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, 2009
OR
o
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
|
For the
transition period from to
Commission
File
Number
|
|
Registrant,
State of Incorporation
Address
and Telephone Number
|
|
IRS
Employer
Identification
No.
|
|
|
|
|
|
0-30512
|
|
CH
Energy Group, Inc.
(Incorporated
in New York)
284
South Avenue
Poughkeepsie,
New York 12601-4839
(845)
452-2000
|
|
14-1804460
|
|
|
|
|
|
|
|
|
|
|
1-3268
|
|
Central
Hudson Gas & Electric Corporation
(Incorporated
in New York)
284
South Avenue
Poughkeepsie,
New York 12601-4839
(845)
452-2000
|
|
14-0555980
|
Securities
registered pursuant to Section 12(b) of the Act:
Title
of each class
|
|
Name
of each exchange
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
4.50%
Series
4.75%
Series
|
Indicate
by check mark if CH Energy Group, Inc. (“CH Energy Group”) is a well-known
seasoned issuer, as defined in Rule 405 of the Securities Act.
Indicate
by check mark if Central Hudson Gas & Electric Corporation (“Central
Hudson”) is a well-known seasoned issuer, as defined in Rule 405 of the
Securities Act.
Indicate
by check mark if CH Energy Group is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Indicate
by check mark if Central Hudson is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Indicate
by check mark whether the Registrants (1) have filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
Registrants were required to file such reports), and (2) have been subject
to such filing requirements for the past 90 days.
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. o
Indicate
by check mark whether CH Energy Group is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large Accelerated Filer
x
|
|
Accelerated Filer o
|
Non-Accelerated Filer
o
|
|
Smaller Reporting Company
o
|
Indicate
by check mark whether Central Hudson is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large Accelerated Filer
o
|
|
Accelerated Filer o
|
Non-Accelerated Filer
x
|
|
Smaller Reporting Company
o
|
Indicate
by check mark whether CH Energy Group is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
Indicate
by check mark whether Central Hudson is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
The
aggregate market value of the voting and non-voting common equity of CH Energy
Group held by non-affiliates as of February 1, 2010, was $636,437,752 based
upon the price at which CH Energy Group’s Common Stock was last 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 of CH Energy
Group held by non-affiliates as of June 30, 2009, the last business day of
CH Energy Group’s most recently completed second fiscal quarter, was
$737,381,745 computed by reference to the price at which CH Energy Group’s
Common Stock was last 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 of Central
Hudson held by non-affiliates as of June 30, 2009 was
zero.
The
number of shares outstanding of CH Energy Group’s Common Stock, as of
February 1, 2010, was 15,804,265.
The
number of shares outstanding of Central Hudson’s Common Stock, as of
February 1, 2010, was 16,862,087. All such shares are owned by CH 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
CH Energy
Group’s definitive Proxy Statement to be used in connection with its Annual
Meeting of Shareholders to be held on April 27, 2010, 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.
GLOSSARY OF
TERMS
The
following is a glossary of frequently used abbreviations or acronyms used
herein.
CH Energy Group Companies and
Investments
|
|
|
|
CHEC
|
|
Central
Hudson Enterprises Corporation (the parent company of Griffith (not
regulated by the PSC) and wholly owned subsidiary of CH Energy
Group)
|
Cornhusker
Holdings
|
|
Cornhusker
Energy Lexington Holdings, LLC (a CHEC investment)
|
JB
Wind
|
|
JB
Wind Holdings, LLC (a CH-Community Wind investee
company)
|
|
|
|
Regulators
|
|
|
|
|
|
NYS
|
|
New
York State
|
PSC
|
|
NYS
Public Service Commission
|
FERC
|
|
Federal
Energy Regulatory Commission
|
DEC
|
|
NYS
Department of Environmental Conservation
|
|
Terms Related to Business Operations Used by CH
Energy Group
|
|
|
|
1993
PSC Policy
|
|
PSC’s
1993 Statement of Policy regarding pension and other post-employment
benefits
|
2006
Rate Order
|
|
Order
Establishing Rate Plan issued by the PSC to Central Hudson on July 24,
2006
|
2009
Rate Order
|
|
Order
Establishing Rate Plan issued by the PSC to Central Hudson on June 22,
2009
|
Distributed
Generation
|
|
An
electrical generating facility located at a customer’s point of delivery
which may be connected in parallel operation to the utility
system
|
kWh
|
|
Kilowatt-hour(s)
|
Mcf
|
|
Thousand
Cubic Feet
|
MGP
|
|
Manufactured
Gas Plant
|
MW
/ MWh
|
|
Megawatt(s)
/ Megawatt-hour(s)
|
OPEB
|
|
Other
Post-Employment Benefits
|
RDMs
|
|
Revenue
Decoupling Mechanisms
|
Retirement
Plan
|
|
Central
Hudson’s Non-Contributory Defined Benefit Retirement Income
Plan
|
ROE
|
|
Return
on Equity
|
ROW
|
|
Right-of-Way
|
Settlement
Agreement
|
|
Amended
and Restated Settlement Agreement dated January 2, 1998, and thereafter
amended, among Central Hudson, PSC Staff, and Certain Other
Parties
|
Other
|
|
|
|
|
|
ASC
|
|
FASB
Accounting Standards Codification
|
COSO
|
|
Committee
of Sponsoring Organizations of the Treadway Commission
|
EITF
|
|
FASB
Emerging Issues Task Force
|
Exchange
Act
|
|
Securities
Exchange Act of 1934
|
FASB
|
|
Financial
Accounting Standards Board
|
GAAP
|
|
Accounting
Principles Generally Accepted in the United States of
America
|
NYISO
|
|
New
York Independent System Operator
|
NYSERDA
|
|
New
York State Energy Research and Development Authority
|
Registrants
|
|
CH
Energy Group and Central Hudson
|
SFAS
|
|
Statement
of Financial Accounting
Standards
|
|
|
|
|
|
|
|
|
|
PAGE
|
|
|
PART I
|
|
|
|
|
|
|
|
ITEM
1
|
|
|
|
2
|
|
|
|
|
|
ITEM
1A
|
|
|
|
14
|
|
|
|
|
|
ITEM
1B
|
|
|
|
18
|
|
|
|
|
|
ITEM
2
|
|
|
|
18
|
|
|
|
|
|
ITEM
3
|
|
|
|
20
|
|
|
|
|
|
ITEM
4
|
|
|
|
20
|
|
|
|
|
|
|
|
PART II
|
|
|
|
|
|
|
|
ITEM
5
|
|
|
|
20
|
|
|
|
|
|
ITEM
6
|
|
|
|
23
|
|
|
|
|
|
ITEM
7
|
|
|
|
25
|
|
|
|
|
|
ITEM
7A
|
|
|
|
103
|
|
|
|
|
|
ITEM
8
|
|
|
|
105
|
|
|
|
|
|
ITEM
9
|
|
|
|
220
|
|
|
|
|
|
ITEM
9A
|
|
|
|
220
|
|
|
|
|
|
ITEM
9B
|
|
|
|
220
|
|
|
PART III
|
|
|
|
|
|
|
|
ITEM
10
|
|
|
|
221
|
|
|
|
|
|
ITEM
11
|
|
|
|
221
|
|
|
|
|
|
ITEM
12
|
|
|
|
222
|
|
|
|
|
|
ITEM
13
|
|
|
|
222
|
|
|
|
|
|
ITEM
14
|
|
|
|
223
|
|
|
|
|
|
|
|
PART IV
|
|
|
|
|
|
|
|
ITEM
15
|
|
|
|
224
|
PART I
FILING
FORMAT
This 10-K
Annual Report for the fiscal year ended December 31, 2009, is a combined report
being filed by two different Registrants: CH Energy Group and Central
Hudson. Any references in this 10-K Annual Report to CH Energy Group
include all subsidiaries of CH Energy Group, including Central Hudson, except
where the context clearly indicates otherwise. Central Hudson makes
no representation as to the information contained in this 10-K Annual Report in
relation to CH Energy Group and its subsidiaries other than Central
Hudson. When this 10-K Annual Report is incorporated by reference
into any filing with the SEC made by Central Hudson, the portions of this 10-K
Annual Report that relate to CH Energy Group and its subsidiaries, other than
Central Hudson, are not incorporated by reference therein.
CH Energy
Group’s wholly owned subsidiaries are shown below. For additional
information, see the subcaption “CHEC and Its Subsidiaries and Investments” in
Item 1 - ”Business” under the caption “Subsidiaries of CH Energy
Group”.
FORWARD-LOOKING
STATEMENTS
Statements
included in this Annual Report on Form 10-K and any 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 Exchange Act. Forward-looking
statements may be identified by words including “anticipates,” “intends,”
“estimates,” “believes,” “projects,” “expects,” “plans,” “assumes,” “seeks,” and
similar expressions. Forward-looking statements including, without
limitation, those relating to CH Energy Group’s and Central Hudson’s 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: deviations from normal seasonal weather and
storm activity; fuel prices; plant capacity factors; energy supply and demand;
potential future acquisitions; legislative, regulatory, and competitive
developments; interest rates; access to capital; market risks; corn and ethanol
prices; electric and natural gas industry restructuring and cost recovery; the
ability to obtain adequate and timely rate relief; changes in fuel supply or
costs including future market prices for energy, capacity, and ancillary
services; the success of strategies to satisfy electricity, natural gas, fuel
oil, and propane requirements; 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. CH Energy Group and Central Hudson 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.
CORPORATE
STRUCTURE
CH Energy
Group is the holding company parent corporation of two principal, wholly owned
subsidiaries, Central Hudson and CHEC. Central Hudson is a regulated electric
and natural gas subsidiary. CHEC, the parent company of CH Energy
Group’s unregulated businesses and investments, has five wholly owned
subsidiaries, Griffith Energy Service, Inc. (“Griffith”), CH-Auburn Energy, LLC
(“CH-Auburn”), CH-Greentree, LLC (“CH-Greentree’), CH-Lyonsdale, LLC
(“CH-Lyonsdale”), and CH Shirley Wind, LLC (“CH Shirley”). CHEC also
has ownership interests in certain subsidiaries that are less than
100%. For more information, see subcaption “CHEC and Its Subsidiaries
and Investments” under caption “Subsidiaries of CH Energy Group”.
For a
discussion of CH Energy Group’s and its subsidiaries’ capital structure and
financing program, see Item 7 - “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” of this 10-K Annual Report under
the subcaptions “Capital Structure” and “Financing Program” under the caption
“Capital Resources and Liquidity.” For a discussion of short-term
borrowing, capitalization, and long-term debt, see Note 7 - “Short-Term
Borrowing Arrangements,” Note 8 - “Capitalization - Common and Preferred
Stock,” and Note 9 - “Capitalization - Long-Term Debt,” respectively, to
the financial statements contained in Item 8 - “Financial Statements and
Supplementary Data” of this 10-K Annual Report (each Note being hereinafter
called a “Note”). For information concerning revenues, certain expenses,
earnings per share, and information regarding assets of Central Hudson’s
regulated electric and regulated natural gas segments and of Griffith, see Note
13 - “Segments and Related Information.”
HOLDING
COMPANY REGULATION
CH Energy
Group is a “holding company” under Public Utility Holding Company Act of 2005
(“PUHCA 2005”) because of its ownership interests in Central Hudson and CHEC. CH
Energy Group, however, is exempt from regulation as a holding company under
PUHCA 2005, because it derives substantially all of its public utility company
revenues from business conducted within a single state, the State of New York.
CH Energy Group will retain this exemption until such time as it derives more
than 13% of its public utility revenues from businesses conducted outside of the
State of New York. At the present time, CH Energy Group cannot predict whether
and when its circumstances may change such that it no longer qualifies for
exemption from PUHCA 2005 or whether regulation under PUHCA 2005 would have a
material impact on its financial condition or results of
operations.
SUBSIDIARIES
OF CH ENERGY GROUP
CENTRAL
HUDSON
Central
Hudson is a New York State natural gas and electric corporation formed in
1926. Central Hudson purchases, sells at wholesale, and distributes
electricity and natural gas at retail in portions of New York
State. Central Hudson also generates a small portion of its
electricity requirements.
Central
Hudson serves 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
684,000. 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. The number of Central Hudson employees at December 31,
2009, was 860.
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.
Central
Hudson’s delivery revenues have historically varied seasonally in response to
weather. Sales of electricity are usually highest during the summer
months, primarily due to the use of air-conditioning and other cooling
equipment. Sales of natural gas are highest during the winter months,
primarily due to space heating usage. Central Hudson’s rates are
developed based on forecasts of monthly sales volumes, which reflect natural
seasonality under normal weather conditions. Effective July 1, 2009,
Central Hudson’s delivery rate structure includes revenue decoupling mechanisms
(“RDMs”), which provide the ability to record revenues equal to those forecasted
in the development of current rates for most of Central Hudson’s
customers. As a result, fluctuations in actual sales volumes as
compared to those under normal weather conditions, no longer have a significant
impact on earnings. However, higher expenses incurred due to storm
activity are not recoverable through the RDM and may impact the Company’s
earnings. Central Hudson has the ability to request regulatory
recovery of significant incremental costs incurred if certain criteria are met
as defined by the PSC and, as such, any impact on earnings for higher storm
expenses should be limited to non-material amounts, as long as the other
criteria for deferred accounting were met.
Central
Hudson is a regulated utility with a legal obligation to deliver electricity and
natural gas within its PSC-approved franchise territory. Central
Hudson has no direct competitors in its electricity distribution business;
indirect competitors include distributed generation systems, including net
metered systems. To date, the primary source of competition is solar
power, which is currently capped for residential net metering at 12
MW. Central Hudson was authorized by the PSC to defer lost revenues
attributable to photovoltaic net metering through June 30, 2009, under an order
issued in Case 07-E-0437 on October 19, 2007. Beginning July 1, 2009,
Central Hudson no longer has the authorization to defer lost revenues
attributable to photovoltaic net metering since the RDM provides similar
protection. Central Hudson’s natural gas business competes with other
fuels, especially fuel oil and propane.
The
competitive marketplace continues to develop for electric and natural gas supply
markets, and Central Hudson’s electric and natural gas customers may purchase
energy and related services from other providers. Central Hudson’s
rate making structure neutralizes any earnings impact of customers’ decisions to
purchase electricity and natural gas from other providers.
Central
Hudson is subject to regulation by the PSC regarding, among other things,
services rendered (including the rates charged), major transmission facility
siting, accounting treatment of certain items, and issuance of
securities. For certain restrictions imposed by the Settlement
Agreement, see Note 2 - “Regulatory Matters”.
Certain
activities of Central Hudson, including accounting and the acquisition and
disposition of property, are subject to regulation by FERC under the Federal
Power Act.
Central
Hudson is not subject to the provisions of the Natural Gas
Act. Central Hudson’s hydroelectric facilities are not required to be
licensed under the Federal Power Act but are regulated by the DEC.
Central
Hudson is subject to regulation by the North American Electric Reliability
Corporation regarding its ownership, operation and use of bulk power
system.
General: The electric
and natural gas rates charged by Central Hudson applicable to service supplied
to retail customers within New York State are regulated by the
PSC. Costs of service, both for electric and gas delivery service and
for electric and gas supply costs, are recovered from customers through PSC
approved tariffs, subject to a standard of prudency. Transmission
rates and rates for electricity sold for resale in interstate commerce by
Central Hudson are regulated by FERC.
Central
Hudson’s 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. Retail rates for delivery and supply are shown separately
on retail bills to allow customers to see the costs associated with their
commodity supply, and thus facilitate retail competition. During
2009, the average price of electricity for full service customers was 14.20
cents per kWh as compared to an average of 14.88 cents per kWh in
2008. The PSC has authorized Central Hudson to recover the costs of
the electric commodity from customers, without earning a profit on the commodity
costs. The average delivery price in 2009 was 4.44 cents per kWh and
3.25 cents per kWh in 2008. The increase in delivery price was
primarily due to a Purchased Power Adjustment (“PPA”) and the implementation of
new rates as part of the 2009 Rate Order. The PPA is a mechanism to
refund to or recover from electric customers, the benefit or costs associated
with the power purchase agreement with the owner of Central Hudson’s former
electric generators. The year over year increase related to the PPA
was $0.34 per kWh and the Rate Order of $0.38 per kWh. Additional
increase is associated with new and updated surcharges to cover additional
assessments from New York State agencies. The average delivery price
does not include any surcharge or credit resulting from the Electric
RDM. The increase in the average delivery price was more than offset
by the decrease in electric commodity costs.
Central
Hudson’s retail natural gas rate structure consists of various service
classifications covering transport, retail access service, and full service
(which includes natural gas supply) for residential, commercial, and industrial
customers. During 2009, the average price of natural gas for
full-service customers was $15.83 per Mcf as compared to an average of $16.78
per Mcf in 2008. The PSC has authorized Central Hudson to recover the
costs of the gas commodity from customers, without earning a profit on the
commodity costs. The average delivery price for natural gas in 2009
was $5.14 per Mcf and $4.60 per Mcf in 2008. The increase in delivery price was
due to the implementation of new rates as part of the 2009 Rate
Order. The average delivery price does not include any surcharge or
credit resulting from the Gas RDM.
The 2009
Rate Order provides for implementation of both Electric and Gas
RDMs. RDMs are intended to minimize the earnings impact resulting
from reduced energy consumption as energy efficiency programs are implemented by
breaking the link between energy sales and utility revenues and/or
profits. Central Hudson’s RDMs allow the Company to recognize
electric delivery revenues and gas sales per customer at the levels approved in
rates for most of Central Hudson’s electric and gas customer
classes.
For
further information regarding the terms of the 2006 Rate Order and the 2009 Rate
Order under which Central Hudson operated during the current reporting period,
see Note 2 - “Regulatory Matters” under the captions “2006 Rate Order” and “2009
Rate Order”.
Rate Proceedings - Electric
and Natural Gas: For information regarding Central Hudson’s
most recent electric and natural gas rate proceeding filed with the PSC in July
2009, see Item 7 - “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” of this 10-K Annual Report under the
caption “Regulatory Matters”.
Cost Adjustment Clauses and
RDMs: For information regarding Central Hudson’s electric and
natural gas cost adjustment clauses and RDMs, see Note 1 - “Summary of
Significant Accounting Policies” under the caption “Rates, Revenues and Cost
Adjustment Clauses.”
Capital
Expenditures and Financing
For
estimates of future capital expenditures for Central Hudson, see the subcaption
“Anticipated Sources and Uses of Cash” in Item 7 - “Management’s Discussion
and Analysis of Financial Condition and Results of Operations” 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 certain credit facilities with financial covenants that
limit the amount of indebtedness Central Hudson may
incur. Additionally, Central Hudson’s ability to issue debt
securities is limited by authority granted by the PSC. Central Hudson
believes these limitations will not impair its ability to issue any or all of
the debt described under the subcaption “Financing Program” in Item 7 -
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” of this 10-K Annual Report under the caption “Capital Resources and
Liquidity.”
Purchased
Power and Generation Costs
|
|
|
|
|
|
|
|
|
For
the year ended December 31, 2009, the sources and related costs of
purchased electricity and electric generation for Central Hudson were as
follows (In Thousands):
|
|
|
|
|
|
|
|
Sources
of Energy
|
|
Aggregate
Percentage of Energy Requirements
|
|
Costs
in 2009
|
|
Purchased
Electricity
|
|
|
97.6 |
% |
|
$ |
268,337 |
|
Hydroelectric
and Other
|
|
|
2.4 |
% |
|
|
47 |
|
|
|
|
100.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
Electricity Cost
|
|
|
|
|
|
|
(7,381 |
) |
Total
|
|
|
|
|
|
$ |
261,003 |
|
Central
Hudson is engaged in the conduct and support of research and development
(“R&D”) activities, which are focused on the improvement of existing energy
technologies and the development of new technologies, including renewable energy
sources, for the delivery and use of energy. Central Hudson’s R&D
expenditures were $3.9 million in both 2009 and 2008 and $3.5 million in
2007. These expenditures were for internal research programs and for
contributions to research administered by NYSERDA, the Electric Power Research
Institute, and other industry organizations. Recovery of expenditures
for R&D is provided for in Central Hudson’s rates charged to customers for
electric and natural gas delivery service. In addition, any
differences between R&D expense and the rate allowances covering these costs
are deferred, pursuant to PSC authorization, for future recovery from or return
to customers.
Other
Central Hudson Matters
Labor
Relations: Central Hudson has an agreement with Local 320
of the International Brotherhood of Electrical Workers for its 538 unionized
employees, representing construction and maintenance employees, customer service
representatives, service workers, and clerical employees (excluding persons in
managerial, professional, or supervisory positions). This agreement
became effective on May 1, 2008, and remains effective through
April 30, 2011. It provides for an average annual general wage
increase of 4.0% and changes to fringe benefits.
CHEC AND ITS SUBSIDIARIES
AND INVESTMENTS
CHEC, a
New York corporation, is a wholly owned subsidiary of CH Energy
Group. Through its subsidiaries and investments, CHEC is engaged in
the business of marketing petroleum products and related services to retail and
wholesale customers, and providing service and maintenance of energy
conservation measures and generation systems for private businesses,
institutions, and government entities. CHEC also participates in
cogeneration, wind generation, biomass energy projects, landfill gas projects
and alternate fuel and energy production projects in New Jersey, New Hampshire,
New York, Wisconsin and Pennsylvania, and a corn-ethanol plant in
Nebraska. For further discussion of certain energy-related projects
within other subsidiaries and investments, see Note 5 - “Acquisitions,
Divestitures and Investments.”
CHEC’s
subsidiaries and investments are shown below.
Griffith
Griffith
is an energy services company engaged in fuel distribution, including heating
oil, gasoline, diesel fuel, kerosene, and propane, and the installation and
maintenance of heating, ventilating, and air conditioning
equipment. During most of 2009, Griffith operated in Virginia, West
Virginia, Maryland, Delaware, Pennsylvania, Rhode Island, Connecticut,
Massachusetts, New York, New Jersey and Washington, D.C. On December
11, 2009, Griffith closed on the sale of operations within certain geographic
locations, which included approximately 45,000 customers in Rhode Island,
Connecticut, Massachusetts, New Jersey, Pennsylvania and New
York. Since being acquired by CHEC in November 2000, Griffith
acquired the assets of 44 regional fuel oil, propane, and related services
companies. Of these acquisitions, 20 remain with Griffith following
the 2009 divestiture. The number of Griffith employees at December
31, 2009 was 413.
Other
Subsidiaries and Investments
CHEC’s
other subsidiaries and investments consist of the following:
Lyonsdale - 75%
controlling interest in a 19-megawatt wood-fired biomass electric generating
plant, which began operation in 1992. The energy and capacity of the
plant is being sold at a fixed price to an investment grade rated counterparty
pursuant to a contract that began May 1, 2006, and will end December 31,
2014. Beginning in 2009, CHEC, through a wholly-owned subsidiary
began providing management oversight services to Lyonsdale.
CH-Greentree -
100% equity interest in a molecular gate used to remove nitrogen from landfill
gas which is being leased to Greentree Landfill Gas Company, LLC (“Greentree”)
at Greentree’s currently operating landfill gas processing plant at the
Greentree landfill in western Pennsylvania. As of December 31, 2009,
this molecular gate was commercially operational. The term of the
lease is seven years.
CH-Auburn - 100%
equity interest in a 3-megawatt electric generating plant that will utilize
methane gas generated by the City of Auburn, NY landfill to produce and sell
electricity to the City. The project began operation in January
2010.
Cornhusker Holdings -
12% equity interest plus approximately $10.2 million subordinated debt
investment in the owner of Cornhusker Energy Lexington, LLC (“CEL”), a
corn-ethanol plant that began operation in January 2006. CEL is
expanding the plant’s capacity and output by approximately 40%.
CH-Community Wind –
50% equity interest in a joint venture that owns 18% equity interest in a
24-megawatt wind project in Bear Creek, Pennsylvania and a 7.5-megawatt wind
project in Atlantic City, New Jersey, which are both commercially
operational.
CH Shirley - 90%
controlling interest in a 20-megawatt wind farm facility to be constructed in
Wisconsin. The project carries a 20-year power purchase agreement
contract at fixed electric prices with Wisconsin Public Service Corporation for
the electric output of the wind farm’s eight wind
turbines. Construction is expected to be completed in the fourth
quarter of 2010.
Other – CHEC has
other interests in renewable energy projects and partnerships and an energy
sector venture capital fund.
A
substantial portion of CHEC’s revenues vary seasonally, as Griffith’s fuel
deliveries are directly related to use for space heating and are highest during
the winter months.
CHEC and
Griffith participate in competitive industries that are subject to different
risks than those found in the businesses of the regulated utility, Central
Hudson. As a competitor in the unregulated fuel distribution
business, Griffith faces competition from other fuel distribution companies and
from companies supplying other fuels for heating, such as natural gas and
propane. For a discussion of Griffith’s operating revenues and
operating income, see the caption “Results of Operations” in Item 7 -
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” of this 10-K Annual Report.
ENVIRONMENTAL
QUALITY REGULATION
Central
Hudson, Griffith, CH-Auburn and Lyonsdale are subject to regulation by federal,
state, and local authorities with respect to the environmental effects of their
operations. Environmental matters may expose Central Hudson,
Griffith, CH-Auburn and/or Lyonsdale 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.
Central
Hudson, Griffith, CH-Auburn and Lyonsdale each monitor their activities in order
to determine their impact on the environment and to comply with applicable
environmental laws and regulations.
The
principal environmental areas relevant to these companies (air, water and
industrial and hazardous wastes, other) are described below. Unless
otherwise noted, all required permits and certifications have been obtained by
the applicable company. Management believes that each company was in
material compliance with these permits and certifications during
2009.
AIR
QUALITY
The Clean
Air Act Amendments of 1990 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. The impacted facilities are listed below. See
Note 12 - “Commitments and Contingencies” under the caption “Environmental
Matters” regarding the investigation by the EPA into the compliance of a former
major Central Hudson generating asset.
Central
Hudson
The South
Cairo and Coxsackie, NY electric generating facilities have Air State Facility
permits regulating their combustion turbines’ nitrogen oxide
emissions.
Lyonsdale
The
Lyonsdale electric generating plant has a Title V Permit regulating certain gas
emissions including carbon monoxide and nitrogen oxide.
CH-Auburn
CH-Auburn
has a Title V air permit regulating certain emissions including carbon monoxide
and nitrogen oxide.
WATER
QUALITY
The Clean
Water Act addresses the discharge of pollutants into waterways and ground
water.
State
Pollution Discharge Elimination System Permits
The
following locations have permits regulating pollutant discharges:
Central
Hudson
· Eltings
Corners, NY maintenance and warehouse facility
· Rifton,
NY Training and Recreation Center
· Kingston,
NY District Office
Griffith
· Bulk
storage plants in Frederick, Westminster and Edgewater, MD
· The
customer service office in Cheverly, MD
Lyonsdale
· Lyonsdale
electric generating plant
Other
Permits and Certifications
Griffith
and Lyonsdale have additional permits and certifications regulating their water
usage and pollutant discharges.
Griffith
has General Storm Water Discharge Permits issued by various states.
Lyonsdale
has a Great Lakes
Water Withdrawal Certificate allowing water withdrawal from the Moose
River.
Other
Requirements
Central
Hudson is subject to drinking water monitoring and reporting requirements at the
following facilities:
|
·
|
Eltings
Corners, NY maintenance and warehouse
facility
|
|
·
|
Rifton,
NY Training and Recreation Center
|
INDUSTRIAL & HAZARDOUS
SUBSTANCES AND WASTES
Central
Hudson, Griffith, CH-Auburn and Lyonsdale are subject to federal, state and
local laws and regulations relating to the use, handling, storage, treatment,
transportation, and disposal of industrial, hazardous, and toxic
wastes. Currently, there are no permit or certification requirements
for Griffith, CH-Auburn or Lyonsdale. The Central Hudson permitted facilities
and equipment are noted below. See Note 12 - “Commitments and
Contingencies” under the caption “Environmental Matters” for additional
discussion regarding, among other things, Central Hudson’s former MGP facilities
and Little Britain Road.
Central
Hudson
|
·
|
NYS
Part 373 Permit for Hazardous Waste Storage Facility at Eltings
Corners
|
|
·
|
Waste
Transporter Permits for certain
vehicles
|
|
·
|
Petroleum
Bulk Storage Certificates for the South Cairo and Coxsackie combustion
turbines and Catskill, Poughkeepsie, Fishkill, Newburgh, Kingston, Eltings
Corners and Stanfordville
facilities
|
OTHER
PERMITS
Lyonsdale
also has permits for the use of wood as fuel and the use of ash as
fertilizer.
ENVIRONMENTAL
EXPENDITURES
2009
actual and 2010 estimated expenditures attributable in whole or in substantial
part to environmental considerations are detailed in the table
below:
Central
Hudson
|
Griffith
|
CH-Auburn
|
Lyonsdale
|
2009
- $6.4 million
2010
- $17.5 million
|
2009
- $0.1 million
2010
- $0.4 million
|
2009
- not material
2010
- not material
|
2009
- not material
2010
- not material
|
Central
Hudson, Griffith, CH-Auburn and Lyonsdale are also subject to regulation with
respect to other environmental matters, such as noise levels, protection of
vegetation and wildlife, and limitations on land use, and are in compliance with
regulations in these areas.
Regarding
environmental matters, except as described in Note 12 - “Commitments and
Contingencies” under the caption “Environmental Matters,” neither CH Energy
Group, Central Hudson, Griffith, CH-Auburn, nor Lyonsdale 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
CH Energy
Group files annual, quarterly, and current reports, proxy statements, and other
information with the SEC. Central Hudson files annual, quarterly, and
current reports and other information with the SEC. The public may
read and copy any of the documents each company files at the SEC’s Public
Reference Room at 100 F Street N.E., Room 1580, 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 www.sec.gov.
CH Energy
Group makes available free of charge on or through its Internet website at www.CHEnergyGroup.com
its proxy statements, 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. Central Hudson’s 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 are also available on this site. CH
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 CH Energy Group’s Internet website 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 12601-4839.
EXECUTIVE
OFFICERS OF CH ENERGY GROUP
All
executive officers of CH Energy Group are elected or appointed annually by its
Board of Directors. There are no family relationship among any of the
executive officers of CH Energy Group. The names of the current
executive officers of CH Energy Group, their positions held and business
experience during the past five years, and ages (at December 31, 2009) are as
follows:
|
|
|
|
Current
|
|
Date
Commenced
|
Executive
Officers
|
|
Age
|
|
and
Prior Positions
|
|
CH
Energy Group
|
|
Central
Hudson
|
|
CHEC
|
Steven
V. Lant
|
|
52
|
|
Chairman
of the Board
|
|
Apr
2004
|
|
May
2004
|
|
May
2004
|
|
|
|
|
Chief
Executive Officer
|
|
Jul
2003
|
|
Jul
2003
|
|
Jul
2003
|
|
|
|
|
President
|
|
Jul
2003
|
|
|
|
Jul
2003
|
|
|
|
|
Director
|
|
Feb
2002
|
|
Dec
1999
|
|
Dec
1999
|
James
P. Laurito(1)
|
|
53
|
|
Executive
Vice President
|
|
Nov
2009
|
|
Nov
2009
|
|
|
|
|
|
|
Director
|
|
|
|
Nov
2009
|
|
Nov
2009
|
Joseph
J. DeVirgilio, Jr.
|
|
58
|
|
Director
|
|
|
|
Mar
2005
|
|
Apr
2003
|
|
|
|
|
Executive
Vice President -
Corporate
Services and
Administration
|
|
Jan
2005
|
|
Jan
2005
|
|
|
|
|
|
|
Executive
Vice President
|
|
|
|
|
|
Jan
2003
|
Christopher
M. Capone
|
|
47
|
|
Executive
Vice President
|
|
Dec
2006
|
|
|
|
|
|
|
|
|
Director
|
|
|
|
Mar
2005
|
|
Mar
2007
|
|
|
|
|
Chief
Financial Officer
|
|
Sep
2003
|
|
Sep
2003
|
|
Sep
2003
|
|
|
|
|
Treasurer
|
|
Apr
2003
|
|
Jun
2001
|
|
Apr
2003
|
John
E. Gould(2)
|
|
65
|
|
Executive
Vice President
and
General Counsel
|
|
Oct
2009
|
|
|
|
|
|
|
|
|
Secretary
|
|
Mar
2007
|
|
Jun
2007
|
|
Jun
2007
|
|
|
|
|
Assistant
Secretary
|
|
Nov
1999
|
|
Jan
2000
|
|
|
Denise
D. VanBuren
|
|
48
|
|
Secretary
and Vice
President
- Corporate
Communications
|
|
Dec
2009
|
|
|
|
|
|
|
|
|
Vice
President -
Public
Affairs and
Energy
Efficiency
|
|
Aug
2007
|
|
Aug
2007
|
|
|
|
|
|
|
Vice
President -
Corporate
Communications
and
Community Relations
|
|
Nov
2000
|
|
Nov
2000
|
|
|
Charles
A. Freni, Jr.
|
|
50
|
|
Senior
Vice President -
Customer
Services
|
|
|
|
Jan
2005
|
|
|
W.
Randolph Groft
|
|
48
|
|
Executive
Vice President
|
|
|
|
|
|
Jan
2003
|
|
|
|
|
Director
|
|
|
|
|
|
Jan
2003
|
Kimberly
J. Wright(3)
|
|
42
|
|
Vice
President -
Accounting
and Controller
|
|
May
2008
|
|
|
|
|
|
|
|
|
Controller
|
|
|
|
Oct
2006
|
|
|
(1)
|
From
2003 to November 2009, served as the President and Chief Executive Officer
of New York State Electric and Gas Corporation and of Rochester Gas and
Electric Corporation; both companies are gas and electric
utilities.
|
(2)
|
Before
October 2009, served as a partner of the law firm of Thompson Hine
LLP.
|
(3)
|
From
January 2005 to October 2006, served as Director - Utility Group Budgets
and Forecasts of Northeast Utilities Service Company, a gas and electric
utility company.
|
CENTRAL
HUDSON’S RATES LIMIT ITS ABILITY TO RECOVER ITS COSTS FROM ITS
CUSTOMERS
Description
and Sources of Risk
Central
Hudson’s retail rates are regulated by the PSC. Rates generally may
not be changed during their respective terms. Therefore, rates cannot
be modified for higher expenses than those assumed in the current rates, absent
circumstances such as an increase in expenses that meet the PSC’s threshold
requirements for filing for approval of deferral accounting. Central
Hudson is operating under a rate order plan approved by the PSC effective July
1, 2009. The following could unfavorably impact Central Hudson’s
financial results:
|
·
|
Higher
expenses than reflected in current rates. Higher expenses could
result from, among other things, increases in state and local taxes, storm
restoration expense, and/or other expense components such as labor, health
care benefits and/or higher levels of uncollectible receivables from
customers.
|
|
·
|
Higher
electric and natural gas capital project costs resulting from escalation
of material and equipment prices, as well as potential delays in the
siting and legislative and/or regulatory approval requirements associated
with these projects.
|
|
·
|
A
determination by the PSC that the cost to place a project in service is
above a level which is deemed
prudent.
|
|
·
|
Penalties
imposed by the PSC for the failure to achieve performance metrics
established in rate proceedings.
|
Potential
Impacts
Central
Hudson could have lower earnings and/or reduced cash flows if cost management
and/or regulatory relief are not sufficient to alleviate the impact of higher
costs.
Additional
Information
See Note
2 - “Regulatory Matters” of this 10-K Annual Report.
UNUSUAL
TEMPERATURES IN GRIFFITH’S SERVICE TERRITORIES MAY ADVERSELY IMPACT
EARNINGS
Description
and Sources of Risk
Griffith
serves the Mid-Atlantic region of the United States. This area
experiences seasonal fluctuations in temperature. A considerable
portion of Griffith’s earnings is derived directly or indirectly from the
weather-sensitive end uses of space heating and air conditioning. As
a result, sales volumes fluctuate and vary from normal expected levels based on
variations in weather from historically normal seasonal levels. Such
variations could significantly reduce sales volumes.
Potential
Impacts
Griffith
could experience lower delivery volumes in periods of milder than normal
weather, leading to lower earnings and reduced cash flows.
GRIFFITH’S
ABILITY TO ATTRACT NEW CUSTOMERS, RETAIN EXISTING CUSTOMERS, MAINTAIN SALES
VOLUMES, AND MAINTAIN MARGINS
Description
and Sources of Risk
Lower
sales can occur for various reasons, including the following:
|
·
|
Changes
in customers’ usage patterns driven by customer responses to product
prices,
|
|
·
|
Energy
efficiency programs, and/or
|
|
·
|
The
loss of major customers, the loss of a large number of customers, or the
addition of fewer new customers than
expected.
|
Unfavorable
activity in the domestic and/or foreign markets resulting in significant
volatility in wholesale oil prices could negatively impact margins and/or cause
current and/or
prospective full service customers to decide to purchase fuel from discount
distributors.
Potential
Impacts
Any one
or more of the following could result from these
events:
|
·
|
An
adverse impact on Griffith’s ability to attract new full-service
residential customers and retain existing full-service residential
customers, resulting in lower earnings and reduced cash flows.
|
|
·
|
Further
sales volume reductions, and/or compressed margins resulting in lower
earnings and reduced cash flows.
|
|
·
|
Increased
working capital requirements stemming from an increase in oil and/or
propane prices.
|
These
events could materially reduce profitability and cash flow
THE
PROFITABILITY AND/OR CASH FLOW OF CHEC’S INVESTMENT IN ITS ETHANOL PROJECT MAY
BE ADVERSELY IMPACTED BY COMMODITY PRICE CHANGES
Description
and Sources of Risk
CHEC’s
Management believes that increases in wholesale corn prices and/or natural gas
prices and/or decreases in ethanol prices and/or distillers grains are caused by
a variety of factors, including, but not limited to the following:
|
·
|
Actions
by the federal government that reduce the demand for, or increase the
supply of, ethanol. Such actions could include, but are not
limited to, a reduction in the required level of ethanol blending or weak
enforcement of existing requirements, decreases in tax credits to refiners
and/or reductions in tariffs on imported
ethanol.
|
|
·
|
Imbalances
in the supply of and demand for corn. This could be caused by,
among other things (1) drought or other acts of nature, (2) increased
construction of new ethanol production facilities, (3) governmental
actions that discourage raising corn for use in ethanol production (such
as providing tax credits for corn grown for human consumption) or (4)
changes in agricultural markets, technology or
regulations.
|
|
·
|
Volatility
in domestic and/or foreign markets.
|
Potential
Impacts
Prolonged
periods of high corn and/or natural gas prices and/or depressed ethanol and/or
distillers’ grain prices could result in reduced net margins and have a material
adverse impact on the earnings of Cornhusker Holdings that could, in turn, lead
to an impairment of CHEC’s investment in the company.
STORMS
AND OTHER EVENTS BEYOND CENTRAL HUDSON’S AND GRIFFITH’S CONTROL MAY INTERFERE
WITH THEIR OPERATIONS
Description
and Sources of Risk
In order
to conduct their businesses, (1) Central Hudson must have access to natural gas
and electric supplies and be able to utilize its electric and natural gas
infrastructure, and (2) Griffith needs access to petroleum supplies from storage
facilities in its service territories. Central Hudson has designed
its electric and natural gas and pipeline systems to serve customers under
various contingencies in accordance with good utility
practice.
However, any one or more
of the following could impact either or both of the companies’ ability to
access supplies and/or utilize critical facilities:
|
·
|
Storms,
natural disasters, wars, terrorist acts, failure of major equipment and
other catastrophic events occurring both
within and outside Central Hudson’s and Griffith’s service
territories.
|
|
·
|
Unfavorable
developments in the world oil markets could impact
Griffith.
|
|
·
|
Third-party
facility owner or supplier financial
distress.
|
|
·
|
Unfavorable
governmental actions or judicial
orders.
|
|
·
|
Bulk
power system and gas transmission pipeline system capacity constraints
could impact Central Hudson.
|
Potential
Impacts
The
companies could experience service disruptions leading to lower earnings and/or
reduced cash flows if the situation is not resolved in a timely manner or the
financial impacts of restoration are not alleviated through insurance policies,
regulated rate recovery for Central Hudson or higher sales prices for
Griffith.
CENTRAL
HUDSON IS SUBJECT TO RISKS RELATING TO ASBESTOS LITIGATION AND MANUFACTURED GAS
PLANT FACILITIES
Description
and Sources of Risk
Litigation
has been commenced by third parties against Central Hudson arising from the use
of asbestos at certain of its previously owned electric generating stations, and
Central Hudson is involved in a number of matters arising from contamination at
former MGP sites.
Potential
Impacts
To the
extent not covered by insurance or recovered through rates, court decisions and
settlements resulting from this litigation could reduce earnings and cash
flows.
Additional
Information
See
Note 12 - “Commitments and Contingencies” and in particular the subcaptions
in Note 12 regarding “Asbestos Litigation” and “Former Manufactured Gas Plant
Facilities” under the caption “Environmental Matters.”
|
UNRESOLVED STAFF
COMMENTS
|
None.
CH Energy
Group has no significant properties other than those of Central Hudson and
CHEC.
CENTRAL
HUDSON
ELECTRIC
Central
Hudson owns hydroelectric and gas turbine generating facilities as described
below.
Type
of Electric
Generating
Plant
|
|
Year
Placed in
Service/Rehabilitated
|
|
|
MW(1)
Net
Capability
|
|
Hydroelectric
(3 stations)
|
|
1920-1986 |
|
|
|
23.0 |
|
Gas
turbine (2 stations)
|
|
1969-1970 |
|
|
|
46.0 |
|
Total
|
|
|
|
|
|
69.0 |
|
(1)
|
Reflects
maximum one-hour net capability (winter rating as of December 31, 2009) of
Central Hudson’s electric generating plants and therefore does not include
firm purchases or sales.
|
Central
Hudson owns substations having an aggregate transformer capacity of 4.9 million
kilovolt amperes. Central Hudson’s electric transmission system
consists of 629 pole miles of line. The electric distribution system
consists of over 8,100 pole miles of overhead lines and over 1,400 trench miles
of underground lines, as well as customer service lines and meters.
ELECTRIC LOAD AND
CAPACITY
Central
Hudson’s maximum one-hour demand for electricity within its own territory for
the year ended December 31, 2009, occurred on August 17, 2009, and amounted to
1,107 MW. In prior summer periods peak electric demand has reached
1,295 MW. Central Hudson’s maximum one-hour demand for electricity
within its own territory for that part of the 2009-2010 winter capability period
through January 18, 2010, occurred on December 29, 2009, and amounted to
910 MW.
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. For more information, see Note 12 - “Commitments and
Contingencies.”
NATURAL
GAS
Central
Hudson’s natural gas system consists of 164 miles of transmission pipelines and
1,167 miles of distribution pipelines, as well as customer service lines and
meters. For the year ended December 31, 2009, the total amount of
natural gas purchased by Central Hudson from all sources was 12,657,392
Mcf. Central Hudson 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 six consecutive days.
The peak
daily demand for natural gas of Central Hudson’s customers for the year ended
December 31, 2009, and for that part of the 2009-2010 heating season through
January 18, 2010, occurred on January 16, 2009, and amounted to 112,826
Mcf. In prior years, winter period daily peak demand has reached
125,496 Mcf. Central Hudson’s firm peak day natural gas capability in
the 2009-2010 heating season was 152,058 Mcf, which excludes approximately 5,000
Mcf of transport customer deliveries.
OTHER CENTRAL HUDSON
MATTERS
Central
Hudson owns its 215,404 square foot corporate headquarters, which is located in
Poughkeepsie, New York. Central Hudson’s electric generating plants
and important property units are generally held by it in fee simple, except for
certain ROW 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 ROW 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 contracts.
During
the three-year period ended December 31, 2009, Central Hudson made gross
property additions of $257.8 million and property retirements and adjustments of
$41.5 million, resulting in a net increase (including construction work in
progress) in gross utility plant of $216.2 million, or 18%.
CHEC
As of
December 31, 2009, CHEC owned a 100% interest in Griffith, CH-Auburn,
CH-Greentree and CH Shirley as well as a 75% interest in Lyonsdale. As of
December 31, 2009, Griffith owned or leased several office, warehouse, and bulk
petroleum storage facilities. These facilities are located in Delaware,
Maryland, Virginia, and West Virginia. The bulk petroleum storage
facilities have capacities from 60,000 gallons up to 760,000 gallons.
Griffith leases its corporate headquarters, which is located in Columbia,
Maryland. CH-Auburn owns a 3-megawatt, landfill gas fired, electric
generating plant in Auburn, New York, on land leased from the City of Auburn,
which began operations in 2010. CH-Greentree owns and operates a molecular
gate installed in 2009 on leased land at the Greentree Landfill in
Pennsylvania. CH Shirley indirectly owns a 90% interest in Shirley Wind,
LLC, which leases sites in Glenmore, Wisconsin for the location of its eight
2.5-megawatt wind turbines that are expected to be constructed in 2010.
Lyonsdale owns a 19-megawatt, wood fired, biomass electric generating plant,
which began operations in 1992. The plant is located in Lyonsdale, New
York.
For
information about developments regarding certain legal proceedings, see Note 12
- “Commitments and Contingencies” of this 10-K Annual Report.
CENTRAL
HUDSON:
Former
Manufactured Gas Plant Facilities
Little
Britain Road
Newburgh
Consolidated Iron Works
Asbestos
Litigation
|
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, 2009.
PART II
|
MARKET FOR
REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
|
For
information regarding the market for CH Energy Group’s Common Stock and related
stockholder matters, see Item 7 - “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” of this 10-K Annual Report under
the captions “Capital Resources and Liquidity - Financing Program” and “Common
Stock Dividends and Price Ranges” and Note 8 - “Capitalization - Common and
Preferred Stock.”
Under
applicable statutes and their respective Certificates of Incorporation, CH
Energy Group may pay dividends on its Common Stock and Central Hudson may pay
dividends on its Common Stock and its Preferred Stock, in each case only out of
surplus.
