333-65597 and 33-56349.
(37) Incorporated herein by reference to Energy Group's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1998 (File No. 333-52797).
(38) Incorporation herein by reference to Central Hudson's
Quarterly Report on Form 10-Q for the fiscal quarter
ended June 30, 1999 (File No. 1-3268).
(39) Incorporated herein by reference to Central Hudson's
Current Report on Form 8-K dated December 15, 1999
(File No. 1-3268)
(40) Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1998 (File No. 1-3268).
(41) Incorporated herein by reference to Energy Group's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1999 (File No. 333-52797).
(42) Incorporated herein by reference to Energy Group's
Quarterly Report on Form 10-Q for the fiscal quarter
ended March 31, 2000 (File No. 0-30512).
E-25
(43) Incorporated herein by reference to Energy Group's
Quarterly Report on Form 10-Q for the fiscal quarter
ended June 30, 2000 (File No. 0-30512).
(44) Incorporated herein by reference to Energy Group's
Quarterly Report on Form 10-Q for the fiscal quarter
ended September 30, 2000 (File No. 0-30512).
(45) Incorporated herein by reference to Energy Group's
Annual Report, on Form 10-K, for the fiscal year
ended December 31, 2000 (File No. 0-30512).
(46) Incorporated herein by reference to Energy Group's
Quarterly Report on Form 10-Q for the fiscal quarter
ended March 31, 2001 (File No. 0-30512).
(47) Incorporated herein by reference to Energy Group's
Annual Report on Form 10-K, for the fiscal year ended
December 31, 2001 (File No. 0-30512)
(48) Incorporated herein by reference to Energy Group's
Quarterly Report on Form 10-Q for the fiscal quarter
ended September 30, 2002 (File No. 0-30512).
(49) Incorporated herein by reference to Energy Group's
Annual Report on Form 10-K, for the fiscal year ended
December 31, 2002 (File No. 0-30512)
(50) Incorporated herein by reference to Energy Group's
Quarterly Report on Form 10-Q, for the fiscal quarter
ended June 30, 2003 (File No. 0-30512)
(51) Incorporated herein by reference to Energy Group's
Annual Report on Form 10-K, for the fiscal year ended
December 31, 2003 (File No. 0-30512)
(52) Incorporated herein by reference to Energy Group's
Registration Statement on Form S-8, filed on October
30, 2003 (File No. 333-110086)
(53) Incorporated herein by reference to Energy Group's
Registration Statement on Form S-8, filed on January
16, 2004 (File No. 333-111984)
E-26