The line
graph set forth below provides a comparison of CH Energy Group’s cumulative
total shareholder return on its Common Stock with the Standard and Poor’s 500
Index (“S&P 500”) and with the Edison Electric Institute Index (the “EEI
Index”), which consists of the 58 U.S. shareholder-owned electric
utilities. Total shareholder return is the sum of the dividends paid
and the change in the market price of the stock.
INDEXED
RETURNS
|
|
Base
Period
|
|
|
Years
Ending
|
|
|
|
Dec
|
|
|
Dec
|
|
|
Dec
|
|
|
Dec
|
|
|
Dec
|
|
|
Dec
|
|
Company
/ Index
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
CH
Energy Group, Inc.
|
|
$ |
100 |
|
|
$ |
100.01 |
|
|
$ |
120.30 |
|
|
$ |
106.11 |
|
|
$ |
129.37 |
|
|
$ |
112.16 |
|
S&P
500 Index
|
|
$ |
100 |
|
|
$ |
104.91 |
|
|
$ |
121.48 |
|
|
$ |
128.16 |
|
|
$ |
80.74 |
|
|
$ |
102.11 |
|
EEI
Index
|
|
$ |
100 |
|
|
$ |
116.05 |
|
|
$ |
140.14 |
|
|
$ |
163.34 |
|
|
$ |
121.03 |
|
|
$ |
133.99 |
|
The
following table provides a summary of shares repurchased by CH Energy Group for
the three months ended December 31, 2009:
|
|
Total
Number
of
Shares
Purchased(1)
|
|
|
Average
Price Paid per Share(2)
|
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs(3)
|
|
|
Maximum
Number of Shares that May Yet be Purchased Under the Plans or
Programs(3)
|
|
Dec.
1-31, 2009
|
|
|
285 |
|
|
$ |
41.98 |
|
|
|
- |
|
|
|
2,000,000 |
|
Total
|
|
|
285 |
|
|
$ |
41.98 |
|
|
|
- |
|
|
|
2,000,000 |
|
(1)
|
Shares
surrendered to CH Energy Group in satisfaction of tax withholdings on the
vesting of restricted shares.
|
(2)
|
Closing
price of a share of CH Energy Group's common stock on the date the stock
was surrendered to the Company.
|
(3)
|
On
July 31, 2007, the Board of Directors authorized the repurchase of up to
2,000,000 shares or approximately 13% of CH Energy Group's outstanding
common stock on that date, from time to time, over the five year period
ending July 31, 2012.
|
|
SELECTED FINANCIAL
DATA OF CH ENERGY GROUP AND ITS
SUBSIDIARIES
|
FIVE-YEAR
SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA(1) (CH
ENERGY GROUP)
(In
Thousands, except per share data)
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
Operating
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
- Delivery
|
|
$ |
270,285 |
|
|
$ |
236,333 |
|
|
$ |
228,270 |
|
|
$ |
205,287 |
|
|
$ |
183,948 |
|
Electric
- Supply
|
|
|
265,885 |
|
|
|
371,828 |
|
|
|
388,569 |
|
|
|
298,621 |
|
|
|
337,046 |
|
Natural
Gas - Delivery
|
|
|
66,916 |
|
|
|
59,897 |
|
|
|
55,326 |
|
|
|
49,629 |
|
|
|
49,317 |
|
Natural
Gas - Supply
|
|
|
107,221 |
|
|
|
129,649 |
|
|
|
110,123 |
|
|
|
105,643 |
|
|
|
106,285 |
|
Competitive
business subsidiaries
|
|
|
221,282 |
|
|
|
341,494 |
|
|
|
296,479 |
|
|
|
276,458 |
|
|
|
248,691 |
|
Total
|
|
|
931,589 |
|
|
|
1,139,201 |
|
|
|
1,078,767 |
|
|
|
935,638 |
|
|
|
925,287 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
80,399 |
|
|
|
70,952 |
|
|
|
75,659 |
|
|
|
76,552 |
|
|
|
78,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations
|
|
|
34,427 |
|
|
|
32,609 |
|
|
|
42,004 |
|
|
|
42,816 |
|
|
|
44,619 |
|
Income/(Loss)
from discontinued operations, net of tax
|
|
|
9,851 |
|
|
|
3,545 |
|
|
|
1,481 |
|
|
|
268 |
|
|
|
(170 |
) |
Dividends
declared on Preferred Stock of subsidiary
|
|
|
970 |
|
|
|
970 |
|
|
|
970 |
|
|
|
970 |
|
|
|
970 |
|
Net
Income attributable to CH Energy Group
|
|
|
43,484 |
|
|
|
35,081 |
|
|
|
42,636 |
|
|
|
43,084 |
|
|
|
44,291 |
|
Dividends
Declared on Common Stock
|
|
|
34,119 |
|
|
|
34,086 |
|
|
|
34,052 |
|
|
|
34,046 |
|
|
|
34,046 |
|
Change
in Retained Earnings
|
|
|
9,365 |
|
|
|
995 |
|
|
|
8,584 |
|
|
|
9,038 |
|
|
|
10,245 |
|
Retained
Earnings - beginning of year
|
|
|
216,634 |
|
|
|
215,639 |
|
|
|
207,055 |
|
|
|
198,017 |
|
|
|
187,772 |
|
Retained
Earnings - end of year
|
|
$ |
225,999 |
|
|
$ |
216,634 |
|
|
$ |
215,639 |
|
|
$ |
207,055 |
|
|
$ |
198,017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Share Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
shares outstanding - basic
|
|
|
15,775 |
|
|
|
15,768 |
|
|
|
15,762 |
|
|
|
15,762 |
|
|
|
15,762 |
|
Income
from continuing operations - basic
|
|
$ |
2.13 |
|
|
$ |
2.00 |
|
|
$ |
2.61 |
|
|
$ |
2.71 |
|
|
$ |
2.82 |
|
Income/(Loss)
from discontinued operations - basic
|
|
$ |
0.63 |
|
|
$ |
0.22 |
|
|
$ |
0.09 |
|
|
$ |
0.02 |
|
|
$ |
(0.01 |
) |
Net
Income attributable to CH Energy Group - basic
|
|
$ |
2.76 |
|
|
$ |
2.22 |
|
|
$ |
2.70 |
|
|
$ |
2.73 |
|
|
$ |
2.81 |
|
Average
shares outstanding - diluted
|
|
|
15,881 |
|
|
|
15,805 |
|
|
|
15,779 |
|
|
|
15,779 |
|
|
|
15,767 |
|
Income
from continuing operations - diluted
|
|
$ |
2.12 |
|
|
$ |
2.00 |
|
|
$ |
2.61 |
|
|
$ |
2.71 |
|
|
$ |
2.82 |
|
Income/(Loss)
from discontinued operations - diluted
|
|
$ |
0.62 |
|
|
$ |
0.22 |
|
|
$ |
0.09 |
|
|
$ |
0.02 |
|
|
$ |
(0.01 |
) |
Net
Income attributable to CH Energy Group - diluted
|
|
$ |
2.74 |
|
|
$ |
2.22 |
|
|
$ |
2.70 |
|
|
$ |
2.73 |
|
|
$ |
2.81 |
|
Dividends
declared per share
|
|
$ |
2.16 |
|
|
$ |
2.16 |
|
|
$ |
2.16 |
|
|
$ |
2.16 |
|
|
$ |
2.16 |
|
Book
value per share (at year-end)
|
|
$ |
33.76 |
|
|
$ |
33.17 |
|
|
$ |
33.19 |
|
|
$ |
32.54 |
|
|
$ |
31.97 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets (at year-end)
|
|
$ |
1,697,883 |
|
|
$ |
1,730,183 |
|
|
$ |
1,494,748 |
|
|
$ |
1,460,532 |
|
|
$ |
1,384,280 |
|
Long-term
Debt (at year-end)(2)
|
|
|
463,897 |
|
|
|
413,894 |
|
|
|
403,892 |
|
|
|
337,889 |
|
|
|
343,886 |
|
Cumulative
Preferred Stock (at year-end)
|
|
|
21,027 |
|
|
|
21,027 |
|
|
|
21,027 |
|
|
|
21,027 |
|
|
|
21,027 |
|
Total
CH Energy Group Common Shareholders' Equity (at year-end)
|
|
|
533,502 |
|
|
|
523,534 |
|
|
|
523,148 |
|
|
|
512,862 |
|
|
|
503,833 |
|
(1)
|
This
summary should be read in conjunction with the Consolidated Financial
Statements and Notes thereto included in Item 8 - “Financial
Statements and Supplementary Data” of this 10-K Annual
Report.
|
(2)
|
Net
of current maturities of long-term
debt.
|
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” of this 10-K Annual Report and Note 5 - “Acquisitions,
Divestitures and Investments” of Item 8 - “Financial Statements and
Supplementary Data” of this 10-K Annual Report.
FIVE-YEAR
SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA(1)
(CENTRAL HUDSON)
(In
Thousands)
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
Operating
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
- Delivery
|
|
$ |
275,167 |
|
|
$ |
242,334 |
|
|
$ |
233,033 |
|
|
$ |
208,284 |
|
|
$ |
183,948 |
|
Electric
- Supply
|
|
|
261,003 |
|
|
|
365,827 |
|
|
|
383,806 |
|
|
|
295,624 |
|
|
|
337,046 |
|
Natural
Gas - Delivery
|
|
|
66,916 |
|
|
|
59,897 |
|
|
|
55,326 |
|
|
|
49,629 |
|
|
|
49,317 |
|
Natural
Gas - Supply
|
|
|
107,221 |
|
|
|
129,649 |
|
|
|
110,123 |
|
|
|
105,643 |
|
|
|
106,285 |
|
Total
|
|
|
710,307 |
|
|
|
797,707 |
|
|
|
782,288 |
|
|
|
659,180 |
|
|
|
676,596 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
76,338 |
|
|
|
67,344 |
|
|
|
71,406 |
|
|
|
70,956 |
|
|
|
70,791 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
|
32,776 |
|
|
|
27,238 |
|
|
|
33,436 |
|
|
|
34,871 |
|
|
|
35,635 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
Declared on Cumulative Preferred Stock
|
|
|
970 |
|
|
|
970 |
|
|
|
970 |
|
|
|
970 |
|
|
|
970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Available for Common Stock
|
|
|
31,806 |
|
|
|
26,268 |
|
|
|
32,466 |
|
|
|
33,901 |
|
|
|
34,665 |
|
Dividends
Declared to Parent - CH Energy Group
|
|
|
- |
|
|
|
- |
|
|
|
8,500 |
|
|
|
8,500 |
|
|
|
17,000 |
|
Change
in Retained Earnings
|
|
|
31,806 |
|
|
|
26,268 |
|
|
|
23,966 |
|
|
|
25,401 |
|
|
|
17,665 |
|
Retained
Earnings - beginning of year
|
|
|
118,944 |
|
|
|
92,676 |
|
|
|
68,710 |
|
|
|
43,309 |
|
|
|
25,644 |
|
Retained
Earnings - end of year
|
|
$ |
150,750 |
|
|
$ |
118,944 |
|
|
$ |
92,676 |
|
|
$ |
68,710 |
|
|
$ |
43,309 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets (at year -end)
|
|
$ |
1,485,600 |
|
|
$ |
1,492,196 |
|
|
$ |
1,252,694 |
|
|
$ |
1,215,823 |
|
|
$ |
1,126,106 |
|
Long-term
Debt (at year-end)(2)
|
|
|
413,897 |
|
|
|
413,894 |
|
|
|
403,892 |
|
|
|
337,889 |
|
|
|
343,886 |
|
Cumulative
Preferred Stock (at year-end)
|
|
|
21,027 |
|
|
|
21,027 |
|
|
|
21,027 |
|
|
|
21,027 |
|
|
|
21,027 |
|
Total
Equity (at year-end)
|
|
|
430,080 |
|
|
|
373,274 |
|
|
|
347,006 |
|
|
|
323,040 |
|
|
|
297,639 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
This
summary should be read in conjunction with the Consolidated Financial
Statements and Notes thereto included in Item 8 - “Financial
Statements and Supplementary Data” of this 10-K Annual
Report.
|
(2)
|
Net
of current maturities of long-term
debt.
|
|
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
INTRODUCTION
The
following Management’s Discussion and Analysis of Financial Condition and
Results of Operations is intended to help the reader understand CH Energy Group
and Central Hudson.
Please
note that the Executive Summary (below) is provided as a supplement to, and
should be read together with, the remainder of this Item 7 - “Management’s
Discussion and Analysis of Financial Condition and Results of Operations,” the
Consolidated Financial Statements, including the Notes thereto, and the other
information included in this 10-K Annual Report.
EXECUTIVE
SUMMARY
BUSINESS
OVERVIEW
CH Energy
Group is a holding company with four business units:
Business
Segments
(1)
Central Hudson’s regulated electric utility business;
(2)
Central Hudson’s regulated natural gas utility business;
(3)
Griffith’s fuel distribution business;
Other Businesses and
Investments
|
(4)
|
CHEC’s
investments in renewable energy supply, energy efficiency, an energy
sector venture capital fund and the holding company’s activities, which
consist primarily of financing its subsidiaries and business
development.
|
A
breakdown by business unit of CH Energy Group’s operating revenues of $0.9
billion and $1.1 billion for the years ended December 31, 2009 and 2008,
respectively, is illustrated below.
CH
Energy Group Revenue by Business Unit
|
(1)
|
A
portion of the revenues above represent amounts collected from customers
for the recovery of purchased electric and natural gas costs at Central
Hudson and the cost of purchased petroleum products at Griffith and
therefore have no material impact on net income. A breakout of
these components is as follows:
|
Electric
2009: 28% cost recovery revenues + 29% other revenues = 57%
Electric
2008: 32% cost recovery revenues + 21% other revenues = 53%
Natural
gas 2009: 12% cost recovery revenues + 7% other revenues = 19%
Natural
gas 2008: 11% cost recovery revenues + 6% other revenues = 17%
Griffith
2009: 21% commodity + 2% other revenues = 23%
Griffith
2008: 27% commodity + 2% other revenues = 29%
A
breakdown by business unit of CH Energy Group’s net income of $43.5 million and
$35.1 million for the years ended December 31, 2009 and 2008, respectively, is
illustrated below.
CH
Energy Group Net Income by Business Unit
(1) Includes
income from discontinued operations of $9,851 and $3,545,
respectively.
A
breakdown by segment of CH Energy Group’s total assets of $1.7 billion as of
both December 31, 2009 and 2008 is illustrated below.
CH
Energy Group Assets at December 31, 2009 and 2008, by Business Unit
As the
graphs above indicate, as of December 31, 2009 and 2008, 88% and 86% of CH
Energy Group’s assets were employed in the electric and natural gas businesses,
which are subject to regulation by the Public Service Commission (“PSC”) (as
discussed in more detail below). The remaining 12% and 14% of its
assets at December 31, 2009 and 2008 were employed in non-regulated
businesses. For the year ended December 31, 2009, CH Energy Group
derived 73% of its net income from the regulated electric and natural gas
business and 27% of its net income from the non-regulated
businesses.
Strategic
Overview
CH Energy
Group’s objective is to deliver value to its shareholders through current
income, in the form of quarterly dividend payments, and through share price
appreciation that is expected to result from earnings growth over the long
term. CH Energy Group seeks to employ its resources in a manner that
supports steady growth. CH Energy Group seeks to invest in projects
that have risk and volatility profiles over the long-term that are similar to
Central Hudson. CH Energy Group seeks to achieve this result through
careful risk management and by regularly considering a range of strategies that
include: acquisitions, operating efficiency improvements, capital structure,
allocation of capital to each business unit, entry into new lines of business,
and divesting all or portions of existing lines of business. The
particular strategy CH Energy Group employs from this range of options is
periodically reviewed by management. Factors that Management
considers in its decision-making include changes in the internal and external
environment as well as the expected significance of each strategy to CH Energy
Group’s ability to achieve its objective.
In
pursuit of its objectives, during 2009 CH Energy Group continued investing in
the regulated electric and natural gas businesses of Central Hudson, divested
selected fuel oil delivery assets of Griffith, and invested in its renewable
energy portfolio. In 2010, CH Energy Group intends to continue to invest in
Central Hudson’s infrastructure, review opportunities for Griffith to expand its
service offerings, reduce costs and make selected tuck-in acquisitions, explore
additional wind and landfill gas projects, explore divestiture of non-core
assets, and evaluate new growth opportunities in all of its business
units.
Central
Hudson continued to invest in replacing aging infrastructure, upgrading the
electric grid to enhance service for its customers, and making capital
investments to reduce operational expenses. While load growth was minimal in
2009, total infrastructure investments were still substantially higher than
annual depreciation, which resulted in a net increase to Central Hudson’s rate
base. Central Hudson is permitted by its regulators to recover its
cost of capital on invested rate base. Infrastructure investments are
expected to continue to exceed annual depreciation for the foreseeable future
increasing rate base, and providing the basis for earnings growth over the long
term.
At
Griffith, the suspension of acquisitions that began in 2008 as a result of
unprecedented energy price volatility was continued throughout
2009. During this time, Management conducted a review to determine
the appropriate scale of Griffith within CH Energy Group and to determine the
best strategy for Griffith to deliver long-term value to CH Energy Group’s
shareholders. Following completion of this review, on December 11,
2009, Griffith sold approximately 43% of its assets, consisting of its
operations in Rhode Island, New York, New Jersey, Connecticut, Massachusetts and
Pennsylvania, where customers tended to have higher annual usage but exhibited
higher sensitivity to price. Management believes this divestiture
will reduce Griffith’s exposure to wholesale oil prices and resulting volatility
that Griffith’s operations have on CH Energy Group’s consolidated earnings and
cash flow. The remaining Griffith business in the Mid-Atlantic region
offers service to its core customers who tend to favor full-service and change
suppliers less frequently. Management also announced its intent to
resume its prior acquisition strategy to expand through selected “tuck-in”
acquisitions in the Mid-Atlantic region. This growth strategy focuses on
acquiring and retaining full-service customers in geographic areas that overlap
Griffith’s existing operations.
In 2009,
CHEC continued to invest in renewable energy projects, with a focus on projects
that are expected to exhibit risk and volatility profiles over the long term
that are similar to those of Central Hudson. During 2009, CHEC
invested $2.6 million of its total investment of $5.5 million in the
construction of the CH-Auburn landfill gas project, which became operational in
January 2010. In the second quarter, CHEC invested $5.5 million in
the CH-Greentree landfill gas project that was substantially complete in the
second quarter, and in the fourth quarter, CHEC announced its commitment to
invest approximately $50 million in the CH Shirley Wind project, which is
expected to be in service at the end of 2010. These investments are discussed in
more detail under Other Businesses and Investments.
Going
forward, Management will continue reviewing its businesses with the goal of
increasing shareholder value. Specifically, Central Hudson will
continue investing in its infrastructure; Griffith plans to explore
potential new service offerings to existing customers, and CHEC plans to pursue
additional investments with risk and volatility profiles that are similar to
those of Central Hudson. Additionally, CH Energy Group may evaluate
opportunities for additional business acquisitions or
divestitures. Based on current market conditions, the Company does
not intend to invest in new ethanol projects.
To
partially finance the growth in its unregulated businesses, CH Energy Group
privately placed $50 million of senior unsecured notes in 2009, its first
non-utility long-term debt. This debt is expected to be serviced by
non-utility operations and investments. With the continued growth of
Central Hudson and with the development of new opportunities at CHEC, CH Energy
Group will periodically consider whether it is appropriate to issue additional
shares of common equity as part of the Company’s financing program.
CENTRAL
HUDSON
Business
Overview and Source of Earnings
Central
Hudson delivers electricity and natural gas to approximately 300,000 electric
customers and 74,000 natural gas customers in a defined service territory in the
Mid-Hudson Valley region of New York State.
The rates Central Hudson
charges its customers are set by the PSC. These rates are
designed to recover the cost of providing safe and reliable service to Central
Hudson’s customers and to provide a fair and reasonable return on the capital
invested by shareholders.
Central
Hudson’s earnings are derived primarily from the revenue it generates from
delivering energy to its customers. Central Hudson also procures
supplies of electricity and natural gas for customers who have not chosen to
utilize an independent third party supplier. The PSC has authorized
Central Hudson to recover the costs of the electric and gas commodities from
customers, without earning a profit on the commodity costs.
Strategic
Overview
Central
Hudson’s mandate to provide service to its franchise territory creates a need
for Central Hudson to balance the objectives and concerns of a diverse set of
stakeholders, including customers, regulators, and shareholders. By carefully
managing costs, maintaining acceptable levels of reliability and customer
service, and developing productive working relationships with regulators,
Central Hudson can deliver the greatest value to shareholders. Central Hudson’s
Management seeks to increase shareholder value by obtaining current recovery of
Central Hudson’s costs of providing service to its customers, earning a fair
return on its investments in infrastructure to meet increasing customer needs
for energy and the quality of service, and obtaining an allowed Return on Equity
(“ROE”) that provides a fair and reasonable return for
shareholders. Because each of these strategies requires regulatory
approval, Central Hudson will continue to build on its relationships with its
regulators. The Company is advocating for the opportunity to invest
in renewable energy projects that would be included in its rate
base. It is also considering how to promote other investment
opportunities that may include Smart Grid, smart meters, transmission upgrades,
and infrastructure to further enhance reliability.
Cost
Management and Process Improvement
Recognizing
the importance of service, reliability and affordable rates to its customers,
Central Hudson has a strong history of putting innovation to work to improve its
operations and reduce costs. This focus has been particularly strong
as the economy has struggled during 2008 and 2009. Across the
company, Central Hudson employees found innovative ways to save time and money
while improving reliability and customer service. Some examples of
these efforts include:
|
·
|
Using
meters that can be read from a distance, increasing meter readers’
productivity
|
|
·
|
Installing
monitoring equipment that provides employees the ability to identify and
address operating problems before they can cause an interruption in
service to customers
|
|
·
|
Using
recycled materials - which are less expensive and more environmentally
friendly than the more common alternative of sand or crushed stone - to
refill trenches after completing underground
work
|
|
·
|
Using
GPS technology to optimize the efficiency of scheduling field
employees
|
|
·
|
Using
scanning technology to more efficiently track and reduce
inventories
|
|
·
|
Implementation
of a web-based tool for customers to identify outages and monitor
restoration efforts following a loss of power from
storms
|
|
·
|
Using
technology that allows a greater number of software programs to run on the
same hardware
|
|
·
|
Increasing
the use of electronic bills and payment
options
|
|
·
|
Challenging
vendors to reduce costs
|
These
examples are representative of Central Hudson’s goal of continuously improving
its operations for the benefit of customers and shareholders alike.
Delivery
Rate Increase
Central
Hudson filed a rate increase request with the PSC in July 2008. A
final, amended Order Adopting Recommended Decision with Modifications was issued
by the PSC on June 26, 2009, for rates that went into effect July 1,
2009. The Order includes an annual $39.6 million and $13.8 million
increase in electric and gas delivery rates, respectively, a 10.0% allowed ROE
and a common equity ratio of 47%. The impact of the electric rate
increase was moderated for customers for the July 1, 2009 to June 30, 2010 rate
year with a $20 million electric bill credit from net regulatory electric
liability balances which have been set aside for this
purpose. Additionally, the Order approved electric and gas Revenue
Decoupling Mechanisms (“RDMs”) which are primarily intended to eliminate the
disincentive to promote energy efficiency associated with the volumetric rate
structures and will also serve to prevent the significant revenue shortfall such
as that which occurred during the 2006-2008 period. As discussed in
more detail under PSC Proceedings, Central Hudson filed a Petition for Rehearing
on the PSC’s disallowance of certain costs. Although the outcome of
this petition cannot be predicted, it is not expected to have a material impact
on Central Hudson’s earnings or cash flows. A particular challenge to
Central Hudson’s ability to earn its authorized ROE is the levels of
uncollectible expense compared to amounts recovered through the rate mechanism
for this item. The uncollectible expense incurred by the Company for
2009 was 50% higher than 2008. A significant portion of this expense
is due to bad debt write-offs above those included in
rates. Management believes this increase in uncollectibles is due to
unfavorable economic conditions, particularly the high unemployment
rate. Central Hudson’s Management is working to control its costs in
a manner that will minimize the impact that the cost disallowances, the PSC
imposed austerity adjustment and undercollection for uncollectible accounts have
on Central Hudson’s ability to earn its 10.0% authorized ROE. In
response to the challenging economy the country has been in since 2008, the PSC
issued a notice of austerity directing each New York utility to identify costs
that may be reduced without impairing the ability to provide safe and adequate
services. These issues are expected to continue to have a direct
impact on Central Hudson’s earnings, the magnitude of which Management cannot
predict. For the rate year ended June 30, 2009, the Company’s bad
debt write-offs exceeded the amount recovered through rates by $3.3
million. The Company has received approval from the PSC to defer $0.5
million of this amount for future recovery. A petition requesting
authority to recover the remaining $2.8 million was filed with the PSC on
October 30, 2009. Management cannot predict the outcome of this
petition. If the PSC approves the petition, upon future recovery,
Central Hudson’s cash flows would increase. If the PSC does not
approve the petition in full, Central Hudson’s expenses would increase by the
amount of the petition denied by the PSC.
While
revenues from the electric and gas delivery rate increase approved by the PSC in
June 2009 provided the Company with rate relief from the conditions of the
recently expired three-year rate plan, these revenues are projected to be
insufficient for the Company to recover the ongoing costs of providing electric
and gas delivery service beyond June 30, 2010, despite the Company’s efforts to
offset these rate pressures through internal productivity gains and cost
efficiencies. The Company faces a number of cost increases broadly
categorized as regulatory mandates and externally imposed costs, low and slowing
customer growth and declining use per customer, increased operating expenses and
employee costs, ongoing need for electric and gas infrastructure improvements,
rising property taxes, increasing uncollectibles and increased cost of
debt. As a result of these cost increases, on July 31, 2009, Central
Hudson filed an electric and natural gas rate case with the PSC seeking to
increase, effective July 1, 2010, the electric and natural gas delivery rates
which have been in effect since July 1, 2009. The filing proposed
one-year increases of $15.2 million and $3.9 million of electric and natural gas
delivery rates, respectively.
The
filing also seeks to recover projected expenditures associated with MGP
remediation, stray voltage testing of Central Hudson owned and municipally owned
electric facilities, tree trimming of distribution lines and enhanced electric
transmission ROW management practices. This filing has resulted in
the Joint Proposal of Settlement, described below.
On
February 3, 2010, Central Hudson, PSC Staff, and Multiple
Intervenors served on all parties to the case a negotiated three year
settlement Joint Proposal ("2010 Joint Proposal") to be considered by the
PSC. The PSC may accept, reject, or modify the 2010 Joint
Proposal. Under the terms of the 2010 Joint Proposal, an increase to
electric delivery revenues of $30.2 million over a three-year term is to be
phased in with annual electric delivery rate increases of approximately $11.8
million as of July 1, 2010; $9.3 million as of July 1, 2011; and $9.1 million as
of July 1, 2012. A natural gas delivery revenue increase of $9.7
million is to be phased-in over three years with natural gas delivery rate
increases of $5.7 million as of July 1, 2010, $2.4 million as of July 1, 2011
and $1.6 million as of July 1, 2012. The impact on the customers of
the electric rate increase will be moderated by continuing the credit to
customers' bills that began with the 2009 Rate Order. These credits totalled $20
million in the current rate year and will be reduced to $12 million and $4
million in rate years 1 and 2 of the 2010 Joint Proposal, respectively, after
which the credit will end.
The 2010
Joint Proposal recommends delivery rates based on a return on equity of 10.0%,
with earnings up to 10.5% retained by Central Hudson, earnings in excess of
10.5% up to 11.0% shared equally between customers and Central Hudson, and
earnings in excess of 11.0% up to 11.5% shared 80/20 between customers and
Central Hudson. Earnings in excess of 11.5% will be shared 90/10
between customers and Central Hudson. Rates would be based on a
capital structure that includes a 48% common equity ratio, an increase from the
current 47%.
Management
cannot predict the outcome of the proceeding. Other provisions in the
2010 Joint Proposal are discussed in greater detail in the New Electric and
Natural Gas Rate Filing Request discussion within the Other Regulatory Matters
Section.
All of
the provisions of the 2010 Joint Proposal are subject to final PSC approval,
which could occur at the earliest at its May 13, 2010, session.
Rate
Base Growth
Management
continually pursues opportunities to invest in Central Hudson’s infrastructure
when doing so will provide both appropriate benefits to customers and a
reasonable return to shareholders. Management anticipates
considerable change in energy policy at both the federal and state levels over
the next several years. Attempts by government to stimulate the
economy by funding or incenting infrastructure investment, as well as efforts to
increase energy efficiency and the proportion of electric generation from
renewable sources, are potential sources of opportunity for Central
Hudson.
Central
Hudson continues to be actively engaged in the New York State energy planning
process with the goal of achieving political and regulatory support for
improving the state’s energy delivery infrastructure. One of Central
Hudson’s actions in this regard is active participation along with other New
York State transmission owners in planning the enhancement of the State’s bulk
transmission system. This initiative, named State Transmission
Assessment and Reliability Study (“STARS”), will examine the bulk transmission
system to identify infrastructure replacement needs and accommodate the addition
of renewable generation sources. A recent condition assessment
conducted by the transmission system owners concluded that the current system
needs to be modernized and expanded, which will require significant investments
for many years.
Central
Hudson is also seeking to increase utility involvement in energy efficiency and
renewable electricity production. Specifically, Central Hudson is
seeking authorization for regulated utilities to own electric generation
facilities powered by renewable resources. Such investments would
increase the rate base upon which shareholders earn a return. As
discussed in more detail under “Regulatory Matters,” Central Hudson is actively
involved in the state’s efforts to increase energy efficiency, and the PSC has
recently authorized Central Hudson to implement six of its programs proposed in
the energy efficiency proceeding discussed under “Regulatory
Matters.” These programs provide the opportunity to earn $1.8 million
in pre-tax incentives over the next three years, but also subject Central Hudson
to possible penalties of approximately the same amount for
non-performance.
These
opportunities for 2010 represent an important avenue for Central Hudson to
expand its scale and scope.
Access
to Capital
The
capital-intensive nature of Central Hudson’s business and its obligation to
serve all customers in its franchise area require continuous access to capital
on reasonable terms. Central Hudson has historically maintained a
strong capital structure and excellent liquidity. Over the past year,
Central Hudson has increased its equity ratio by 4.7%, from 43.7% at December
31, 2008 to 48.4% at December 31, 2009. Despite challenging financial
markets, the Company maintained access to $125 million of committed credit and
various uncommitted credit lines and issued long-term debt in the public markets
at competitive rates. Access to capital is expected to remain a vital
component of Central Hudson’s strategy in 2010 and beyond.
GRIFFITH
Business
Overview and Source of Earnings
During
the majority of 2009, Griffith provided petroleum products and services to
approximately 103,000 customers in a market area comprised primarily of parts of
Connecticut, Delaware, Washington, D.C., Maryland, Massachusetts, New Jersey,
New York, Pennsylvania, Rhode Island, Virginia, and West Virginia. As
a result of its recent sale of operations in certain geographic locations,
Griffith now provides its products and services to approximately 57,000
customers in Delaware, Washington, D.C., Maryland, Pennsylvania, Virginia and
West Virginia. Griffith’s revenues, cash flows, and earnings are
derived from the sale and delivery of heating oil, gasoline, diesel fuel,
kerosene, and propane and from the installation and maintenance of heating,
ventilating, and air conditioning equipment.
Below is
a breakdown of Griffith’s gross profit from continuing operations of $53.6
million and $55.5 million by petroleum product and by service and installations
for the years ended December 31, 2009 and 2008, respectively.
Griffith
Gross Profit by Product & Service Line
Gross
profits from discontinued operations of $35.1 million and $38.9 million by
product and service lines for the years ended December 31, 2009 and 2008,
excluded from the chart above are as follows:
Heating
Oil: $19.2 million, or 55% for 2009 and $22.5 million, or 58% for
2008
Motor
Fuels: $3.2 million, or 9% for 2009 and $3.4 million, or 9% for
2008
Other
Fuels: $1.3 million, or 4% for 2009 and $1.2 million, or 3% for
2008
Service
& Installations: $10.9 million, or 31% for 2009 and $11.2 million, or 29%
for 2008
Other:
$0.5 million, or 1% for 2009 and $0.6 million, or 1% for 2008
Strategic
Overview
Griffith’s
Management seeks to position the company as a full-service provider in the
Mid-Atlantic region, offering automatic fuel delivery and integrated equipment
installation and servicing to residential and commercial customers who use
heating oil and motor fuels. Customers have reacted positively to
this premium service offering, which has resulted in expanding
margins. Management strives to further improve profitability by
continuously enhancing operational efficiencies. The sale of
Griffith’s Connecticut, Rhode Island and Pennsylvania assets, where average use
per customer was higher, but customers were generally more price-sensitive,
reduces CH Energy Group’s overall exposure to petroleum price volatility and
allows Griffith to focus on growing the profitability, and potentially its
market share in the Mid-Atlantic region.
Earnings
and Cash Flow
2009
Results: Griffith’s 2009 results support CH Energy Group’s
objectives of increasing shareholder value through higher
earnings. Griffith contributed $0.76 per share to CH Energy Group’s
earnings, an increase of $0.50 per share from 2008. The increase
includes $0.40 per share from the gain on the divestiture and $0.10 per share,
or 38% from 2008’s $0.26 per share, from operations. After taking
into account higher tax obligations at the holding company as a result of the
gain, the divestiture contributed a net $0.34 per share to CH Energy Group’s
earnings. In addition to contributing $0.34 per share to CH Energy
Group’s 2009 earnings, the divestiture also resulted in the accelerated recovery
of approximately $10 million of goodwill. That recovery of goodwill
reduces the book value of the remaining portion of Griffith’s
businesses. The $0.10 per share increase from the operations of the
business is particularly significant because it includes a $0.14 per share
increase in earnings related to the portion of the business that Griffith
retained. Operating results improved due to Griffith’s continued
reductions of operating expenses as a result of cost control measures initiated
in 2008 and are indicative of the value Griffith’s Management expects to be able
to deliver to shareholders. These positive variances were partially
offset by the unfavorable impact of reduced volumes as residential and
commercial customers continued to use less fuel in response to the weakened
economy.
In 2008
and 2009, the number of Griffith’s fixed and capped customers
fell. The margin per gallon for these customers is typically below
the margins earned in full service variable price customers. To
achieve this migration of customers, Griffith restructured its pricing programs
to encourage customers to select variable pricing instead of price protected
contracts. This provided Griffith with more flexibility to adjust to
changes in market prices, reducing its total hedging costs. With the
divestiture, the percentage of fixed and capped customers as a percentage of
total customers dropped from approximately 10% to less than 2%.
Looking
Forward: Management believes that Griffith’s focus on its
Mid-Atlantic operations, its strong brand name, effective cost management
practices and reputation for high quality and dependable service position it
well for future contributions to CH Energy Group’s earnings and cash
flows.
Management
plans to operate the business to produce long-term value including resuming
tuck-in acquisitions in the Mid-Atlantic region and exploring various other
growth opportunities such as offering new services to existing customers and
non-traditional customers.
OTHER BUSINESSES AND
INVESTMENTS
Business
Overview and Source of Earnings
In
addition to Griffith, CHEC derives earnings through investments in renewable
energy supply, energy efficiency and an energy sector venture capital
fund. This business unit also includes the holding company’s
activities, which consist primarily of financing its subsidiaries and business
development.
Strategic
Overview
CHEC’s
investment objectives are to increase earnings and cash flow with a heightened
focus on investments with stable and predictable income streams and cash
flows. The renewable energy markets provide opportunities that fit
well with these objectives. CHEC’s investments in wind energy
projects and landfill gas projects are indicative of the type of investment CH
Energy Group intends to pursue in the future. However, there are
inherent risks associated with the construction and operation of these types of
projects including the ability to efficiently develop and operate the assets,
the successful and timely completion of the projects, counterparties to
contracts not performing and competition from other and new sources of
generation. While none of these risks have surfaced, Management
considers these risks when assessing these types of investments for the
future. The Shirley Wind project also has the risk of actual wind
speeds being less than expected. In addition, CHEC’s investment in
Cornhusker could face a risk that the expansion of plant capacity could be
delayed. At the current time, CHEC does not expect to make further
investments in ethanol projects, because of the uncertainty and volatility
associated with the commodities in these industries. A summary of
CHEC’s current investments is provided below.
Managing
and Growing Our Investments
During
2009, CHEC’s investments contributed $0.03 to CH Energy Group’s earnings per
share and provided cash flow of $6.3 million before any dividend payments made
to CH Energy Group.
Biomass: During
2009, CHEC’s Lyonsdale biomass investment earned $0.9 million, $0.4 million less
than the prior year primarily because of an extended outage to make certain
repairs to the plant.
Wind: During
2009, CHEC’s CH-Community Wind investment in two wind projects - one in
Pennsylvania and one in New Jersey – earned $0.2 million, the same as the prior
year. During 2009, CH Shirley, a wholly owned subsidiary of CHEC,
agreed to invest approximately $50 million for a 90% controlling interest in a
20-megawatt wind farm facility in Wisconsin. The project carries a
20-year power purchase agreement at pre-determined electric prices with
Wisconsin Public Service Corporation for the electric output of the wind farm’s
eight wind turbines. This project is expected to contribute
attractive, reasonably stable and predictable earnings and cash
flows. Construction is expected to be completed in the fourth quarter
of 2010.
Ethanol: CHEC’s
ethanol projects were challenged by continued low margins leading to a write off
of a $1.2 million development loan to Buckeye Biopower. Cornhusker
results were similar to the prior year, although margins improved during the
fourth quarter.
CHEC made
a $1.2 million loan to Buckeye Biopower, LLC ("Buckeye") in June 2007 for
development of a corn-ethanol plant. Low margins for corn-to-ethanol plants and
credit market conditions have made the arrangement of construction financing
difficult. As a result, Management established a reserve for the full
outstanding loan balance in the first quarter of 2009. Due to
management’s assessment of the developer’s ability to pay the outstanding
balance, the full balance was written-off against the reserve in the fourth
quarter of 2009.
The
Energy Independence and Security Act of 2007 increases requirements for blending
ethanol with gasoline from 10.5 billion gallons in 2009 to 12 billion gallons in
2010.
Cornhusker
Energy Lexington, LLC ("CEL") has a requirement as part of its senior note
agreement for completing the expansion of plant capacity and output from 40
million gallons per year to 57.5 million gallons per year by December 31, 2009.
Construction of the expansion of the plant's capacity was substantially complete
by that date. The output testing achieved the capacity required for a 24-hour
period, but it was unable to be sustained for the full 72-hour timeframe
required. Management believes additional equipment upgrades and adjustments
would be necessary to achieve this requirement. CEL has requested a waiver from
this requirement from the senior note holder. As of February 10, 2010, the
senior note holder has had the ability to accelerate all amounts due under the
senior note and has not done so. Management cannot predict the outcome of these
negotiations or the senior note holder's actions regarding its rights under the
senior note agreement,
however, based on current capacity and market conditions, CEL expects to
generate cash from operations to fund capital expenditures and continue to make
required debt and principal payments. As such, Management
believes it is not probable that the senior note holder will accelerate amounts
due under the note. CEL is current on all payments of principal and
interest due under the senior note agreement and in compliance with all other
terms of the senior note agreement. Management believes CHEC's
investment in Cornhusker Holdings is not impaired as of December 31, 2009 based
on Management’s intent and ability to hold the investments until fully
recovered, as well as an analysis of forecasted cash flows, which indicates all
amounts are recoverable. Management will continue to monitor the results of
CEL. If any of the assumptions within the forecasted cash flow were
to change significantly, Management would perform a reassessment of the
recoverability of its investment at that time.
Despite
the recent improvement in margins, the ethanol industry remains volatile, and
CHEC is not planning to invest in additional ethanol projects under such
conditions.
Landfill
Gas: Management successfully renegotiated the Energy Services
agreement for the Auburn landfill gas project on March 31, 2009 and the project
will utilize methane gas generated by the City of Auburn landfill to produce and
sell electricity to the City. The plant began operation in January
2010.
CHEC’s
wholly owned subsidiary, CH-Greentree, entered into an agreement in April 2009
to develop, construct and own a molecular gate system to be leased to Greentree
Landfill Gas Company, LLC (“Greentree”) and installed and operated at
Greentree’s currently operating landfill gas processing plant at the Greentree
landfill facility in western Pennsylvania. The molecular gate is
being used to remove nitrogen from landfill gas produced by the Greentree
facility thereby increasing its energy content and allowing Greentree to sell
more of its gas output. The term of the lease is seven years and
construction was substantially complete on June 30, 2009. This
investment is expected to provide stable, predictable earnings and cash flow as
the quarterly lease payments are fixed for the next seven years.
2009 IN
REVIEW
Annual
earnings for CH Energy Group totaled $2.76 per share in 2009, an increase of
$0.54 per share from the $2.22 per share posted in 2008.
The 2009
earnings reflect an excellent recovery from 2008, a very difficult year for CH
Energy Group’s earnings. Central Hudson’s new rate plan approved by
the PSC, which took effect July 1, 2009, corrected a misalignment of costs and
revenues for the regulated business. Additionally, in the fourth
quarter of 2009, Griffith completed a successful partial divestiture, which
contributed $0.34 per share to corporate earnings.
The
challenging economic conditions that began in 2008 continued to impact Central
Hudson’s customers’ ability to pay their bills in 2009 and resulted in higher
write-offs and reserves for uncollectible accounts. Management
believes the economy has also impacted increased customer conservation resulting
in a decline in sales volumes for Griffith’s fuel distribution
business. Management has continued to implement operational
efficiencies and cost reductions in an effort to reduce expenses and increase
productivity.
Central
Hudson
Central
Hudson's contribution to earnings per share was $2.02 per share, an increase of
$0.35 per share over the $1.67 per share posted in 2008. The improvement is due
primarily to improved cost recovery through delivery rates, which accounted for
$0.88 per share of the increase ($0.22 per share of which was from the new RDMs
that went into effect on July 1, 2009). These delivery rates are
designed to cover higher operational expenses, including depreciation,
tree-trimming, property and other taxes and higher interest expense and carrying
charges. The increases in these costs over 2008 totaled $0.35 per
share, or nearly 40% of the increased revenue. Higher write-offs and
increased reserves for uncollectible accounts ($0.18) per share represented
an extraordinary expense and, as such and in accordance with regulatory
practice, Central Hudson has deferred the incremental expense over the amount
recovered through rates totaling $0.13 per share and requested
authorization for recovery from the PSC. The absence of major storms
and the resulting lower expense of restoring service to electric customers
contributed $0.09 per share to year-over-year
performance.
Griffith
Griffith
contributed $0.76 per share in 2009 as compared to $0.26 per share in
2008. This increase was primarily attributable to the sale of
operations in certain geographic locations, which accounted for $0.40 per share
of Griffith’s increase in earnings. Customer conservation continued
to have a negative impact on sales ($0.21) per share, but was offset by the
favorable impacts of weather of $0.11 per share, higher margins of $0.02 per
share, and lower uncollectible accounts of $0.04 per share. Continued
operational cost reductions implemented by Management totaling $0.11 per share
was the primary driver of the year-over-year increase excluding the
sale.
Other
Businesses and Investments
CH Energy
Group (the holding company) and CHEC’s partnerships and other investments
resulted in a loss of ($0.02) per share in 2009, a decrease of ($0.31) per share
from 2008 for several reasons. Interest expense on the debt issued at
the holding company in 2009 to finance CH Energy Group’s unregulated businesses
reduced earnings by ($0.07) per share. Income taxes on the gain from
the Griffith sale lowered earnings by ($0.06) per share. The
write-off of the Buckeye investment lowered 2009 earnings by ($0.05) per
share. The operations of Lyonsdale decreased ($0.03) per share from
the prior year as a result of an extended plant outage incurred in
2009.
REGULATORY
MATTERS
ELECTRIC AND NATURAL GAS
RATE INCREASE
(Cases
08-E-0887 and 08-G-0888 - Proceeding on Motion of the PSC as to the Rates,
Charges, Rules and Regulations of Central Hudson Gas & Electric Corporation
for Electric and Gas Service)
Background: On July
31, 2008, Central Hudson filed an electric and natural gas rate case with the
PSC to increase, effective July 1, 2009, electric and natural gas delivery rates
which have been in effect since July 1, 2008, the final year of a three-year
rate plan that took effect on July 1, 2006.
Final Order: On
June 22, 2009, the PSC issued its Order Adopting Recommended Decision with
Modifications which was subsequently modified with an Errata Notice issued on
June 26, 2009 (“2009 Rate Order”). Components of the 2009 Rate Order
include:
|
·
|
Electric
and gas delivery increases effective July 1, 2009, of $39.6 million and
$13.8 million, respectively. The electric rate increase will be
moderated by a $20.0 million customer bill credit from an excess
depreciation reserve.
|
|
·
|
Common
equity ratio of 47% of permanent
capital.
|
|
·
|
Base
return on equity (“ROE”) of 10.0%.
|
|
·
|
RDMs
for both electric and gas delivery service. While the primary
purpose of the RDMs is to remove a disincentive for the Company to promote
energy efficiency to its customers, they should also serve to prevent a
significant revenue shortfall such as that which occurred during the three
year period of the rate plan which ended on June 30,
2009.
|
|
·
|
An
austerity expense savings imputation of $3.0 million ($2.4 million
electric and $0.6 million gas, respectively). The 2009 Rate
Order required the Company to supplement its June 15 austerity filing to
identify specific capital and expense reductions that will be used to
implement its austerity program (which is further discussed below in Case
09-M-0435).
|
|
·
|
Continued
funding for the full recovery of the Company’s current pension and OPEB
costs and continued deferral authorization for pensions, OPEBs, research
and development costs, stray voltage testing, MGP site remediation
expenditures and electric and gas supply cost recovery and deferral
treatment for variable rate debt.
|
|
·
|
New
deferral authorizations for: fixed debt costs; the costs to bring electric
lines into compliance with current height above ground requirements; and
the recently enacted New York State Temporary
Assessment.
|
|
·
|
Continuation,
with minor modifications, of the Company’s Electric Reliability, Gas
Safety and Customer Service performance
mechanisms.
|
|
·
|
Recovery
through offset against a deferred liability account (non-cash) of the $3.3
million in incremental storm restoration costs incurred from the December
2008 ice storm (which is further discussed
below).
|
Central
Hudson made its rates and tariffs compliance filing on June 30, 2009 to become
effective July 1, 2009. In addition, and as required by the 2009 Rate
Order, the Company filed a supplement to its austerity plan on July 7, 2009,
which identified the specific capital and expense reductions that would be used
to meet the austerity imputation reflected in the 2009 Rate
Order. Central Hudson also made two additional compliance filings on
September 21, 2009, with an implementation plan for the expansion of a Mandatory
Hourly Pricing program to a specific class of customers, and a proposed suite of
Economic Development programs. The Company also made a compliance
filing on January 20, 2010, with respect to a voltage specific electric loss
factor study.
The PSC
has not yet adopted the rates and tariffs on a permanent basis or acted on any
of these matters and no prediction can be made regarding the outcome at this
time.
PETITION FOR
REHEARING
(Cases
08-E-0887 and 08-G-0888 - Proceeding on Motion of the PSC as to the Rates,
Charges, Rules and Regulations of Central Hudson Gas & Electric Corporation
for Electric and Gas Service)
Background: On July
22, 2009, Central Hudson filed a Petition for Rehearing on certain portions of
the 2009 Rate Order. In addition to a technical correction and
request for clarification on the application of carrying charges, the petition
sought rehearing on the following:
|
·
|
The
accounting treatment and level of expense associated with the cost of
removal for gas main replacements.
|
|
·
|
The
disallowance of 50% of Central Hudson’s Directors and Officers
insurance.
|
|
·
|
Inadequate
recovery of non-MGP environmental
expenses.
|
|
·
|
Inconsistency
of the carrying charge rate for RDMs relative to other comparable deferred
items.
|
Central
Hudson pointed out that the impact of the above items results in Central Hudson
not having a reasonable opportunity to earn the allowed ROE approved in the 2009
Rate Order.
Potential
Impacts: The PSC has not yet acted on this Petition and no
prediction can be made regarding the outcome to this proceeding at this time,
however Management does not expect this to have a material impact on earnings or
cash flows.
NEW ELECTRIC AND NATURAL GAS
RATE FILING REQUEST
Background: On July
31, 2009, Central Hudson filed an electric and natural gas rate case with the
PSC seeking to increase, effective July 1, 2010 electric and natural gas
delivery rates, which have been in effect since July 1, 2009.
A summary
of the most significant components of the filing include:
|
·
|
A
proposed one-year increase of $15.2 million and $3.9 million of electric
and natural gas delivery rates,
respectively.
|
|
·
|
Common
equity ratio of 48% and a base return on equity (“ROE”) of
10.0%. The 10.0% ROE reflects the result of the PSC’s decision
on the Company’s allowed ROE in the 2009 Rate Order. Central
Hudson reserved its rights to file an update to increase or reduce the
requested rate of return should economic conditions change. The
current Rate Order permits a common equity ratio of 47% with an allowed
base ROE of 10.0%.
|
The
filing was made in order to align electric and natural gas delivery rates with
the projected costs of providing electric and gas service to our
customers. Factors contributing to the need for an increase in rates
include the following:
|
·
|
Ongoing
need for electric and natural gas system infrastructure
improvements
|
The
filing also seeks to recover projected expenditures associated with the
following:
|
·
|
Stray
voltage testing of Central Hudson owned and municipally owned electric
facilities
|
|
·
|
Distribution
line tree trimming
|
|
·
|
Enhanced
electric transmission right of way management
practices
|
PSC Staff
and Intervenor testimonies were filed on November 19, 2009 and Rebuttal
testimonies were filed on December 23, 2009. Under the settlement
track adopted in the proceeding, settlement discussions initiated in November
2009 and continued through January 2010.
On
February 3, 2010, a Settlement Joint Proposal, with the Company, PSC Staff and
Multiple Intervenors as signatories, establishing rates for three years
beginning July 1, 2010 (“RY1”), 2011 (“RY2”) and 2012 (“RY3”) was filed with the
PSC. The major components of the Joint Proposal
include:
|
·
|
Electric
delivery increases of $30.2 million over the three year term with annual
delivery rate increases of $11.8 million, $9.3 million and $9.1 million
effective July 1, 2010, 2011 and 2012, respectively. A natural
gas delivery rate increase of $9.7 million is to be phased in over three
years with annual delivery increases of $5.7 million, $2.4 million and
$1.6 million effective July 1, 2010, 2011 and 2012,
respectively. The electric rate increase will be moderated by
the continuation of the electric Bill Credit mechanisms from Case
08-E-0887 reduced from $20 million in the current rate year, to $12
million and $4 million in RY1 and RY2, respectively, after which the
credit mechanism ceases.
|
|
·
|
A
common equity ratio of 48% of permanent capital and a base return on
common equity of 10% earnings up to 10.5% retained by Central
Hudson. Earnings in excess of 10.5% up to 11.0% will be shared
equally between customers and Central Hudson, and earnings in excess of
11.0% up to 11.5% will be shared 80/20 between customers and Central
Hudson. Earnings in excess of 11.5% will be shared 90/10
between customers and Central
Hudson.
|
|
·
|
Continuation
of the existing RDMs, with minor modifications, that are currently in
place for both gas and electric
service.
|
|
·
|
Electric,
gas and common capital expenditures with deferral on any shortfalls in
capital expenditures spending as measured against the electric and gas net
plant targets as reflected in
rates.
|
|
·
|
Continuation
of the existing gas and electric supply cost recovery mechanisms, and
continued deferral authorization for pensions, OPEBs, research and
development costs, asbestos litigation, MGP site remediation expenditures,
the low income Enhanced Powerful Opportunities (“EPOP”) program, stray
voltage mitigation costs, General and Temporary State Assessment, and
transmission sag program.
|
|
·
|
Continued
deferral authorization for variable rate debt costs for the entire term,
with deferral on new fixed rate debt issuances in RY2 and
RY3.
|
|
·
|
A
new, shared property tax deferral, with differences shared 90/10 between
customers/Company, with the Company’s exposure (or gain) capped at 10
basis points of common equity
annually.
|
|
·
|
New
deferral authority for management audit costs (with a $200,000 annual rate
allowance) and costs related to the implementation of International
Financial Reporting Standards (“IFRS”) in RY2 and RY3, however, IFRS costs
are subject to a deferral cap of
$375,000.
|
|
·
|
New
deferral authority for any legislative, governmental, and PSC or other
regulatory actions (subject to a 2% of net income materiality
threshold).
|
|
·
|
Updated
allowance factors for electric and gas uncollectible expense, with new
factors and rate allowance based on the Company’s most recent history
through November 30, 2009, but without deferral authority for actual net
bad debt write offs in excess of the rate
allowance.
|
|
·
|
Full
funding support for continued transmission ROW maintenance and
distribution tree trimming funding of $36 million over the term of the
agreement, with a commitment to complete the first complete cycle of the
four year Modified Enhanced Trimming Program by December 31, 2011, with
deferral on any spending
shortfalls.
|
|
·
|
A
productivity adjustment of 1.5% of labor and related expenses for each of
the three rate years, with no other specified austerity
reductions.
|
|
·
|
Continuation
of existing performance mechanisms for electric reliability, gas safety,
and customer service performance mechanisms with penalties for
non-achievement.
|
|
·
|
Increased
funding for expansion of the Company’s low-income program, expanded to
serve an incremental 110 customers each year of the rate plan, with
increased bill credits in each of the three rate
years.
|
|
·
|
Additional
terms of the Joint Proposal include a storm restoration allowance set at
$5 million annually, Directors and Officers insurance expense recovery
increased from 50% to 70% and an Economic Development rate allowance
established in RY3 at $300,000.
|
Statements
in Support or Opposition to the Joint Proposal are due on February 12, 2010 and
settlement hearings, if needed, to address contested issues are scheduled for
February 25, 2010. A PSC Order regarding the Joint Proposal and
establishing a new three year rate plan is not expected until the second quarter
of 2010.
NEW YORK STATE TEMPORARY
ASSESSMENT
(Case
09-M-0311 - Implementation of Chapter 59 of the Laws of 2009 Establishing a
Temporary Annual Assessment Pursuant to Public Service Law §18-a(6)
Background: On
April 7, 2009, NYS enacted the NYS Budget of 2009-2010, which in part requires
the PSC to collect a Temporary State Energy and Utility Service Conservation
Assessment (“Temporary State Assessment”) from April 4, 2009 to March 31,
2014. On June 19, 2009, an Order was issued in the above proceeding
authorizing recovery by utilities of the revenues required for payments of the
Temporary State Assessment, including carrying charges, subject to
reconciliation over five years, July 1, 2009 through June 30,
2014. The Temporary State Assessment imposes a charge of 2% of gross
intrastate operating revenues, less the amounts assessed for the PSC General
Assessment to be collected from customers in a separately stated surcharge on
customer bills effective July 1, 2009. The Company submitted its
compliance filing in this proceeding on June 29, 2009.
DEVELOPMENT OF UTILITY
AUSTERITY PROGRAMS
(Case
09-M-0435 - Proceeding on the Motion of the PSC Regarding the Development of
Utility Austerity Programs)
Background: On May
15, 2009, the PSC issued a Notice directing each utility to closely examine its
capital expenditures, operation and maintenance expenses and any other expense
area over which it has discretion, to identify costs that may be reduced without
impairing the ability to provide safe and adequate service. The
Notice also directed each utility to report to the PSC by June 15, 2009
concerning actions taken by the utility since September 2008 to respond to the
need for austerity, the utility’s plans for austerity in the future, the
appropriate allocation of the austerity cost savings between customers and
shareholders, and the mechanisms proposed to deliver the customer portion of the
savings to customers as promptly as possible.
Notable
Activity:
2009
|
·
|
June
15, 2009 - Central Hudson filed its response, describing the financial
austerity conditions it had been operating under throughout the term of
the 2006 Rate Order, and identifying capital costs it may avoid or defer
to the next year and expense reductions that could be taken as further
austerity measures without impairing our ability to provide safe and
adequate service.
|
|
·
|
June
22, 2009 - The PSC incorporated $3 million in austerity reductions into
Central Hudson’s rates that were approved in the 2009 Rate Order for rates
beginning July 1, 2009.
|
|
·
|
July
7, 2009 - Central Hudson filed its required Supplemental Austerity filing
for PSC approval as a compliance filing in Cases 08-E-0887 and
08-G-0888. The filing identified electric, gas and common
capital reductions that equate to $980,000 of the $2.4 million electric
and $360,000 of the $600,000 gas Economic Austerity Imputations
established in the 2009 Rate Order. To address the balance of
the austerity imputation, Central Hudson proposed a total of $1.48 million
of gas and electric expense reductions to several expense items including
research and development activities; certain maintenance expenditures; and
informational and institutional advertising. Central Hudson
also proposed executive salary freezes during 2010 and funding the
allowance for the approved transmission enhanced infrastructure
maintenance program through charges to its remaining electric excess
depreciation reserve. None of the measures proposed by the
Company are expected to materially affect the Company’s ability to provide
safe and adequate service in the rate
year.
|
|
·
|
December
22, 2009 - The PSC issued an Order Approving Ratepayer Credits in this
proceeding, approving an austerity filing and specifying bill credits for
a utility other than Central Hudson. The Order directed
utilities to proceed to comply with any existing obligations and
commitments, and to further address austerity in any new rate filings, and
further directed utilities, until the current economic downturn reverses,
to employ as many cost-cutting measures as possible, including but not
limited to, training of employees in only safety or legally mandated
areas, freezing managerial salaries, foregoing managerial bonuses, and
limiting travel. The Order did not address Central Hudson’s
austerity plan or supplemental austerity plan compliance filing, or direct
any further action for Central
Hudson.
|
Potential
Impacts: The incorporation of the $3 million austerity
reduction into the 2009 Rate Order could result in Central Hudson earning less
than the 10.0% ROE allowed in the 2009 Rate Order.
OTHER
PSC PROCEEDINGS AND ADMINISTRATION INITIATIVES
CH Energy
Group and Central Hudson continue to monitor a number of generic and specific
regulatory proceedings. Neither CH Energy Group nor Central Hudson
can predict the final outcome of New York State’s energy policies, or the
following PSC proceedings.
ENERGY EFFICIENCY PORTFOLIO
STANDARD AND STATE ENERGY PLANNING
(Case
07-M-0548 - Proceeding on Motion of the PSC Regarding an Energy Efficiency
Portfolio Standard and Governor Paterson’s Executive Order issued April 9,
2008)
Background: Governor
Paterson affirmed his support for the previous administration’s goal of
substantially reducing electricity usage. In support of this goal,
the PSC is investigating various approaches to reduce customers’ demand for
energy and to provide utility incentives for meeting specified energy savings
targets.
Notable
Activity:
2008
|
Ø
|
Governor
Paterson issued an Executive Order establishing a State Energy Planning
Board and authorizing the creation and implementation of a State Energy
Plan (“SEP”).
|
|
Ø
|
Central
Hudson submitted its own comments on the draft scope of the State Energy
Plan and joined those submitted by the Energy Association of New York
State Member Companies’ comments. Central Hudson also provided
briefing papers to the SEP working group on pressing issues facing Central
Hudson for consideration in developing the
SEP.
|
|
Ø
|
Central
Hudson has filed comments with the PSC supporting the opportunity to
establish energy efficiency businesses, with corresponding opportunities
to contribute to the state energy goal of reducing electricity consumption
by 15% by 2015 and provide meaningful earnings for investors from energy
efficiency services.
|
|
Ø
|
The
PSC established energy efficiency targets to be achieved by individual
utilities through 2011 that included three utility administered fast track
programs and five fast track programs to be administered by the New York
State Energy Research and Development Authority
(“NYSERDA”). Central Hudson has filed its plans to implement
its programs with the PSC.
|
|
Ø
|
Effective
October 1, 2008, the PSC ordered the creation of a gas System Benefit
Charge and increased electric System Benefit Charges to invest in funding
these energy efficiency programs.
|
2009
|
·
|
On
January 7, 2009, Governor Paterson outlined various strategies and policy
goals in his State of the State address, including one of the most
aggressive clean energy goals in the country, with a goal for New York to
meet 45% of its electricity needs by 2015 (“45 x 15”) through improved
energy efficiency and clean renewable energy production. This would
be accomplished by expanding the Renewable Portfolio Standard from 25% by
2013 to 30% by 2015 and decreasing electric usage by 15% by
2015.
|
|
·
|
A
SEP Interim Report was issued for comment on March 31,
2009. Central Hudson filed comments on May 15, 2009 in support
of policies and efforts with potential to promote economic development and
job creation, foster private investment, increase the tax base, enhance
energy reliability, lower customer bills and protect public health, safety
and the environment. The 2009 Draft SEP was issued on August
10, and the Final 2009 State Energy Plan was issued on December 15,
2009. The plan adopts the following policy objectives: to
assure that New York has reliable energy and transportation systems, to
support energy and transportation systems that enable the State to
significantly reduce greenhouse emissions, to address affordability
concerns caused by rising energy bills and improve the State’s economic
competitiveness. The SEP is designed to also reduce health and
environmental risks associated with the production and use of energy
across all sectors and to improve the State’s energy independence and fuel
diversity by developing in-state energy supply resources. The
strategies to achieve these policy objectives include producing,
delivering and using energy more efficiently, supporting development of
in-state energy supplies, investing in the energy and transportation
infrastructure, stimulating innovation in a clean energy economy and
engaging others in achieving the State’s policy
objectives.
|
|
·
|
The
PSC continues to work on additional issues of the energy efficiency
program design with participation by interested parties in various working
groups that include utility performance incentives, on-bill financing,
demand response and peak reduction and impacts on low-income and rental
customers.
|
|
·
|
Central
Hudson received approval through the Energy Efficiency Portfolio Standard
(“EEPS”) proceedings in January 2009 to implement electric energy
efficiency programs including a Residential Electric HVAC Electric program
and a Small Commercial Business program. These two programs
have been operational since May
2009.
|
|
·
|
Central
Hudson received approval through the EEPS proceedings in April 2009 to
implement a gas energy efficiency program for Residential Natural Gas HVAC
equipment. This program has been operational since July
2009.
|
|
·
|
Central
Hudson received approval through the EEPS proceedings in October 2009 to
implement a mid-size business efficiency program for commercial customers.
Central Hudson received approval through the EEPS proceedings in December
2009 to implement an appliance recycling program for residential customers
and an expanded Residential Electric HVAC equipment program. These
programs will be operational in
2010.
|
Potential Impacts: This PSC
proceeding could result in opportunities for increased earnings from incentives
associated with achieving energy efficiency targets or could result in negative
rate adjustments if the 70% performance criterion is not met. No
prediction can be made regarding the final outcome of this matter, however, any
earnings variations are not likely to be material.
REQUESTS FOR DEFERRAL OF
INCREMENTAL COSTS
(Case
09-M-0009 - Petition of Central Hudson Gas & Electric Corporation for
Authority to Defer Incremental Costs Related to the December 11, 2008 Ice
Storm)
Background and
Impact: In December 2008, Central Hudson filed a petition with
the PSC seeking approval to defer certain incremental and material storm
restoration expenses resulting from a severe ice storm in December 2008 that
disrupted service to approximately 72,000 of Central Hudson’s customers.
The initial petition sought PSC authorization to defer $3.1 million of
incremental expenses at December 31, 2008. An updated schedule
showing total costs incurred at $3.3 million was provided to the PSC as of March
31, 2009. The PSC authorized the deferral request and agreed that the
incremental storm costs would be included on the electric offset list for the
rate year in Central Hudson’s rate increase proceeding which was discussed
earlier in this section.
(Case
09-M-0140 - Petition of Central Hudson Gas & Electric Corporation for
Authority to Defer Bad Debt Net Write-Off Expense for the Year Ended December
31, 2008)
Background and
Impact: In February 2009, Central Hudson filed a petition with
the PSC seeking approval to defer $1.3 million of incremental electric and $0.5
million of gas net bad debt write-off expense incurred during the twelve months
ended December 31, 2008 over the amounts provided for in rates during that
period. In an Order issued August 24, 2009, the PSC granted authority
to defer the gas incremental bad debt write-off expense of $0.5 million, but
denied the Company’s deferral request for the electric incremental expense on
the basis that it did not meet the PSC’s materiality standard for
deferral.
(Case
09-G-0139 - Petition of Central Hudson Gas & Electric Corporation for
Authority to Defer Gas Leak Repairs Expense for the Year Ended December 31,
2008)
Background and
Impact: In February 2009, Central Hudson filed a petition with
the PSC seeking approval to defer $0.5 million of incremental gas non-labor
expense related to leak repairs incurred during the twelve months ended December
31, 2008 over the amounts provided for in rates during that
period. In an Order issued August 20, 2009, the PSC denied the
Company’s request concluding that the request did not meet the PSC’s requirement
that an item must be extraordinary in nature, in order to qualify for deferral
accounting treatment.
(Case
09-M-0788 - Petition of Central Hudson Gas & Electric Corporation for
Authority to Defer Gas Debt Net Write-Off Expense for the Twelve Months Ended
June 30, 2009)
Background: In
October 2009, Central Hudson filed a petition with the PSC seeking approval to
defer $2.4 million of incremental electric and $0.4 million of incremental gas
net bad debt write-off expense incurred during the twelve months ended June 30,
2009 (Rate Year 3 of the 2005 Rate Plan) over the amounts provided for in our
rates during that time period and over the gas deferral amount provided in Case
09-M-0140.
Potential Impacts: The $2.8
million of incremental gas and electric uncollectible expenses impacted Central
Hudson’s cash flows in 2008 and 2009. Central Hudson has recorded a
deferral of these incremental uncollectible expenses because it believes it has
made a strong demonstration in support of its request for authorization to defer
the incremental costs, consistent with criteria cited in recent PSC decisions
with positive outcomes regarding the ice storm and the gas portion of the 2008
net bad debt deferral petition. However, Management cannot predict
the outcome of this filing. If the PSC approves the petition, upon
future recovery, Central Hudson’s cash flows would increase. If the
PSC does not approve the petition in full, Central Hudson’s expenses would
increase by the amount of the petition denied by the PSC.
ADVANCED METERING
INFRASTRUCTURE
(Case
09-M-0074 - Proceeding on Matter of Advanced Metering
Infrastructure)
Background: On
February 13, 2009, the PSC issued an Order establishing minimum functional
requirements for Advanced Metering Infrastructure (“AMI”) in New York State and
creating a process for the development of a generic approach to the benefit/cost
analysis of AMI. The February 13, 2009 Order directed Central Hudson
to file an AMI pilot program within 60 days. The filing requirements
set forth by the PSC in the Order were designed to put utilities on track to
potentially receive federal financial assistance that may become available under
the American Recovery and Reinvestment Act of 2009’s (“ARRA”) Department of
Energy (“DOE”) administered program for Electricity Delivery and Energy
Reliability (“EDER”). The DOE may provide grants to successful
applicants under the EDER program in an amount equal to not more than 50% of the
costs of qualifying investments.
Notable
Activity:
2009
|
·
|
On
April 14, 2009, Central Hudson filed its AMI and Smart Grid Proposal with
the PSC.
|
|
·
|
On
April 14, 2009, the PSC issued its “Proposed Framework for the
Benefit-Cost Analysis of Advanced Metering Infrastructure”. A
Notice Seeking Comment on the proposal was also issued directing parties
to file comments on the generic benefit-cost framework by June 15,
2009.
|
|
·
|
The
Company filed comments on June 15,
2009.
|
|
·
|
In
an AMI / ARRA Order issued July 27, 2009, the PSC approved the Company’s
project proposals, which allows the Company to demonstrate on application
to the DOE, a ratepayer commitment, through cost recovery via a surcharge,
for the portion of eligible project costs not covered by the DOE
grant. This PSC funding approval was necessary for the Company
to proceed with its DOE filing.
|
|
·
|
On
August 4, 2009, Central Hudson submitted its grant application with the
DOE.
|
|
·
|
On
October 27, 2009, the DOE notified Central Hudson that the Company’s
application submitted in response to the Smart Grid Investment Grant
funding opportunity was not selected for
award.
|
|
·
|
Central
Hudson is currently reviewing and reconsidering its AMI / Smart Grid
position. No prediction can be made regarding future steps at
this time.
|
THE ARRA PROJECT
FUNDING
(Case
09-E-0310 - In the Matter of American Recovery and Reinvestment Act of 2009 -
Utility Filings for New York Economic Stimulus)
Background: ARRA
includes a DOE administered program for EDER. The sum of $4.5 billion
is appropriated by ARRA for the EDER program to be dispersed by DOE through a
competitive grant process. Additional funds may also be available
through programs such as Transportation Electrification.
Notable
Activity:
2009
|
·
|
On
April 2, 2009, the PSC sent a letter to the state’s regulated utilities
requesting a submittal of project lists from the utilities that are being
considered for application for ARRA
funding.
|
|
·
|
The
ARRA funding in some cases only covers a portion of the project costs and
therefore will require other funding sources which may include ratepayer
funds for which PSC approval is
required.
|
|
·
|
Regulated
utilities, New York Power Authority, Long Island Power Authority, and
NYISO, along with other parties collaborated on portions of project
filings.
|
|
·
|
Central
Hudson submitted its current project list to the PSC on April 17, 2009 and
filed its updated stimulus plans with the PSC on July 2,
2009. Included in this filing were Central Hudson’s Smart Grid
project, and two collaborative projects including the Statewide Capacitor
Installation and the Statewide Phasor Monitoring Unit (“PMU”)
Project. On May 29, 2009, Central Hudson applied for ARRA
funding under the “Clean Cities FY09 Petroleum Reduction Technologies
Projects for the Transportation Sector” funding opportunity in
collaboration with the New York and Lower Hudson Valley Clean Communities
and NYSERDA.
|
|
Ø
|
In
an AMI / ARRA Order issued July 27, 2009, the PSC approved Central
Hudson’s project proposals, which allows Central Hudson to demonstrate on
application to the DOE, a ratepayer commitment, through cost recovery via
a surcharge, for the portion of eligible project costs not covered by the
DOE grant. This PSC funding approval was necessary for Central
Hudson to proceed with its DOE
filing.
|
|
Ø
|
On
August 4, 2009, Central Hudson submitted its grant application with the
DOE.
|
|
Ø
|
On
October 27, 2009, the DOE notified Central Hudson that its application
submitted in response to the Smart Grid Investment Grant funding
opportunity was not selected for
award.
|
|
Ø
|
Central
Hudson is currently reviewing and reconsidering its AMI / Smart Grid
position. No prediction can be made regarding future steps at
this time.
|
|
·
|
Statewide
Collaborative Projects
|
|
Ø
|
On
August 6, 2009, the NYISO submitted its grant application for the
collaborative projects.
|
|
Ø
|
On
October 27, 2009, the DOE notified the NYISO that the Statewide Capacitor
Installation Project and the Statewide PMU Project have been approved and
awarded the NYISO $37.4 million of the total $75.7 million for the
projects. Central Hudson’s portion of this project is $1.6
million of the total $3.1 million for the Capacitor Installation Project
and $0.1 million of the total $0.2 million for the Statewide PMU
Project.
|
|
Ø
|
Central
Hudson is currently working with the NYISO and the other New York State
utilities on a Sub-Award Agreement for these
projects.
|
|
Ø
|
The
EEI has requested the DOE to seek clarification from the IRS and the
Treasury Department on the issue of the taxability of DOE grants under the
ARRA.
|
|
Ø
|
Central
Hudson has a tariff filing due on March 1, 2010 to define the mechanism
for recovery from customers for the portion of the projects not provided
through the DOE grant.
|
|
·
|
Plug-In
Hybrid Technologies
|
|
Ø
|
On
August 26, 2009, Central Hudson was notified that its grant request to
fund the incremental cost of Plug-In Hybrid and Hybrid technology for
eight heavy duty line trucks, and associated charging infrastructure
improvements was successful, and received $0.7 million to implement the
technologies in 2010 and 2011.
|
|
Ø
|
The
development of Plug-In Hybrid and Hybrid systems in regard to this grant
has the potential to reduce fleet diesel fuel consumption by approximately
10,000 gallons annually and associated emissions. No prediction
can be made regarding the final outcome of this matter; however, any
overall earnings impacts are not likely to be
material.
|
CENTRAL HUDSON GAS &
ELECTRIC FINANCING PETITION
(Case
09-M-0308 - Petition of Central Hudson Gas & Electric Corporation for
Authority to enter into multi-year committed credit agreements and issue and
sell long-term debt)
Background: On
March 26, 2009, Central Hudson filed a petition with the PSC seeking approval to
(a) enter into multi-year committed credit agreements to provide committed
funding to meet expected liquidity needs, in amounts not to exceed $175 million
in the aggregate and maturities not to exceed five years, and (b) approval to
issue and sell long-term debt, commencing immediately upon issuance of an order
regarding the petition, and from time to time through December 31, 2012, in an
amount not to exceed $250 million in the aggregate.
Notable
Activity:
2009
|
·
|
Central
Hudson filed its petition on March 26,
2009.
|
|
·
|
An
order approving the above requests was received on September 22,
2009.
|
Impacts: Central
Hudson’s ability to seek a higher level of committed credit could enable greater
liquidity to support forecasted construction expenditures, seasonality of the
business, volatile energy markets, adverse borrowing environments, and other
unforeseen events. The approval to issue and sell $250 million of
long-term debt will support Central Hudson’s ability to finance its construction
expenditures, refund maturing long-term debt, and potentially refinance $116
million of multi-modal long-term NYSERDA bonds, which are currently in an
auction rate interest mode.
MANAGEMENT
AUDIT
(Case
09-M-07674 - Comprehensive Management Audit of Central Hudson Gas & Electric
Business)
Background: In
August 2009, the PSC authorized the issuance of a Request for Proposal (“RFP”)
for an independent third-party consultant to conduct a comprehensive management
audit of Central Hudson’s construction planning processes and operational
efficiencies of its electric and gas businesses. The PSC is required
to audit New York utilities every five years. Audit work is expected
to get underway in the first quarter of 2010. A final report of the
consultant’s findings and recommendations is not expected until the second
quarter of 2011. No prediction can be made regarding the outcome of
the matter at this time.
NON-UTILITY LAND
SALES
For
further information regarding non-utility land sales, see Note 2 - “Regulatory
Matters.”
ELECTRIC RELIABILITY
PERFORMANCE
For
further information regarding Central Hudson’s electric reliability performance,
see Note 2 - “Regulatory Matters.”
CAPITAL
RESOURCES AND LIQUIDITY
CH ENERGY GROUP - CASH FLOW
SUMMARY
Changes
in CH Energy Group’s cash and cash equivalents resulting from operating,
investing, and financing activities are summarized in the following chart (In
Millions):
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Net
Cash Provided By/(Used In):
|
|
|
|
Operating
Activities
|
|
$ |
126.4 |
|
|
$ |
110.3 |
|
|
$ |
34.1 |
|
Investing
Activities
|
|
|
(55.7 |
) |
|
|
(88.7 |
) |
|
|
(73.7 |
) |
Financing
Activities
|
|
|
(17.1 |
) |
|
|
(13.1 |
) |
|
|
26.8 |
|
Net
change for the period
|
|
|
53.6 |
|
|
|
8.5 |
|
|
|
(12.8 |
) |
Balance
at beginning of period
|
|
|
19.8 |
|
|
|
11.3 |
|
|
|
24.1 |
|
Balance
at end of period
|
|
$ |
73.4 |
|
|
$ |
19.8 |
|
|
$ |
11.3 |
|
CH Energy
Group’s cash and cash equivalents increased by $53.6 million and $8.5 million
for the years ended December 31, 2009 and 2008 and decreased by $12.8 million
for the year ended December 31, 2007. For each of these periods, CH
Energy Group’s working capital needs were provided by cash from operations and
supplemented seasonally with short-term financing as needed. Capital
expenditures, investments and dividends in each year, as well as acquisitions in
2008 and 2007, were partially funded with cash from operations in excess of
expenses and working capital needs. The remainder of the funding for
investing activities was provided by long-term debt issued by Central Hudson and
CH Energy Group and supplemented in 2008 and 2007 with proceeds from the sale of
short-term investments. In December 2009, Griffith sold operations in
certain geographic locations. Net of adjustments, primarily for
working capital, CH Energy Group received $74.4 million. CH Energy
Group plans to use the majority of the after-tax proceeds to fund the
development of a 20-megawatt wind farm facility in Wisconsin (“Shirley Wind
project”).
Net cash
provided by operations was $126.4 million, $110.3 million and $34.1 million for
the years ended December 31, 2009, 2008 and 2007, respectively. Cash
provided by sales exceeded the period’s expenses and working capital needs in
each year, particularly in 2009 and 2008 when lower energy prices resulted in a
significant return of working capital. In the third quarter of 2009,
Central Hudson paid $17.7 million to the PSC for a new tax surcharge instituted
in April 2009; however, only $7.2 million of this surcharge had been collected
from customers through December 31, 2009. The required payment of the
full year assessment in the third quarter of 2009 increased Central Hudson’s
working capital needs in the current period, requiring financing. In
March 2010, Central Hudson will begin making bi-annual installments of
approximately $8.9 million for this surcharge and will collect the amounts from
customers in subsequent months. Central Hudson also paid $1.1 million
to the PSC for the bi-annual general assessment, of which $0.7 million had been
collected through December 31, 2009. Cash from operations was also
significantly impacted by an overpayment of federal income taxes in 2009, as
well as the receipt of a refund in 2007 for a prior year’s
overpayment. Central Hudson’s MGP site remediation costs in excess of
amounts recovered through rates and other regulatory mechanisms totaling $2.3
million, $2.8 million and $5.1 million in the years ended December 31, 2009,
2008 and 2007, respectively, also impacted cash from
operations.
Net cash
used in investing activities was $55.7 million, $88.7 million and $73.7 million
in the years ended December 31, 2009, 2008 and 2007,
respectively. Cash was used primarily to fund investments in Central
Hudson’s electric and natural gas systems. In June 2009, Central
Hudson closed on the purchase of certain real-estate in Kingston, NY resulting
in an increase of approximately $13 million to plant additions. Other
increases in capital expenditures at Central Hudson in each year relate
primarily to maintenance and proactive repairs to transmission and distribution
infrastructure to improve reliability. Additionally in December 2009,
CH Energy Group received $74.4 million in proceeds from the sale of select
operations of Griffith and invested approximately $12.3 million in the Shirley
Wind project. In 2008 and 2007, cash was also used for acquisitions
made by Griffith and was partially offset by net proceeds from short-term
investments held by the holding company.
Net cash
(used in) provided by financing activities was ($17.1) million, ($13.1) million
and $26.8 million in the years ended December 31, 2009, 2008 and 2007,
respectively. Financing activities have consistently included annual
dividends of $34.1 million. Central Hudson’s and Griffith’s cash
flows benefited from lower energy prices in 2009. Cash from
operations in excess of expenses and working capital needs was used to repay
short-term borrowings in 2009 and redeem Central Hudson’s long-term debt of
$20.0 million at maturity in January 2009. Central Hudson issued $24
million of 30-year notes in September 2009, the proceeds of which were used
primarily for the repayment of short-term debt incurred as interim financing for
capital expenditures. In addition, CH Energy Group sold $50 million
of 5-year notes in the second quarter of 2009 to provide long-term debt
financing for CHEC. In 2008, the use of cash overdraft due to
increased interest rates at Central Hudson and the proceeds of short-term debt
at Griffith were used to supplement working capital needs and to pay dividends
in that year. In 2007, net proceeds from the issuance of long-term
debt was used primarily to finance capital expenditures and net borrowings of
$29.5 million in short-term debt were used primarily to supplement the company’s
working capital needs and to pay dividends in that year.
CENTRAL HUDSON - CASH FLOW
SUMMARY
Changes
in Central Hudson’s cash and cash equivalents resulting from operating,
investing, and financing activities are summarized in the following chart (In
Millions):
|
|
Year
Ended December 31, 2009
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Net
Cash Provided By/(Used In):
|
|
|
|
Operating
Activities
|
|
$ |
107.5 |
|
|
$ |
68.1 |
|
|
$ |
32.8 |
|
Investing
Activities
|
|
|
(107.3 |
) |
|
|
(80.2 |
) |
|
|
(83.3 |
) |
Financing
Activities
|
|
|
2.1 |
|
|
|
11.0 |
|
|
|
52.4 |
|
Net
change for the period
|
|
|
2.3 |
|
|
|
(1.1 |
) |
|
|
1.9 |
|
Balance
at beginning of period
|
|
|
2.5 |
|
|
|
3.6 |
|
|
|
1.7 |
|
Balance
at end of period
|
|
$ |
4.8 |
|
|
$ |
2.5 |
|
|
$ |
3.6 |
|
Central
Hudson’s cash and cash equivalents increased by $2.3 million for the year ended
December 31, 2009, decreased by $1.1 million for the year ended December 31,
2008 and increased by $1.9 million for the year ended December 31,
2007. For each of these periods, Central Hudson’s working capital
needs were provided by cash from operations and supplemented seasonally with
short-term financing as needed. Cash from operations in excess of
expenses and working capital needs provided partial funding for capital
expenditures in each year. The remainder of the funding for capital
expenditures was provided by the issuance of long-term debt in each year and
supplemented with an equity investment from CH Energy Group in
2009.
Net cash
provided by operations was $107.5 million, $68.1 million and $32.8 million for
the years ended December 31, 2009, 2008 and 2007, respectively. Cash
provided by sales exceeded the period’s expenses and working capital needs in
each year, particularly in 2009 when lower energy prices resulted in a
significant return of working capital. In the third quarter of 2009,
Central Hudson paid $17.7 million to the PSC for a new tax surcharge instituted
in April 2009; however, only $7.2 million of this surcharge had been collected
from customers through December 31, 2009. The required payment of the
full year assessment in the third quarter of 2009 increased Central Hudson’s
working capital needs in the current period, requiring financing. In
March 2010, Central Hudson will begin making bi-annual installments of
approximately $8.9 million for this surcharge and will collect the amounts from
customers in subsequent months. Central Hudson also paid $1.1 million
to the PSC for the bi-annual general assessment, of which $0.7 million had been
collected through December 31, 2009. Cash from operations was also
significantly impacted by an overpayment of federal income taxes in 2009, as
well as the receipt of a refund in 2007 for a prior year’s
overpayment. Central Hudson’s MGP site remediation costs in excess of
amounts recovered through rates and other regulatory mechanisms totaling $2.3
million, $2.8 million and $5.1 million in the years ended December 31, 2009,
2008 and 2007, respectively, also impacted cash from operations.
Net cash
used in investing activities of $107.3 million, $80.2 million and $83.3 million
in the years ended December 31, 2009, 2008 and 2007, respectively, was primarily
for investments in its electric and natural gas systems. In June
2009, Central Hudson closed on the purchase of certain real-estate in Kingston,
NY resulting in an increase of approximately $13 million to plant
additions. Other increases in capital expenditures at Central Hudson in
each year relate primarily to maintenance and proactive repairs to transmission
and distribution infrastructure to improve reliability.
Net cash
provided by financing activities was $2.1 million, $11.0 million and $52.4
million in the years ended December 31, 2009, 2008 and 2007,
respectively. During 2009 and 2008, Central Hudson retained its net
income to invest in its transmission and distribution systems. In
2007, Central Hudson paid dividends to CH Energy Group of $8.5
million. Central Hudson’s cash flow benefited from lower energy
prices at the end of 2008 and throughout 2009. Cash from operations
in excess of expenses and working capital needs were used to repay short-term
borrowings in 2009 and 2008 and redeem its long-term debt of $20.0 million at
maturity in January 2009. Additionally, an investment of $25.0
million from CH Energy Group in 2009 and the net proceeds from the issuance of
long-term debt in each year supplemented the funding of capital
expenditures.
CAPITALIZATION - ISSUANCE OF
TREASURY STOCK
Effective
January 26, 2009, CH Energy Group granted 2,930 restricted shares to certain
officers and key employees of Griffith. Effective October 1, 2009, CH
Energy Group granted 14,375 restricted shares to a new CH Energy Group executive
officer. These restricted shares granted were issued from CH Energy
Group’s treasury stock.
On May 1,
2009, performance shares earned as of December 31, 2008 for the award cycle with
a grant date of April 25, 2006 were issued to participants. Those
recipients electing not to defer this compensation under the CH Energy Group
Directors and Executives Deferred Compensation Plan received shares issued from
CH Energy Group’s treasury stock. A total of 4,560 shares were issued
from CH Energy Group’s treasury stock on May 1, 2009. Additionally,
due to the retirement of one of Central Hudson’s executive officers on January
1, 2009, a pro-rated number of shares under the January 25, 2007 and January 24,
2008 grants were paid to this individual on July 2, 2009. An
additional 294 shares were issued from CH Energy Group’s treasury stock on this
date in satisfaction of these awards.
For
further information regarding the above equity compensation, see Note 11 -
“Equity Based Compensation” of this 10-K Annual Report. The Company
intends to continue to utilize shares issued from CH Energy Group’s treasury
stock for the payout of future performance awards.
CAPITAL
STRUCTURE
CH Energy
Group’s consolidated capital structure reflects the external debt and preferred
stock of Central Hudson and privately placed external debt at CH Energy
Group. CHEC’s long-term debt is comprised entirely of intercompany
loans from CH Energy Group that are eliminated upon consolidation.
During
the first half of the year, Central Hudson operated under the 2006 Rate
Order. Central Hudson’s rates were based on a capital structure that
reflected 45% common equity, but a common equity ratio up to 47% could have been
used for the purpose of determining earnings sharing. Central Hudson
has been gradually increasing its equity ratio to bolster its credit quality
with the expectation that it would earn a return on the incremental equity
through future delivery rates. Effective July 1, 2009, Central Hudson
operated under the 2009 Rate Order. Central Hudson’s rates are based on a
capital structure that reflects 47% common equity. These ratios are
calculated according to a PSC methodology, which excludes short-term
debt.
In April
2009, CH Energy Group invested $25 million in Central Hudson, which was recorded
as additional paid-in capital. Central Hudson paid no common stock
dividends in 2009 and is targeting an equity ratio of approximately 48%,
excluding short-term debt.
Central
Hudson’s current senior unsecured debt rating/outlook is ‘A’/stable by both
Standard & Poor’s Rating Services (“Standard & Poor’s”) and Fitch
Ratings and ‘A3’/negative by Moody’s Investors Service (“Moody’s”).1 On
September 9, 2009, Moody’s downgraded Central Hudson’s senior unsecured debt and
issuer ratings to ‘A3’ from ‘A2’, with a continued negative outlook, to
reflect their view of the current weakness in our credit metrics and the ongoing
need for rate relief to support planned capital expenditures. Moody’s
analysis focused on four key rating factors that they identified as being
important determinants in assigning ratings; (1) regulatory framework, (2)
ability to recover costs and earn returns, (3) diversification, and (4)
financial strength, liquidity and key financial metrics. The
downgrade is not expected to have a material impact on Central Hudson’s
financial performance.
1 These
ratings reflect only the views of the rating agency issuing the rating, are not
recommendations to buy, sell, or hold securities of Central Hudson and may be
subject to revision or withdrawal at any time by the rating agency issuing the
rating. Each rating should be evaluated independently of any other
rating.
Year-end
capital structures for CH Energy Group and its subsidiaries are set forth below
as of December 31:
CH Energy
Group
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008
|
|
|
2007
|
|
Long-term
debt(1)
|
|
|
46.8
|
% |
|
|
42.8
|
% |
|
|
40.8
|
% |
Short-term
debt
|
|
|
- |
|
|
|
3.5 |
|
|
|
4.3 |
|
Preferred
stock
|
|
|
2.0 |
|
|
|
2.1 |
|
|
|
2.1 |
|
Common
equity
|
|
|
51.2 |
|
|
|
51.6 |
|
|
|
52.8 |
|
|
|
|
100.0
|
% |
|
|
100.0
|
% |
|
|
100.0
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
Hudson
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
|
2008 |
|
|
|
2007 |
|
Long-term
debt
|
|
|
49.2
|
% |
|
|
50.8
|
% |
|
|
49.6
|
% |
Short-term
debt(2)
|
|
|
- |
|
|
|
3.0 |
|
|
|
5.2 |
|
Preferred
stock
|
|
|
2.4 |
|
|
|
2.5 |
|
|
|
2.6 |
|
Common
equity
|
|
|
48.4 |
|
|
|
43.7 |
|
|
|
42.6 |
|
|
|
|
100.0
|
% |
|
|
100.0
|
% |
|
|
100.0
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
CHEC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
|
2008 |
|
|
|
2007 |
|
Long-term
debt(1)
|
|
|
32.1
|
% |
|
|
26.8
|
% |
|
|
48.9
|
% |
Short-term
debt
|
|
|
- |
|
|
|
6.4 |
|
|
|
- |
|
Preferred
stock
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Common
equity
|
|
|
67.9 |
|
|
|
66.8 |
|
|
|
51.1 |
|
|
|
|
100.0
|
% |
|
|
100.0
|
% |
|
|
100.0
|
% |
(1)
|
Based
on stand-alone financial statements and including intercompany balances
which are eliminated upon
consolidation.
|
(2)
|
Excluded
from the common equity ratio under the PSC’s methodology for Central
Hudson delivery rates
|
CONTRACTUAL
OBLIGATIONS
A review
of capital resources and liquidity should also consider other contractual
obligations and commitments, which are further disclosed in Note 12 -
“Commitments and Contingencies.”
The
following is a summary of the contractual obligations for CH Energy Group and
its affiliates as of December 31, 2009 (In Thousands):
Projected Payments Due By
Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less
than
1
year
|
|
|
Years
Ending
2011-2012
|
|
|
Years
Ending
2013-2014
|
|
|
2015
and After
|
|
|
Total
|
|
Long-Term
Debt(1)
|
|
$ |
24,000 |
|
|
$ |
37,948 |
|
|
$ |
72,726 |
|
|
$ |
353,276 |
|
|
$ |
487,950 |
|
Interest
Payments - Long-Term Debt(1)
|
|
|
22,737 |
|
|
|
42,042 |
|
|
|
35,303 |
|
|
|
206,358 |
|
|
|
306,440 |
|
Operating
Leases
|
|
|
2,450 |
|
|
|
4,904 |
|
|
|
4,565 |
|
|
|
8,992 |
|
|
|
20,911 |
|
Construction/Maintenance
& Other Projects(2)
|
|
|
79,307 |
|
|
|
29,849 |
|
|
|
7,663 |
|
|
|
3,784 |
|
|
|
120,603 |
|
Purchased
Electric Contracts(3)
|
|
|
109,732 |
|
|
|
40,355 |
|
|
|
7,998 |
|
|
|
3,613 |
|
|
|
161,698 |
|
Purchased
Natural Gas Contracts(3)
|
|
|
55,369 |
|
|
|
53,410 |
|
|
|
22,624 |
|
|
|
49,599 |
|
|
|
181,002 |
|
Purchased
Fixed Liquid Petroleum Contracts(4)
|
|
|
3,959 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,959 |
|
Total
Contractual Obligations(5)
|
|
$ |
297,554 |
|
|
$ |
208,508 |
|
|
$ |
150,879 |
|
|
$ |
625,622 |
|
|
$ |
1,282,563 |
|
(1)
|
Includes
fixed rate obligations and variable interest rate bonds with estimated
variable interest payments based on the actual interest paid in
2009.
|
(2)
|
Including
Specific, Term, and 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.
|
(3)
|
Purchased
electric and purchased natural gas costs for Central Hudson are fully
recovered via their respective regulatory cost adjustment
mechanisms.
|
(4)
|
Estimated
based on pricing on December 31,
2009.
|
(5)
|
The
estimated present value of CH Energy Group’s total contractual obligations
is $856 million, assuming a discount rate of
5.5%.
|
The
following is a summary of the contractual obligations for Central Hudson as of
December 31, 2009 (In Thousands):
Projected Payments Due By
Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less
than
1
year
|
|
|
Years
Ending
2011-2012
|
|
|
Years
Ending
2013-2014
|
|
|
2015
and After
|
|
|
Total
|
|
Long-Term
Debt(1)
|
|
$ |
24,000 |
|
|
$ |
36,000 |
|
|
$ |
44,000 |
|
|
$ |
333,950 |
|
|
$ |
437,950 |
|
Interest
Payments - Long-Term Debt(1)
|
|
|
19,395 |
|
|
|
35,454 |
|
|
|
29,867 |
|
|
|
197,926 |
|
|
|
282,642 |
|
Operating
Leases
|
|
|
1,546 |
|
|
|
3,013 |
|
|
|
2,907 |
|
|
|
2,888 |
|
|
|
10,354 |
|
Construction/Maintenance
& Other Projects(2)
|
|
|
52,022 |
|
|
|
29,773 |
|
|
|
7,587 |
|
|
|
3,784 |
|
|
|
93,166 |
|
Purchased
Electric Contracts(3)
|
|
|
109,732 |
|
|
|
40,355 |
|
|
|
7,998 |
|
|
|
3,613 |
|
|
|
161,698 |
|
Purchased
Natural Gas Contracts(3)
|
|
|
55,369 |
|
|
|
53,410 |
|
|
|
22,624 |
|
|
|
49,599 |
|
|
|
181,002 |
|
Total
Contractual Obligations(4)
|
|
$ |
262,064 |
|
|
$ |
198,005 |
|
|
$ |
114,983 |
|
|
$ |
591,760 |
|
|
$ |
1,166,812 |
|
(1)
|
Includes
fixed rate obligations and variable interest rate bonds with estimated
variable interest payments based on the actual interest paid in
2009.
|
(2)
|
Including
Specific, Term, and Service Contracts, as defined in footnote (2) of the
preceding chart.
|
(3)
|
Purchased
electric and purchased natural gas costs for Central Hudson are fully
recovered via their respective regulatory cost adjustment
mechanisms.
|
(4)
|
The
estimated present value of Central Hudson’s total contractual obligations
is $763 million, assuming a discount rate of
5.5%.
|
Central
Hudson has an obligation to meet its contractual benefit payment
obligations. Decisions about how to fund the Retirement Plan to meet
these obligations are made annually and are primarily affected by the discount
rate used to determine benefit obligations, current asset values and the
projection of Retirement Plan assets. Based on the funding
requirements of the Pension Protection Act, Central Hudson plans to make
contributions that maintain the target funded percentage at 80% or
higher. On January 22, 2010, Central Hudson contributed $30 million
to its Retirement Plan. Central Hudson’s contributions for 2010 are
expected to total approximately $30-$55 million, resulting in a funded status
that meets Central Hudson’s objective. The actual contributions could
vary significantly based upon economic growth, projected investment returns,
inflation, and interest rate assumptions. Actual funded status could vary
significantly based on asset returns and changes in the discount rate used to
estimate the present value of future obligations.
Employer
contributions in 2009 to fund OPEBs were $3.5 million. Obligations
for future funding depend on a number of factors, including the discount rate,
expected return, and medical claims assumptions used. If these
factors remain stable, OPEB contributions over the next few years are expected
to range from $5-$7 million annually.
During
2009, the financial markets experienced less volatility than the level
experienced in 2008 and the value of the Retirement Plan and OPEB assets
increased by $52.9 million and $14.5 million, respectively. These
increases reduced the underfunded status of these plans. However, the
decrease in discount rates from 2008 increased the present value of the plans’
liabilities. The net effect on the funded status of the plans from
the financial markets and the discount rates was a decrease in the unfunded
status of the plans. If future market conditions do not improve
sufficiently to completely offset the volatility of 2008, additional
contributions will likely become necessary under the terms of the Pension
Protection Act of 2006. Management expects that such contributions
will be recovered through the rate making process over time. Central
Hudson has investment policies for these plans which include asset allocation
ranges designed to achieve a reasonable return over the long-term, recognizing
the impact of market volatility. Central Hudson monitors actual
performance against target asset allocations and adjusts actual allocations and
targets as deemed appropriate in accordance with the Investment
Policy. Management cannot currently predict what impact future
financial market volatility may have on the funded status of the plan or future
funding decisions.
Management
is reviewing changes to the Plan’s investment strategy to reduce the
year-to-year volatility of the funded status and the level of
contributions. Options being considered include extending the
duration of the Plan’s investments as well as changes to the target asset
allocation to more closely align with the Plan’s long-term
obligations.
Under the
policy of the PSC regarding pension and OPEB costs, Central Hudson recovers
these costs through customer rates with differences between actual cost and rate
allowances deferred for future recovery from or return to
customers. Based on the current policy, Central Hudson expects to
fully recover its net periodic pension and OPEB costs over time.
ANTICIPATED SOURCES AND USES
OF CASH
CH Energy
Group’s cash flow is primarily generated by the operations of its direct
subsidiaries, Central Hudson and CHEC. Generally, the subsidiaries do
not accumulate cash but rather provide cash to CH Energy Group in the form of
dividends and, in the case of CHEC, repayments on its intercompany
loan.
Central
Hudson’s planned capital expenditures for construction and removal during 2010
are expected to total approximately $85 million. For 2011, planned
capital expenditures are expected to range from $90 million to $100
million. Capital expenditures are expected to be funded with cash
from operations and a combination of short-term and long-term
borrowings. Central Hudson may alter its plan for capital
expenditures as its business needs require.
Based on
the PSC decision in June 2009 and the proposed terms of its July 2009 rate case
filing, Central Hudson intends to retain a significant portion of its 2010
earnings to partially fund growth in its long-lived assets while issuing
approximately $45 million of its Series G medium-term notes to fund the
remainder of such growth, fund maturing long-term debt, and manage its capital
structure. Central Hudson plans to maintain an equity ratio of
approximately 48% in 2010, excluding short-term balances. Central
Hudson expects to utilize short-term debt to fund seasonal and temporary
variations in working capital requirements. If wholesale energy
prices increase, Central Hudson would expect a corresponding increase in its
current level of working capital.
On
December 11, 2009, CH Energy Group announced the sale of operations of Griffith
in certain geographic locations. Net of adjustments, primarily for
working capital, Griffith received approximately $74 million in
proceeds. CH Energy Group expects to pay taxes on the gain on the
sale of approximately $12-$13 million and plans to use the majority of the
remaining proceeds to fund the development of a 20-megawatt wind farm facility
in Wisconsin. In December 2009, CHEC invested approximately $12
million in the Shirley Wind project, and expects to invest an additional $35
million during 2010 to complete development and bring its total investment to
$47 million. CHEC also intends to invest $0.5 million to complete
development of a landfill gas energy facility in Auburn, NY during the first
quarter of 2010. Additionally, capital expenditures at Griffith are
expected to be approximately $2.0 million during 2010, excluding acquisitions
and investments arising from CHEC’s business development
activities. For 2011, capital expenditures at Griffith, excluding
acquisitions and investments arising from its business development activities,
are expected to range from $2.0 million to $2.5 million.
CH Energy
Group believes cash generated from operations and funds obtained from its
financing program will be sufficient in 2010 and the foreseeable future to meet
working capital needs, pay dividends on its Common Stock, and fund investments
and acquisitions to fulfill its public service obligations and growth
objectives. CH Energy Group’s primary source of funds is the cash it
generates from the operations of Central Hudson and CHEC, which can be affected
by volatility in energy markets that affects their working capital needs and
profitability. CH Energy Group’s secondary sources of funds are its
cash reserves and its credit facility. CH Energy Group’s ability to
use its credit facility is contingent upon maintaining certain financial
covenants. CH Energy Group does not anticipate that those covenants
will restrict its access to funds in 2010 or the foreseeable
future.
FINANCING
PROGRAM
CH Energy
Group believes that it is well positioned with a strong balance sheet and strong
liquidity. CH Energy Group entered 2010 with no short-term debt
liabilities and significant available capacity under CH Energy Group’s and
Central Hudson’s committed credit facilities. Central Hudson’s strong
investment-grade credit ratings help facilitate access to long-term debt;
however, despite improving conditions in financial markets, Management can make
no assurance regarding the availability of financing or its terms and
costs. With the exception of treasury shares to be issued for several
restricted share grants and performance share awards earned, no significant
equity issuance is currently planned for 2010. As discussed earlier,
CH Energy Group is actively seeking growth opportunities aligned to its strategy
for Central Hudson and CHEC, and it continues to evaluate alternatives for
raising capital should those opportunities warrant investment of capital in
excess of internal resources.
CH Energy
Group maintains a $150 million revolving credit agreement with several
commercial banks to provide committed liquidity beyond its cash
balance. That agreement was amended in 2008 to expand CH Energy
Group’s committed credit from $75 million to $150 million for a period of five
years from the effective date. At December 31, 2009, CH Energy Group
had no outstanding borrowings under its credit agreement.
In the
second quarter of 2009, CH Energy Group privately placed $50 million of senior
unsecured notes. The notes bear interest at the rate of 6.58% per
annum and mature on April 17, 2014. CH Energy Group used a portion of
the proceeds from the sale of the notes to repay short-term debt and retained
the remainder for general corporate purposes. On December 15, 2009,
following the sale of operations of Griffith in certain geographic locations, CH
Energy Group entered into a supplemental note purchase agreement for the sale of
$23.5 million of new notes and redeemed $23.5 million of the notes placed during
the second quarter of 2009. The newly issued notes bear interest at a
rate of 6.80% per annum and mature on December 15, 2025. Interest is
payable semi-annually and, commencing June 15, 2011, with semi-annual payments
of principal. The mortgage style amortization of principal results in
the final payment of principal and interest upon maturity. CH Energy
Group intends to use approximately $23.5 million of the proceeds from the
December sale of notes to fund a portion of its investment in the Shirley Wind
project.
Effective
January 2, 2007 and pursuant to PSC authorization, Central Hudson amended its
$75 million committed credit agreement with several commercial banks, increasing
the committed credit to $125 million and extending the term of the agreement to
January 2, 2012. In addition to this credit agreement, Central Hudson
maintains several uncommitted lines of credit with various
banks. These arrangements give Central Hudson competitive options to
minimize the cost of its short-term borrowings. At December 31, 2009,
Central Hudson had no outstanding balance under its uncommitted lines of credit
and no outstanding balance under its committed credit agreement.
The
lenders under both the CH Energy Group ($150 million) and Central Hudson ($125
million) credit agreements include JPMorgan Chase Bank, N.A., Bank of America,
N.A., HSBC Bank USA, N.A. and KeyBank National Association. The
availability of these facilities is contingent upon the ability of the lenders
to fulfill their commitments. If one or more banks are deemed at risk
of being unable to meet their commitments, CH Energy Group and Central Hudson
may seek alternative sources of committed credit to supplement the current
agreements. However, alternate sources may not be readily available.
CH Energy Group and Central Hudson plan for such a situation by reserving
portions of the total commitment for unforeseen events.
Central
Hudson meets its need for long-term debt financing through a medium-term notes
program. As a regulated electric and natural gas utility company,
Central Hudson is required to obtain authorization from the PSC to issue
securities with maturities greater than 12 months.
The PSC
issued an Order in September 2006, authorizing Central Hudson to issue
medium-term notes of up to $140 million over the three-year period ending
December 31, 2009. With this authorization, Central Hudson
established its Series F notes and issued $120 million during that
period. A summary of Series F issuances follows:
Date
|
|
Amount
of Issuance
|
|
Term,
Rate
|
|
Proceeds
Used for:
|
March
23, 2007
|
|
$33,000,000
|
|
30-year,
5.80%
|
|
Redemption
at maturity of $33,000,000 5-year, 5.87% Series D Notes
|
September
14, 2007
|
|
$33,000,000
|
|
10-year,
6.028%
|
|
Financing
ongoing investments in electric and natural gas systems
|
November
18, 2008
|
|
$30,000,000
|
|
5-year,
6.854%
|
|
Financing
ongoing investments in electric and natural gas systems
|
September
30, 2009
|
|
$24,000,000
|
|
30-year,
5.80%
|
|
Financing
ongoing investments in electric and natural gas systems
|
On
September 22, 2009, the PSC authorized Central Hudson to increase its multi-year
committed credit to $175 million and to issue up to $250 million of long-term
debt through December 31, 2012. The Order authorizes Central Hudson
to issue and sell $250 million of long-term debt to finance its construction
expenditures, refund maturing long-term debt, and potentially refinance its 1999
NYSERDA Bonds, Series B, C and D. A new shelf registration statement
was filed by Central Hudson with the SEC covering the offer and sale of up to
$250 million of long-term debt pursuant to the authority granted by the
PSC. An amended registration statement was filed on December 23, 2009
and the registration of the Series G notes became effective on January 6,
2010. No immediate action is planned to increase Central Hudson’s
committed credit; however, options to do so will be evaluated in the
future.
Central
Hudson has five debt series, totaling $166 million, which were issued in prior
years in conjunction with the sale of tax-exempt pollution control revenue bonds
by New York State Energy Research and Development Authority
(“NYSERDA”). These NYSERDA bonds are insured by Ambac Assurance
Corporation (“Ambac”) and the ratings on these bonds reflect the higher of the
credit rating of Ambac or Central Hudson. The current underlying
rating and outlook on these bonds and Central Hudson’s other senior unsecured
debt is ‘A’/stable by Standard & Poor’s and Fitch Ratings and ‘A3’/negative
by Moody’s.2
Central
Hudson’s 1998 NYSERDA Series A Bonds, totaling $16.7 million, were re-marketed
on December 1, 2008. Under the terms of the applicable indenture,
Central Hudson converted the bonds to a fixed rate of 6.5%, which will continue
until their maturity in December 2028. Prior to the December 1, 2008
re-marketing, the bonds bore interest at a five-year term rate of
3.0%.
2 These
ratings reflect only the views of the rating agency issuing the rating, are not
recommendations to buy, sell, or hold securities of Central Hudson and may be
subject to revision or withdrawal at any time by the rating agency issuing the
rating. Each rating should be evaluated independently of any other
rating.
Central
Hudson’s 1999 NYSERDA Series A Bonds, totaling $33.4 million, have an interest
rate that is fixed to maturity in 2027 at 5.45%.
Central
Hudson’s 1999 NYSERDA Bonds, Series B, C, and D, totaling $115.9 million, are
multi-modal bonds that are currently in auction rate mode. Beginning
in 1999 when the bonds were issued, the bonds’ interest rate has been reset
every 35 days in a Dutch auction. Auctions in the market for
municipal auction rate securities have experienced widespread failures since
early 2008. Generally, an auction failure occurs because there is an
insufficient level of demand to purchase the bonds and the bondholders who want
to sell must hold the bonds for the next interest rate period. Since
February 2008, all auctions for Central Hudson’s three series of auction rate
bonds have failed. As a consequence, the interest rate paid to the
bondholders has been set to the then prevailing maximum rate defined in the
trust indenture. Central Hudson’s maximum rate results in interest
rates that are generally higher than the expected results from the auction
process. For the foreseeable future, Central Hudson expects the
interest rate to be set at the maximum rate, determined on the date of each
auction, to be 175% of the yield on an index of tax-exempt short-term debt, or
its approximate equivalent. Since the first auction failure in
February 2008, the applicable rate for Central Hudson’s bonds has ranged from
0.40% to 9.01% and in 2009 averaged 0.80%. In its Orders, the PSC has authorized
deferral accounting treatment for the interest costs from Central Hudson’s three
series of variable rate 1999 NYSERDA Bonds. As a result, variations
in interest rates on these bonds are deferred for future recovery from or refund
to customers and Central Hudson does not expect the auction failures to have any
adverse impact on earnings. To mitigate the potential impact of
unexpected increases in short-term interest rates, Central Hudson purchases
interest rate caps based on an index for short-term tax-exempt
debt. Effective April 1, 2009, Central Hudson entered into a one-year
rate cap with Key Bank National Association to protect against unexpected
short-term interest rate increases. The cap is based on the monthly
weighted average of an index of tax-exempt variable rate debt, multiplied by
175% to align with the maximum rate formula of the three series of variable rate
1999 NYSERDA Bonds. Central Hudson would receive a payout if the
bonds reset at rates above 4.375%. During 2009 and 2008, the average
for any quarter did not exceed the cap rate and therefore no payments were
received in each of these years.
Central
Hudson is currently evaluating what actions, if any, it may take in the future
in connection with its 1999 NYSERDA Bonds, Series B, C and D. Potential actions
may include converting the debt from auction rate to another interest rate mode
or refinancing with taxable bonds.
Griffith’s
financing is provided by CH Energy Group.
Effective
July 31, 2007, CH Energy Group’s Board of Directors extended and amended the
Common Stock Repurchase Program of the Company (the “Repurchase Program”), which
was originally authorized in 2002. As amended, the Repurchase Program
authorizes the repurchase of up to 2,000,000 shares (excluding shares
repurchased before July 31, 2007) or approximately 13% of the CH Energy Group’s
outstanding Common Stock, from time to time, through July 31,
2012. No shares were purchased under the Repurchase Program in 2007,
2008, or 2009. CH Energy Group intends to set repurchase targets, if
any, based on circumstances from time to time.
For more
information on CH Energy Group's and Central Hudson's financing program, see
Note 7 - "Short-Term Borrowing Arrangements," Note 8 - "Capitalization - Common
and Preferred Stock," and Note 9 - "Capitalization - Long-Term
Debt."
PARENTAL
GUARANTEES
For
information on parental guarantees issued by CH Energy Group and CHEC, see
Note 1 - “Summary of Significant Accounting Policies” under the caption
“Parental Guarantees.”
PRODUCT
WARRANTIES
For
information on product warranties issued by Griffith, see Note 1 - “Summary
of Significant Accounting Policies” under the caption “Product
Warranties.”
ENVIRONMENTAL
MATTERS
For
information on environmental matters related to CH Energy Group, Central Hudson,
CHEC, and Griffith, see subcaption “Environmental Matters” in Note 12 -
“Commitments and Contingencies” under the caption “Contingencies.”
RELATED
PARTIES
For
information on related parties to CH Energy Group and Central Hudson, see Note 1
- “Summary of Significant Accounting Policies” under the caption “Related Party
Transactions.”
EARNINGS
PER SHARE
The
following discussion and analyses include explanations of significant changes in
revenues and expenses between the year ended December 31, 2009, and 2008, and
the year ended December 31, 2008, and 2007 for Central Hudson’s regulated
electric and natural gas businesses, Griffith, and the Other Businesses and
Investments.
The
discussions and tables below present the change in earnings of CH Energy Group’s
business units in terms of earnings for each share of CH Energy Group’s Common
Stock. Management believes this presentation is useful because these
business units are each wholly owned by CH Energy Group. This
information is considered a non-GAAP financial measure and not an alternative to
earnings per share determined on a consolidated basis, which is the most
directly comparable GAAP measure. A reconciliation of each business
unit’s earnings per share to CH Energy Group’s earnings per share, determined on
a consolidated basis, is included in the table below.
EARNINGS
Earnings
per share (basic and diluted) of CH Energy Group’s Common Stock are computed on
the basis of the average number of common shares outstanding (basic and diluted)
during the subject year. The number of average shares outstanding of
CH Energy Group Common Stock, the earnings per share, and the rate of return
earned on average common equity, which is net income as a percentage of a
monthly average of common equity, are as follows (Shares In
Thousands):
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Average
shares outstanding:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
15,775 |
|
|
|
15,768 |
|
|
|
15,762 |
|
Diluted
|
|
|
15,881 |
|
|
|
15,805 |
|
|
|
15,779 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
2.13 |
|
|
$ |
2.00 |
|
|
$ |
2.61 |
|
Diluted
|
|
$ |
2.12 |
|
|
$ |
2.00 |
|
|
$ |
2.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share from discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.63 |
|
|
$ |
0.22 |
|
|
$ |
0.09 |
|
Diluted
|
|
$ |
0.62 |
|
|
$ |
0.22 |
|
|
$ |
0.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
2.76 |
|
|
$ |
2.22 |
|
|
$ |
2.70 |
|
Diluted
|
|
$ |
2.74 |
|
|
$ |
2.22 |
|
|
$ |
2.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return
earned on common equity
|
|
|
8.6 |
% |
|
|
6.6 |
% |
|
|
8.1 |
% |
2009 as compared to
2008
CH ENERGY GROUP
CONSOLIDATED
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per Share (Basic)
|
|
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
Central
Hudson - Electric
|
|
$ |
1.60 |
|
|
$ |
1.33 |
|
|
$ |
0.27 |
|
Central
Hudson - Natural Gas
|
|
|
0.42 |
|
|
|
0.34 |
|
|
|
0.08 |
|
Griffith
|
|
|
0.76 |
|
|
|
0.26 |
|
|
|
0.50 |
|
Other
Businesses and Investments
|
|
|
(0.02 |
) |
|
|
0.29 |
|
|
|
(0.31 |
) |
|
|
$ |
2.76 |
|
|
$ |
2.22 |
|
|
$ |
0.54 |
|
Earnings
for CH Energy Group totaled $2.76 per share in 2009, versus $2.22 per share in
2008, an increase of $0.54 per share. The 2009 earnings reflect a
recovery from somewhat depressed levels in 2008. Central Hudson’s new
rate plan approved by the PSC, which took effect July 1, 2009, corrected a
misalignment of costs and revenues. Additionally, Griffith completed
a successful partial divestiture in the fourth quarter of 2009 and implemented
continued operational efficiencies and cost reductions in its continuing
operations.
Details
by business unit were as follows:
CENTRAL
HUDSON
Earnings per Share
(Basic)
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
Electric
|
|
$ |
1.60 |
|
|
$ |
1.33 |
|
|
$ |
0.27 |
|
Natural
Gas
|
|
|
0.42 |
|
|
|
0.34 |
|
|
|
0.08 |
|
|
|
$ |
2.02 |
|
|
$ |
1.67 |
|
|
$ |
0.35 |
|
Earnings
from Central Hudson's electric and natural gas operations increased $0.35 per
share in 2009 compared to 2008 due to the following:
Regulatory
mechanisms and other events:
|
|
|
|
Uncollectible
deferral - approved
|
|
$ |
0.02 |
|
Uncollectible
deferral - pending approval
|
|
|
0.11 |
|
Cable
attachment rents in 2008
|
|
|
(0.03 |
) |
Rate
increases
|
|
|
0.66 |
|
Revenue
decoupling mechanisms
|
|
|
0.22 |
|
Weather
normalized sales
|
|
|
(0.17 |
) |
Weather
impact on sales (including hedging)
|
|
|
(0.04 |
) |
Higher
uncollectible accounts
|
|
|
(0.18 |
) |
Higher
depreciation
|
|
|
(0.15 |
) |
Higher
property and other taxes
|
|
|
(0.07 |
) |
Higher
interest expense and carrying charges
|
|
|
(0.07 |
) |
Higher
tree trimming and other distribution maintenance
|
|
|
(0.06 |
) |
Lower
storm restoration expense
|
|
|
0.09 |
|
Other
|
|
|
0.02 |
|
|
|
$ |
0.35 |
|
Central
Hudson's contribution to earnings per share was $2.02 per share, an increase of
$0.35 per share over the $1.67 per share posted in 2008. The improvement is due
primarily to improved cost recovery though delivery rates, though higher
uncollectible accounts, depreciation, property taxes and other expenses offset
much of the increased revenue. The absence of major storms and the resulting
expense of restoring service to electric customers contributed $0.09 per share
to year-over-year performance.
GRIFFITH
Earnings per Share
(Basic)
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
$ |
0.76 |
|
|
$ |
0.26 |
|
|
$ |
0.50 |
|
Griffith’s
earnings increased $0.50 per share in 2009 compared to 2008 due to the
following:
Other
events:
|
|
|
|
Gain
on the sale of Northeast operations(1)
|
|
$ |
0.40 |
|
Discontinued
operations
|
|
|
(0.04 |
) |
Margin
on petroleum sales and services
|
|
|
0.02 |
|
Weather
normalized sales (including conservation)
|
|
|
(0.21 |
) |
Weather
impact on sales (including hedging)
|
|
|
0.11 |
|
Operating
expenses
|
|
|
0.11 |
|
Lower
uncollectible accounts
|
|
|
0.04 |
|
Other
|
|
|
0.07 |
|
|
|
$ |
0.50 |
|
(1)
|
See
additional taxes owed by the holding company within Other Businesses &
Investments.
|
Griffith
contributed $0.76 to earnings per share in 2009 as compared to $0.26 per share
in 2008. This increase was primarily attributable to the sale of
operations in certain geographic locations. Customer conservation
continued to have a negative impact on sales, but was offset by the favorable
impacts of weather and continued operational cost reductions implemented by
Management.
OTHER BUSINESSES AND
INVESTMENTS
Earnings per Share
(Basic)
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
|
$ |
(0.02 |
) |
|
$ |
0.29 |
|
|
$ |
(0.31 |
) |
The
variation in earnings per share from CH Energy Group (the holding company) and
CHEC’s partnership and other investment interests in 2009 compared to 2008 is
due to the following:
Other
events:
|
|
|
|
Holding
Company's income taxes on Griffith sale
|
|
$ |
(0.06 |
) |
Buckeye
investment
|
|
|
(0.05 |
) |
Lyonsdale
investment
|
|
|
(0.03 |
) |
Holding
company interest expense
|
|
|
(0.07 |
) |
Higher
other taxes
|
|
|
(0.02 |
) |
Higher
costs associated with pursuing future investments
|
|
|
(0.03 |
) |
Other
operating assets and investments
|
|
|
(0.03 |
) |
Other
|
|
|
(0.02 |
) |
|
|
$ |
(0.31 |
) |
CH Energy
Group (the holding company) and CHEC’s partnerships and other investments
resulted in a loss of ($0.02) per share in 2009, a decrease of ($0.31) per share
from 2008. Interest expense on the debt issued at the holding company
in 2009 to finance CH Energy Group’s unregulated businesses reduced earnings by
($0.07) per share. Income taxes on the gain from the Griffith sale lowered
earnings by ($0.06) per share. Additionally, the write-off of the Buckeye
investment lowered 2009 earnings by ($0.05) per share.
2008 as compared to
2007
CH ENERGY GROUP
CONSOLIDATED
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per Share (Basic)
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Central
Hudson - Electric
|
|
$ |
1.33 |
|
|
$ |
1.66 |
|
|
$ |
(0.33 |
) |
Central
Hudson - Natural Gas
|
|
|
0.34 |
|
|
|
0.40 |
|
|
|
(0.06 |
) |
Griffith
|
|
|
0.26 |
|
|
|
0.20 |
|
|
|
0.06 |
|
Other
Businesses and Investments
|
|
|
0.29 |
|
|
|
0.44 |
|
|
|
(0.15 |
) |
|
|
$ |
2.22 |
|
|
$ |
2.70 |
|
|
$ |
(0.48 |
) |
Details
by business unit were as follows:
CENTRAL
HUDSON
Earnings per Share
(Basic)
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
Electric
|
|
$ |
1.33 |
|
|
$ |
1.66 |
|
|
$ |
(0.33 |
) |
Natural
Gas
|
|
|
0.34 |
|
|
|
0.40 |
|
|
|
(0.06 |
) |
Total
|
|
$ |
1.67 |
|
|
$ |
2.06 |
|
|
$ |
(0.39 |
) |
Earnings
from Central Hudson’s electric and natural gas operations decreased $0.39 per
share in 2008 compared to 2007, due to the following:
Regulatory
mechanisms and other events:
|
|
|
|
Shared
earnings recorded in 2007
|
|
$ |
0.04 |
|
Gain
on non-utility property sales in 2007
|
|
|
(0.02 |
) |
Cable
attachment rents in 2008
|
|
|
0.03 |
|
Rate
increases
|
|
|
0.16 |
|
Higher
storm restoration expense
|
|
|
(0.13 |
) |
Higher
tree trimming
|
|
|
(0.08 |
) |
Higher
depreciation
|
|
|
(0.09 |
) |
Higher
interest expense and carrying charges
|
|
|
(0.08 |
) |
Higher
property and other taxes
|
|
|
(0.06 |
) |
Higher
uncollectible accounts
|
|
|
(0.17 |
) |
Weather
normalized sales (including conservation)
|
|
|
(0.01 |
) |
Other
|
|
|
0.02 |
|
|
|
$ |
(0.39 |
) |
Central
Hudson's contribution to annual earnings per share was $1.67, which was $0.39
lower than that of 2007. As a result of the shortfall in sales, the
delivery rate increases that were approved in 2006 and took effect in 2008 did
not generate sufficient revenue to meet the higher operating costs that those
rates had been designed to cover. In particular, those expenditures
included higher tree trimming (reducing earnings per share by $0.08) and
depreciation ($0.09). In addition, Central Hudson experienced
significantly higher costs associated with customers being unable to pay their
bills as a result of the weak economy ($0.17), as well as higher costs
associated with restoring electric service following storms
($0.13).
GRIFFITH
Earnings per Share
(Basic)
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
$ |
0.26 |
|
|
$ |
0.20 |
|
|
$ |
0.06 |
|
Griffith’s
earnings increased $0.06 per share in 2008 compared to 2007, due to the
following:
Other
events:
|
|
|
|
Discontinued
operations
|
|
$ |
0.11 |
|
Margin
on petroleum sales and services
|
|
|
0.20 |
|
Weather
normalized sales (including conservation)
|
|
|
(0.20 |
) |
Higher
uncollectible accounts
|
|
|
(0.11 |
) |
Operating
expenses
|
|
|
(0.03 |
) |
Weather
impact on sales (including hedging)
|
|
|
0.08 |
|
Other
|
|
|
0.01 |
|
|
|
$ |
0.06 |
|
Griffith
contributed $0.26 to earnings per share in 2008, up from $0.20 in 2007, due
largely to higher margins. Favorable margins in the latter part of
the year offset margin compression that had reduced profits during the first
three quarters of 2008. High oil prices and the weakening economy led
to price-induced conservation (reducing earnings per share by $0.20), as well as
significantly higher costs from uncollectible accounts ($0.11).
OTHER BUSINESSES AND
INVESTMENTS
Earnings per Share
(Basic)
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
$ |
0.29 |
|
|
$ |
0.44 |
|
|
$ |
(0.15 |
) |
The
variation in earnings per share from CH Energy Group (the holding company) and
CHEC’s partnership and other investment interests in 2008 compared to 2007 is
due to the following:
Cornhusker
Holdings
|
|
$ |
(0.06 |
) |
Lyonsdale
|
|
|
0.03 |
|
Lower
interest and investment income
|
|
|
(0.09 |
) |
Other
|
|
|
(0.03 |
) |
|
|
$ |
(0.15 |
) |
CH Energy
Group (the holding company) and CHEC’s partnerships and other investments
contributed $0.29 toward corporate earnings per share in 2008, down $0.15 from
2007 results largely due to lower interest and investment income. The
earnings from CHEC’s ethanol investment were lower due to reduced margins,
however, the ethanol plant investment, two wind energy installations and an
upstate New York biomass plant continued to add positively to earnings as part
of a diversified portfolio of investments within the energy
industry.
RESULTS
OF OPERATIONS
CENTRAL
HUDSON
The
following discussions and analyses include explanations of significant changes
in revenues and expenses between the years ended December 31, 2009 and 2008 for
Central Hudson’s regulated electric and natural gas businesses.
Income
Statement Variances
|
|
|
|
|
|
|
(Dollars
In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
|
December
31, 2009
|
|
|
|
Over/(Under)
same period
|
|
|
|
in
2008
|
|
|
|
Amount
|
|
|
Percent
|
|
Operating
Revenues
|
|
$ |
(87,400 |
) |
|
|
(11.0 |
)% |
|
|
|
|
|
|
|
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
|
Purchased
electricity, fuel and natural gas
|
|
|
(127,252 |
) |
|
|
(25.7 |
)% |
Depreciation
and amortization
|
|
|
2,282 |
|
|
|
7.7 |
% |
Other
operating expenses
|
|
|
28,576 |
|
|
|
13.9 |
% |
Total
Operating Expenses
|
|
|
(96,394 |
) |
|
|
(13.2 |
)% |
Operating
Income
|
|
|
8,994 |
|
|
|
13.4 |
% |
Other
Income, net
|
|
|
(2,128 |
) |
|
|
(46.3 |
)% |
Interest
Charges
|
|
|
(541 |
) |
|
|
(2.1 |
)% |
Income
before income taxes
|
|
|
7,407 |
|
|
|
15.9 |
% |
Income
Taxes
|
|
|
1,869 |
|
|
|
9.7 |
% |
Net
income
|
|
$ |
5,538 |
|
|
|
20.3 |
% |
Income
Statement Variances
|
|
|
|
|
|
|
(Dollars
in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
|
December
31, 2008
|
|
|
|
Over/(Under)
same period
|
|
|
|
in
2007
|
|
|
|
Amount
|
|
|
Percent
|
|
Operating
Revenues
|
|
$ |
15,419 |
|
|
|
2.0 |
% |
|
|
|
|
|
|
|
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
|
Purchased
electricity, fuel and natural gas
|
|
|
1,547 |
|
|
|
0.3 |
% |
Depreciation
and Amortization
|
|
|
1,413 |
|
|
|
5.0 |
% |
Other
operating expenses
|
|
|
16,521 |
|
|
|
8.8 |
% |
Total
operating expenses
|
|
|
19,481 |
|
|
|
2.7 |
% |
Operating
Income
|
|
|
(4,062 |
) |
|
|
(5.7 |
)% |
Other
income, net
|
|
|
(670 |
) |
|
|
(12.7 |
)% |
Interest
Charges
|
|
|
2,519 |
|
|
|
11.0 |
% |
Income
before income taxes
|
|
|
(7,251 |
) |
|
|
(13.5 |
)% |
Income
Taxes
|
|
|
(1,053 |
) |
|
|
(5.2 |
)% |
Net
(loss)/income
|
|
$ |
(6,198 |
) |
|
|
(18.5 |
)% |
The
following discusses variations and the primary drivers of the changes in
operating revenues, operating expenses, volumes delivered, other income,
interest charges, and income taxes for Central Hudson’s regulated electric and
natural gas businesses.
Delivery
Volumes
Delivery
volumes for Central Hudson vary in response to weather conditions and customer
behavior. Electric deliveries peak in the summer and deliveries of
natural gas used for heating purposes peak in the winter. Delivery
volumes also vary as customers respond to the price of the particular energy
product and changes in local economic conditions.
The
following chart reflects the change in the level of electric and natural gas
deliveries for Central Hudson in 2009, compared to 2008, and in 2008, compared
to 2007. Deliveries of electricity and natural gas to residential and
commercial customers have historically contributed the most to Central Hudson's
earnings. Effective July 1, 2009, Central Hudson’s delivery rate
structure includes a revenue decoupling mechanism which provides the ability to
record revenues equal to those forecasted in the development of current rates
for most of Central Hudson’s customers. As a result, fluctuations in
actual delivery volumes no longer have a significant impact on Central Hudson’s
earnings. Industrial sales and interruptible sales have a negligible
impact on earnings.
Actual Deliveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
Year
Ended
|
|
|
|
December
31, 2009
|
|
|
December
31, 2008
|
|
|
|
Increase/(Decrease)
from
|
|
|
Increase/(Decrease)
from
|
|
|
|
same
period in 2008
|
|
|
same
period in 2007
|
|
|
|
Electric
|
|
|
Natural
Gas
|
|
|
Electric
|
|
|
Natural
Gas
|
|
Residential
|
|
|
(3 |
)% |
|
|
(1 |
)% |
|
|
(2 |
)% |
|
|
0 |
% |
Commercial
|
|
|
(4 |
)% |
|
|
1 |
% |
|
|
(2 |
)% |
|
|
(1 |
)% |
Industrial
and other(1)
|
|
|
(10 |
)% |
|
|
(16 |
)% |
|
|
(7 |
)% |
|
|
(1 |
)% |
Total
Deliveries
|
|
|
(5 |
)% |
|
|
(3 |
)% |
|
|
(3 |
)% |
|
|
(1 |
)% |
(1)
|
Includes
interruptible natural gas
deliveries.
|
Weather Normalized
Deliveries
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
Year
Ended
|
|
|
|
December
31, 2009
|
|
|
December
31, 2008
|
|
|
|
Increase/(Decrease)
from
|
|
|
Increase/(Decrease)
from
|
|
|
|
same
period in 2008
|
|
|
same
period in 2007
|
|
|
|
Electric
|
|
|
Natural
Gas
|
|
|
Electric
|
|
|
Natural
Gas
|
|
Residential
|
|
|
(2 |
)% |
|
|
(1 |
)% |
|
|
0 |
% |
|
|
(3 |
)% |
Commercial
|
|
|
(3 |
)% |
|
|
0 |
% |
|
|
(2 |
)% |
|
|
(2 |
)% |
Industrial
and other (2)
|
|
|
(10 |
)% |
|
|
(16 |
)% |
|
|
(7 |
)% |
|
|
(5 |
)% |
Total
Deliveries
|
|
|
(4 |
)% |
|
|
(3 |
)% |
|
|
(2 |
)% |
|
|
(3 |
)% |
(2)
|
Excludes
interruptible natural gas
deliveries.
|
Note:
|
Central
Hudson uses an internal analysis based on historical weather data to
remove the estimated impacts of weather on delivery
volumes.
|
Electric
and natural gas deliveries to residential and commercial customers during 2009
and 2008 were negatively impacted by declines in use per customer compared to
the previous year.
For
electric deliveries, the cooler summer weather experienced in both 2009 compared
to 2008 and 2008 compared to 2007, further contributed to the decline in
sales. Natural gas deliveries to residential and commercial customers
in 2009 were favorably impacted by a slight increase in heating degree days, but
were not enough to offset the lower use per customer. Residential and
commercial natural gas heating degree days increased 5% in 2008 as compared to
2007 and had an even larger favorable impact on sales in that
year. However, the colder weather did not result in higher net
delivery volumes for residential and commercial natural gas customers due to the
effects of customer conservation.
Revenues
Central
Hudson’s revenues consist of two major categories: those which offset specific
expenses in the current period (matching revenues), and those that impact
earnings. Matching revenues recover Central Hudson's actual costs for
particular expenses. Any difference between these revenues and the actual
expenses incurred is deferred for future recovery from or refund to customers
and therefore does not impact earnings.
Change in Central Hudson
Revenues
|
|
|
|
|
|
|
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31, 2009
|
|
|
|
Increase/(Decrease)
from same period in 2008
|
|
|
|
Electric
|
|
|
Natural
Gas
|
|
|
Total
|
|
Revenues
with Matching Expense Offsets:(1)
|
|
|
|
|
|
|
|
|
|
Energy
cost adjustment
|
|
$ |
(104,345 |
) |
|
$ |
(19,496 |
) |
|
$ |
(123,841 |
) |
Sales
to others for resale
|
|
|
(479 |
) |
|
|
(3,890 |
) |
|
|
(4,369 |
) |
Other
revenues with matching offsets
|
|
|
20,791 |
|
|
|
3,055 |
|
|
|
23,846 |
|
Subtotal
|
|
|
(84,033 |
) |
|
|
(20,331 |
) |
|
|
(104,364 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
Impacting Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
sales
|
|
|
7,761 |
|
|
|
3,374 |
|
|
|
11,135 |
|
RDM
and other regulatory mechanisms
|
|
|
4,711 |
|
|
|
224 |
|
|
|
4,935 |
|
Finance
charges
|
|
|
8 |
|
|
|
183 |
|
|
|
191 |
|
Weather-hedging
contracts
|
|
|
57 |
|
|
|
113 |
|
|
|
170 |
|
Other
revenues
|
|
|
(495 |
) |
|
|
1,028 |
|
|
|
533 |
|
Subtotal
|
|
|
12,042 |
|
|
|
4,922 |
|
|
|
16,964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Decrease in Revenues
|
|
$ |
(71,991 |
) |
|
$ |
(15,409 |
) |
|
$ |
(87,400 |
) |
(1)
|
Revenues
with matching offsets do not affect earnings since they offset related
costs, the most significant being energy cost adjustment revenues, which
provide for the recovery of purchased electricity and natural gas
costs. Other related costs are pensions, OPEB, and the cost of
special programs authorized by the PSC, which are funded with certain
available credits. Changes in revenues from electric sales to
other utilities also do not affect earnings since any related profits or
losses are returned or charged, respectively, to customers. For
natural gas sales to other entities for resale, 85% of such profits are
returned to customers.
|
Electric
and natural gas revenues decreased in the year ended December 31, 2009, as
compared to the same period in 2008 primarily due to lower energy cost
adjustment revenues. For electric, this resulted from both lower
wholesale prices and lower delivery volumes. For natural gas, this
was primarily driven by lower net gas costs. Lower revenues from gas
sales to others for resale also contributed to the decrease in natural gas
revenues.
These
decreases in both electric and natural gas revenue were partially offset by an
increase in other revenues with matching expense offsets resulting from an
increase in rates related to increased pension costs, New York State (“NYS”)
energy efficiency programs and a new tax surcharge implemented by the PSC. The
reasons for the increase in revenues with matching expense offsets are discussed
in more detail under operating expenses.
The
revenues impacting earnings increased primarily due to an increase in electric
and natural gas delivery rates on customer sales and the RDMs, both of which
became effective July 1, 2009.
Change in Central Hudson
Revenues
|
|
|
|
|
|
|
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31, 2008
|
|
|
|
Increase/(Decrease)
from same period in 2007
|
|
|
|
Electric
|
|
|
Natural
Gas
|
|
|
Total
|
|
Revenues
with Matching Offsets:(1)
|
|
|
|
|
|
|
|
|
|
Energy
cost adjustment
|
|
$ |
(15,903 |
) |
|
$ |
7,594 |
|
|
$ |
(8,309 |
) |
Sales
to others for resale
|
|
|
(2,076 |
) |
|
|
12,298 |
|
|
|
10,222 |
|
Pension,
OPEB and other revenues
|
|
|
3,763 |
|
|
|
3,260 |
|
|
|
7,023 |
|
Subtotal
|
|
|
(14,216 |
) |
|
|
23,152 |
|
|
|
8,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
Impacting Earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer
sales
|
|
|
619 |
|
|
|
921 |
|
|
|
1,540 |
|
Other
regulatory mechanisms
|
|
|
2,481 |
|
|
|
673 |
|
|
|
3,154 |
|
Pole
attachments and other rents
|
|
|
1,022 |
|
|
|
- |
|
|
|
1,022 |
|
Finance
charges
|
|
|
764 |
|
|
|
210 |
|
|
|
974 |
|
Other
revenues
|
|
|
652 |
|
|
|
(859 |
) |
|
|
(207 |
) |
Subtotal
|
|
|
5,538 |
|
|
|
945 |
|
|
|
6,483 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
(Decrease)/Increase in Revenues
|
|
$ |
(8,678 |
) |
|
$ |
24,097 |
|
|
$ |
15,419 |
|
(1)
|
Revenues
with matching offsets do not affect earnings since they offset related
costs, the most significant being energy cost adjustment revenues, which
provide for the recovery of purchased electricity and natural gas
costs. Other related costs are pensions, OPEB, and the cost of
special programs authorized by the PSC, which are funded with certain
available credits. Changes in revenues from electric sales to
other utilities also do not affect earnings since any related profits or
losses are returned or charged, respectively, to customers. For
natural gas sales to other entities for resale, 85% of such profits are
returned to customers.
|
Electric
revenues decreased in the year ended
December 31, 2008, as compared to the same period in 2007 primarily due to lower
energy cost adjustment revenues driven by lower delivery volumes, partially
offset by higher wholesale electricity costs. The increase in
revenues from other regulatory mechanisms was driven primarily by the
absence of shared earnings in 2008.
Natural
gas revenues increased for the year ended December 31, 2008, as compared to the
same period in 2007, due to higher energy cost adjustment revenues as a result
of higher wholesale costs through the third quarter of 2008, partially offset by
lower delivery volumes. The increase for the year was also due to
higher revenues from gas sales to others for resale.
Incentive
Arrangements
Under
certain earnings incentive provisions approved by the PSC, Central Hudson 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 arrangements are currently effective for interruptible natural gas
deliveries and natural gas capacity release transactions. Performance
standards apply to electric service reliability, certain aspects of customer
service, natural gas safety, customer satisfaction, and certain aspects of
retail market participant satisfaction.
The net
results of these and previous earnings sharing arrangements had the effect of
increasing pre-tax earnings by $0.1 million in 2009, $0.7 million in 2008, and
$0.5 million in 2007.
In
addition to the above-noted items, for the period from July 1, 2006 through June
30, 2009, Central Hudson was required to share with customers earnings over a
base ROE of 10.6% on the equity portion of Central Hudson’s rate base, which was
determined in accordance with the criteria set forth in the 2006 Rate
Order. Central Hudson did not record shared earnings in 2009 or
2008. In 2007, Central Hudson recorded $1.1 million as a regulatory
liability for the customer portion of these pre-tax shared
earnings.
See Note
2 - “Regulatory Matters” of this 10-K Annual Report under the caption “2006 Rate
Order” for a description of earnings sharing formulas approved by the PSC for
Central Hudson.
Operating
Expenses
The most
significant elements of Central Hudson’s operating expenses are purchased
electricity and purchased natural gas; however, changes in these costs do not
affect earnings since they are offset by changes in related revenues recovered
through Central Hudson’s energy cost adjustment
mechanisms. Additionally, there are other costs that are matched to
revenues largely from customer billings, notably the cost of NYS energy
efficiency programs, PSC tax surcharge, pensions and OPEBs.
Total
utility operating expenses decreased 13% in 2009 compared to 2008 and increased
3% in 2008 compared to 2007. The following summarizes the change in
operating expenses:
Change in Central Hudson Operating
Expenses
|
|
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
Year
Ended
|
|
|
|
December
31, 2009
|
|
|
December
31, 2008
|
|
|
|
Increase
/ (Decrease) from
|
|
|
Increase
/ (Decrease) from
|
|
|
|
same
period in 2008
|
|
|
same
period in 2007
|
|
Expenses
Currently Matched to Revenues:(1)
|
|
|
|
|
|
|
Purchased
electricity
|
|
$ |
(104,824 |
) |
|
$ |
(17,979 |
) |
Purchased
natural gas
|
|
|
(23,386 |
) |
|
|
19,892 |
|
Pension
|
|
|
7,763 |
|
|
|
(320 |
) |
OPEB
|
|
|
(1,528 |
) |
|
|
(253 |
) |
NYS
energy programs
|
|
|
8,568 |
|
|
|
3,118 |
|
MGP
site remediations
|
|
|
539 |
|
|
|
825 |
|
PSC
tax surcharge
|
|
|
7,115 |
|
|
|
- |
|
Residual
gas deferred balances
|
|
|
242 |
|
|
|
2,791 |
|
Other
matched expenses
|
|
|
1,080 |
|
|
|
718 |
|
Subtotal
|
|
|
(104,431 |
) |
|
|
8,792 |
|
|
|
|
|
|
|
|
|
|
Other
Expense Variations:
|
|
|
|
|
|
|
|
|
Tree
trimming
|
|
|
849 |
|
|
|
2,131 |
|
Uncollectible
expense
|
|
|
4,268 |
|
|
|
3,042 |
|
Uncollectible
deferrals
|
|
|
(3,327 |
) |
|
|
- |
|
Purchased
natural gas incentive arrangements
|
|
|
958 |
|
|
|
(366 |
) |
Storm
restoration expenses(2)
|
|
|
(2,467 |
) |
|
|
3,270 |
|
Property
taxes
|
|
|
1,518 |
|
|
|
1,044 |
|
Depreciation
|
|
|
2,283 |
|
|
|
1,413 |
|
Interest
and carrying charges
|
|
|
1,102 |
|
|
|
1,259 |
|
Other
expenses
|
|
|
2,853 |
|
|
|
(1,104 |
) |
Subtotal
|
|
|
8,037 |
|
|
|
10,689 |
|
|
|
|
|
|
|
|
|
|
Total
(Decrease)/Increase in Operating
Expenses
|
|
$ |
(96,394 |
) |
|
$ |
19,481 |
|
(1)
|
Includes
expenses that, in accordance with the 2006 Rate Order and the 2009 Rate
Order, are adjusted in the current period to equal the revenues earned for
the applicable expenses.
|
(2)
|
Does
not include $3.1 million in incremental costs related to the December 2008
ice storm deferred for future recovery from customers. See
further discussion below.
|
In
addition to the required adjustment to match revenues collected from customers,
the variation in purchased electric and natural gas expense in 2009 reflects the
effects of lower wholesale prices for electricity and natural gas, as well as
lower volumes delivered to electric customers. Purchased electricity
costs decreased in 2008 compared to 2007 primarily due to lower volumes
delivered (resulting from the switch of industrial customers from full service
to delivery service, as well as weather and customer conservation), partially
offset by higher wholesale prices. Purchased natural gas costs
increased in 2008 as compared to 2007 primarily due to higher wholesale prices,
which were only partially offset by lower delivery volumes resulting from
customer conservation.
The
increase in the PSC tax surcharge is due to a new tax surcharge instituted by
the PSC in April 2009. Effective July 1, 2009, the surcharge is being
collected from customers and is expected to total approximately $18 million per
year. The increase in pensions in both 2009 and 2008 is due to an
increase in the level of expenses recorded with a corresponding increase in
revenues resulting from the increase in delivery rates authorized in the 2009
and 2006 Rate Orders. The increase in NYS energy program
expenses relates to the costs of energy efficiency programs under the
Energy Efficiency Portfolio Standard which began in October 2008, as well as,
higher spending levels associated with other energy programs as authorized by
the 2006 and 2009 Rate Orders.
Uncollectible
expense increased in both 2009 and 2008, which management believes is a result
of the unfavorable economic conditions, particularly the rise in unemployment
rates. The higher wholesale prices in 2008 also had an impact on
customers’ ability to pay their bills. Additionally, in 2009 Central
Hudson has deferred approximately $3.3 million of uncollectible expense and
requested PSC authorization for future recovery from customers. The
PSC has approved approximately $0.5 million of this deferral related to gas
uncollectible expenses incurred for the calendar year ended December 31,
2008. The petition requesting authorization for deferral of the
remaining $2.8 million relates to the twelve months ended June 30, 2009 for
electric and the six months ended June 30, 2009 for gas and is still
pending. However, Management cannot predict the outcome of this
filing. If the PSC does not approve the petition in full, Central
Hudson’s expenses would increase by the amount of the petition denied by the
PSC.
Storm
restoration costs can fluctuate from year to year based on changes in the number
and severity of storms each year. Storm restoration costs decreased
in 2009 as compared to 2008, but had increased in 2008 compared to
2007. The increase in 2008 does not include $3.1 million in
incremental costs related to an ice storm in December 2008 which interrupted
service to approximately 72,000 customers. Central Hudson received
authorization from the PSC to recover these incremental restoration costs
through the 2009 Rate Order. The increases in depreciation in 2009
and 2008 are the result of continued investments in Central Hudson’s electric
and natural gas infrastructures. The increases in tree trimming each
year reflect Central Hudson’s continuing efforts to improve system
reliability. Management believes these efforts contributed to
improved system reliability during storms. These costs are covered by
higher revenues resulting from the 2006 and 2009 Rate Orders.
Other
Income
Other
income and deductions for Central Hudson for the year ended December 31, 2009,
decreased $2.1 million, compared to the same period in 2008, primarily due to a
decrease in regulatory carrying charges due from customers related to pension
costs and regulatory adjustments resulting from changes in interest costs on
Central Hudson’s variable rate long-term debt. The latter adjustment
offsets the decrease in interest on the variable rate debt, as discussed under
the caption “Interest Charges.” The impact of these decreases on
earnings was reduced by higher earnings on deferred compensation plan
assets.
Other
income and deductions for Central Hudson for the year ended December 31, 2008,
decreased $0.7 million compared to the same period in 2007, primarily due to
losses on Central Hudson’s deferred compensation plan assets and a reduction in
regulatory carrying charges on balances due from customers.
Interest
Charges
Central
Hudson’s interest charges decreased $0.5 million for the year ended December 31,
2009, compared to the same period in 2008. Increases resulting from
higher outstanding debt balances and increased carrying charges due customers
were offset primarily by a decrease in interest rates on variable rate notes and
short-term borrowings. Issuances of $30 million in medium-term notes
in November 2008 and $24 million in October 2009, offset by the redemption of
$20 million in January 2009, resulted in a net increase in average outstanding
debt during the year. The increase in carrying charges due customers
was primarily related to an increase in the underlying reserve balance for other
post-retirement benefits and carrying charges beginning July 1, 2009 on the net
regulatory electric liability set aside for future customer
benefit. Lower working capital requirements as a result of decreasing
energy prices allowed Central Hudson to decrease short-term
borrowings.
Central
Hudson’s interest charges increased by $2.5 million for the year ended December
31, 2008, compared to the same period in 2007 largely due to an increase in
long-term debt resulting primarily from the issuance of medium-term notes in
September 2007 and also from the issuance of medium-term notes in November
2008. The proceeds from both issuances were used to finance ongoing
investments in Central Hudson’s electric and natural gas
systems.
The
following table sets forth pertinent data on Central Hudson’s outstanding debt
(Dollars in Thousands):
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Long-Term
Debt:
|
|
|
|
|
|
|
|
|
|
Debt
retired
|
|
$ |
20,000 |
|
|
$ |
- |
|
|
$ |
33,000 |
|
Debt
issued
|
|
$ |
24,000 |
|
|
$ |
30,000 |
|
|
$ |
66,000 |
|
Outstanding
at year end:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
(including current portion)
|
|
$ |
437,897 |
|
|
$ |
433,894 |
|
|
$ |
403,892 |
|
Weighted
average interest rate
|
|
|
4.78 |
% |
|
|
5.43 |
% |
|
|
5.49 |
% |
Short-Term
Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
daily amount outstanding
|
|
$ |
21,962 |
|
|
$ |
32,304 |
|
|
$ |
32,501 |
|
Weighted
average interest rate
|
|
|
0.98 |
% |
|
|
3.00 |
% |
|
|
5.37 |
% |
Overall
weighted average interest rate
|
|
|
4.39 |
% |
|
|
5.26 |
% |
|
|
5.48 |
% |
See
Note 7 - “Short-Term Borrowing Arrangements” and Note 9 -
“Capitalization - Long-Term Debt” for additional information on short-term and
long-term debt of CH Energy Group and/or Central Hudson.
Income
Taxes
Income
taxes for Central Hudson increased $1.9 million for the year ended December 31,
2009 when compared to the same period in 2008 primarily due to an increase in
pre-tax book income.
Income
taxes for Central Hudson decreased $1.1 million in 2008 when compared to 2007
due to a decrease in pre-tax book earnings which was partially offset by the
unfavorable impacts of flow-through items related to depreciation, reserves
(primarily uncollectible customer receivables) and the Medicare Act of 2003 and
a reduction in tax-exempt income.
CH ENERGY
GROUP
In
addition to the impacts of Central Hudson discussed above, CH Energy Group’s
sales volumes, revenues and operating expenses, income taxes and other income
were impacted by Griffith and the other businesses described
below. The results of Griffith and the other businesses described
below exclude inter-company interest income and expense which are eliminated in
consolidation.
Income
Statement Variances
|
|
|
|
|
|
|
(Dollars
In Thousands)
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
|
December
31, 2009
|
|
|
|
Over/(Under)
same period
|
|
|
|
in
2008
|
|
|
|
Amount
|
|
|
Percent
|
|
Operating
Revenues
|
|
$ |
(207,612 |
) |
|
|
(18.2 |
)% |
Operating
Expenses:
|
|
|
|
|
|
|
|
|
Purchased
electricity, fuel, natural gas and petroleum
|
|
|
(245,496 |
) |
|
|
(31.9 |
)% |
Depreciation
and amortization
|
|
|
2,445 |
|
|
|
6.9 |
% |
Other
operating expenses
|
|
|
25,992 |
|
|
|
9.9 |
% |
Total
Operating Expenses
|
|
|
(217,059 |
) |
|
|
(20.3 |
)% |
Operating
Income
|
|
|
9,447 |
|
|
|
13.2 |
% |
Other
Income, net
|
|
|
(5,047 |
) |
|
|
(95.9 |
)% |
Interest
Charges
|
|
|
1,504 |
|
|
|
6.2 |
% |
Income
before income taxes, non-controlling interest and preferred dividends of
subsidiaries
|
|
|
2,896 |
|
|
|
5.5 |
% |
Income
Taxes
|
|
|
1,078 |
|
|
|
5.5 |
% |
Net
income from continuing operations
|
|
|
1,818 |
|
|
|
5.5 |
% |
Net
income from discontinued operations, net of tax
|
|
|
6,306 |
|
|
|
183.5 |
% |
Net
loss attributable to non-controlling interest
|
|
|
(279 |
) |
|
|
(26.0 |
)% |
Net
income attributable to CH Energy Group
|
|
$ |
8,403 |
|
|
|
24.0 |
% |
Income
Statement Variances
|
|
|
|
|
|
|
(Dollars
in Thousands)
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
|
December
31, 2008
|
|
|
|
Over/(Under)
same period
|
|
|
|
in
2007
|
|
|
|
Amount
|
|
|
Percent
|
|
Operating
Revenues
|
|
$ |
60,434 |
|
|
|
5.6 |
% |
Operating
Expenses:
|
|
|
|
|
|
|
|
|
Purchased
electricity, fuel, natural gas and petroleum
|
|
|
42,121 |
|
|
|
5.8 |
% |
Depreciation
and Amortization
|
|
|
1,356 |
|
|
|
4.0 |
% |
Other
operating expenses
|
|
|
21,664 |
|
|
|
9.0 |
% |
Total
Operating Expenses
|
|
|
65,141 |
|
|
|
6.5 |
% |
Operating
Income
|
|
|
(4,707 |
) |
|
|
(6.2 |
)% |
Other
Income, net
|
|
|
(3,759 |
) |
|
|
(41.7 |
)% |
Interest
Charges
|
|
|
2,575 |
|
|
|
11.9 |
% |
Income
before income taxes, non-controlling interest and preferred dividends of
subsidiaries
|
|
|
(11,041 |
) |
|
|
(17.5 |
)% |
Income
Taxes
|
|
|
(1,646 |
) |
|
|
(7.9 |
)% |
Net
loss from continuing operations
|
|
|
(9,395 |
) |
|
|
(22.4 |
)% |
Net
income from discontinued operations, net of tax
|
|
|
2,064 |
|
|
|
139.4 |
% |
Net
income attributable to non-controlling interest
|
|
|
224 |
|
|
|
26.4 |
% |
Net
income attributable to CH Energy Group
|
|
$ |
(7,555 |
) |
|
|
(17.6 |
)% |
GRIFFITH
Sales
Volumes
Delivery
and sales volumes for Griffith vary in response to weather conditions and
customer behavior. Deliveries of petroleum products used for heating
purposes peak in the winter. Sales also vary as customers respond to
the price of the particular energy product and changes in local economic
conditions.
Changes
in sales volumes of petroleum products, including the impact of acquisitions,
are set forth below.
Actual Deliveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
Year
Ended
|
|
|
|
December
31, 2009
|
|
|
December
31, 2008
|
|
|
|
%
Change
from
same period in 2008
|
|
|
2009
Volumes
as % of Total Volume
|
|
|
%
Change
from
same period in 2007
|
|
|
2008
Volumes
as % of Total Volume
|
|
Heating
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
company volume
|
|
|
- |
% |
|
|
29 |
% |
|
|
(9 |
)% |
|
|
25 |
% |
Divested
volume
|
|
|
(7 |
)% |
|
|
24 |
% |
|
|
11 |
% |
|
|
25 |
% |
Total
Heating Oil
|
|
|
(7 |
)% |
|
|
53 |
% |
|
|
2 |
% |
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Motor
Fuels
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
company volume
|
|
|
(15 |
)% |
|
|
34 |
% |
|
|
(9 |
)% |
|
|
38 |
% |
Divested
volume
|
|
|
(5 |
)% |
|
|
9 |
% |
|
|
7 |
% |
|
|
10 |
% |
Total
Motor Fuels
|
|
|
(20 |
)% |
|
|
43 |
% |
|
|
(2 |
)% |
|
|
48 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane
and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
company volume
|
|
|
50 |
% |
|
|
2 |
% |
|
|
(3 |
)% |
|
|
1 |
% |
Divested
volume
|
|
|
14 |
% |
|
|
2 |
% |
|
|
12 |
% |
|
|
1 |
% |
Total
Propane and Other
|
|
|
64 |
% |
|
|
4 |
% |
|
|
9 |
% |
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
company volume
|
|
|
(6 |
)% |
|
|
65 |
% |
|
|
(9 |
)% |
|
|
64 |
% |
Divested
volume
|
|
|
(6 |
)% |
|
|
35 |
% |
|
|
9 |
% |
|
|
36 |
% |
Total
|
|
|
(12 |
)% |
|
|
100 |
% |
|
|
- |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note
1:
|
For
the purposes of this chart, acquisitions made in 2008 and 2009 are
included in either Retained company volume or Divested volume depending
upon whether the acquisition was retained or
divested.
|
Note
2:
|
For
the purposes of this chart, acquisitions made in 2007 and 2008 are
included in either Retained company volume or Divested volume depending
upon whether the acquisition was retained or
divested.
|
Weather Normalized
Deliveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
Year
Ended
|
|
|
|
December
31, 2009
|
|
|
December
31, 2008
|
|
|
|
%
Change
from
same period in 2008
|
|
|
2009
Volumes
as % of Total Volume
|
|
|
%
Change
from
same period in 2007
|
|
|
2008
Volumes
as % of Total Volume
|
|
Heating
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
company volume
|
|
|
(4 |
)% |
|
|
28 |
% |
|
|
(8 |
)% |
|
|
25 |
% |
Divested
volume
|
|
|
(9 |
)% |
|
|
24 |
% |
|
|
12 |
% |
|
|
25 |
% |
Total
Heating Oil
|
|
|
(13 |
)% |
|
|
52 |
% |
|
|
4 |
% |
|
|
50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
. |
|
Motor
Fuels
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
company volume
|
|
|
(15 |
)% |
|
|
35 |
% |
|
|
(9 |
)% |
|
|
38 |
% |
Divested
volume
|
|
|
(5 |
)% |
|
|
9 |
% |
|
|
7 |
% |
|
|
10 |
% |
Total
Motor Fuels
|
|
|
(20 |
)% |
|
|
44 |
% |
|
|
(2 |
)% |
|
|
48 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane
and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
company volume
|
|
|
46 |
% |
|
|
2 |
% |
|
|
(3 |
)% |
|
|
1 |
% |
Divested
volume
|
|
|
10 |
% |
|
|
2 |
% |
|
|
13 |
% |
|
|
1 |
% |
Total
Propane and Other
|
|
|
56 |
% |
|
|
4 |
% |
|
|
10 |
% |
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
company volume
|
|
|
(8 |
)% |
|
|
65 |
% |
|
|
(8 |
)% |
|
|
64 |
% |
Divested
volume
|
|
|
(7 |
)% |
|
|
35 |
% |
|
|
10 |
% |
|
|
36 |
% |
Total
|
|
|
(15 |
)% |
|
|
100 |
% |
|
|
2 |
% |
|
|
100 |
% |
Note
1:
|
Due
to a warming trend in actual weather over the past 30 years, Griffith has
developed a trend normal weather value. This trend analysis has
resulted in approximately 670 and 150 less heating degree-days as compared
to a standard 30-year average for Griffith's customers in the Northeast
and Mid-Atlantic regions, respectively. The above chart of
weather normalized deliveries was determined using Griffith's trend normal
weather value.
|
Note
2:
|
For
the purposes of this chart, acquisitions made in 2008 and 2009 are
included in either Retained company volume or Divested volume depending
upon whether the acquisition was retained or
divested.
|
Note
3:
|
For
the purposes of this chart, acquisitions made in 2007 and 2008 are
included in either Retained company volume or Divested volume depending
upon whether the acquisition was retained or
divested.
|
Sales of
petroleum products decreased 12% in the year ended December 31, 2009 compared to
the same period in 2008. The decrease was due primarily to reduced
consumption by residential and motor fuel customers in response to the weakened
economy, and to a lesser extent, the divestiture in December. The
decrease in customer usage was partially offset by increased heating oil volume
related to weather that was 7.2% colder in heating degree-days in 2009 as
compared to 2008. Degree-day variation is adjusted for the delay
between the time the actual weather occurs, and the time of product
delivery.
Sales of
petroleum products increased 1% in the year ended December 31, 2008 compared to
the same period in 2007. The increase was due primarily to
acquisitions made in 2008 and 2007, partially offset by reduced consumption
caused by price-related conservation. Additionally, there was a 2%
decrease in heating degree-days in 2008 as compared to
2007. Degree-day variation is adjusted for the delay between the time
the actual weather occurs, and the time of product delivery.
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Griffith
Revenues
|
|
|
|
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
Year
Ended
|
|
|
|
December
31, 2009
|
|
|
December
31, 2008
|
|
|
|
Increase
/ (Decrease) from same period in 2008
|
|
|
Increase
/ (Decrease) from same period in 2007
|
|
Heating
Oil
|
|
|
|
|
|
|
Retained
company
|
|
$ |
(33,162 |
) |
|
$ |
9,848 |
|
Divested
Revenue
|
|
|
(44,569 |
) |
|
|
43,134 |
|
Total
Heating Oil
|
|
$ |
(77,731 |
) |
|
$ |
52,982 |
|
Motor
Fuels
|
|
|
|
|
|
|
|
|
Retained
company
|
|
$ |
(85,439 |
) |
|
$ |
31,032 |
|
Divested
Revenue
|
|
|
(24,408 |
) |
|
|
24,719 |
|
Total
Motor Fuels
|
|
$ |
(109,847 |
) |
|
$ |
55,751 |
|
Other
|
|
|
|
|
|
|
|
|
Retained
company
|
|
$ |
(343 |
) |
|
$ |
527 |
|
Divested
Revenue
|
|
|
(1,270 |
) |
|
|
992 |
|
Total
Propane
|
|
$ |
(1,613 |
) |
|
$ |
1,519 |
|
Service
Revenues
|
|
|
|
|
|
|
|
|
Retained
company
|
|
$ |
427 |
|
|
$ |
(697 |
) |
Divested
Revenue
|
|
|
(653 |
) |
|
|
6,557 |
|
Total
Service Revenues
|
|
$ |
(226 |
) |
|
$ |
5,860 |
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
Weather-hedging
contracts
|
|
$ |
(247 |
) |
|
$ |
938 |
|
Retained
- Other
|
|
|
(211 |
) |
|
|
796 |
|
Other
- Divestiture
|
|
|
(75 |
) |
|
|
256 |
|
Total
Other
|
|
$ |
(533 |
) |
|
$ |
1,990 |
|
|
|
|
|
|
|
|
|
|
Total
Revenues
|
|
$ |
(189,950 |
) |
|
$ |
118,102 |
|
Note
1:
|
For
the purposes of this chart, acquisitions made in 2008 and 2009 are
included in either Retained company revenue or Divested revenue depending
upon whether the acquisition was retained or
divested.
|
Note
2:
|
For
the purposes of this chart, acquisitions made in 2007 and 2008 are
included in either Retained company revenue or Divested revenue depending
upon whether the acquisition was retained or
divested.
|
Revenues,
net of the effect of weather hedging contracts decreased in the year ended
December 31, 2009 compared to 2008, due primarily to a decrease in the selling
price, reduced volumes and the divestiture in mid-December.
Revenues,
net of the effect of weather hedging contracts, increased in the year ended 2008
compared to 2007, due largely to an increase in the selling price and revenues
from petroleum products resulting from the acquisitions made in 2008 and
2007.
Operating
Expenses
For the
year ended December 31, 2009, operating expenses, net of divested operations,
decreased $121.0 million, or 37%, from $326.6 million in 2008 to $205.6 million
in 2009. The cost of petroleum products decreased $117.1 million, or
44%, due to lower wholesale market prices and a decrease in sales
volume.
Other
operating expenses decreased $4.6 million for the year ended December 31, 2009
due primarily to lower costs associated with lower oil prices, effective cost
reduction initiatives, and the divestiture of its Connecticut, Pennsylvania, and
Rhode Island assets.
For the
year ended December 31, 2008, operating expenses, net of divested operations,
increased $43.9 million, or 16%, from $282.7 million in 2007 to $326.6 million
in 2008. The cost of petroleum products increased $39.3 million, or
17% due to higher wholesale market prices and an increase in sales volume due to
the impact of acquisitions.
Other
operating expenses increased $4.6 million for the year ended December 31, 2008
due primarily to an increase in expenses associated with the increased sales
volumes, additional operating and overhead expenses associated with acquisitions
made during 2008 and 2007, and an increase in the allowance for doubtful
accounts.
OTHER BUSINESSES AND
INVESTMENTS
Revenues
and Operating Expenses
The
operating results of Lyonsdale, CH-Greentree and CH Shirley are consolidated in
the Consolidated Financial Statements of CH Energy Group. Results for
the year ended December 31, 2009 compared to the same period in 2008 reflect a
decrease in operating revenues of $1.2 million and essentially no change in
operating expenses with a net decrease in CH Energy Group’s net income of $0.5
million. This is primarily attributable to the outage for equipment
repairs at Lyonsdale in the second quarter of 2009. CH-Greentree became operational in
the third quarter of 2009.
Lyonsdale’s
operating results in 2008 reflect an increase in operating revenue of $2.6
million and increased total operating expenses of $1.6 million with a net
increase in CH Energy Group’s net income of $0.5 million. The
increased capacity factor at Lyonsdale and higher sales of Renewable Energy
Credits in 2008 as compared to 2007 were partially offset by higher fuel
costs.
Other
Income and Interest Charges
Other
income and deductions and interest charges for the balance of CH Energy Group,
primarily the holding company and CHEC’s investments in partnerships and other
investments (other than Griffith), decreased $5.3 million for the year ended
December 31, 2009, when compared to the same period in 2008. The
decrease is due to an increase in interest expense related to the private
placement of debt at the holding company in the second quarter of 2009 and lower
earnings at the partnerships. This decrease also includes the
write-off of $1.2 million for the full amount of an outstanding loan to
Buckeye.
Other
income and deductions for the balance of CH Energy Group, primarily the holding
company and CHEC’s investments in partnerships and other investments (other than
Griffith), decreased $2.9 million for the year ended December 31, 2008, when
compared to the same period in 2007. Nearly half of this decrease is
attributable to lower interest and investment income resulting from the
redeployment of capital from short-term investments to CH Energy Group’s
subsidiaries. Lower earnings of CHEC’s Cornhusker Holdings
investment, as a result of lower margins, also impacted these
results.
CH ENERGY GROUP - INCOME
TAXES
Income
taxes on income from continuing operations for CH Energy Group increased $1.1
million for the year ended December 31, 2009, when compared to the same period
in 2008 due to an increase in pre-tax book income and higher taxes incurred at
the holding company resulting primarily from the gain on the sale of Griffith’s
operations in certain geographic locations. Income taxes on income
from discontinued operations increased $4.5 million due to an increase in
pre-tax book income related to the discontinued operations as well as higher
taxes incurred by Griffith as a result of the gain on the Griffith
sale.
Income
taxes on income from continuing operations for CH Energy Group decreased $1.6
million in 2008 when compared to 2007 due to lower taxes at Central Hudson and
decreased pre-tax book earnings at CHEC. These favorable variations
were partially offset by the unfavorable impact of a reduction in tax-exempt
income at the holding company. Income taxes on income from
discontinued operations for CH Energy Group increased $1.6 million due to an
increase in pre-tax book income related to the divested operations of
Griffith.
COMMON
STOCK DIVIDENDS AND PRICE RANGES
CH Energy
Group and its principal predecessors (including Central Hudson) have paid
dividends on their respective Common Stock in each year commencing in 1903, and
the Common Stock has been listed on the New York Stock Exchange since
1945. The closing price as of December 31, 2009 and 2008 was $42.52
and $51.39, respectively. The price ranges and the dividends paid for
each quarterly period during the last two fiscal years are as
follows:
|
|
2009
|
|
|
2008
|
|
|
|
High
|
|
|
Low
|
|
|
Dividend
|
|
|
High
|
|
|
Low
|
|
|
Dividend
|
|
1st
Quarter
|
|
$ |
52.66 |
|
|
$ |
37.68 |
|
|
$ |
0.54 |
|
|
$ |
45.38 |
|
|
$ |
34.53 |
|
|
$ |
0.54 |
|
2nd
Quarter
|
|
|
48.16 |
|
|
|
40.60 |
|
|
|
0.54 |
|
|
|
40.73 |
|
|
|
34.25 |
|
|
|
0.54 |
|
3rd
Quarter
|
|
|
51.32 |
|
|
|
43.67 |
|
|
|
0.54 |
|
|
|
48.92 |
|
|
|
34.00 |
|
|
|
0.54 |
|
4th
Quarter
|
|
|
45.57 |
|
|
|
39.54 |
|
|
|
0.54 |
|
|
|
52.36 |
|
|
|
33.39 |
|
|
|
0.54 |
|
In 2009,
CH Energy Group maintained its quarterly dividend rate at $0.54 per
share. In making future dividend decisions, CH Energy Group will
evaluate all circumstances at the time of making such decisions, including
business, financial, and regulatory considerations.
The
Settlement 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 CH Energy Group
or any CH 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 to a rating below “BBB+,” (ii) 50%, if the senior debt
were placed on “Credit Watch” (or the equivalent) with a rating below “BBB,” or
(iii) no dividends payable if the downgrade were to a rating below
“BBB-.” These limitations survived the June 30, 2001, expiration
of the Settlement Agreement. Central Hudson is currently rated “A” or
the equivalent for the purposes of these limitations and therefore the
limitations noted above do not apply.
The
number of registered holders of Common Stock of CH Energy Group as of December
31, 2009 was 14,926.
All of
the outstanding Common Stock of Central Hudson and all of the outstanding Common
Stock of CHEC is held by CH Energy Group.
OTHER
MATTERS
PENSION PROTECTION
ACT
On August
17, 2006, President Bush signed the Pension Protection Act into
law. The Pension Protection Act introduces new funding requirements
for single and multi-employer defined benefit pension plans, addresses plan
design for cash balance and other hybrid plans, and addresses contributions to
defined contribution plans, deduction limits for contributions to retirement
plans, and investment advice provided to plan participants. The new
defined benefit funding rules are effective for plan years beginning after
December 31, 2007. Certain transition rules apply for 2008 through
2010. For additional discussion regarding the Pension Protection Act,
please see the “Retirement Plan” discussion that follows.
CHANGES IN ACCOUNTING
STANDARDS
See
Note 3 - “New Accounting Guidance” for a discussion of the status of new
accounting guidance issued.
RETIREMENT
PLAN
As
described more fully in Note 10 - “Post-Employment Benefits,” Central
Hudson has a non-contributory Retirement Income Plan (“Retirement Plan”)
covering substantially all of its employees hired on or before January 1,
2008. The Retirement Plan is a defined benefit plan, which provides
pension benefits based on an employee’s compensation and years of
service. In 2007, Central Hudson amended the Retirement Plan to
eliminate these benefits for managerial, professional, and supervisory employees
hired on or after January 1, 2008. The Retirement Plan for unionized
employees was similarly amended for employees hired on or after May 1,
2008.
The
significant assumptions and estimates used to account for the Retirement Plan
are the discount rate, the expected long-term rate of return on Retirement Plan
assets, the rate of compensation increase, and the method of amortizing gains
and losses.
The
discount rate was determined as of December 31, 2009 based on the rate at which
obligations could be effectively settled. The rate is based on the
Citigroup Pension Discount Curve. Central Hudson selects the rate
after consultation with its actuarial consultant. Central Hudson’s
discount rate was 5.7% and 6.2% as of the most recent valuation dates, December
31, 2009 and December 31, 2008, respectively.
In
determining the expected long-term rate of return on Retirement Plan assets,
Central Hudson considered the current level of expected returns on risk-free
investments (primarily United States government bonds), the historical level of
risk premiums associated with other asset classes, and the expectations of
future returns over a 20-year time horizon on each asset class. The
expected return for each asset class was then weighted based on the Retirement
Plan’s target asset allocation. Central Hudson also considered
expectations of value-added by active management, net of investment
expenses.
The rate
of compensation increase was based on historical and current compensation
practices of Central Hudson giving consideration to any anticipated changes in
this practice.
Actuarial
gains and losses, which include investment returns and demographic experience
which are different than anticipated based on the actuarial assumptions, are
amortized in accordance with procedures set forth by the PSC which require the
full gain or loss arising each year to be amortized uniformly over ten
years. The net losses are currently $152.1 million, including
losses for the years 2000 through 2009. Therefore, the future annual
amortization of these losses will increase pension expense, determined in
accordance with current accounting guidance related to pensions (FASB Accounting
Standards Codification (“ASC”) 715-20), from its current level unless there are
offsetting future gains or other offsetting components of pension
expense.
Based on
current levels of Retirement Plan assets and obligations, a change of 0.25% in
the long-term rate of return assumption would change pension expense by
approximately $0.6 million and a change of
0.25% in the discount rate would change pension expense by approximately $1.2
million.
Under the
policy of the PSC regarding pension costs, Central Hudson recovers its net
periodic pension and OPEB costs through customer rates with differences from
rate allowances deferred for future recovery from or return to
customers. As a result, Central Hudson expects to fully recover its
net periodic pension and OPEB costs over time. The Retirement Plan’s
liquidity is primarily affected by the cash contributions made by Central Hudson
to the Retirement Plan. Central Hudson contributed $22.6 million and
$12.5 million to the Retirement Plan in 2009 and 2008,
respectively. Based on the funding requirements of the Pension
Protection Act, Central Hudson plans to make contributions that maintain the
target funded percentage at 80% or higher. On January 22, 2010,
Central Hudson contributed $30 million to its Retirement
Plan. Central Hudson’s contributions for 2010 are expected to total
approximately $30-$55 million, resulting in a funded status that meets Central
Hudson’s objective. The actual contributions could vary significantly
based upon economic growth, corporate resources, projected investment returns,
actual investment returns, inflation, and interest rate
assumptions.
Management
is reviewing changes to the Plan’s investment strategy to reduce the
year-to-year volatility of the funded status and the level of
contributions. Options being considered include extending the
duration of the Plan’s investments as well as changes to the target asset
allocation to more closely align with the Plan’s long-term
obligations.
For
additional information regarding the Retirement Plan, see Note 10 -
“Post-Employment Benefits.”
CLIMATE
While it
is possible that some form of global climate change program will be adopted
at the federal level in 2010, it is too early to determine what impact such
program will have on CH Energy Group. It should be noted, however,
that the Company's calculated CO2 emission
levels are relatively small, primarily because the Company does not generate
electricity in significant quantities. Therefore, federally mandated
greenhouse gas reductions or limits on CO2 emissions
are not expected to have a material impact on the Company’s financial position
or results of operations. However, the Company can make no prediction as to the
outcome of this matter. If the cost of CO2 emissions
causes purchased electricity and natural gas costs to rise, such increases are
expected to be collected through automatic adjustment clauses. If
sales are depressed by higher costs through price elasticity, the RDM mechanisms
are expected to prevent an earnings impact on the Company.
CRITICAL
ACCOUNTING POLICIES
REGULATION
The
Financial Statements were prepared in conformity with accounting principles
generally accepted in the United States of America (“GAAP”), which for regulated
public utilities, includes specific guidance for Regulated Operations (Financial
Accounting Standard Board’s (“FASB”) Accounting Standards Codification (“ASC”)
980). For additional information regarding regulatory accounting, see
Note 2 – “Regulatory Matters”.
USE OF
ESTIMATES
Preparation
of the Consolidated Financial Statements in accordance with accounting
principles generally accepted in The United States of America (“GAAP”) includes
the use of estimates and assumptions by management that affect financial
results. Actual results may differ from those estimated; however the
methods used by CH Energy Group to prepare estimates have historically produced
reliable results.
Expense
items most affected by the use of estimates are depreciation and amortization
(including amortization of intangible assets), reserves for uncollectible
accounts receivable, other operating reserves, unbilled revenues, and pension
and other post-retirement benefits.
Depreciation
and amortization is based on estimates of the useful lives and estimated net
salvage value of properties. For Central Hudson, these estimates are
subject to change as the result of a future rate
proceeding. Historical changes have not been material to the
Company’s financial results. For Griffith and Lyonsdale, any changes
in estimates used for depreciation are not expected to have a material impact on
CH Energy Group’s financial results. The amortization of CH Energy
Group’s other intangible assets is discussed in detail below under the caption
“Goodwill and Other Intangible Assets.”
Estimates
for uncollectible accounts are based on customer accounts receivable aging data
as well as consideration of various quantitative and qualitative factors,
including economic factors such as future outlooks for the economy, unemployment
rates, energy prices and special collection issues. The
estimates for other operating reserves are based on assessments of future
obligations related to injuries and damages and workers compensation
claims. Unbilled revenues are determined based on the estimated sales
for bi-monthly accounts that have not been billed by Central Hudson in the
current month. The estimation methods used in determining these sales
are the same methods used for billing customers when actual meter readings
cannot be obtained. Historical changes to these items have not been
material to the Company’s financial results.
See Note
1 - “Summary of Significant Accounting Policies” under the caption “Use of
Estimates” to the Consolidated Financial Statements of this 10-K Annual Report
for additional discussion.
GOODWILL AND OTHER
INTANGIBLE ASSETS
The
balances reflected on CH Energy Group’s Consolidated Balance Sheet at December
31, 2009 and December 31, 2008 for “Goodwill” and “Other intangible assets -
net” relate to Griffith. 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
accordance with current accounting guidance related to goodwill and other
intangible assets (ASC 350), both goodwill and intangible assets not subject to
amortization are tested at least annually for impairment and whenever events or
circumstances make it more likely than not that an impairment may have occurred,
such as a significant adverse change in the business climate or a decision to
sell or dispose of a reporting unit. In assessing whether an
impairment exists the fair value of the reporting units is compared to the
carrying amount of assets. Fair value of goodwill is estimated using
a weighted average of the discounted cash flow and market approach
methodologies. In applying this methodology to the discounted cash flow,
reliance is placed on a number of factors, including actual operating results,
future business plans, economic projections and market data. The
carrying amount for goodwill was $35.7 million as of December 31, 2009, and
$67.5 million as of December 31, 2008. Historical impairment tests
have not resulted in the recognition of any impairment. However, if the
operating cash flows of Griffith decline significantly in the future, the result
could be recognition of a future goodwill impairment charge to operations and
the amount could be material to CH Energy Group's Consolidated Financial
Statements. However, given the accelerated recovery of $10 million of
goodwill as a result of the 2009 divestiture, and the significant excess of fair
value over the book value of the Company, Management believes the likelihood of
any such write-off is remote.
The most
significant assumptions used in the discounted cash flow valuation regarding
Griffith’s fair value in connection with goodwill valuations are: (1) detailed
five-year cash flow projections, (2) the risk adjusted discount rate, and (3)
Griffith’s expected long-term growth rate, which approximates the growth rate
imputed from the discrete period cash flow projections on key aspects of the
business. The primary drivers of Griffith's cash flow projections include
sales volumes, margin rates and expense inflation, particularly for
labor. The risk adjusted discount rate represents Griffith’s weighted
average cost of capital and is established based on (1) the 30-year risk-free
rate, which is impacted by events external to Griffith, such as investor
expectations regarding economic activity, (2) Griffith’s required rate of return
on equity, and (3) the current after-tax rate of return on debt. In
valuing its goodwill for 2009, Griffith used an average risk-adjusted discount
rate of 10.1%. Had the risk-adjusted discount rate been 25 basis points
higher, the aggregate estimated fair value of the reporting units would have
decreased by $2.4 million, or 1.6%. In addition, Griffith used an average
expected terminal growth rate of 1.5%. If the expected terminal
growth rate was 25 basis points lower, the aggregate estimated fair value of the
reporting units would have decreased by $1.7 million, or 1.1%. Had each
year in Griffith’s five-year cash flow projections been lower by 1.0%, the
aggregate estimated fair value of the reporting units would have decreased by
$0.4 million, or 0.2%. As of September 30, 2009, the fair value of
goodwill as calculated was approximately $49.6 million above its carrying
value.
Other
intangible assets - net relate to Griffith and are comprised of customer
relationships, trademarks and covenants not to compete. If events
indicate that an impairment exists, these assets are tested for impairment by
comparing the carrying amount to the sum of undiscounted cash flows expected to
be generated by the asset.
In
accordance with current accounting guidance (ASC 350), intangible assets that
have finite useful lives continue to be amortized over their useful
lives. The estimated useful life for customer relationships is 15
years, which is believed to be appropriate in view of average historical
customer attrition. The useful lives of trademarks were estimated to
range from 10 to 15 years based upon Management’s assessment of several
variables such as brand recognition, Management’s expected use of the trademark,
and other factors that may have affected the duration of the trademark’s
life. The useful life of a covenant not to compete is based on the
expiration date of the covenant, generally between three and ten
years. Amortization expense was $4.0 million, $4.1 million and $3.4
million for each of the years ended December 31, 2009, 2008 and 2007,
respectively. The estimated annual amortization expense for each of
the next five years, assuming no new acquisitions, is approximately $2.3
million. The weighted average amortization period for all amortizable
intangible assets is 14.97 years. The weighted average
amortization periods for customer relationships and covenants not to compete are
15 years and 5 years, respectively. In December 2009, Griffith sold
the rights to all its trademarks as part of the sale of select operations
discussed further below. The estimated useful life of Griffith’s
customer relationships is tested annually based on actual
experience. The amortizable life of these assets has not changed
since Griffith was acquired.
See Note
6 - “Goodwill and Other Intangible Assets” of this 10-K Annual Report 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.
The
significant assumptions and estimates used to account for the Retirement Plan
and other post-retirement benefit expenses and liabilities are the discount
rate, the expected long-term rate of return on the pension plan and other
post-retirement plan assets, health care cost trend rate, the rate of
compensation increase, mortality assumptions, and the method of amortizing gains
and losses.
For 2009
the Projected Benefit Obligation (“PBO”) for Central Hudson’s Retirement Plan
($467.2 million) and its obligation for OPEB costs ($127.1 million) were both
determined using 5.7% discount rates. This rate was determined using
the Citigroup Pension Discount Curve reflecting projected cash
flows. A 0.25% change in the discount rate would affect the
projection of the pension PBO by approximately $13.7 million and the OPEB
obligation by approximately $3.8 million. Investment losses in the
years 2000 through 2002, and a reduction in the discount rate during that period
have resulted in a significant increase in pension and OPEB costs since
2001. Declines in the market value of the Trust Funds investment
portfolio in 2008 resulted in significant future increases in pension
costs. During 2009, the financial markets experienced less volatility
than the level experienced in 2008 and the value of the Retirement Plan and OPEB
assets increased by $52.9 million and $14.5 million,
respectively. These increases reduced the underfunded status of these
plans. However, the decrease in discount rates from 2008 increased
the present value of the plans’ liabilities. The net effect on the
funded status of the plans from the financial markets and the discount rates was
a decrease in the unfunded liability by $9.2 million and $6.4 million,
respectively. If future market conditions do not improve sufficiently
to completely offset the volatility of 2008, additional contributions will
likely become necessary under the terms of the Pension Protection Act of
2006. Management expects that such contributions will be incorporated
in the rate making process over time. Central Hudson has investment
policies for these plans which include asset allocation ranges designed to
achieve a reasonable return over the long-term, recognizing the impact of market
volatility. Central Hudson monitors actual performance against target
asset allocations and adjusts actual allocations and targets as deemed
appropriate in accordance with the Retirement Plan strategy. A 0.25%
change in the discount rate would impact the net periodic benefit cost by $1.2
million for the Retirement Plan and $0.3 million for OPEBs. In order
to reduce the total costs of benefits, OPEB plan changes were negotiated with
the IBEW Local 320 for unionized employees and certain retired employees
effective May 1, 2008.
Central
Hudson amortizes actuarial gains and losses related to these obligations over
ten years in accordance with PSC-prescribed provisions.
The
expected long-term rate of return on Retirement Plan and OPEB assets are 7.75%
and 8.00%, net of investment expense. In determining the expected
long-term rate of return on these assets, Central Hudson considered the current
level of expected returns on risk-free investments (primarily United States
government bonds), the historical level of risk premiums associated with other
asset classes, and the expectations of future returns over a 20-year time
horizon on each asset class, based on the views of leading financial advisors
and economists. The expected return for each asset class was then
weighted based on each plan’s target asset allocation. Central Hudson
also considered expectations of value-added by active management, net of
investment expenses. The actual annual return on Central Hudson’s
Retirement Plan and OPEB assets over the previous three years are summarized as
follows:
Calendar
Year Performance
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Central
Hudson Retirement Plan
|
|
|
21.2 |
% |
|
|
(30.0 |
)% |
|
|
6.9 |
% |
Central
Hudson OPEB (1)
|
|
|
27.9 |
% |
|
|
(26.4 |
)% |
|
|
5.0 |
% |
Central
Hudson OPEB (1)
|
|
|
24.6 |
% |
|
|
(25.0 |
)% |
|
|
4.1 |
% |
(1)
|
OPEB
assets are comprised of two separate groups of investment
funds
|
A 25
basis point decrease in the expected long-term rate of return on Retirement Plan
and OPEB assets would have the following impact: increase the net periodic
benefit cost by $0.6 million for the pension plan and $0.2 million for
OPEBs. The expected long-term rate of return is reviewed annually in
the fourth quarter and updated if the determinants have changed.
The
estimates of health care cost trend rates are based on a review of actual recent
trends and projected future trends. Assumed health care cost trend
rates have a significant effect on the amounts reported for the health care
plan. A 1% change in assumed health care cost trend rates would have
the following effects (In Thousands):
|
|
One
Percentage
Point
Increase
|
|
|
One
Percentage
Point
Decrease
|
|
Effect
on total of service and interest cost components for 2009
|
|
$ |
447 |
|
|
$ |
(385 |
) |
|
|
|
|
|
|
|
|
|
Effect
on year-end 2009 post-retirement benefit obligation
|
|
$ |
4,217 |
|
|
$ |
(3,722 |
) |
In
accordance with the terms of the 2006 & 2009 Rate Orders, Central Hudson is
authorized to defer any differences between rate allowances and actual costs for
both its Retirement and OPEB plans.
See Note
10 - “Post-Employment Benefits” of this 10-K Annual Report for additional
discussion.
ACCOUNTING FOR
DERIVATIVES
CH Energy
Group and its subsidiaries use derivatives to manage their commodity and
financial market risks; they do not enter into derivative instruments for
speculative purposes. As a result of deferrals under Central Hudson’s
regulatory mechanisms and offsetting changes of commodity prices for both
Central Hudson and Griffith, derivatives that CH Energy Group and Central Hudson
enter into do not materially impact earnings.
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 14 - “Accounting for
Derivative Instruments and Hedging Activities” of this 10-K Annual
Report.
|
QUANTITATIVE AND
QUALITATIVE DISCLOSURE ABOUT MARKET
RISK
|
The
practices employed by CH Energy Group and Central Hudson to mitigate risks
discussed below continue to operate effectively. For related
discussion on this activity, see Item 7 - “Management’s Discussion and Analysis
of Financial Condition and Results of Operations” under the subcaption “Capital
Resources and Liquidity”, Note 14 - “Accounting for Derivative Instruments and
Hedging Activities” and Note 9 - Long-Term Debt within this 10-K Annual
Report.
The
primary market risks for CH Energy Group and its subsidiaries and investments
are commodity price risk and interest rate risk. Commodity price
risk, related primarily to purchases of natural gas, electricity, and petroleum
products for resale to retail customers, is mitigated in several different
ways. Central Hudson, as authorized by the PSC in the 2006 and 2009
Rate Orders, collects its actual purchased electricity and purchased natural gas
costs from its customers through cost adjustment clauses in its
rates. These adjustment clauses provide for the collection of costs,
including risk management and working capital 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 may increase
the prices charged for the commodities it sells in response to changes in costs;
however, its ability to raise prices is limited by what the competitive market
in which it participates will bear. Depending on market conditions, Central
Hudson may 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. CH Energy Group also bears commodity price risk for
the purchase of corn and natural gas and the sale of ethanol and distillers
grains by Cornhusker Holdings.
Central
Hudson and Griffith have in place an energy risk management program within their
operations. This risk management program permits the use of
derivative financial instruments for hedging purposes but does not permit their
use for trading or speculative purposes. Central Hudson and Griffith
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 to
hedge the effect on earnings due to significant variations in weather conditions
from historical patterns. The types of derivative instruments
typically used include natural gas futures and swaps to hedge natural gas
purchases, contracts for differences to hedge electricity purchases, put and
call options to hedge oil purchases, and degree-day based weather derivatives to
hedge weather variations. In this latter case, Griffith uses such
derivative instruments to dampen the impact of weather variations on delivery
revenues. OTC derivative transactions are entered into only with
counterparties that meet certain credit criteria. The
creditworthiness of these counterparties is determined primarily by reference to
published credit ratings. Commodity price risk related to both corn
and ethanol is managed by Cornhusker Holdings at the entity level, not by CHEC
or CH Energy Group directly.
The use
of derivative instruments for hedging purposes is discussed in more detail in
Note 14 -“Accounting for Derivative Instruments and Hedging Activities”, which
incorporates sensitivity analysis for each type of derivative
instrument.
Interest
rate risk affects Central Hudson but is managed through the issuance of
fixed-rate debt with varying maturities and of variable rate debt for which
interest is reset on a periodic basis to reflect current market
conditions. In the case of Central Hudson’s variable rate debt, the
difference between costs associated with actual variable interest rates 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 replaced the expiring cap, effective April 1, 2009, with a one-year rate
cap with Key Bank National Association. The cap is based on the
monthly weighted average of an index of tax-exempt variable rate debt,
multiplied by 175% to align with the maximum rate formula of the three series of
variable rate 1999 NYSERDA Bonds. The interest rate cap is evaluated
quarterly and Central Hudson would receive a payout under the terms of the cap
if the bonds reset at rates above 4.375%. Please refer to Note 9 -
“Capitalization - Long-Term Debt”, Note 15 - “Fair Value Measurements” and Item
7 - “Management’s Discussion and Analysis of Financial Condition and Results of
Operations” under the subcaption “Capital Resources and Liquidity” for
additional disclosure related to long-term debt.
|
FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
|
I
- INDEX TO FINANCIAL STATEMENTS:
|
PAGE
|
|
|
|
|
|
107
|
|
|
|
111
|
|
|
|
|
|
CH ENERGY GROUP
|
|
|
|
|
115
|
|
|
|
117
|
|
|
|
118
|
|
|
|
119
|
|
|
|
121
|
|
|
|
|
|
CENTRAL HUDSON
|
|
|
|
|
122
|
|
|
|
123
|
|
|
|
124
|
|
|
|
125
|
|
|
|
127
|
|
|
|
|
|
|
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
|
|
|
|
|
|
128
|
|
|
|
|
139
|
|
|
|
|
147
|
|
|
|
|
151
|
|
|
|
|
155
|
|
|
|
|
158
|
|
|
|
|
160
|
|
|
|
|
162
|
|
|
|
|
163
|
|
|
|
|
167
|
|
|
|
|
180
|
|
|
|
|
185
|
|
|
|
|
195
|
|
|
|
|
199
|
|
|
|
|
207
|
|
|
|
|
213
|
|
|
|
214
|
|
|
|
|
|
|
FINANCIAL STATEMENT
SCHEDULES
|
|
|
|
|
215
|
|
|
|
219
|
|
|
|
219
|
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.
To the
Board of Directors and Shareholders of CH Energy Group, Inc.
In our
opinion, the consolidated financial statements listed in the accompanying index
present fairly, in all material respects, the financial position of CH Energy
Group, Inc. and its subsidiaries (collectively, the "Company") at December 31,
2009 and 2008, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2009 in conformity with
accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement
schedules listed in the accompanying index present
fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. Also
in our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2009, based on
criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company's management is responsible
for these financial statements and financial statement schedules for maintaining
effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting, included in the
accompanying CH Energy Group Report of Management on Internal Control Over
Financial Reporting. Our responsibility is to express opinions on
these financial statements, on the financial statement schedules, and on the
Company's internal control over financial reporting based on our integrated
audits. We conducted our audits in accordance with the standards of
the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting was
maintained in all material respects. Our audits of the financial
statements included 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. Our audit of internal control over
financial reporting included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audits also included
performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis
for our opinions.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that (i)
pertain to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
/s/
PRICEWATERHOUSECOOPERS LLP
Buffalo,
New York
February
10, 2010
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders of Central Hudson Gas & Electric
Corporation
In our
opinion, the financial statements listed in the accompanying index present
fairly, in all material respects, the financial position of Central Hudson Gas
& Electric Corporation (the "Company") at December 31, 2009 and 2008,
and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2009 in conformity with accounting
principles generally accepted in the United States of America. In
addition, in our opinion, the financial statement schedule listed in the
accompanying index presents
fairly, in all material respects, the information set forth therein when read in
conjunction with the related financial statements. Also in our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2009, based on criteria
established in Internal
Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Company's
management is responsible for these financial statements and financial statement
schedule, for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Central Hudson Report of Management on
Internal Control over Financial Reporting. Our responsibility is to
express opinions on these financial statements, on the financial statement
schedule, and on the Company's internal control over financial reporting based
on our integrated audits. We conducted our audits in accordance with
the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audits
to obtain reasonable assurance about whether the financial statements are free
of material misstatement and whether effective internal control over financial
reporting was maintained in all material respects. Our audits of the
financial statements included 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. Our audit of
internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audits provide a reasonable
basis for our opinions.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that (i)
pertain to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (iii) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
/s/
PRICEWATERHOUSECOOPERS LLP
Buffalo,
New York
February
10, 2010
REPORT OF MANAGEMENT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The
management of CH Energy Group, Inc. (“Management”) is responsible for
establishing and maintaining adequate internal control over financial reporting
for CH Energy Group, Inc. (the “Corporation”) as defined in Rules 13a-15(f) and
15d-15(f) under the Securities Exchange Act of 1934. Internal control
over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with accounting
principles generally accepted in the United States of
America. Internal control over financial reporting includes those
policies and procedures that:
|
·
|
pertain
to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of the
Corporation;
|
|
·
|
provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with accounting
principles generally accepted in the United States of America and that
receipts and expenditures of the Corporation are being made only in
accordance with authorization of Management and directors of the
Corporation; and
|
|
·
|
provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of assets that could have a
material effect on the consolidated financial
statements.
|
Internal
control over financial reporting includes the controls themselves, monitoring
(including internal auditing practices) and actions taken to correct
deficiencies as identified.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Management
assessed the effectiveness of the Corporation’s internal control over financial
reporting as of December 31, 2009. Management based this assessment
on criteria for effective internal control over financial reporting described in
“Internal Control - Integrated
Framework” issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Based on this assessment, Management
determined that, as of December 31, 2009, the Corporation maintained effective
internal control over financial reporting.
The
effectiveness of the Corporation’s internal control over financial reporting as
of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which
appears herein.
STEVEN
V. LANT
|
CHRISTOPHER
M. CAPONE
|
Chairman
of the Board,
|
Executive
Vice President
|
President,
and
|
and
Chief Financial Officer
|
Chief
Executive Officer
|
|
February
10, 2010
CENTRAL
HUDSON
REPORT OF MANAGEMENT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
The
management of Central Hudson Gas & Electric Corporation (“Management”) is
responsible for establishing and maintaining adequate internal control over
financial reporting for Central Hudson Gas & Electric Corporation (the
“Corporation”) as defined in Rules 13a-15(f) and 15d-15(f) under the Securities
Exchange Act of 1934. Internal control over financial reporting is a
process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with accounting principles generally accepted in the
United States of America. Internal control over financial reporting
includes those policies and procedures that:
|
·
|
pertain
to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of the
Corporation;
|
|
·
|
provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with accounting
principles generally accepted in the United States of America and that
receipts and expenditures of the Corporation are being made only in
accordance with authorization of Management and directors of the
Corporation; and
|
|
·
|
provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of assets that could have a
material effect on the consolidated financial
statements.
|
Internal
control over financial reporting includes the controls themselves, monitoring
(including internal auditing practices) and actions taken to correct
deficiencies as identified.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Management
assessed the effectiveness of the Corporation’s internal control over financial
reporting as of December 31, 2009. Management based this assessment
on criteria for effective internal control over financial reporting described in
“Internal Control - Integrated
Framework” issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Based on this assessment, Management
determined that, as of December 31, 2009, the Corporation maintained effective
internal control over financial reporting.
The
effectiveness of the Corporation’s internal control over financial reporting as
of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which
appears herein.
STEVEN
V. LANT
|
CHRISTOPHER
M. CAPONE
|
Chairman
of the Board
|
Executive
Vice President
|
and
Chief Executive Officer
|
and
Chief Financial Officer
|
February
10, 2010
|
|
(In
Thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Operating
Revenues
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
536,170 |
|
|
$ |
608,161 |
|
|
$ |
616,839 |
|
Natural
gas
|
|
|
174,137 |
|
|
|
189,546 |
|
|
|
165,449 |
|
Competitive
business subsidiaries:
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum
products
|
|
|
193,288 |
|
|
|
312,764 |
|
|
|
269,070 |
|
Other
|
|
|
27,994 |
|
|
|
28,730 |
|
|
|
27,409 |
|
Total
Operating Revenues
|
|
|
931,589 |
|
|
|
1,139,201 |
|
|
|
1,078,767 |
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
electricity and fuel used in electric generation
|
|
|
265,885 |
|
|
|
371,828 |
|
|
|
388,569 |
|
Purchased
natural gas
|
|
|
107,221 |
|
|
|
129,649 |
|
|
|
110,123 |
|
Purchased
petroleum
|
|
|
151,411 |
|
|
|
268,536 |
|
|
|
229,200 |
|
Other
expenses of operation - regulated activities
|
|
|
194,383 |
|
|
|
167,805 |
|
|
|
153,978 |
|
Other
expenses of operation - competitive business subsidiaries
|
|
|
54,338 |
|
|
|
57,355 |
|
|
|
52,308 |
|
Depreciation
and amortization
|
|
|
37,703 |
|
|
|
35,258 |
|
|
|
33,902 |
|
Taxes,
other than income tax
|
|
|
40,249 |
|
|
|
37,818 |
|
|
|
35,028 |
|
Total
Operating Expenses
|
|
|
851,190 |
|
|
|
1,068,249 |
|
|
|
1,003,108 |
|
Operating
Income
|
|
|
80,399 |
|
|
|
70,952 |
|
|
|
75,659 |
|
Other
Income and Deductions
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from unconsolidated affiliates
|
|
|
228 |
|
|
|
568 |
|
|
|
1,895 |
|
Interest
on regulatory assets and investment income
|
|
|
5,924 |
|
|
|
4,667 |
|
|
|
8,406 |
|
Write-off
of note receivable
|
|
|
(1,299 |
) |
|
|
- |
|
|
|
- |
|
Regulatory
adjustments for interest cost
|
|
|
(1,366 |
) |
|
|
766 |
|
|
|
538 |
|
Business
development costs
|
|
|
(2,012 |
) |
|
|
(1,589 |
) |
|
|
(1,451 |
) |
Other
- net
|
|
|
(1,259 |
) |
|
|
851 |
|
|
|
(366 |
) |
Total
Other Income
|
|
|
216 |
|
|
|
5,263 |
|
|
|
9,022 |
|
Interest
Charges
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
on long-term debt
|
|
|
20,999 |
|
|
|
20,518 |
|
|
|
18,653 |
|
Interest
on regulatory liabilities and other interest
|
|
|
4,797 |
|
|
|
3,774 |
|
|
|
3,064 |
|
Total
Interest Charges
|
|
|
25,796 |
|
|
|
24,292 |
|
|
|
21,717 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes, non-controlling interest and preferred dividends of
subsidiary
|
|
|
54,819 |
|
|
|
51,923 |
|
|
|
62,964 |
|
Income
Taxes
|
|
|
20,392 |
|
|
|
19,314 |
|
|
|
20,960 |
|
Net
Income from Continuing Operations
|
|
|
34,427 |
|
|
|
32,609 |
|
|
|
42,004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from discontinued operations before tax
|
|
|
6,073 |
|
|
|
6,060 |
|
|
|
2,419 |
|
Gain
from sale of discontinued operations
|
|
|
10,767 |
|
|
|
- |
|
|
|
- |
|
Income
tax expense from discontinued operations
|
|
|
6,989 |
|
|
|
2,515 |
|
|
|
938 |
|
Net
Income from Discontinued Operations
|
|
|
9,851 |
|
|
|
3,545 |
|
|
|
1,481 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
|
44,278 |
|
|
|
36,154 |
|
|
|
43,485 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income attributable to non-controlling interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-controlling
interest in subsidiary
|
|
|
(176 |
) |
|
|
103 |
|
|
|
(121 |
) |
Dividends
declared on Preferred Stock of subsidiary
|
|
|
970 |
|
|
|
970 |
|
|
|
970 |
|
Net
income attributable to CH Energy Group
|
|
|
43,484 |
|
|
|
35,081 |
|
|
|
42,636 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
declared on Common Stock
|
|
|
34,119 |
|
|
|
34,086 |
|
|
|
34,052 |
|
Change
in Retained Earnings
|
|
$ |
9,365 |
|
|
$ |
995 |
|
|
$ |
8,584 |
|
The Notes
to Financial Statements are an integral part hereof.
CH
ENERGY GROUP CONSOLIDATED STATEMENT OF INCOME (CONT'D)
|
|
(In
Thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Common
Stock:
|
|
|
|
|
|
|
|
|
|
Average
shares outstanding
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
15,775 |
|
|
|
15,768 |
|
|
|
15,762 |
|
Diluted
|
|
|
15,881 |
|
|
|
15,805 |
|
|
|
15,779 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from continuing operations attributable to CH Energy Group common
shareholders
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
2.13 |
|
|
$ |
2.00 |
|
|
$ |
2.61 |
|
Diluted
|
|
$ |
2.12 |
|
|
$ |
2.00 |
|
|
$ |
2.61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.63 |
|
|
$ |
0.22 |
|
|
$ |
0.09 |
|
Diluted
|
|
$ |
0.62 |
|
|
$ |
0.22 |
|
|
$ |
0.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts
attributable to CH Energy Group common shareholders
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
2.76 |
|
|
$ |
2.22 |
|
|
$ |
2.70 |
|
Diluted
|
|
$ |
2.74 |
|
|
$ |
2.22 |
|
|
$ |
2.70 |
|
Dividends
Declared Per Share
|
|
$ |
2.16 |
|
|
$ |
2.16 |
|
|
$ |
2.16 |
|
The Notes
to Financial Statements are an integral part hereof.
CH
ENERGY GROUP CONSOLIDATED STATEMENT OF COMPREHENSIVE
INCOME
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Net
Income
|
|
$ |
44,278 |
|
|
$ |
36,154 |
|
|
$ |
43,485 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized
(losses) gains - net of tax of $7, ($318) and ($687)
|
|
|
(10 |
) |
|
|
477 |
|
|
|
1,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification
for (gains) losses realized in net income-net of tax of ($29), $806 and
($44)
|
|
|
44 |
|
|
|
(1,208 |
) |
|
|
67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
unrealized (losses) gains on investments held by equity method investees -
net of tax of ($63), $258 and ($402)
|
|
|
95 |
|
|
|
(387 |
) |
|
|
604 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive (loss) income
|
|
|
129 |
|
|
|
(1,118 |
) |
|
|
1,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
Income
|
|
|
44,407 |
|
|
|
35,036 |
|
|
|
45,187 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income attributable to non-controlling interest
|
|
|
794 |
|
|
|
1,073 |
|
|
|
849 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income attributable to CH Energy Group
|
|
$ |
43,613 |
|
|
$ |
33,963 |
|
|
$ |
44,338 |
|
The Notes
to Financial Statements are an integral part hereof.
CH
ENERGY GROUP CONSOLIDATED STATEMENT OF CASH
FLOWS
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Operating
Activities:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
44,278 |
|
|
$ |
36,154 |
|
|
$ |
43,485 |
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
35,399 |
|
|
|
33,292 |
|
|
|
32,208 |
|
Amortization
|
|
|
5,146 |
|
|
|
5,006 |
|
|
|
3,715 |
|
Deferred
income taxes - net
|
|
|
15,514 |
|
|
|
13,933 |
|
|
|
5,349 |
|
Bad
debt expense
|
|
|
12,814 |
|
|
|
12,470 |
|
|
|
5,853 |
|
Distributed
(undistributed) equity in earnings of unconsolidated
affiliates
|
|
|
829 |
|
|
|
756 |
|
|
|
(18 |
) |
Pension
expense
|
|
|
20,282 |
|
|
|
12,377 |
|
|
|
12,697 |
|
Other
post-employment benefits ("OPEB") expense
|
|
|
8,346 |
|
|
|
9,844 |
|
|
|
10,097 |
|
Regulatory
liability - rate moderation
|
|
|
(9,915 |
) |
|
|
(5,954 |
) |
|
|
(18,425 |
) |
Revenue
decoupling mechanism
|
|
|
(5,789 |
) |
|
|
- |
|
|
|
- |
|
Regulatory
asset amortization
|
|
|
4,541 |
|
|
|
4,299 |
|
|
|
1,509 |
|
Gain
on sale of assets
|
|
|
(10,778 |
) |
|
|
(143 |
) |
|
|
(627 |
) |
Changes
in operating assets and liabilities - net of business
acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable, unbilled revenues and other receivables
|
|
|
6,854 |
|
|
|
(7,071 |
) |
|
|
(65,210 |
) |
Fuel,
materials and supplies
|
|
|
9,187 |
|
|
|
(2,857 |
) |
|
|
(3,764 |
) |
Special
deposits and prepayments
|
|
|
(305 |
) |
|
|
6,809 |
|
|
|
(4,390 |
) |
Prepaid
income taxes
|
|
|
(2,304 |
) |
|
|
- |
|
|
|
11,244 |
|
Accounts
payable
|
|
|
(3,875 |
) |
|
|
8,458 |
|
|
|
1,576 |
|
Accrued
income taxes and interest
|
|
|
168 |
|
|
|
(621 |
) |
|
|
1,316 |
|
Customer
advances
|
|
|
1,839 |
|
|
|
7,397 |
|
|
|
(2,687 |
) |
Pension
plan contribution
|
|
|
(23,124 |
) |
|
|
(13,027 |
) |
|
|
(6,347 |
) |
OPEB
contribution
|
|
|
(3,485 |
) |
|
|
(4,200 |
) |
|
|
(6,547 |
) |
Regulatory
asset - manufactured gas plant ("MGP") site remediation
|
|
|
(2,278 |
) |
|
|
(2,834 |
) |
|
|
(5,050 |
) |
Regulatory
asset - PSC tax surcharge and general assessment
|
|
|
(10,947 |
) |
|
|
- |
|
|
|
- |
|
Deferred
natural gas and electric costs
|
|
|
14,321 |
|
|
|
(12,453 |
) |
|
|
(3,310 |
) |
Other
- net
|
|
|
19,657 |
|
|
|
8,620 |
|
|
|
21,375 |
|
Net
cash provided by operating activities
|
|
|
126,375 |
|
|
|
110,255 |
|
|
|
34,049 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase
of short-term investments
|
|
|
- |
|
|
|
- |
|
|
|
(69,293 |
) |
Proceeds
from sale of short-term investments
|
|
|
- |
|
|
|
3,545 |
|
|
|
108,359 |
|
Acceptance
of notes receivable
|
|
|
- |
|
|
|
- |
|
|
|
(4,200 |
) |
Proceeds
from sale of assets
|
|
|
74,659 |
|
|
|
261 |
|
|
|
4,574 |
|
Additions
to utility and other property and plant
|
|
|
(123,132 |
) |
|
|
(84,198 |
) |
|
|
(84,601 |
) |
Acquisitions
made by competitive business subsidiaries
|
|
|
- |
|
|
|
(9,262 |
) |
|
|
(25,614 |
) |
Other
- net
|
|
|
(7,249 |
) |
|
|
1,012 |
|
|
|
(2,899 |
) |
Net
cash used in investing activities
|
|
|
(55,722 |
) |
|
|
(88,642 |
) |
|
|
(73,674 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemption
of long-term debt
|
|
|
(20,000 |
) |
|
|
- |
|
|
|
(33,000 |
) |
Proceeds
from issuance of long-term debt
|
|
|
74,000 |
|
|
|
30,000 |
|
|
|
66,000 |
|
(Repayments)
borrowings of short-term debt - net
|
|
|
(35,500 |
) |
|
|
(7,000 |
) |
|
|
29,500 |
|
Dividends
paid on Preferred Stock of subsidiary
|
|
|
(970 |
) |
|
|
(970 |
) |
|
|
(970 |
) |
Dividends
paid on Common Stock
|
|
|
(34,107 |
) |
|
|
(34,081 |
) |
|
|
(34,046 |
) |
Other
- net
|
|
|
(465 |
) |
|
|
(1,050 |
) |
|
|
(667 |
) |
Net
cash (used in) provided by financing activities
|
|
|
(17,042 |
) |
|
|
(13,101 |
) |
|
|
26,817 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Change in Cash and Cash Equivalents
|
|
|
53,611 |
|
|
|
8,512 |
|
|
|
(12,808 |
) |
Cash
and Cash Equivalents at Beginning of Period
|
|
|
19,825 |
|
|
|
11,313 |
|
|
|
24,121 |
|
Cash
and Cash Equivalents at End of Period
|
|
$ |
73,436 |
|
|
$ |
19,825 |
|
|
$ |
11,313 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosure of Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
paid
|
|
$ |
21,548 |
|
|
$ |
22,633 |
|
|
$ |
20,001 |
|
Federal
and state taxes paid
|
|
$ |
30,148 |
|
|
$ |
10,029 |
|
|
$ |
13,096 |
|
Additions
to plant included in liabilities
|
|
$ |
2,235 |
|
|
$ |
17,876 |
|
|
$ |
12,304 |
|
The Notes
to Financial Statements are an integral part hereof.
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
ASSETS
|
|
|
|
|
|
|
Utility
Plant
|
|
|
|
|
|
|
Electric
|
|
$ |
908,807 |
|
|
$ |
862,465 |
|
Natural
gas
|
|
|
281,139 |
|
|
|
263,874 |
|
Common
|
|
|
139,754 |
|
|
|
135,732 |
|
|
|
|
1,329,700 |
|
|
|
1,262,071 |
|
|
|
|
|
|
|
|
|
|
Less:
Accumulated depreciation
|
|
|
375,434 |
|
|
|
369,925 |
|
|
|
|
954,266 |
|
|
|
892,146 |
|
|
|
|
|
|
|
|
|
|
Construction
work in progress
|
|
|
58,120 |
|
|
|
53,778 |
|
Net
Utility Plant
|
|
|
1,012,386 |
|
|
|
945,924 |
|
|
|
|
|
|
|
|
|
|
Non-Utility
Property & Plant
|
|
|
|
|
|
|
|
|
Griffith
non-utility property & plant
|
|
|
27,951 |
|
|
|
42,691 |
|
Other
non-utility property & plant
|
|
|
37,654 |
|
|
|
15,345 |
|
|
|
|
65,605 |
|
|
|
58,036 |
|
|
|
|
|
|
|
|
|
|
Less: Accumulated
depreciation - Griffith
|
|
|
18,619 |
|
|
|
23,398 |
|
Less: Accumulated
depreciation - other
|
|
|
3,333 |
|
|
|
2,212 |
|
Net
Non-Utility Property & Plant
|
|
|
43,653 |
|
|
|
32,426 |
|
|
|
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
73,436 |
|
|
|
19,825 |
|
Accounts
receivable from customers - net of allowance for doubtful accounts of $7.7
million and $8.8 million, respectively
|
|
|
94,526 |
|
|
|
131,727 |
|
Accrued
unbilled utility revenues
|
|
|
14,159 |
|
|
|
12,657 |
|
Other
receivables
|
|
|
6,612 |
|
|
|
7,914 |
|
Fuel,
materials and supplies
|
|
|
24,841 |
|
|
|
36,585 |
|
Regulatory
assets
|
|
|
59,993 |
|
|
|
60,502 |
|
Prepaid
income tax
|
|
|
1,863 |
|
|
|
- |
|
Fair
value of derivative instruments
|
|
|
741 |
|
|
|
- |
|
Special
deposits and prepayments
|
|
|
21,290 |
|
|
|
21,344 |
|
Accumulated
deferred income tax
|
|
|
300 |
|
|
|
7,498 |
|
Total
Current Assets
|
|
|
297,761 |
|
|
|
298,052 |
|
|
|
|
|
|
|
|
|
|
Deferred
Charges and Other Assets
|
|
|
|
|
|
|
|
|
Regulatory
assets - pension plan
|
|
|
168,705 |
|
|
|
197,934 |
|
Regulatory
assets - OPEB
|
|
|
- |
|
|
|
4,257 |
|
Regulatory
assets - other
|
|
|
83,691 |
|
|
|
109,743 |
|
Goodwill
|
|
|
35,651 |
|
|
|
67,455 |
|
Other
intangible assets - net
|
|
|
14,813 |
|
|
|
36,129 |
|
Unamortized
debt expense
|
|
|
5,094 |
|
|
|
5,009 |
|
Investments
in unconsolidated affiliates
|
|
|
8,698 |
|
|
|
9,711 |
|
Other
investments
|
|
|
10,812 |
|
|
|
7,815 |
|
Other
|
|
|
16,619 |
|
|
|
15,728 |
|
Total
Deferred Charges and Other Assets
|
|
|
344,083 |
|
|
|
453,781 |
|
Total
Assets
|
|
$ |
1,697,883 |
|
|
$ |
1,730,183 |
|
The Notes
to Financial Statements are an integral part hereof.
CH
ENERGY GROUP CONSOLIDATED BALANCE SHEET (CONT'D)
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
CH
Energy Group Common Shareholders' Equity
|
|
|
|
|
|
|
Common
Stock (30,000,000 shares authorized: $0.10 par value;16,862,087 shares
issued) 15,804,562 shares and 15,783,083 shares outstanding,
respectively
|
|
$ |
1,686 |
|
|
$ |
1,686 |
|
Paid-in
capital
|
|
|
350,367 |
|
|
|
350,873 |
|
Retained
earnings
|
|
|
225,999 |
|
|
|
216,634 |
|
Treasury
stock - 1,057,525 shares and 1,079,004 shares,
respectively
|
|
|
(44,406 |
) |
|
|
(45,386 |
) |
Accumulated
other comprehensive income
|
|
|
184 |
|
|
|
55 |
|
Capital
stock expense
|
|
|
(328 |
) |
|
|
(328 |
) |
Total
CH Energy Group Common Shareholders' Equity
|
|
|
533,502 |
|
|
|
523,534 |
|
Non-controlling
interest in subsidiary
|
|
|
1,385 |
|
|
|
1,448 |
|
Total
Equity
|
|
|
534,887 |
|
|
|
524,982 |
|
Preferred
Stock of subsidiary
|
|
|
21,027 |
|
|
|
21,027 |
|
Long-term
debt
|
|
|
463,897 |
|
|
|
413,894 |
|
Total
Capitalization
|
|
|
1,019,811 |
|
|
|
959,903 |
|
Current
Liabilities
|
|
|
|
|
|
|
|
|
Current
maturities of long-term debt
|
|
|
24,000 |
|
|
|
20,000 |
|
Notes
payable
|
|
|
- |
|
|
|
35,500 |
|
Accounts
payable
|
|
|
43,197 |
|
|
|
52,824 |
|
Accrued
interest
|
|
|
6,067 |
|
|
|
5,899 |
|
Dividends
payable
|
|
|
8,777 |
|
|
|
8,765 |
|
Accrued
vacation and payroll
|
|
|
6,192 |
|
|
|
6,628 |
|
Customer
advances
|
|
|
22,450 |
|
|
|
30,442 |
|
Customer
deposits
|
|
|
8,579 |
|
|
|
8,445 |
|
Regulatory
liabilities
|
|
|
29,974 |
|
|
|
8,724 |
|
Fair
value of derivative instruments
|
|
|
13,837 |
|
|
|
15,759 |
|
Accrued
environmental remediation costs
|
|
|
17,399 |
|
|
|
5,757 |
|
Accrued
income taxes
|
|
|
- |
|
|
|
441 |
|
Deferred
revenues
|
|
|
4,725 |
|
|
|
8,827 |
|
Other
|
|
|
17,814 |
|
|
|
27,974 |
|
Total
Current Liabilities
|
|
|
203,011 |
|
|
|
235,985 |
|
Deferred
Credits and Other Liabilities
|
|
|
|
|
|
|
|
|
Regulatory
liabilities - OPEB
|
|
|
1,521 |
|
|
|
- |
|
Regulatory
liabilities - other
|
|
|
91,457 |
|
|
|
126,444 |
|
Operating
reserves
|
|
|
4,756 |
|
|
|
5,155 |
|
Accrued
environmental remediation costs
|
|
|
6,375 |
|
|
|
21,796 |
|
Accrued
OPEB costs
|
|
|
46,241 |
|
|
|
52,645 |
|
Accrued
pension costs
|
|
|
152,383 |
|
|
|
161,674 |
|
Other
|
|
|
14,245 |
|
|
|
12,478 |
|
Total
Deferred Credits and Other Liabilities
|
|
|
316,978 |
|
|
|
380,192 |
|
Accumulated
Deferred Income Tax
|
|
|
158,083 |
|
|
|
154,103 |
|
Commitments
and Contingencies
|
|
|
|
|
|
|
|
|
Total
Capitalization and Liabilities
|
|
$ |
1,697,883 |
|
|
$ |
1,730,183 |
|
The Notes
to Financial Statements are an integral part hereof.
CH ENERGY GROUP CONSOLIDATED STATEMENT OF EQUITY
(In
Thousands, except share and per share amounts)
|
|
CH
Energy Group Common Shareholders
|
|
|
|
|
|
|
|
|
|
Common
Stock
$0.10
par value; 30,000,000 shares authorized
|
|
|
Treasury
Stock
|
|
|
|
|
|
Capital
Stock Expense
|
|
|
|
|
|
Accumulated
Other Comprehensive Income / (Loss)
|
|
|
|
|
|
|
|
|
|
Shares
Issued
|
|
|
Amount
|
|
|
Shares
Repurchased
|
|
|
Amount
|
|
|
Paid-In
Capital
|
|
|
Retained
Earnings
|
|
|
Non-controlling
Interest
|
|
|
Total
Equity
|
|
Balance
at January 1, 2007
|
|
|
16,862,087 |
|
|
$ |
1,686 |
|
|
|
(1,100,087 |
) |
|
$ |
(46,252 |
) |
|
$ |
351,230 |
|
|
$ |
(328 |
) |
|
$ |
207,055 |
|
|
$ |
(529 |
) |
|
$ |
1,481 |
|
|
$ |
514,343 |
|
Comprehensive
Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,636 |
|
|
|
|
|
|
|
(121 |
) |
|
|
42,515 |
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15 |
) |
|
|
(15 |
) |
Change
in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,031 |
|
|
|
|
|
|
|
1,031 |
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
604 |
|
|
|
|
|
|
|
604 |
|
Reclassification
adjustments for losses recognized in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67 |
|
|
|
|
|
|
|
67 |
|
Dividends
declared on common stock ($2.16 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(34,052 |
) |
|
|
|
|
|
|
|
|
|
|
(34,052 |
) |
Treasury
shares activity - net
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
Balance
at December 31, 2007
|
|
|
16,862,087 |
|
|
$ |
1,686 |
|
|
|
(1,100,087 |
) |
|
$ |
(46,252 |
) |
|
$ |
351,230 |
|
|
$ |
(328 |
) |
|
$ |
215,639 |
|
|
$ |
1,173 |
|
|
$ |
1,345 |
|
|
$ |
524,493 |
|
Comprehensive
Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,081 |
|
|
|
|
|
|
|
103 |
|
|
|
35,184 |
|
Change
in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
477 |
|
|
|
|
|
|
|
477 |
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(387 |
) |
|
|
|
|
|
|
(387 |
) |
Reclassification
adjustments for losses recognized in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,208 |
) |
|
|
|
|
|
|
(1,208 |
) |
Dividends
declared on common stock ($2.16 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(34,086 |
) |
|
|
|
|
|
|
|
|
|
|
(34,086 |
) |
Treasury
shares activity - net
|
|
|
|
|
|
|
|
|
|
|
21,083 |
|
|
|
866 |
|
|
|
(357 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
509 |
|
Balance
at December 31, 2008
|
|
|
16,862,087 |
|
|
$ |
1,686 |
|
|
|
(1,079,004 |
) |
|
$ |
(45,386 |
) |
|
$ |
350,873 |
|
|
$ |
(328 |
) |
|
$ |
216,634 |
|
|
$ |
55 |
|
|
$ |
1,448 |
|
|
$ |
524,982 |
|
Comprehensive
Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43,484 |
|
|
|
|
|
|
|
(176 |
) |
|
|
43,308 |
|
Capital
Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
213 |
|
|
|
213 |
|
Capital
Distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(100 |
) |
|
|
(100 |
) |
Change
in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
|
|
|
|
(10 |
) |
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44 |
|
|
|
|
|
|
|
44 |
|
Reclassification
adjustments for losses recognized in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95 |
|
|
|
|
|
|
|
95 |
|
Dividends
declared on common stock ($2.16 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(34,119 |
) |
|
|
|
|
|
|
|
|
|
|
(34,119 |
) |
Treasury
shares activity - net
|
|
|
|
|
|
|
|
|
|
|
21,479 |
|
|
|
980 |
|
|
|
(506 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
474 |
|
Balance
at December 31, 2009
|
|
|
16,862,087 |
|
|
$ |
1,686 |
|
|
|
(1,057,525 |
) |
|
$ |
(44,406 |
) |
|
$ |
350,367 |
|
|
$ |
(328 |
) |
|
$ |
225,999 |
|
|
$ |
184 |
|
|
$ |
1,385 |
|
|
$ |
534,887 |
|
The Notes
to Financial Statements are an integral part hereof.
CENTRAL HUDSON STATEMENT OF INCOME
(In
Thousands)
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Operating
Revenues
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$ |
536,170 |
|
|
$ |
608,161 |
|
|
$ |
616,839 |
|
Natural
gas
|
|
|
174,137 |
|
|
|
189,546 |
|
|
|
165,449 |
|
Total
Operating Revenues
|
|
|
710,307 |
|
|
|
797,707 |
|
|
|
782,288 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased
electricity and fuel used in electric generation
|
|
|
261,003 |
|
|
|
365,827 |
|
|
|
383,806 |
|
Purchased
natural gas
|
|
|
107,221 |
|
|
|
129,649 |
|
|
|
110,123 |
|
Other
expenses of operation
|
|
|
194,383 |
|
|
|
167,805 |
|
|
|
153,978 |
|
Depreciation
and amortization
|
|
|
32,094 |
|
|
|
29,812 |
|
|
|
28,399 |
|
Taxes,
other than income tax
|
|
|
39,268 |
|
|
|
37,270 |
|
|
|
34,576 |
|
Total
Operating Expenses
|
|
|
633,969 |
|
|
|
730,363 |
|
|
|
710,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Income
|
|
|
76,338 |
|
|
|
67,344 |
|
|
|
71,406 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Income and Deductions
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
on regulatory assets and other interest income
|
|
|
5,030 |
|
|
|
3,171 |
|
|
|
5,743 |
|
Other
- net
|
|
|
(1,199 |
) |
|
|
656 |
|
|
|
(1,018 |
) |
Regulatory
adjustments for interest costs
|
|
|
(1,366 |
) |
|
|
766 |
|
|
|
538 |
|
Total
Other Income
|
|
|
2,465 |
|
|
|
4,593 |
|
|
|
5,263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
Charges
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
on other long-term debt
|
|
|
18,830 |
|
|
|
20,518 |
|
|
|
18,653 |
|
Interest
on regulatory liabilities and other interest
|
|
|
6,055 |
|
|
|
4,908 |
|
|
|
4,254 |
|
Total
Interest Charges
|
|
|
24,885 |
|
|
|
25,426 |
|
|
|
22,907 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Income Taxes
|
|
|
53,918 |
|
|
|
46,511 |
|
|
|
53,762 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Taxes
|
|
|
21,142 |
|
|
|
19,273 |
|
|
|
20,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
|
32,776 |
|
|
|
27,238 |
|
|
|
33,436 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
Declared on Cumulative Preferred Stock
|
|
|
970 |
|
|
|
970 |
|
|
|
970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Available for Common Stock
|
|
$ |
31,806 |
|
|
$ |
26,268 |
|
|
$ |
32,466 |
|
The Notes
to Financial Statements are an integral part hereof.
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
|
2009
|
|
2008
|
|
2007
|
|
Net
Income
|
|
$ |
32,776 |
|
|
$ |
27,238 |
|
|
$ |
33,436 |
|
Other
Comprehensive Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
Income
|
|
$ |
32,776 |
|
|
$ |
27,238 |
|
|
$ |
33,436 |
|
The Notes
to Financial Statements are an integral part hereof.
CENTRAL HUDSON STATEMENT OF CASH FLOWS
(In
Thousands)
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Operating
Activities:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
32,776 |
|
|
$ |
27,238 |
|
|
$ |
33,436 |
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
30,949 |
|
|
|
28,922 |
|
|
|
28,047 |
|
Amortization
|
|
|
1,145 |
|
|
|
890 |
|
|
|
352 |
|
Deferred
income taxes - net
|
|
|
20,010 |
|
|
|
11,375 |
|
|
|
3,105 |
|
Bad
debt expense
|
|
|
8,833 |
|
|
|
7,892 |
|
|
|
4,850 |
|
Pension
expense
|
|
|
20,282 |
|
|
|
12,377 |
|
|
|
12,697 |
|
OPEB
expense
|
|
|
8,346 |
|
|
|
9,844 |
|
|
|
10,097 |
|
Regulatory
liability - rate moderation
|
|
|
(9,915 |
) |
|
|
(5,954 |
) |
|
|
(18,425 |
) |
Revenue
decoupling mechanism
|
|
|
(5,789 |
) |
|
|
- |
|
|
|
- |
|
Regulatory
asset amortization
|
|
|
4,541 |
|
|
|
4,299 |
|
|
|
1,509 |
|
Loss
on sale of property and plant
|
|
|
25 |
|
|
|
- |
|
|
|
(468 |
) |
Changes
in operating assets and liabilities - net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable, unbilled revenues and other receivables
|
|
|
3,785 |
|
|
|
(13,205 |
) |
|
|
(39,577 |
) |
Fuel,
materials and supplies
|
|
|
9,810 |
|
|
|
(6,845 |
) |
|
|
(1,466 |
) |
Special
deposits and prepayments
|
|
|
364 |
|
|
|
5,952 |
|
|
|
(3,409 |
) |
Prepaid
income taxes
|
|
|
(10,706 |
) |
|
|
- |
|
|
|
10,477 |
|
Accounts
payable
|
|
|
(7,325 |
) |
|
|
13,656 |
|
|
|
(4,111 |
) |
Accrued
income taxes and interest
|
|
|
(345 |
) |
|
|
(3,434 |
) |
|
|
3,771 |
|
Customer
advances
|
|
|
5,428 |
|
|
|
(1,268 |
) |
|
|
(5,065 |
) |
Pension
plan contribution
|
|
|
(23,124 |
) |
|
|
(13,027 |
) |
|
|
(6,347 |
) |
OPEB
contribution
|
|
|
(3,485 |
) |
|
|
(4,200 |
) |
|
|
(6,547 |
) |
Regulatory
asset - MGP site remediation
|
|
|
(2,278 |
) |
|
|
(2,834 |
) |
|
|
(5,050 |
) |
Regulatory
asset - PSC tax surcharge and general assessment
|
|
|
(10,947 |
) |
|
|
- |
|
|
|
- |
|
Deferred
natural gas and electric costs
|
|
|
14,321 |
|
|
|
(12,453 |
) |
|
|
(3,310 |
) |
Other
- net
|
|
|
20,810 |
|
|
|
8,865 |
|
|
|
18,232 |
|
Net
cash provided by operating activities
|
|
|
107,511 |
|
|
|
68,090 |
|
|
|
32,798 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from sale of property and plant
|
|
|
- |
|
|
|
- |
|
|
|
862 |
|
Additions
to utility plant
|
|
|
(99,756 |
) |
|
|
(78,931 |
) |
|
|
(81,288 |
) |
Other
- net
|
|
|
(7,489 |
) |
|
|
(1,276 |
) |
|
|
(2,853 |
) |
Net
cash used in investing activities
|
|
|
(107,245 |
) |
|
|
(80,207 |
) |
|
|
(83,279 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemption
of long-term debt
|
|
|
(20,000 |
) |
|
|
- |
|
|
|
(33,000 |
) |
Proceeds
from issuance of long-term debt
|
|
|
24,000 |
|
|
|
30,000 |
|
|
|
66,000 |
|
(Repayments)
borrowings of short-term debt - net
|
|
|
(25,500 |
) |
|
|
(17,000 |
) |
|
|
29,500 |
|
Additional
paid-in capital
|
|
|
25,000 |
|
|
|
- |
|
|
|
- |
|
Dividends
paid on cumulative Preferred Stock
|
|
|
(970 |
) |
|
|
(970 |
) |
|
|
(970 |
) |
Dividends
paid to parent - CH Energy Group
|
|
|
- |
|
|
|
- |
|
|
|
(8,500 |
) |
Other
- net
|
|
|
(467 |
) |
|
|
(1,050 |
) |
|
|
(667 |
) |
Net
cash provided by financing activities
|
|
|
2,063 |
|
|
|
10,980 |
|
|
|
52,363 |
|
Net
Change in Cash and Cash Equivalents
|
|
|
2,329 |
|
|
|
(1,137 |
) |
|
|
1,882 |
|
Cash
and Cash Equivalents - Beginning of Period
|
|
|
2,455 |
|
|
|
3,592 |
|
|
|
1,710 |
|
Cash
and Cash Equivalents - End of Period
|
|
$ |
4,784 |
|
|
$ |
2,455 |
|
|
$ |
3,592 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosure of Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
paid
|
|
$ |
19,672 |
|
|
$ |
22,080 |
|
|
$ |
20,001 |
|
Federal
and state taxes paid
|
|
$ |
29,764 |
|
|
$ |
11,355 |
|
|
$ |
13,619 |
|
Additions
to plant included in liabilities
|
|
$ |
1,619 |
|
|
$ |
17,876 |
|
|
$ |
12,304 |
|
The Notes
to Financial Statements are an integral part hereof.
CENTRAL HUDSON BALANCE SHEET
(In
Thousands)
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
Utility
Plant
|
|
|
|
|
|
|
Electric
|
|
$ |
908,807 |
|
|
$ |
862,465 |
|
Natural
gas
|
|
|
281,139 |
|
|
|
263,874 |
|
Common
|
|
|
139,754 |
|
|
|
135,732 |
|
|
|
|
1,329,700 |
|
|
|
1,262,071 |
|
|
|
|
|
|
|
|
|
|
Less:
Accumulated depreciation
|
|
|
375,434 |
|
|
|
369,925 |
|
|
|
|
954,266 |
|
|
|
892,146 |
|
|
|
|
|
|
|
|
|
|
Construction
work in progress
|
|
|
58,120 |
|
|
|
53,778 |
|
Net
Utility Plant
|
|
|
1,012,386 |
|
|
|
945,924 |
|
|
|
|
|
|
|
|
|
|
Non-Utility
Property and Plant
|
|
|
681 |
|
|
|
445 |
|
Less:
Accumulated depreciation
|
|
|
33 |
|
|
|
32 |
|
Net
Non-Utility Property and Plant
|
|
|
648 |
|
|
|
413 |
|
|
|
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
4,784 |
|
|
|
2,455 |
|
Accounts
receivable from customers - net of allowance for doubtful accounts of $5.8
million and $4.0 million, respectively
|
|
|
68,328 |
|
|
|
85,352 |
|
Accrued
unbilled utility revenues
|
|
|
14,159 |
|
|
|
12,657 |
|
Other
receivables
|
|
|
3,025 |
|
|
|
3,447 |
|
Fuel,
materials and supplies - at average cost
|
|
|
21,305 |
|
|
|
31,115 |
|
Regulatory
assets
|
|
|
59,993 |
|
|
|
60,502 |
|
Prepaid
income tax
|
|
|
10,706 |
|
|
|
- |
|
Fair
value of derivative instruments
|
|
|
393 |
|
|
|
- |
|
Special
deposits and prepayments
|
|
|
18,304 |
|
|
|
18,573 |
|
Accumulated
deferred income tax
|
|
|
- |
|
|
|
4,685 |
|
Total
Current Assets
|
|
|
200,997 |
|
|
|
218,786 |
|
|
|
|
|
|
|
|
|
|
Deferred
Charges and Other Assets
|
|
|
|
|
|
|
|
|
Regulatory
assets - pension plan
|
|
|
168,705 |
|
|
|
197,934 |
|
Regulatory
assets - OPEB
|
|
|
- |
|
|
|
4,257 |
|
Regulatory
assets - other
|
|
|
83,691 |
|
|
|
109,743 |
|
Unamortized
debt expense
|
|
|
5,094 |
|
|
|
5,009 |
|
Other
investments
|
|
|
10,543 |
|
|
|
7,697 |
|
Other
|
|
|
3,536 |
|
|
|
2,433 |
|
Total
Deferred Charges and Other Assets
|
|
|
271,569 |
|
|
|
327,073 |
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
1,485,600 |
|
|
$ |
1,492,196 |
|
CENTRAL
HUDSON BALANCE SHEET (CONT'D)
(In
Thousands)
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
Common
Stock, 30,000,000 shares authorized; 16,862,087 shares issued and
outstanding, $5 par value
|
|
$ |
84,311 |
|
|
$ |
84,311 |
|
Paid-in
capital
|
|
|
199,980 |
|
|
|
174,980 |
|
Retained
earnings
|
|
|
150,750 |
|
|
|
118,944 |
|
Capital
stock expense
|
|
|
(4,961 |
) |
|
|
(4,961 |
) |
Total
Equity
|
|
|
430,080 |
|
|
|
373,274 |
|
Cumulative
Preferred Stock not subject to mandatory redemption
|
|
|
21,027 |
|
|
|
21,027 |
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
413,897 |
|
|
|
413,894 |
|
Total
Capitalization
|
|
|
865,004 |
|
|
|
808,195 |
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
|
|
Current
maturities of long-term debt
|
|
|
24,000 |
|
|
|
20,000 |
|
Notes
payable
|
|
|
- |
|
|
|
25,500 |
|
Accounts
payable
|
|
|
32,069 |
|
|
|
42,913 |
|
Accrued
interest
|
|
|
5,637 |
|
|
|
5,895 |
|
Dividends
payable - Preferred Stock
|
|
|
242 |
|
|
|
242 |
|
Accrued
vacation and payroll
|
|
|
5,046 |
|
|
|
4,896 |
|
Customer
advances
|
|
|
15,002 |
|
|
|
9,574 |
|
Customer
deposits
|
|
|
8,504 |
|
|
|
8,317 |
|
Regulatory
liabilities
|
|
|
29,974 |
|
|
|
8,724 |
|
Fair
value of derivative instruments
|
|
|
13,553 |
|
|
|
15,759 |
|
Accrued
environmental remediation costs
|
|
|
16,982 |
|
|
|
5,563 |
|
Accrued
income taxes
|
|
|
- |
|
|
|
87 |
|
Accumulated
deferred income tax
|
|
|
1,883 |
|
|
|
- |
|
Other
|
|
|
8,761 |
|
|
|
21,284 |
|
Total
Current Liabilities
|
|
|
161,653 |
|
|
|
168,754 |
|
|
|
|
|
|
|
|
|
|
Deferred
Credits and Other Liabilities
|
|
|
|
|
|
|
|
|
Regulatory
liabilities - OPEB
|
|
|
1,521 |
|
|
|
- |
|
Regulatory
liabilities - other
|
|
|
91,457 |
|
|
|
126,444 |
|
Operating
reserves
|
|
|
3,503 |
|
|
|
3,898 |
|
Accrued
environmental remediation costs
|
|
|
3,248 |
|
|
|
20,621 |
|
Accrued
OPEB costs
|
|
|
46,241 |
|
|
|
52,645 |
|
Accrued
pension costs
|
|
|
152,383 |
|
|
|
161,674 |
|
Other
|
|
|
13,495 |
|
|
|
11,891 |
|
Total
Deferred Credits and Other Liabilities
|
|
|
311,848 |
|
|
|
377,173 |
|
|
|
|
|
|
|
|
|
|
Accumulated
Deferred Income Tax
|
|
|
147,095 |
|
|
|
138,074 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Capitalization and Liabilities
|
|
$ |
1,485,600 |
|
|
$ |
1,492,196 |
|
(In
Thousands, except share and per share amounts)
|
|
Central
Hudson Common Shareholders
|
|
|
|
|
|
|
Common
Stock
$5.00
par value;
30,000,000
shares authorized
|
|
|
Treasury
Stock
|
|
|
|
|
|
Capital
Stock Expense
|
|
|
|
|
|
Accumulated
Other Comprehensive Income / (Loss)
|
|
|
|
|
|
|
Shares
Issued
|
|
|
Amount
|
|
|
Shares
Repurchased
|
|
|
Amount
|
|
|
Paid-In
Capital
|
|
|
Retained
Earnings
|
|
|
Total
Equity
|
|
Balance
at January 1, 2007
|
|
|
16,862,087 |
|
|
$ |
84,311 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
174,980 |
|
|
$ |
(4,961 |
) |
|
$ |
68,710 |
|
|
$ |
- |
|
|
$ |
323,040 |
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,436 |
|
|
|
|
|
|
|
33,436 |
|
Dividends
declared
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On
cumulative Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(970 |
) |
|
|
|
|
|
|
(970 |
) |
On
Common Stock to parent - CH Energy Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8,500 |
) |
|
|
|
|
|
|
(8,500 |
) |
Balance
at December 31, 2007
|
|
|
16,862,087 |
|
|
$ |
84,311 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
174,980 |
|
|
$ |
(4,961 |
) |
|
$ |
92,676 |
|
|
$ |
- |
|
|
$ |
347,006 |
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27,238 |
|
|
|
|
|
|
|
27,238 |
|
Dividends
declared
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On
cumulative Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(970 |
) |
|
|
|
|
|
|
(970 |
) |
On
Common Stock to parent - CH Energy Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
- |
|
Balance
at December 31, 2008
|
|
|
16,862,087 |
|
|
$ |
84,311 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
174,980 |
|
|
$ |
(4,961 |
) |
|
$ |
118,944 |
|
|
$ |
- |
|
|
$ |
373,274 |
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,776 |
|
|
|
|
|
|
|
32,776 |
|
Dividends
declared
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On
cumulative Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(970 |
) |
|
|
|
|
|
|
(970 |
) |
On
Common Stock to parent - CH Energy Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
- |
|
Additional
Paid-in Capital
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,000 |
|
Balance
at December 31, 2009
|
|
|
16,862,087 |
|
|
$ |
84,311 |
|
|
|
- |
|
|
$ |
- |
|
|
$ |
199,980 |
|
|
$ |
(4,961 |
) |
|
$ |
150,750 |
|
|
$ |
- |
|
|
$ |
430,080 |
|
NOTES
TO FINANCIAL STATEMENTS
NOTE 1 -
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
CH Energy
Group, Inc. (“CH Energy Group”) is the holding company parent corporation of
Central Hudson Gas & Electric Corporation (“Central Hudson”) and Central
Hudson Enterprises Corporation (“CHEC”). Central Hudson and CHEC are
each wholly owned by CH Energy Group. Their businesses are comprised
of a regulated electric utility and regulated natural gas utility, fuel
distribution, cogeneration, energy management, and investments in energy-related
assets.
CHEC’s
wholly owned subsidiaries include: Griffith Energy Services, Inc.
(“Griffith”), CH-Auburn Energy, LLC (“CH-Auburn”), CH-Greentree, LLC
(“CH-Greentree”) and CH Shirley Wind, LLC (“CH Shirley”). On December
11, 2009, Griffith sold operations in certain geographic
locations. For more information of sale, see Note 5 – “Acquisitions,
Divestitures and Investments”.
On April
12, 2006, CHEC purchased a 75% interest in Lyonsdale Biomass, LLC
(“Lyonsdale”). The operating results of Lyonsdale are consolidated in
the financial statements of CH Energy Group. The non-controlling
interest shown on CH Energy Group’s Consolidated Financial Statements includes
the minority owner’s proportionate share of the income and equity of
Lyonsdale.
On
December 15, 2009, CH Shirley purchased a 90% interest in Shirley Wind
(Delaware), LLC (“Shirley Delaware”). The operating results of
Shirley Delaware are consolidated in the financial statements of CH Energy
Group. The non-controlling interest shown on CH Energy Group’s
Consolidated Financial Statements includes the minority owner’s proportionate
share of the income and equity of Shirley Delaware.
CHEC’s
investments in limited partnerships (“Partnerships”) and limited liability
companies are accounted for under the equity method. CH Energy
Group’s proportionate share of the change in fair value of available for sale
securities held by the Partnerships is recorded in CH Energy Group’s
Consolidated Statement of Comprehensive Income. For more information,
see Note 5 - “Acquisitions, Divestitures and Investments.”
Basis
of Presentation
This
Annual Report on Form 10-K is a combined report of CH Energy Group and Central
Hudson. The Notes to the Consolidated Financial Statements apply to both CH
Energy Group and Central Hudson. CH Energy Group’s Consolidated Financial
Statements include the accounts of CH Energy Group and its wholly owned
subsidiaries, which include Central Hudson and CHEC. Operating results of
Griffith, CH-Auburn, CH-Greentree, CH Shirley and CH-Lyonsdale are consolidated
in the Consolidated Financial Statements of CH Energy Group. The minority
interest shown on CH Energy Group’s Consolidated Financial Statements represents
the minority owner’s proportionate share of the income and equity of Shirley
Delaware and Lyonsdale. Intercompany balances and transactions have been
eliminated in consolidation.
The
Financial Statements were prepared in conformity with accounting principles
generally accepted in the United States of America (“GAAP”), which for regulated
public utilities, includes specific accounting guidance for Regulated Operations
(Financial Accounting Standards Board’s (“FASB”) Accounting Standards
Codification (“ASC”) 980). For additional information regarding
regulatory accounting, see Note 2 - “Regulatory Matters”.
Reclassification
Certain
amounts in the 2008 and 2007 Financial Statements have been reclassified to
conform to the 2009 presentation.
On
December 11, 2009, Griffith closed on the sale of operations in certain
geographic locations. In accordance with current accounting guidance
related to presentations of financial statements (ASC 205), CH Energy Group
concluded that divested operations met the definition of discontinued
operations, and accordingly, reclassified the results of operations associated
with these operations for current and prior periods, to be reported in the
discontinued operations section of CH Energy Group’s Consolidated Statement of
Income. As permitted by this guidance, the consolidated statement of
cash flows, up to the date of sale, were combined with cash flows from
continuing operations. The cash received from the sale, net of cash
transferred, is included as cash flows from investing activities in the cash
flow statement. For more information, see Note 5 – “Acquisitions,
Divestitures and Investments”.
Effective
January 1, 2009, Central Hudson adopted current accounting guidance related to
non-controlling interests in consolidated financial statements, (ASC
810-10-65-1). Accordingly, CH
Energy Group modified the presentation of minority interest or non-controlling
interest in the prior periods presented for CH Energy Group’s Consolidated
Statement of Income, Consolidated Statement of Cash Flow and Consolidated
Balance Sheet. For more information, see Note 3 - “New Accounting
Guidance”.
Use
of Estimates
Preparation
of the financial statements in accordance with GAAP 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 amounts of revenues and
expenses during the reporting period. Actual results may differ from
those estimated, but the methods used by CH Energy Group to prepare estimates
have historically produced reliable results. Expense items most
affected by the use of estimates are depreciation and amortization (including
amortization of intangible assets), reserves for uncollectible accounts
receivable, other operating reserves, unbilled revenues, and pension and other
post-retirement benefits. 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 customer
relationships related to Griffith, which are amortized based on an assessment of
customer attrition as described in Note 6 - “Goodwill and Other
Intangible Assets.”
Estimates
for uncollectible accounts are based on customer accounts receivable aging data
as well as consideration of various quantitative and qualitative factors,
including special collection issues. In the current year, the
increase in the allowance for doubtful accounts reflects the impact of the
continued weak economy on customers’ ability to pay their bills. The
estimates for other operating reserves are based on assessments of future
obligations related to injuries and damages and workers compensation
claims. Unbilled revenues are determined based on the estimated sales
for bimonthly accounts that have not been billed by Central Hudson in the
current month. The estimation methods used in determining these sales
are the same methods used for billing customers when actual meter readings
cannot be obtained. Estimated unbilled revenues are reported as
current assets, and include amounts recorded both in revenues and as regulatory
liabilities. Revenues for 2009, 2008 and 2007 include an estimate for
unbilled revenues of $8.9 million, $8.2 million and $7.8 million,
respectively. Pursuant to regulatory requirements, a portion of
unbilled revenue is offset by a regulatory liability and is not included in
revenues. The portion of unbilled revenues offset by a regulatory
liability at December 31, 2009, 2008 and 2007 was $5.3 million, $4.5 million and
$4.2 million, respectively.
The
significant assumptions and estimates used to account for the pension plan and
other post-retirement benefit expenses and liabilities are the discount rate,
the expected long-term rate of return on the retirement plan and post-retirement
plan assets, the rate of compensation increase, the healthcare cost trend rate,
mortality assumptions, and the method of amortizing gains and
losses.
Estimates
are also reflected for certain commitments and contingencies where there is
sufficient basis to project a future obligation. Disclosures related
to these certain commitments and contingencies are included in Note 12 -
“Commitments and Contingencies.”
Rates,
Revenues, and Cost Adjustment Clauses
Central
Hudson’s electric and natural gas retail rates are regulated by the New York
State Public Service Commission (“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 tariffs for retail electric and natural gas service include purchased
electricity and purchased natural gas cost adjustment clauses by which electric
and natural gas rates are adjusted to collect the actual purchased electricity
and purchased natural gas costs incurred in providing service.
Effective
July 1, 2009, Central Hudson’s delivery rate structure includes revenue
decoupling mechanisms (“RDMs”), which provide the ability to record revenues
equal to those forecasted in the development of current rates for most of
Central Hudson’s customers.
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 30 days subsequent to the meter-read date. As of
December 31, 2009, and 2008, the portion of estimated electric unbilled revenues
that is unrecognized in accordance with current regulatory agreements were $10.1
million and $9.8 million, respectively. The full amount of estimated
natural gas unbilled revenues are recognized on the Consolidated Balance
Sheet.
As
required by the PSC, Central Hudson records gross receipts tax revenues and
expenses on a gross income statement presentation basis (i.e., included in both
revenue and expenses). Sales and use taxes for both Central Hudson
and Griffith are accounted for on a net basis (excluded from
revenue).
Griffith
records revenue when products are delivered to customers or services have been
rendered. Deferred revenues include unamortized payments from fuel
oil burner maintenance and tank service agreements, as well as fees paid by
customers for price-protected programs. These agreements require a
one-time payment from the customer at inception of the agreements. CH
Energy Group’s deferred revenue balances as of December 31, 2009 and December
31, 2008 were $4.7 million and $8.8 million, respectively. The
deferred revenue balance will be recognized in competitive business
subsidiaries’ operating revenues over the 12-month term of the respective
customer contract.
For
Central Hudson and Griffith, payments received from customers who participate in
budget billing, whose balance represents the amount paid in excess of deliveries
received at December 31, are included in customer advances. On an
annual basis, each such customer’s budget billings are reconciled with their
actual purchases and the accounts are settled.
Cash
and Cash Equivalents
For
purposes of the Statement of Cash Flows and the Balance Sheet, CH Energy Group
and Central Hudson consider temporary cash investments with a maturity (when
purchased) of three months or less, to be cash equivalents.
Fuel,
Materials and Supplies
Fuel,
materials and supplies for CH Energy Group are valued using the following
accounting methods:
Company
|
Valuation Method
|
Central
Hudson
|
Average
cost
|
Griffith
|
FIFO
|
Lyonsdale
|
Weighted
average cost
|
The
following is a summary of CH Energy Group’s and Central Hudson’s inventories (In
Thousands):
CH Energy Group
|
|
|
|
|
|
|
|
December
31,
|
|
December
31,
|
|
|
2009
|
|
2008
|
|
Natural
gas
|
|
$ |
12,020 |
|
|
$ |
22,684 |
|
Petroleum
products and propane
|
|
|
2,583 |
|
|
|
2,782 |
|
Fuel
used in electric generation
|
|
|
480 |
|
|
|
586 |
|
Materials
and supplies
|
|
|
9,758 |
|
|
|
10,533 |
|
Total
|
|
$ |
24,841 |
|
|
$ |
36,585 |
|
Central Hudson
|
|
|
|
|
|
|
|
December
31,
|
|
December
31,
|
|
|
2009
|
|
2008
|
|
Natural
gas
|
|
$ |
12,020 |
|
|
$ |
22,684 |
|
Petroleum
products and propane
|
|
|
547 |
|
|
|
550 |
|
Fuel
used in electric generation
|
|
|
308 |
|
|
|
343 |
|
Materials
and supplies
|
|
|
8,430 |
|
|
|
7,538 |
|
Total
|
|
$ |
21,305 |
|
|
$ |
31,115 |
|
Utility
Plant - Central Hudson
The cost
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 allowances for funds
used during construction (“AFUDC”), as further discussed below. The
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.
The
following summarizes the type and amount of assets included in the electric,
natural gas, and common categories of Central Hudson’s utility plant balances
(In Thousands):
|
|
Estimated
|
|
|
Utility
Plant
|
|
|
|
Depreciable
|
|
|
December
31,
|
|
|
|
Life
in Years
|
|
|
2009
|
|
|
2008
|
|
Electric
|
|
|
|
|
|
|
|
|
|
Production
|
|
25-75 |
|
|
$ |
33,837 |
|
|
$ |
32,110 |
|
Transmission
|
|
28-70 |
|
|
|
209,381 |
|
|
|
199,463 |
|
Distribution
|
|
7-80 |
|
|
|
664,641 |
|
|
|
630,021 |
|
Other
|
|
37 |
|
|
|
948 |
|
|
|
871 |
|
Total
|
|
|
|
|
$ |
908,807 |
|
|
$ |
862,465 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
Gas
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
25-60 |
|
|
$ |
5,464 |
|
|
$ |
5,414 |
|
Transmission
|
|
18-70 |
|
|
|
45,016 |
|
|
|
43,796 |
|
Distribution
|
|
25-70 |
|
|
|
230,217 |
|
|
|
214,172 |
|
Other
|
|
N/A |
|
|
|
442 |
|
|
|
492 |
|
Total
|
|
|
|
|
$ |
281,139 |
|
|
$ |
263,874 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
|
|
|
|
|
|
|
|
|
Land
and Structures
|
|
50 |
|
|
$ |
55,579 |
|
|
$ |
54,084 |
|
Office
and Other Equipment, Radios and Tools
|
|
8-35 |
|
|
|
35,566 |
|
|
|
36,074 |
|
Transportation
Equipment
|
|
10-12 |
|
|
|
41,450 |
|
|
|
40,390 |
|
Other
|
|
5 |
|
|
|
7,159 |
|
|
|
5,184 |
|
Total
|
|
|
|
|
$ |
139,754 |
|
|
$ |
135,732 |
|
Allowance
For Funds Used During Construction
Central
Hudson’s regulated utility plant includes AFUDC, which is defined 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 AFUDC rate was 1.00%
in 2009, 3.00% in 2008, and 5.25% in 2007. The amounts recorded for
years 2009, 2008, and 2007 are $0.2 million, $0.6 million, and $1.1 million,
respectively.
Depreciation
and Amortization
The
regulated assets of Central Hudson include electric, natural gas, and common
assets and are listed under the heading “Utility Plant” on Central Hudson’s and
CH Energy Group’s Consolidated Balance Sheets. The accumulated
depreciation associated with these regulated assets is also reported on the
Consolidated Balance Sheets.
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 generally 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.
Current
accounting guidance related to asset retirement and environmental obligations
(ASC 410), precludes the recognition of expected future retirement obligations
as a component of depreciation expense or accumulated
depreciation. Central Hudson, however, is required to use
depreciation methods and rates approved by the PSC under regulatory
accounting. In accordance with current accounting guidance for
Regulated Operations (ASC 980), Central Hudson continues to accrue for the
future cost of removal for its rate-regulated natural gas and electric utility
assets. In accordance with ASC 410, Central Hudson has classified
$47.0 million and $47.6 million of net cost of removal as a regulatory liability
as of December 31, 2009 and 2008, respectively.
Central
Hudson performs depreciation studies periodically and, upon approval by the PSC,
adjusts the depreciation rates of its various classes of depreciable
property. Central Hudson’s composite rates for depreciation were
2.75% in 2009, 2.74% in 2008, and 2.78% in 2007 of the original average cost of
depreciable property. The ratio of the amount of accumulated
depreciation to the original cost of depreciable property at December 31 was
28.4% in 2009, 29.4% in 2008, and 30.4% in 2007.
For
financial statement purposes, Griffith’s, Lyonsdale’s, CH-Auburn’s and
CH-Greentree’s 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.
Research
and Development
Central
Hudson is engaged in the conduct and support of research and development
(“R&D”) activities, which are focused on the improvement of existing energy
technologies and the development of new technologies for the delivery and
customer use of energy. Central Hudson’s R&D expenditures were
$3.9 million in 2009 and 2008, and $3.5 million in 2007. These
expenditures were for internal research programs and for contributions to
research administered by New York State Energy Research and Development
Authority (“NYSERDA”), the Electric Power Research Institute, and other industry
organizations. R&D expenditures are provided for in Central
Hudson’s rates charged to customers for electric and natural gas delivery
service. In addition, the PSC has authorized that differences between
R&D expense and the rate allowances covering these costs be deferred for
future recovery from or return to customers.
Income
Tax
CH Energy
Group and its subsidiaries file consolidated federal and state income tax
returns. Income taxes are deferred under the asset and liability
method in accordance with current accounting guidance for income taxes (ASC
740). Under the asset and 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, CH Energy Group
and its subsidiaries use an accelerated method of depreciation and generally use
the shortest life permitted for each class of assets. Deferred
investment tax credits are amortized over the estimated life of the properties
giving rise to the credits. 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. CHEC, Griffith and Lyonsdale file state income tax
returns in those states in which they conduct business. For more
information, see Note 4 - “Income Tax.”
Equity-Based
Compensation
CH Energy
Group has an equity-based employee compensation plan that is described in Note
11 - “Equity-Based Compensation.”
Earnings
Per Share
The
following table presents CH Energy Group’s basic and diluted earnings per share
included on the Consolidated Statement of Income (In Thousands except Earnings
Per Share):
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Avg.
|
|
|
Net
|
|
|
Earnings
|
|
|
Avg.
|
|
|
Net
|
|
|
Earnings
|
|
|
Avg.
|
|
|
Net
|
|
|
Earnings
|
|
|
|
Shares
|
|
|
Income
|
|
|
Per
Share
|
|
|
Shares
|
|
|
Income
|
|
|
Per
Share
|
|
|
Shares
|
|
|
Income
|
|
|
Per
Share
|
|
Earnings
attributable to Common Stock - continuing operations
|
|
|
|
|
$ |
33,633 |
|
|
|
|
|
|
|
|
$ |
31,536 |
|
|
|
|
|
|
|
|
$ |
41,155 |
|
|
|
|
Earnings
attributable to Common Stock - discontinued operations
|
|
|
|
|
$ |
9,851 |
|
|
|
|
|
|
|
|
$ |
3,545 |
|
|
|
|
|
|
|
|
$ |
1,481 |
|
|
|
|
Average
number of common shares outstanding - basic - continuing
operations
|
|
|
15,775 |
|
|
|
|
|
|
$ |
2.13 |
|
|
|
15,768 |
|
|
|
|
|
|
$ |
2.00 |
|
|
|
15,762 |
|
|
|
|
|
|
$ |
2.61 |
|
Average
number of common shares outstanding - basic - discontinued
operations
|
|
|
15,775 |
|
|
|
|
|
|
$ |
0.63 |
|
|
|
15,768 |
|
|
|
|
|
|
$ |
0.22 |
|
|
|
15,762 |
|
|
|
|
|
|
$ |
0.09 |
|
Average
dilutive effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
options(1)
(2)
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
(1 |
) |
|
|
- |
|
|
|
1 |
|
|
|
(31 |
) |
|
|
- |
|
Performance
shares(2)
|
|
|
65 |
|
|
|
- |
|
|
|
- |
|
|
|
25 |
|
|
|
- |
|
|
|
- |
|
|
|
16 |
|
|
|
- |
|
|
|
- |
|
Restricted
shares(2)
|
|
|
41 |
|
|
|
- |
|
|
|
- |
|
|
|
12 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Average
number of common shares outstanding - diluted
|
|
|
15,881 |
|
|
$ |
43,485 |
|
|
$ |
2.74 |
|
|
|
15,805 |
|
|
$ |
35,080 |
|
|
$ |
2.22 |
|
|
|
15,779 |
|
|
$ |
42,605 |
|
|
$ |
2.70 |
|
(1)
|
For
2009, 2008 and 2007, certain stock options have been 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 17,420
shares for 2009, 39,980 shares for 2008 and 18,420 shares for
2007.
|
(2)
|
See
Note 11 - “Equity-Based Compensation” for additional information regarding
stock options, performance shares and restricted
shares.
|
Related
Party Transactions
Thompson
Hine LLP serves as outside counsel to CH Energy Group and Central
Hudson. Prior to becoming Executive Vice President and General
Counsel of CH Energy Group, John E. Gould was a partner in the law firm Thompson
Hine LLP, while serving as Secretary of each corporation. In
addition, one partner in that firm served as Assistant Secretary of each
corporation during the year. CH Energy Group and Central Hudson paid
combined legal fees to Thompson Hine LLP of $3.3 million in 2009, $3.6 million
in 2008, and $3.4 million in 2007.
Parental
Guarantees
CH Energy
Group and CHEC have issued guarantees in conjunction with certain commodity,
derivative and construction 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.
The
guarantees described above have been issued to counterparties to assure the
payment, when due, of certain obligations incurred by CH Energy Group
subsidiaries in physical and financial transactions related to heating oil,
propane, other petroleum products, weather and commodity hedges and to secure
payment under certain equipment supply and construction
agreements. At December 31, 2009, the aggregate amount of subsidiary
obligations covered by these guarantees was $35.3 million. Where
liabilities exist under the commodity-related contracts subject to these
guarantees, these liabilities are included in CH Energy Group’s Consolidated
Balance Sheet.
Other
Guarantees
Central
Hudson had a reimbursement obligation with respect to a $6.8 million standby
letter of credit issued by a financial institution to support a real estate
transaction that closed in June 2009. No premium was received or is
receivable by Central Hudson in connection with this letter of
credit. This uncollateralized letter of credit was issued February
29, 2008 and expired upon the closing of the real estate
transaction.
Product
Warranties
Griffith
offers a multi-year warranty on heating system installations and has recorded
liabilities for the estimated costs of fulfilling its obligations under these
warranties. CH Energy Group’s approximate aggregate potential
liability for product warranties at December 31, 2009 and 2008 was not
material. CH Energy Group’s liabilities for these product warranties
were determined by accruing the present value of future estimated warranty
expense based on the number and type of contracts outstanding and historical
costs for these contracts.
Consolidation
of Variable Interest Entities
Current
accounting guidance relating to consolidation of Variable Interest Entities
(“VIE”) (ASC 810) provides rules related to the identification of a variable
interest and a VIE to determine when the assets, liabilities, and results of
operations should be consolidated in a company’s financial
statements. A VIE is an entity that is not controllable through
voting interests and where the equity investment at risk is not sufficient to
permit the VIE to finance its activities without additional subordinated
financial support provided by any party, including the equity
holders. A company that holds a variable interest in an entity is
required to consolidate the entity if the company’s interest in the VIE is such
that the company will absorb a majority of the VIE’s expected losses and/or
receive a majority of the VIE’s expected residual returns.
CH Energy
Group and its subsidiaries do not have any interests in special purpose entities
and do not have material affiliations with any variable interest entities that
require consolidation.
Common
Stock Dividends
CH Energy
Group’s ability to pay dividends may be affected by the ability of its
subsidiaries to pay dividends. The Federal Power Act limits the payment of
dividends by Central Hudson to its retained earnings. More
restrictive is the PSC’s limit on the dividends Central Hudson may pay to CH
Energy Group which is 100% of the average annual income available for common
stock, calculated on a two-year rolling average basis. Based on this
calculation as of December 31, 2009, Central Hudson would be able to pay a
maximum of $29.0 million in dividends to CH Energy Group without violating the
restrictions by the PSC. Central Hudson’s dividend would be reduced
to 75% of its average annual income in the event of a downgrade of its senior
debt rating below “BBB+” by more than one rating agency if the stated reason for
the downgrade is related to CH Energy Group or any of Central Hudson’s
affiliates. Further restrictions are imposed for any downgrades below
this level. Central Hudson’s current senior unsecured debt
rating/outlook is ‘A’/stable by both Standard & Poor’s Rating Services
(“Standard & Poor’s”) and Fitch Ratings and ‘A3’/negative by Moody’s
Investors Service (“Moody’s”).3 CH
Energy Group’s other subsidiaries do not have express restrictions on their
ability to pay dividends.
On
December 17, 2009, the Board of Directors of CH Energy Group declared a
quarterly dividend of $0.54 per share, payable February 1, 2010, to shareholders
of record as of January 11, 2010.
_________________________________
3 These
ratings reflect only the views of the rating agency issuing the rating, are not
recommendations to buy, sell, or hold securities of Central Hudson and may be
subject to revision or withdrawal at any time by the rating agency issuing the
rating. Each rating should be evaluated independently of any other
rating.
In
response to the May 1996 Order, the PSC issued in its generic Competitive
Opportunities Proceeding, Central Hudson, PSC Staff, and certain other parties
entered into a settlement agreement (the “Settlement Agreement”). The
PSC approved the Settlement Agreement by its final Order effective June 30,
1998, for which a final amendment was approved as of March 7, 2000.
The
Settlement 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, CH Energy Group, and any other subsidiaries
of CH Energy Group (such as CHEC and Griffith); (iii) prohibitions against
Central Hudson making loans to CH Energy Group or any other subsidiary of CH
Energy Group and against Central Hudson guaranteeing debt of CH Energy Group or
any other subsidiary of CH Energy Group; (iv) limitations on the transfer of
Central Hudson employees to CH Energy Group or other CH 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 GAAP, which includes accounting guidance for regulated
operations. In accordance with this guidance, regulated companies
such as Central Hudson apply AFUDC to the cost of construction projects and
defer costs and credits on the balance sheet as regulatory assets and
liabilities (see the caption “Summary of Regulatory Assets and Liabilities” of
this Note) 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. For Central Hudson, these
deferred regulatory assets and liabilities, and the related deferred taxes, are
then either eliminated by offset as directed by the PSC or reflected in the
Consolidated Statement of Income 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, whichever the case may be.
Summary
of Regulatory Assets and Liabilities
The
following table sets forth Central Hudson’s regulatory assets and liabilities
(In Thousands):
|
|
December
31,
|
|
|
|
December
31,
|
|
|
|
2009
|
|
|
|
2008
|
|
Regulatory Assets (Debits):
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
Deferred
purchased electric and natural gas costs
|
|
$ |
27,610 |
|
|
|
$ |
41,931 |
|
Deferred
unrealized losses on derivatives
|
|
|
13,161 |
|
|
|
|
15,759 |
|
PSC
tax surcharge
|
|
|
11,186 |
|
|
|
|
- |
|
Revenue
decoupling mechanism ("RDM")
|
|
|
5,121 |
|
|
|
|
- |
|
Residual
natural gas deferred balances
|
|
|
2,825 |
|
|
|
|
2,812 |
|
Other
|
|
|
90 |
|
|
|
|
- |
|
|
|
|
59,993 |
|
|
|
|
60,502 |
|
Long-term:
|
|
|
|
|
|
|
|
|
|
Deferred
pension costs
|
|
|
168,705 |
|
(1) |
|
|
197,934 |
|
Carrying
charges - pension reserve
|
|
|
1,297 |
|
(1) |
|
|
10,642 |
|
Deferred
costs - MGP site remediation
|
|
|
20,530 |
|
(1) |
|
|
30,397 |
|
Deferred
OPEB costs
|
|
|
- |
|
(1) |
|
|
4,257 |
|
Deferred
debt expense on re-acquired debt
|
|
|
4,874 |
|
|
|
|
5,442 |
|
Residual
natural gas deferred balances
|
|
|
17,583 |
|
|
|
|
22,825 |
|
Income
taxes recoverable through future rates
|
|
|
28,658 |
|
|
|
|
26,874 |
|
Uncollectible
Deferral
|
|
|
3,360 |
|
|
|
|
- |
|
Storm
costs
|
|
|
- |
|
(1) |
|
|
3,085 |
|
Other
|
|
|
7,389 |
|
(1) |
|
|
10,478 |
|
|
|
|
252,396 |
|
|
|
|
311,934 |
|
Total
Regulatory Assets
|
|
$ |
312,389 |
|
|
|
$ |
372,436 |
|
|
|
|
|
|
|
|
|
|
|
Regulatory Liabilities
(Credits):
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
Excess
electric depreciation reserve
|
|
$ |
19,296 |
|
|
|
$ |
- |
|
Income
taxes refundable through future rates
|
|
|
5,456 |
|
|
|
|
4,275 |
|
Deferred
unbilled gas revenues
|
|
|
5,222 |
|
|
|
|
4,449 |
|
|
|
|
29,974 |
|
|
|
|
8,724 |
|
Long-term:
|
|
|
|
|
|
|
|
|
|
Customer
benefit fund
|
|
|
3,792 |
|
|
|
|
4,266 |
|
Deferred
cost of removal
|
|
|
46,955 |
|
|
|
|
47,630 |
|
Excess
electric depreciation reserve
|
|
|
12,965 |
|
|
|
|
32,313 |
|
Income
taxes refundable through future rates
|
|
|
18,611 |
|
|
|
|
19,756 |
|
Deferred
OPEB costs
|
|
|
1,521 |
|
(1) |
|
|
- |
|
Carrying
charges - OPEB reserve
|
|
|
1,469 |
|
(1) |
|
|
5,633 |
|
Other
|
|
|
7,665 |
|
(1) |
|
|
16,846 |
|
|
|
|
92,978 |
|
|
|
|
126,444 |
|
Total
Regulatory Liabilities
|
|
$ |
122,952 |
|
|
|
$ |
135,168 |
|
|
|
|
|
|
|
|
|
|
|
Net
Regulatory Assets
|
|
$ |
189,437 |
|
|
|
$ |
237,268 |
|
(1)
|
Effective July 1, 2009, Central
Hudson offset all or a portion of certain regulatory assets and
liabilities, including full offset of the June 30, 2009 balances for
Carrying charges - OPEB reserve, Carrying charges - pension reserve and
Storm costs in accordance with the 2009 Rate
Order.
|
The
significant regulatory assets and liabilities include:
PSC tax
surcharge: In 2009, Central Hudson paid $17.7 million to the
PSC for a new tax surcharge instituted in April 2009. However, only
$7.2 million of this surcharge has been collected from customers through
December 31, 2009. In March 2010, Central Hudson will begin making
bi-annual installments of approximately $8.9 million for this surcharge and will
collect the amounts from customers in subsequent months.
Deferred Pension
Costs: Deferred pension costs recoverable from customers
include the following: (A) As discussed further in Note 10 - “Post-Employment
Benefits,” the amount of deferred pension cost undercollected as of December 31,
2009, and December 31, 2008, includes $164.6 million and $192.1 million,
respectively, related to the current accounting guidance related to pensions
(ASC 715-30) for recording the funded status. (B) The remaining $4.1
million and $5.8 million at December 31, 2009 and 2008, respectively, are the
cumulative undercollected pension costs in excess of amounts provided in
rates.
Carrying Charges - Pension
Reserve: Under the policy of the PSC regarding pension costs,
carrying charges are accrued on cash differences between rate allowances and
cash contributions to Central Hudson’s defined benefit pension
plan. For further discussion regarding this plan, see Note 10 -
“Post-Employment Benefits.”
Income Taxes
Recoverable: Regulatory asset balance established to offset deferred tax
liabilities determined in accordance with current accounting guidance related to
income tax (ASC 740) and for which it is probable that they will be recoverable
from customers.
Storm
Costs: The 2009 Rate Order authorized the recovery of
restoration costs incurred by the Company related to an ice storm in December
2008 through an offset against certain electric regulatory liability
balances.
Income Taxes
Refundable: Regulatory liability balances established to
offset deferred tax assets determined in accordance with current accounting
guidance related to income taxes (ASC 740). As it is probable that
the related balances will be refundable to customers, Central Hudson established
a net regulatory liability for these balances.
Customer Benefit
Fund: The
2006 Order prescribes the use of the residual balance to fund economic
development and competitive metering initiative programs.
Carrying Charges - OPEB
Reserve: Under the policy of the PSC regarding OPEB costs,
carrying charges are accrued on cash differences between rate allowances and
cash contributions to Central Hudson’s OPEB plan. For further
discussion regarding this plan, see Note 10 - “Post-Employment
Benefits.”
RDM: The
2009 Rate Order authorized a revenue decoupling mechanism as part of the rate
increase which allows Central Hudson to recognize revenues at the level approved
in rates for most of Central Hudson’s electric customer classes and recognized
sales at the approved level per customer in rates for most of Central Hudson’s
gas customer classes.
Excess Electric Depreciation
Reserve (“EDR”): Per the 2009 Rate Order, $8.8 million of
additional excess electric depreciation reserve was transferred in July
2009. The transfer represented a portion of the electric depreciation
reserve that was in excess of the theoretical book reserve based on depreciation
rates approved by the PSC in 2009. The 2009 Rate Order prescribed the
use of the EDR to offset certain electric regulatory assets and liabilities
balances accumulated as of June 30, 2009 which resulted in an additional
increase in this net regulatory liability balance of $1.1 million. As defined
within the 2009 Rate Order, the new balance after the above adjustments is to be
used for authorized rate moderation. The current portion of the EDR
as of December 31, 2009 represents the amount estimated to be used for rate
moderation in the next twelve months related to the Electric Bill Credit,
Incremental Finance Charges and amounts estimated to be spent over the electric
portion of MGP rate allowance as defined in the 2009 Rate Order.
Residual Natural Gas
Deferred Balances: Per the 2006 Rate Order, certain gas
regulatory assets and liabilities were identified for offset, resulting in a net
regulatory asset balance. As a result of the 2009 Rate Order, in July
2009 a $2.8 million gas depreciation reserve adjustment identified by the PSC
was transferred to accumulated depreciation as a reduction to this
balance. Other adjustments increased the Residual Natural Gas
Deferred Balance by $0.1 million. The remaining balance is to be
amortized over a five-year period beginning July 1, 2009.
Uncollectible
Deferral: In October 2009, Central Hudson filed a petition
with the PSC seeking approval to defer $2.4 million of incremental electric and
$0.4 million of incremental gas net bad debt write-off expense incurred during
the twelve months ended June 30, 2009 over the amounts provided for in rates
during that time period and over the gas deferral amount previously
approved.
In terms
of the expected timing for recovery, regulatory asset balances at December 31,
2009, reflect the following (In Thousands):
Balances
with offsetting accrued liability balances recoverable when future costs
are actually incurred:
|
|
|
|
Deferred
pension related to underfunded status
|
|
$ |
164,644 |
|
Income
taxes recoverable through future rates
|
|
|
28,658 |
|
Deferred
costs - MGP sites
|
|
|
20,230 |
|
Other
|
|
|
4,529 |
|
|
|
|
218,061 |
|
|
|
|
|
|
Balances
earning a return via inclusion in rates and/or the application of carrying
charges:
|
|
|
|
|
Residual
natural gas deferred balances
|
|
|
17,476 |
|
Deferred
pension costs undercollected(1)
|
|
|
4,061 |
|
PSC
tax surcharge
|
|
|
10,947 |
|
Uncollectible
deferral(2)
|
|
|
3,327 |
|
Other(1)
|
|
|
8,130 |
|
|
|
|
43,941 |
|
|
|
|
|
|
Subject
to current recovery:
|
|
|
|
|
Deferred
purchased electric and natural gas costs
|
|
|
40,770 |
|
Residual
natural gas deferred balances
|
|
|
2,825 |
|
RDMs
|
|
|
5,031 |
|
|
|
|
48,626 |
|
|
|
|
|
|
Accumulated
carrying charges:(1)
|
|
|
|
|
Pension
reserve
|
|
|
1,297 |
|
Other
|
|
|
464 |
|
|
|
|
1,761 |
|
|
|
|
|
|
Total
Regulatory Assets
|
|
$ |
312,389 |
|
(1)
|
Subject
to recovery in Central Hudson's future rate
proceedings.
|
(2)
|
PSC
approval has been obtained for $0.5 million related to gas uncollectible
expenses incurred for the calendar year ended December 31,
2008. $2.8 million of this balance relates to the twelve months
ended June 30, 2009 for electric uncollectible expenses and six months
ended June 30, 2009 for gas uncollectible expenses and is subject to
recovery in Central Hudson's filed
petition.
|
2001
Rate Order
Central
Hudson continued to operate, through June 30, 2006, under the terms of a Rate
Plan approved by the PSC on October 25, 2001, and further modified by the PSC on
June 14, 2004 (“2001 Rate Order”).
Two
initiatives survived the expiration of the 2001 Rate Order: 1) Economic
Development and 2) Competitive Metering Initiative. These programs
are funded by the Customer Benefit Fund, established to benefit customers as a
result of proceeds retained from Central Hudson’s sale of generating assets in
2001.
2006
Rate Order
From July
1, 2006 through June 30, 2009, Central Hudson operated under the terms of the
2006 Rate Order, which provided for the following:
|
·
|
Electric
delivery revenues increase of $53.7 million over the three-year term with
annual rate increases of approximately $17.9 million on July 1, 2006, July
1, 2007, and July 1, 2008.
|
|
·
|
Natural
gas delivery revenues increase by $14.1 million with rate increases of $8
million on July 1, 2006 and $6.1 million on July 1,
2007.
|
|
·
|
Delivery
rates based on a ROE of 9.6% with an earnings sharing threshold of 10.6%,
above which Central Hudson is to share 50% with its
customers. Earnings above 11.6% are shared 65% with customers
and earnings above 14.0% are allocated entirely to
customers.
|
|
·
|
Limits
on Central Hudson’s ability to defer certain costs if earnings exceed an
11.0% ROE. However, these deferral limitations could not cause
earnings to be reduced below 11.0%.
|
|
·
|
Rates
based on a capital structure that includes 45% common
equity. However, the actual proportion of common equity, up to
a limit of 47%, was used to determine the ROE for the purpose of earnings
sharing.
|
|
·
|
Continued
full recovery of all purchased natural gas and electricity costs through
existing monthly supply cost recovery
mechanisms.
|
|
·
|
Established
targets for electric, natural gas, and common plant expenditures, and
increased allowances for the recovery of operating costs, including
transmission and distribution Right-of-Way (“ROW”) maintenance
expenses. The capital expenditure targets were subject to
true-up provisions, requiring deferral of 150% of the revenue requirement
of any shortfalls in spending over the 2006 Rate Order’s three-year term,
if such shortfall existed at June 30,
2009.
|
|
·
|
Transmission
and distribution ROW maintenance expenses were also subject to true-up
provisions over the 2006 Rate Order’s three-year term, requiring the
deferral of shortfalls in actual expenditures, if such shortfall existed
at June 30, 2009.
|
|
·
|
Increased
rate allowances and continued deferral accounting authorization for the
recovery of expenses for pensions, OPEB, stray voltage testing, MGP site
remediation, and certain other expense
items.
|
|
·
|
Additional
funding to assist low-income customers in paying their energy bills as
well as continued funding of programs to encourage customers to explore
new opportunities available through the competitive retail supply
markets.
|
|
·
|
Penalty-only
performance mechanisms with established targets for specified levels of
performance related to customer service quality, natural gas safety, and
electric reliability measures.
|
|
·
|
No
penalties were recorded in 2009, 2008 and
2007.
|
2009
Rate Order
From July
1, 2009 through June 30, 2010, Central Hudson operates under the terms of the
2009 Rate Order, which provides for the following:
|
·
|
Electric
delivery increase of $39.6 million moderated by a $20.0 million customer
bill credit from the excess depreciation
reserve.
|
|
·
|
Natural
gas delivery increase of $13.8
million.
|
|
·
|
Delivery
rates based on a ROE of 10.0%.
|
|
·
|
Common
equity layer of 47% of permanent
capital.
|
|
·
|
RDM
for both electric and gas delivery
service.
|
|
·
|
Continued
funding for the full recovery of the Company’s current pension and OPEB
costs and continued deferral authorization for pensions, OPEBs, research
and development costs, stray voltage testing, MGP site remediation
expenditures and electric and gas supply cost recovery and variable rate
debt.
|
|
·
|
New
deferral authorizations for: fixed debt costs; the costs to bring electric
lines into compliance with current height above ground requirements; and
the New York State Temporary
Assessment.
|
|
·
|
Continuation,
with minor modifications, of the Company’s Electric Reliability, Gas
Safety and Customer Service performance
mechanisms.
|
|
·
|
Recovery
through offset against a deferred liability account (non-cash) of the $3.3
million in incremental storm restoration costs incurred from the December
2008 ice storm.
|
Financing
Petition
On
September 22, 2009, the PSC issued an Order authorizing issuance of securities,
in response to a financing petition Central Hudson filed on March 26,
2009. The Order authorized Central Hudson to issue and sell up to
$250 million of long-term debt through December 31, 2012, and to enter into
revolving credit agreements in an amount not to exceed $175 million in the
aggregate and for periods not to exceed five years.
Other
Regulatory Matters
Non-Utility Land Sales -
Central Hudson
Central
Hudson did not sell any parcels of non-utility property during 2009 or
2008. Central Hudson sold a total of four parcels of non-utility real
property for $0.5 million in excess of book value and transaction costs, during
the year ended December 31, 2007. This excess is recorded as a
reduction to Other Expenses of Operation on the Consolidated Statement of
Income.
New
accounting guidance is summarized below, and explanations of the underlying
information for all guidance (except that which is not currently applicable to
CH Energy Group and its subsidiaries) follow the chart.
Category
|
|
Accounting
Reference
|
|
Title
|
|
Issued
Date
|
|
Effective
Date
|
Under
Assessment(1)
|
|
|
|
|
|
|
Variable
Interest Entities
|
|
SFAS
No. 167
|
|
Amendments
to ASC 810-10-25-38
|
|
Jun-09
|
|
Jan-10
|
Implemented(2)
|
|
|
|
|
|
|
Postretirement
Benefit Plan Assets
|
|
ASC
715-20-65-2
|
|
Employers'
Disclosures about Postretirement Benefit Plan Assets
|
|
Dec-08
|
|
Dec-09
|
Fair
Value Measurement
|
|
ASU
No. 2009-05
|
|
Amendments
to ASC 820-10 - Fair Value Measurements and Disclosures-Overall, for the
fair value measurement of liabilities
|
|
Aug-09
|
|
Dec-09
|
GAAP
Hierarchy
|
|
SFAS
No. 168
|
|
The
FASB Accounting Standards Codification and the Hierarchy of Generally
Accepted Accounting Principles - a replacement of SFAS No.
162
|
|
Jun-09
|
|
Sep-09
|
Subsequent
Events
|
|
ASC
855
|
|
Subsequent
Events
|
|
May-09
|
|
Jun-09
|
Business
Combinations
|
|
ASC
805
|
|
Business
Combinations
|
|
Apr-09
|
|
Jan-09
|
Business
Combinations
|
|
ASC
805
|
|
Business
Combinations
|
|
Dec-07
|
|
Jan-09
|
Fair
Value Measurement
|
|
ASC
820
|
|
Fair
Value Measurements and Disclosures
|
|
Apr-09
|
|
Jun-09
|
Liabilities
Measured at Fair Value
|
|
ASC
820
|
|
Fair
Value Measurement and Disclosures (encompassing Issuer's Accounting for
Liabilities Measured at Fair Value with a Third-Party Credit
Enhancement)
|
|
Sep-08
|
|
Jan-09
|
Other-Than-Temporary-Investments
|
|
ASC
320
|
|
Investments
- Debt and Equity Securities
|
|
Apr-09
|
|
Jun-09
|
Financial
Instruments
|
|
ASC
825
|
|
Financial
Instruments
|
|
Apr-09
|
|
Jun-09
|
Equity
Method Investments
|
|
ASC
323-10
|
|
Investments
- Equity Method
|
|
Nov-08
|
|
Jan-09
|
Credit
Derivatives
|
|
ASC
815-10-65-2
|
|
Disclosures
About Credit Derivatives and Certain Guarantees: An Amendment
of FASB Statement No. 133 and FASB Interpretation No. 45; and
Clarification of the Effective Date of FASB Statement No.
161
|
|
Sep-08
|
|
Jan-09
|
Derivative
Instruments
|
|
ASC
815
|
|
Derivatives
and Hedging
|
|
Mar-08
|
|
Jan-09
|
Share-Based
Payments
|
|
ASC
260-10-55
|
|
Participating
Share-Based Payment Awards
|
|
Jun-08
|
|
Jan-09
|
Noncontrolling
Interests
|
|
ASC
810-10-65-1
|
|
Transition
Related to FASB Statement No. 160, Noncontrolling Interests in
Consolidated Financial Statements - an amendment of ARB No.
51
|
|
Dec-07
|
|
Jan-09
|
Intangible
Assets
|
|
ASC
350-30
|
|
General
Intangibles Other than Goodwill
|
|
Nov-07
|
|
Jan-09
|
Not Currently
Applicable(3)
|
|
|
|
|
|
|
Financial
Assets
|
|
SFAS
No. 166
|
|
Accounting
for Transfers of Financial Assets - an amendment of FAS
140
|
|
Jun-09
|
|
Jan-10
|
Impact
Key:
1 - No
significant impact on the financial condition, results of operations and cash
flows of CH Energy Group and its subsidiaries expected.
2 -
Following the chart, the impacts are separately disclosed as of standard
effective dates.
3 - No
current impact on the financial condition, results of operations and cash flows
of CH Energy Group and its subsidiaries.
Standards
Under Assessment
SFAS No.
167 amends ASC 810-10-25-38, Consolidation Based on Variable
Interests. This Statement
requires an enterprise involved with variable interest entities to perform an
analysis to determine whether the enterprise’s variable interest or interests
give it a controlling financial interest in the variable interest entity. This Statement
is effective for annual reporting periods beginning after November 15,
2009. SFAS No. 167 has not been superseded by the FASB Accounting
Standards Codification. It is not expected that this Statement will
have a significant impact on CH Energy Group or Central Hudson.
Standards
Implemented
ASC
715-20-65-2 provides guidance on an employer’s disclosures about plan assets of
a defined benefit pension or other post-retirement plan. The ASC
defines the objectives of the disclosures as providing users of the financial
statements with an understanding of how investment allocation decisions are
made, pertinent factors of investment policies and strategies, major categories
of plan assets, inputs and valuation techniques used to measure the fair value
of plan assets, the effect of fair value measurements using significant
unobservable inputs on changes in the plan assets for the period, and
significant concentrations of credit risk within plan assets. In
accomplishing these objectives, expanded disclosures related to pension and
other post-retirement benefit plans are made beginning for fiscal periods ending
after December 15, 2009. There was no significant impact on CH Energy
Group or Central Hudson upon adoption of this standard.
ASU No.
2009-05, an update to ASC 820-10, Fair Value Measurements and
Disclosures-Overall, for the fair value measurements of liabilities,
establishes a hierarchy of valuation techniques preferred and defines that the
restrictions on the transfer of liabilities do not need to be considered in
assessing the fair value of liabilities. This update is effective for
fiscal periods ending after December 15, 2009. There was no
significant impact on CH Energy Group or Central Hudson upon adoption of this
standard.
SFAS No.
168 (which was not superseded by FASB Accounting Standards Codification)
identifies the FASB Accounting Standards Codification as the source of
authoritative US Generally Accepted Accounting Principles (“GAAP”) recognized by
FASB for nongovernmental entities. SFAS No. 168 supersedes SFAS No.
162 by defining the Codification as the only authoritative
GAAP. There was no significant impact on CH Energy Group or Central
Hudson upon adoption of this standard.
ASC 855
provides general standards of accounting for and disclosure of events that occur
after the balance sheet date but before financial statements are issued or
available to be issued. CH Energy Group implemented this standard for
interim reporting periods ending June 30, 2009. There was no
significant impact on CH Energy Group or Central Hudson upon adoption of this
standard.
ASC 805
includes amendments to and clarifies application issues regarding the accounting
and disclosure provisions for contingencies in FASB Statement No. 141 (R), Business
Combinations. This ASC includes amendments to Statement 141(R)
by replacing the guidance on the initial recognition and measurements of assets
and liabilities arising from contingencies acquired or assumed in business
combinations. CH Energy Group implemented ASC 805 upon its
issuance. There was no significant impact on CH Energy Group or
Central Hudson upon adoption of this standard.
ASC 805
requires that acquisition-related costs be expensed in the period incurred and
can no longer be capitalized and included as a cost of the acquired
business. The objective of ASC 805 is to improve the relevance,
representational faithfulness, and comparability of the information that an
entity provides in its financial reports about a business combination and its
effects. This standard applies to all transactions or events in which an entity
obtains control of one or more businesses, and to combinations achieved without
the transfer of consideration. There was no significant impact on CH
Energy Group or Central Hudson upon adoption of this standard.
ASC 820
provides factors that should be considered in determining whether there has been
a significant decrease in the volume and level of activity for an asset or
liability and guidance on additional analysis that may be necessary, as a result
in estimating fair value in accordance with this standard. This ASC
also includes guidance on identifying circumstances that indicate whether a
transaction is considered orderly. There was no significant impact on
CH Energy Group or Central Hudson upon adoption of this
ASC. Management cannot predict what impact, if any, this ASC will
have on future valuations.
ASC 820
also clarifies that the issuer of a liability with a third-party credit
enhancement that is inseparable from the liability shall not include the effect
of the credit enhancement in the fair value measurement of the liability, but
the issuer should discuss the existence of this third-party credit
enhancement. There was no significant impact on CH Energy Group or
Central Hudson upon adoption of this ASC.
ASC 320
amends the other-than-temporary impairment guidance relating to debt securities
classified as available-for-sale or held-to-maturity. The objective
of this ASC is to improve the presentation and disclosure of
other-than-temporary impairments in the financial statements. CH
Energy Group implemented this ASC for the interim reporting period ended June
30, 2009. There was no significant impact on CH Energy Group or
Central Hudson upon adoption of this ASC.
ASC 825,
Financial Instruments,
requires disclosures about the fair value of financial instruments for interim
reporting periods, in addition to the annual disclosures previously required.
This ASC also requires those disclosures in summarized financial information at
interim reporting periods. CH Energy Group implemented this ASC for
the interim reporting period ended June 30, 2009, and the additional required
interim disclosures have been incorporated in Note 15 - “Fair Value
Measurements”. There was no significant impact on CH Energy Group or
Central Hudson upon adoption of this ASC.
ASC
323-10 provides guidance related to certain accounting considerations for equity
method investments. Specifically, this guidance clarifies the
accounting guidance on issues related to the determination of the initial
carrying value of an equity method investment, the performance of impairment
assessments of underlying indefinite-lived intangible assets of an equity method
investment, the accounting for the issuance of shares by an equity method
investment, and the accounting for a change in an investment from the equity
method to the cost method. CH Energy Group implemented ASC 323-10 on
January 1, 2009. There was no significant impact on CH Energy Group
or Central Hudson upon adoption of this ASC.
ASC
815-10-65-2 requires more detailed disclosures about credit derivatives,
including the potential adverse effects of changes in credit risk on the
financial position, financial performance, and cash flows of the sellers of the
instruments. ASC 815, Derivatives and Hedging,
requires increased disclosures by sellers of credit derivatives, including
credit derivatives embedded in hybrid instruments. The ASC also
requires an additional disclosure about the current status of the payment or
performance risk of a guarantee. There was no significant impact on
CH Energy Group or Central Hudson upon adoption of this ASC.
ASC 815
requires entities to provide qualitative disclosures about the objectives and
strategies for using derivatives and quantitative data about the fair value of
gains and losses on derivative contracts. ASC 815 also requires more
information about the location and amounts of derivative instruments in
financial statements, how derivatives are accounted for under the ASC, and how
hedges affect the entity's financial position, financial performance and cash
flows. For more information, see Note 14 - “Accounting for Derivative
Instruments and Hedging Activities”. There was no significant impact
on CH Energy Group or Central Hudson upon adoption of this
standard.
ASC
260-10-55 clarifies that instruments granted in share-based payment transactions
are considered participating securities prior to vesting if they contain
non-forfeitable rights to dividends or dividend equivalents and therefore need
to be included in the computation of EPS under the two-class method as described
in the guidance. There was no significant impact on CH Energy Group
or Central Hudson upon adoption of this ASC.
ASC
810-10-65-1 establishes accounting and reporting standards for the
non-controlling interest in a subsidiary and for the deconsolidation of a
subsidiary. It clarifies that a non-controlling interest in a
subsidiary is an ownership interest in the consolidated entity that should be
reported as equity in the consolidated financial statements. The
objective of ASC 810-10-65-1 is to improve the relevance, comparability and
transparency of the financial information that an entity provides in its
consolidated financial statements. There was no significant impact on
CH Energy Group or Central Hudson upon adoption of this
standard.
ASC
350-30 amends the factors that should be considered in developing renewal or
extension assumptions used to determine the useful life of recognized intangible
assets. The guidance is intended to improve consistency between the
recognized useful asset life, and the period of expected cash flows used to
measure the fair value of the asset. There was no significant impact
on CH Energy Group or Central Hudson upon adoption of this ASC.
CH Energy
Group and its subsidiaries file a consolidated Federal and New York State income
tax return. CHEC, Griffith, and Lyonsdale also file state income tax
returns in those states in which they conduct business.
As a
result of CHEC’s ownership in Cornhusker Energy Lexington Holdings, LLC
(“Cornhusker Holdings”) and Lyonsdale, a $1.4 and $1.6 million benefit for
federal production tax credits, for 2009 and 2008, respectively, is included in
CH Energy Group’s federal income tax expense. CHEC investments in
Cornhusker Holdings and Lyonsdale are discussed further in Note 5 -
“Acquisitions, Divestitures and Investments.”
Due to no
uncertain tax positions, no interest or penalties have been recorded in the
financial statements in accordance with current accounting guidance for
income taxes (ASC 740). If CH Energy Group and its subsidiaries incur
any interest or penalties on underpayment of income taxes, the amounts would be
included in the line “Other” under current liabilities on the Consolidated
Balance Sheet and in the line “Other - net” on the Consolidated Statement of
Income. CH Energy Group and its subsidiaries file a consolidated
Federal and New York State income tax return, which represents the major tax
jurisdictions of CH Energy Group. The statute of limitations for
federal tax years 2006 through 2008 are still open for audit and the tax years
2007 and 2008 are currently under audit. The New York State income
tax return is currently open for audit for tax years 2005 through
2008.
See Note
2 - “Regulatory Matters” under the caption “Summary of Regulatory Assets and
Liabilities” for additional information regarding CH Energy Group’s and its
subsidiaries’ income taxes.
Components
of Income Tax
The
following is a summary of the components of state and federal income taxes for
CH Energy Group as reported in its Consolidated Statement of Income (In
Thousands):
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Federal
income tax
|
|
$ |
7,747 |
|
|
$ |
6,611 |
|
|
$ |
14,630 |
|
State
income tax
|
|
|
4,120 |
|
|
|
1,285 |
|
|
|
1,919 |
|
Deferred
federal income tax
|
|
|
14,951 |
|
|
|
12,403 |
|
|
|
4,636 |
|
Deferred
state income tax
|
|
|
563 |
|
|
|
1,530 |
|
|
|
713 |
|
Total
income tax
|
|
$ |
27,381 |
|
|
$ |
21,829 |
|
|
$ |
21,898 |
|
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 CH
Energy Group’s Consolidated Statement of Income (In Thousands):
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Net
income attributable to CH Energy Group
|
|
$ |
43,484 |
|
|
$ |
35,081 |
|
|
$ |
42,636 |
|
Preferred
Stock dividends of Central Hudson
|
|
|
970 |
|
|
|
970 |
|
|
|
970 |
|
Non-controlling
interest in subsidiary
|
|
|
(176 |
) |
|
|
103 |
|
|
|
(121 |
) |
Federal
income tax
|
|
|
7,747 |
|
|
|
6,611 |
|
|
|
14,630 |
|
State
income tax
|
|
|
4,120 |
|
|
|
1,285 |
|
|
|
1,919 |
|
Deferred
federal income tax
|
|
|
14,951 |
|
|
|
12,403 |
|
|
|
4,636 |
|
Deferred
state income tax
|
|
|
563 |
|
|
|
1,530 |
|
|
|
713 |
|
Income
before taxes
|
|
$ |
71,659 |
|
|
$ |
57,983 |
|
|
$ |
65,383 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Computed
federal tax at 35% statutory rate
|
|
$ |
25,081 |
|
|
$ |
20,294 |
|
|
$ |
22,884 |
|
State
income tax net of federal tax benefit
|
|
|
3,559 |
|
|
|
2,137 |
|
|
|
1,812 |
|
Depreciation
flow-through
|
|
|
2,906 |
|
|
|
2,738 |
|
|
|
2,437 |
|
Cost
of Removal
|
|
|
(1,524 |
) |
|
|
(1,432 |
) |
|
|
(1,185 |
) |
Production
tax credits
|
|
|
(1,402 |
) |
|
|
(1,606 |
) |
|
|
(1,366 |
) |
Other
|
|
|
(1,239 |
) |
|
|
(302 |
) |
|
|
(2,684 |
) |
Total
income tax
|
|
$ |
27,381 |
|
|
$ |
21,829 |
|
|
$ |
21,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective
tax rate - federal
|
|
|
31.7 |
% |
|
|
32.8 |
% |
|
|
29.5 |
% |
Effective
tax rate - state
|
|
|
6.5 |
% |
|
|
4.8 |
% |
|
|
4.0 |
% |
Effective
tax rate - combined
|
|
|
38.2 |
% |
|
|
37.6 |
% |
|
|
33.5 |
% |
In 2009,
the effective state income tax rate increase was due to Griffith's sale of
operations in certain geographic locations. This state tax increase
resulted in a federal tax benefit contributing to the decrease of the effective
federal tax income rate. Additional favorable federal tax impacts
included the Medicare Act of 2003, property tax, and tax-exempt
interest. Unfavorable federal impacts included depreciation and
reserves.
The
following is a summary of the components of deferred taxes as reported in CH
Energy Group’s Consolidated Balance Sheet (In Thousands):
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
Accumulated
Deferred Income Tax Asset:
|
|
|
|
|
|
|
Excess
depreciation reserve
|
|
$ |
12,780 |
|
|
$ |
12,801 |
|
Unbilled
revenues
|
|
|
10,711 |
|
|
|
16,778 |
|
Plant-related
|
|
|
10,742 |
|
|
|
10,393 |
|
OPEB
expense
|
|
|
23,165 |
|
|
|
21,721 |
|
Other
|
|
|
40,842 |
|
|
|
48,162 |
|
Accumulated
Deferred Income Tax Asset:
|
|
|
98,240 |
|
|
|
109,855 |
|
|
|
|
|
|
|
|
|
|
Accumulated
Deferred Income Tax Liability:
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
165,491 |
|
|
|
147,982 |
|
Repair
Allowance
|
|
|
11,292 |
|
|
|
11,856 |
|
Pension
expense
|
|
|
5,691 |
|
|
|
12,641 |
|
Residual
deferred gas balance
|
|
|
8,041 |
|
|
|
10,083 |
|
Other
|
|
|
65,508 |
|
|
|
73,898 |
|
Accumulated
Deferred Income Tax Liability
|
|
|
256,023 |
|
|
|
256,460 |
|
Net
Deferred Income Tax Liability
|
|
|
157,783 |
|
|
|
146,605 |
|
Net
Current Deferred Income Tax Asset
|
|
|
300 |
|
|
|
7,498 |
|
Net
Long-term Deferred Income Tax Liability
|
|
$ |
158,083 |
|
|
$ |
154,103 |
|
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 (In
Thousands):
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Federal
income tax
|
|
$ |
(3 |
) |
|
$ |
6,186 |
|
|
$ |
13,944 |
|
State
income tax
|
|
|
1,135 |
|
|
|
1,712 |
|
|
|
3,277 |
|
Deferred
federal income tax
|
|
|
18,538 |
|
|
|
10,496 |
|
|
|
2,814 |
|
Deferred
state income tax
|
|
|
1,472 |
|
|
|
879 |
|
|
|
291 |
|
Total
income tax
|
|
$ |
21,142 |
|
|
$ |
19,273 |
|
|
$ |
20,326 |
|
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 Central
Hudson’s Consolidated Statement of Income (In Thousands):
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Net
income
|
|
$ |
32,776 |
|
|
$ |
27,238 |
|
|
$ |
33,436 |
|
Federal
income tax
|
|
|
(3 |
) |
|
|
6,186 |
|
|
|
13,944 |
|
State
income tax
|
|
|
1,135 |
|
|
|
1,712 |
|
|
|
3,277 |
|
Deferred
federal income tax
|
|
|
18,538 |
|
|
|
10,496 |
|
|
|
2,814 |
|
Deferred
state income tax
|
|
|
1,472 |
|
|
|
879 |
|
|
|
291 |
|
Income
before taxes
|
|
$ |
53,918 |
|
|
$ |
46,511 |
|
|
$ |
53,762 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Computed
federal tax at 35% statutory rate
|
|
$ |
18,871 |
|
|
$ |
16,279 |
|
|
$ |
18,817 |
|
State
income tax net of federal tax benefit
|
|
|
2,210 |
|
|
|
1,992 |
|
|
|
2,421 |
|
Depreciation
flow-through
|
|
|
2,906 |
|
|
|
2,738 |
|
|
|
2,437 |
|
Cost
of Removal
|
|
|
(1,524 |
) |
|
|
(1,432 |
) |
|
|
(1,185 |
) |
Other
|
|
|
(1,321 |
) |
|
|
(304 |
) |
|
|
(2,164 |
) |
Total
income tax
|
|
$ |
21,142 |
|
|
$ |
19,273 |
|
|
$ |
20,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective
tax rate - federal
|
|
|
34.4 |
% |
|
|
35.8 |
% |
|
|
31.2 |
% |
Effective
tax rate - state
|
|
|
4.8 |
% |
|
|
5.6 |
% |
|
|
6.6 |
% |
Effective
tax rate - combined
|
|
|
39.2 |
% |
|
|
41.4 |
% |
|
|
37.8 |
% |
In 2009,
the effective federal income tax rate decrease was due primarily to the net
effect of favorable tax impacts of the Medicare Act of 2003, property tax, tax
exempt interest, and unfavorable tax impacts of depreciation and
reserves.
The
following is a summary of the components of deferred taxes as reported in
Central Hudson’s Consolidated Balance Sheet (In Thousands):
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
Accumulated
Deferred Income Tax Asset:
|
|
|
|
|
|
|
Unbilled
revenues
|
|
$ |
10,711 |
|
|
$ |
16,778 |
|
Plant-related
|
|
|
10,742 |
|
|
|
10,393 |
|
OPEB
expense
|
|
|
23,165 |
|
|
|
21,721 |
|
Excess
depreciation reserve
|
|
|
12,780 |
|
|
|
12,801 |
|
Other
|
|
|
38,660 |
|
|
|
45,350 |
|
Accumulated
Deferred Income Tax Asset:
|
|
|
96,058 |
|
|
|
107,043 |
|
|
|
|
|
|
|
|
|
|
Accumulated
Deferred Income Tax Liability:
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
164,904 |
|
|
|
145,721 |
|
Repair
Allowance
|
|
|
11,293 |
|
|
|
11,856 |
|
Pension
expense
|
|
|
5,691 |
|
|
|
12,641 |
|
Residual
deferred gas balance
|
|
|
8,041 |
|
|
|
10,083 |
|
Other
|
|
|
55,107 |
|
|
|
60,131 |
|
Accumulated
Deferred Income Tax Liability
|
|
|
245,036 |
|
|
|
240,432 |
|
Net
Deferred Income Tax Liability
|
|
|
148,978 |
|
|
|
133,389 |
|
Net
Current Deferred Income Tax Liability (Asset)
|
|
|
(1,883 |
) |
|
|
4,685 |
|
Net
Long-term Deferred Income Tax Liability
|
|
$ |
147,095 |
|
|
$ |
138,074 |
|
NOTE 5 -
ACQUISITIONS, DIVESTITURES AND INVESTMENTS
Acquisitions
During
the years ended December 31, 2009, 2008 and 2007, Griffith acquired fuel
distribution companies as follows (In Millions):
|
|
#
of
|
|
|
|
|
|
Total
|
|
|
|
|
|
Total
|
|
|
|
Acquired
|
|
Purchase
|
|
|
Intangible
|
|
|
|
|
|
Tangible
|
|
Year
Ended
|
|
Companies
|
|
Price
|
|
|
Assets(1)
|
|
Goodwill
|
|
|
Assets
|
|
December
31, 2009
|
|
|
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
December
31, 2008
|
|
|
4 |
|
|
$ |
9.3 |
|
|
$ |
8.5 |
|
|
$ |
4.0 |
|
|
$ |
0.8 |
|
December
31, 2007
|
|
|
13 |
|
|
$ |
25.6 |
|
|
$ |
22.1 |
|
|
$ |
10.6 |
|
|
$ |
3.5 |
|
Total
|
|
|
17 |
|
|
$ |
34.9 |
|
|
$ |
30.6 |
|
|
$ |
14.6 |
|
|
$ |
4.3 |
|
(1) Including
goodwill.
Six of
the above noted acquisition transactions had agreements containing clauses
(known as “earn out provisions”) for a possible additional payment provided
certain conditions are met. These provisions increase the purchase
price if certain sales volumes are attained. In 2009 there were no
earn outs paid, while 2008 and 2007 payments were not
material. As of December 31, 2009, there are no remaining earn out
provisions.
In 2008,
Griffith acquired four fuel distribution and service companies consisting of one
located in Connecticut and Delaware and two located in Pennsylvania for a total
of $9.3 million.
Of the
seventeen acquisitions noted above, only three were retained after the
divestiture in December 2009 discussed below.
Divestitures
On
December 11, 2009, Griffith closed on the sale of operations in certain
geographic locations, which included approximately 45,000
customers. This divestiture followed an approximate year-long
strategic review and is expected to reduce the volatility of both earnings and
cash flow of the fuel delivery business segment. At closing,
Griffith received approximately $74.4 million, which resulted in a pre-tax gain
of $10.8 million. The assets sold include intangible assets of $39.2
million, accounts receivable of $11.5 million, net fixed assets of $8.4 million,
inventory of $2.6 million, and other current assets of $0.5 million in addition
to another $3.6 million in notes receivable sold. The liabilities
totaled $16.3 million. In accordance with current accounting guidance
related to property, plant, equipment (ASC 350), Griffith ceased depreciation
and amortization of its assets held for sale on November 4,
2009. This resulted in a reduction of depreciation and amortization
in 2009 of approximately $0.6 million. In accordance with current
accounting guidance related to goodwill (ASC 350), when a portion of a reporting
unit that constitutes a business is disposed of, goodwill associated with that
business shall be included in the carrying amount of the business in determining
the gain or loss on disposal. As a result of a required goodwill
allocation that was performed upon the sale of the Griffith holdings, $10
million of goodwill in addition to the goodwill recorded when the divested
assets were purchased, was removed from the balance sheet and included in the
calculation of the gain on the sale. For additional information
regarding goodwill, see Note 6 - “Goodwill and Other Intangible
Assets”.
The
results of operations for 2009 reflect activity only through the closing date of
the sale of December 11, 2009. The table below summarizes financial
results of the discontinued operations (In Thousands):
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Revenues
from discontinued operations
|
|
$ |
122,675 |
|
|
$ |
193,650 |
|
|
$ |
117,990 |
|
Income
from discontinued operations before tax
|
|
|
6,073 |
|
|
|
6,060 |
|
|
|
2,419 |
|
Gain
from sale of discontinued operations
|
|
|
10,767 |
|
|
|
- |
|
|
|
- |
|
Income
tax expense from discontinued operations
|
|
|
6,989 |
|
|
|
2,515 |
|
|
|
938 |
|
Investments
On April
12, 2006, CHEC purchased a 75% interest in Lyonsdale from Catalyst Renewables
Corporation (“Catalyst”) for $10.8 million, including a working capital
adjustment of $1.0 million. Catalyst remains the owner of a minority
share of Lyonsdale. Lyonsdale owns and operates a 19-megawatt,
wood-fired, biomass electric generating plant, which began operation in
1992. The plant is located in Lyonsdale, New York. The
energy and capacity of the plant is being sold at a fixed price to an investment
grade rated counterparty pursuant to a contract beginning May 1, 2006 and ending
December 31, 2014. Beginning January 1, 2010, Lyonsdale is no longer
eligible to receive production tax credits as previously received under the
Internal Revenue Code’s five year tax credit period. Lyonsdale was
eligible and received $1.2 million and $1.3 million of production tax credits in
2009 and 2008. The operating results of Lyonsdale have been
consolidated in the Consolidated Financial Statements of CH Energy
Group.
CHEC
holds a 12% interest in preferred equity units plus subordinated notes issued by
Cornhusker Holdings. Cornhusker Holdings is the owner of Cornhusker Energy
Lexington, LLC ("CEL"), a corn-ethanol production facility located in Nebraska
that began operation as of the end of January 2006. This investment is accounted
for under the equity method. As of December 31, 2009, CHEC's total investment in
Cornhusker consisted of subordinated notes totaling $10.2 million, including
interest, and an equity investment of $2.4 million. In response to the
continuation of lower than expected margins, Management stopped accruing
interest income on the subordinated debt and will record such interest on a cash
basis until the current outstanding balance of interest has been paid. The
recoverability of the Company's total investment in Cornhusker Holdings is
predicated on CEL achieving sufficient positive cash flow to repay the notes
receivable. If CEL does not achieve sufficient positive cash flow, the
investment and notes receivable may become impaired. CEL has a requirement as
part of its senior note agreement for completing expansion of plant capacity and
output from 40 million gallons per year to 57.5 million gallons per year by
December 31, 2009. Construction of the expansion of the plant's capacity was
substantially complete by that date. The output testing achieved the capacity
required for a 24-hour period, but it was unable to be sustained for the full
72-hour timeframe required. Management believes additional equipment upgrades
and adjustments would be necessary to achieve this requirement. CEL has
requested a waiver from this requirement from the senior note holder. As of
February 10, 2010, the senior note holder has had the ability to accelerate all
amounts due under the senior note and has not done so. Management cannot predict
the outcome of these negotiations or the senior note holder's actions regarding
its rights under the senior note agreement, however,
Management believes it is not probable that the senior note holder will
accelerate amounts due under the note. CEL is current on all payments
of principal and interest due under the senior note agreement and in compliance
with all other terms of the senior note agreement. Management
believes CHEC's investment in Cornhusker Holdings is not impaired as of December
31, 2009 based on Management’s intent and
ability to hold the investments until fully recovered, as well as an analysis of
forecasted cash flows, which indicates all amounts are recoverable. Management
will continue to monitor the results of CEL. If any of the
assumptions within the forecasted cash flow were to change significantly,
Management would perform a reassessment of the recoverability of its investment
at that time.
On March
10, 2006, CHEC made a $4.9 million investment in CH-Community Wind Energy, LLC,
a joint venture between CHEC and Community Energy, Inc. that owns an 18%
interest in two wind farm projects in the Mid-Atlantic region. The
24-megawatt Bear Creek wind project is located near Wilkes-Barre, Pennsylvania
and the 7.5-megawatt New Jersey Atlantic project is built at a wastewater
treatment plant in Atlantic City, New Jersey. Both are commercially
operational. CHEC’s ownership represents a minority interest in each
project. This investment is accounted for under the equity
method.
In the
fourth quarter of 2007, CHEC’s subsidiary, CH-Auburn entered into a 15-year
Energy Services Agreement (“ESA”) to supply the City of Auburn, NY (the “City”)
with a portion of its electricity needs by constructing and operating a
3-megawatt electric generating plant in the City that will burn gas derived from
a landfill to generate renewable power. Under the ESA as renegotiated
on March 31, 2009, the project will utilize methane gas generated by the City
landfill to produce and sell electricity to the City. The project
began operation in January 2010. CH-Auburn has incurred approximately
$5.5 million of design and construction costs related to this
investment.
In June
2007, CHEC made a $1.2 million loan to Buckeye for development of a corn-ethanol
plant. Since receipt of the loan from CHEC, the developers
entered into a lease for a site, and a Letter of Intent to provide engineering,
procurement and construction for the plant. In June 2008, the
developers paid CHEC all interest owed on the loan for the initial term and
extended the term of the loan for one additional year. Low margins
for corn-to-ethanol plants and credit market conditions made the arrangement of
construction financing difficult. In the first quarter of 2009,
CHEC’s Management notified the developers that the loan was past due and
recorded a reserve. Due to Management’s assessment of the developer’s
ability to pay the outstanding balance, the full balance of the loan was
written-off in the fourth quarter of 2009.
In April
2009, CHEC’s subsidiary, CH-Greentree, entered into an agreement to invest $5.5
million in the acquisition, construction and installation of a molecular gate
for lease to Greentree Landfill Gas Company, LLC (“Greentree”) at Greentree’s
currently operating landfill gas processing plant at the Greentree landfill in
western Pennsylvania. The molecular gate is used to remove nitrogen
from the landfill gas produced by the Greentree facility thereby increasing its
energy content and quality, thus allowing Greentree to sell more of its landfill
gas output. The term of the lease is seven years. Lease
payments total approximately $1.2 million per year through the end of the lease
term. Construction was substantially complete on June 30, 2009 and
final testing was completed during December 2009.
During
2009, CH Shirley, a wholly owned subsidiary of CHEC, agreed to invest
approximately $50 million for a 90% controlling interest in a 20-megawatt wind
farm facility in Wisconsin. This project carries a 20-year power
purchase agreement contract at pre-determined electric prices with Wisconsin
Public Service Corporation for the electric output of the wind farm’s eight wind
turbines. Construction is expected to be completed in the fourth
quarter of 2010. As of December 31, 2009, CH Shirley has invested
approximately $13.3 million.
NOTE 6 -
GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill,
customer relationships, trademarks 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. The balances reflected on CH Energy Group’s Consolidated
Balance Sheet at December 31, 2009 and 2008, for “Goodwill” and “Other
intangible assets - net” relate to Griffith. In accordance with
current accounting guidance related to goodwill and other intangible assets (ASC
350), goodwill and other intangible assets that have indefinite useful lives no
longer are amortized, but instead are periodically reviewed for
impairment. Griffith tests the goodwill remaining on the balance
sheet for impairment annually in the fourth quarter, and retests goodwill
between annual tests and tests intangible assets if an event should occur or
circumstances arise that would more likely than not reduce the fair value below
its carrying amount for all periods presented. No impairment existed
during the annual test for any of the periods presented. At the time
of the 2009 annual impairment test, fair value of Griffith exceeded its carrying
value by approximately $49.6 million. Impairment testing compares the
fair value of Griffith to its carrying amount. Fair value of the
reporting unit is estimated using a discounted cash flow
measurement. For tax purposes, goodwill is amortized ratably over a
15-year period, beginning in the month of acquisition.
In
accordance with current accounting guidance related to good-will (ASC 350),
Griffith allocated its goodwill based on the fair values of the divested region
and the portion of the business retained. As a result of the
divestiture discussed in Note 5 - “Acquisitions, Divestitures and Investments”,
Griffith reduced its goodwill by approximately $10 million in addition to the
goodwill recorded when the divested assets were purchased.
Intangible
assets include separate, identifiable, intangible assets such as customer
relationships, trademarks, and covenants not to compete. Intangible
assets with finite lives are amortized over their useful lives. The
estimated useful life for customer relationships is 15 years, which is believed
to be appropriate in view of average historical customer
attrition. The useful lives of trademarks were estimated to range
from 10 to 15 years based upon Management’s assessment of several variables such
as brand recognition, Management’s expected use of the trademark, and other
factors that may have affected the duration of the trademark’s
life. The useful life of a covenant not to compete is based on the
expiration date of the covenant, generally between three and ten
years. Amortization expense was $4.0 million, $4.1 million and $3.4
million for each of the year ended December 31, 2009, 2008 and 2007,
respectively. The estimated annual amortization expense for each of
the next five years, assuming no new acquisitions, is approximately $2.3
million. The weighted average amortization period for all amortizable
intangible assets is 14.97 years. The
weighted average amortization periods for customer relationships and covenants
not to compete are 15 years and 5 years, respectively. In December
2009, Griffith sold the rights to all of its trademarks as part of the sale of
select operations discussed further below.
On
December 11, 2009, CH Energy Group announced the sale of operations of Griffith
in certain geographic locations. In connection with this sale,
Griffith transferred certain amortizable intangible assets associated with this
region. The following chart reflects adjustments recorded to the cost
and accumulated amortization balances of the intangible assets sold (In
Thousands):
|
|
Gross
Carrying Amount
|
|
|
Accumulated
Amortization
|
|
|
Net
|
|
Customer
relationships
|
|
$ |
21,420 |
|
|
$ |
6,850 |
|
|
$ |
14,570 |
|
Trademarks
|
|
|
2,956 |
|
|
|
624 |
|
|
|
2,332 |
|
Covenants
not to compete
|
|
|
1,505 |
|
|
|
1,097 |
|
|
|
408 |
|
Total
|
|
$ |
25,881 |
|
|
$ |
8,571 |
|
|
$ |
17,310 |
|
The
components of amortizable intangible assets of CH Energy Group are summarized as
follows (In Thousands):
|
|
December
31, 2009
|
|
|
December
31, 2008
|
|
|
|
Gross
Carrying Amount
|
|
|
Accumulated
Amortization
|
|
|
Gross
Carrying Amount
|
|
|
Accumulated
Amortization
|
|
Customer
relationships
|
|
$ |
33,745 |
|
|
$ |
18,957 |
|
|
$ |
55,171 |
|
|
$ |
22,248 |
|
Trademarks
|
|
|
- |
|
|
|
- |
|
|
|
2,956 |
|
|
|
372 |
|
Covenants
not to compete
|
|
|
100 |
|
|
|
75 |
|
|
|
1,605 |
|
|
|
983 |
|
Total
Amortizable Intangibles
|
|
$ |
33,845 |
|
|
$ |
19,032 |
|
|
$ |
59,732 |
|
|
$ |
23,603 |
|
The chart
below provides a rollforward of goodwill balances of CH Energy Group (In
Thousands):
|
|
December
31,
|
|
|
|
December
31,
|
|
|
|
2009
|
|
|
|
2008
|
|
Balance
at Beginning of Period
|
|
$ |
67,455 |
|
|
|
$ |
63,433 |
|
Acquisitions
|
|
|
- |
|
|
|
|
4,022 |
|
Divestitures
|
|
|
(31,804 |
) |
(1) |
|
|
- |
|
Balance
at End of Period
|
|
$ |
35,651 |
|
|
|
$ |
67,455 |
|
(1) Includes
$10 million in goodwill in addition to the goodwill recorded when the divested
assets were purchased.
NOTE 7 -
SHORT-TERM BORROWING ARRANGEMENTS
CH Energy
Group maintains a $150 million revolving credit facility with several commercial
banks to provide committed liquidity. This facility expires in
February 2013. As of December 31, 2009 and December 31, 2008, there
were no borrowings under this facility. The notes payable balances
reported in the CH Energy Group Consolidated Balance Sheet reflect the
borrowings of CH Energy Group’s subsidiaries as of December 31, 2009 and
December 31, 2008, as discussed below.
Central
Hudson maintains a revolving credit facility with several commercial banks,
pursuant to PSC authorization, in the amount of $125 million, for a five-year
term ending January 2, 2012. As of December 31, 2009 and December 31,
2008, there were no borrowings under this agreement.
Both the
CH Energy Group and Central Hudson credit facilities reflect commitments from
JPMorgan Chase Bank, N.A., Bank of America, N.A., HSBC Bank USA, N.A. and
KeyBank National Association. If any of these lenders are unable to
fulfill their commitments under these facilities, funding may not be available
as needed.
Central
Hudson also maintains certain uncommitted lines of credit that diversify its
sources of cash and provide competitive options to minimize its cost of
short-term debt. As of December 31, 2009, Central Hudson had no
borrowings under these lines of credit. As of December 31, 2008,
Central Hudson’s outstanding balance on these lines of credit, in aggregate, was
$25.5 million.
On
September 22, 2009, the PSC issued an order authorizing Central Hudson to
increase its multi-year committed credit to $175 million through December 31,
2012. The higher level of committed credit could provide Central
Hudson with greater liquidity to support construction forecasts, seasonality of
the business, volatile energy markets, adverse borrowing environments, and other
unforeseen events.
On
January 18, 2008, Griffith established an uncommitted line of credit of up to
$25 million with a commercial bank for the purpose of funding seasonal working
capital and for general corporate purposes. As of December 31, 2008,
there were borrowings under this agreement of $10.0 million. On April
30, 2009, Griffith Management elected to allow this uncommitted line of credit
to expire. The obligations of Griffith under the line of credit were
guaranteed by CH Energy Group and CHEC. Griffith’s short-term
financing needs are currently provided by CH Energy Group through intercompany
debt agreements.
Debt
Covenants
CH Energy
Group’s $150 million credit facility and Central Hudson’s $125 million credit
facility both require compliance with certain restrictive covenants, including
maintaining a ratio of total consolidated debt to total consolidated
capitalization of no more than 0.65 to 1.00. Currently, both CH
Energy Group and Central Hudson are in compliance with all of their respective
debt covenants.
For a
schedule of activity related to common stock, paid-in capital, and capital
stock, see the Consolidated Statements of Equity for CH Energy Group and Central
Hudson.
Cumulative
Preferred Stock
Central
Hudson, $100 par value; 210,300 shares authorized, not subject to mandatory
redemption:
|
Redemption
|
|
|
Shares
Outstanding
|
|
|
Price
|
|
|
December
31,
|
|
Series
|
12/31/09
|
|
|
2009
|
|
|
2008
|
|
4.50%
|
|
$ |
107.00 |
|
|
|
70,285 |
|
|
|
70,285 |
|
4.75%
|
|
|
106.75 |
|
|
|
19,980 |
|
|
|
19,980 |
|
4.35%
|
|
|
102.00 |
|
|
|
60,000 |
|
|
|
60,000 |
|
4.96%
|
|
|
101.00 |
|
|
|
60,000 |
|
|
|
60,000 |
|
|
|
|
|
|
|
|
210,265 |
|
|
|
210,265 |
|
There
were no repurchases in 2007, 2008 or 2009.
In the
event of a liquidation of Central Hudson, the holders of the Cumulative
Preferred Stock are entitled to receive the redemption price (in the case of a
voluntary liquidation) or the par value (in the case of an involuntary
liquidation) plus, in either case, accrued dividends.
Capital
Stock Expense
Expenses
incurred on issuance of capital stock are accumulated and reported as a
reduction in common equity.
Repurchase
Program
On July
25, 2002, the Board of Directors of CH 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-year
period ending July 31, 2007. Effective July 31, 2007, the Board of
Directors of CH Energy Group extended and amended the Repurchase
Program. As amended, the Repurchase Program authorizes the repurchase
of up to 2,000,000 shares (excluding shares purchased before July 31, 2007) or
approximately 13% of the Company's outstanding common stock, from time to time,
over the five-year period ending July 31, 2012. No shares were
repurchased under the Repurchase Program during the years ended December 31,
2009, 2008, and 2007. CH Energy Group reserves the right to modify,
suspend, renew, or terminate the Repurchase Program at any time without
notice.
NOTE 9 -
CAPITALIZATION - LONG-TERM DEBT
Details
of CH Energy Group's and Central Hudson’s long-term debt are as follows (In
Thousands):
|
|
|
|
December
31,
|
|
Series
|
|
Maturity
Date
|
|
2009
|
|
|
2008
|
|
CH
Energy Group:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Promissory
Notes:
|
|
|
|
|
|
|
|
|
2009
Series A (6.58%)
|
|
Apr.
17, 2014
|
|
$ |
26,500 |
|
|
$ |
- |
|
2009
Series B (6.80%)
|
|
Dec.
15, 2025
|
|
|
23,500 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
CH
Energy Group Net Long-term debt
|
|
|
|
$ |
50,000 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
Central
Hudson:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Promissory
Notes:
|
|
|
|
|
|
|
|
|
|
|
1999
Series C (6.00%)
|
|
Jan.
15, 2009
|
|
$ |
- |
|
|
$ |
20,000 |
|
2003
Series D (4.33%)(4)
|
|
Sep.
23, 2010
|
|
|
24,000 |
|
|
|
24,000 |
|
2002
Series D (6.64%)(4)
|
|
Mar.
28, 2012
|
|
|
36,000 |
|
|
|
36,000 |
|
2008
Series F (6.854%)(2)
|
|
Nov.
01, 2013
|
|
|
30,000 |
|
|
|
30,000 |
|
2004
Series D (4.73%)(4)
|
|
Feb.
27, 2014
|
|
|
7,000 |
|
|
|
7,000 |
|
2004
Series E (4.80%)(5)
|
|
Nov.
05, 2014
|
|
|
7,000 |
|
|
|
7,000 |
|
2007
Series F (6.028%)(2)
|
|
Sep.
01, 2017
|
|
|
33,000 |
|
|
|
33,000 |
|
2004
Series E (5.05%)(5)
|
|
Nov.
04, 2019
|
|
|
27,000 |
|
|
|
27,000 |
|
1999
Series A (5.45%)(1)
|
|
Aug.
01, 2027
|
|
|
33,400 |
|
|
|
33,400 |
|
1999
Series C(1)(3)
|
|
Aug.
01, 2028
|
|
|
41,150 |
|
|
|
41,150 |
|
1999
Series D(1)(3)
|
|
Aug.
01, 2028
|
|
|
41,000 |
|
|
|
41,000 |
|
1998
Series A (6.50%)(1)
|
|
Dec.
01, 2028
|
|
|
16,700 |
|
|
|
16,700 |
|
2006
Series E (5.76%)(5)
|
|
Nov.
17, 2031
|
|
|
27,000 |
|
|
|
27,000 |
|
1999
Series B(1)(3)
|
|
July
01, 2034
|
|
|
33,700 |
|
|
|
33,700 |
|
2005
Series E (5.84%)(5)
|
|
Dec.
05, 2035
|
|
|
24,000 |
|
|
|
24,000 |
|
2007
Series F (5.804%)(2)
|
|
Mar.
23, 2037
|
|
|
33,000 |
|
|
|
33,000 |
|
2009
Series F (5.80%)(2)
|
|
Oct.
1, 2039
|
|
|
24,000 |
|
|
|
- |
|
|
|
|
|
|
437,950 |
|
|
|
433,950 |
|
|
|
|
|
|
|
|
|
|
|
|
Unamortized
Discount on Debt
|
|
|
|
|
(53 |
) |
|
|
(56 |
) |
Total
Long-term debt
|
|
|
|
$ |
437,897 |
|
|
$ |
433,894 |
|
|
|
|
|
|
|
|
|
|
|
|
Less:
Current Portion
|
|
|
|
|
(24,000 |
) |
|
|
(20,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
Central
Hudson Net Long-term debt
|
|
|
|
$ |
413,897 |
|
|
$ |
413,894 |
|
(1)
|
Promissory
Notes issued in connection with the sale by NYSERDA of tax-exempt
pollution control revenue bonds.
|
(2)
|
Issued
under Central Hudson’s medium-term note program, described
below.
|
(3)
|
Variable
(auction) rate notes.
|
(4)
|
Issued
pursuant to a 2001 PSC Order approving the issuance by Central Hudson
prior to June 30, 2004, of up to $100 million of unsecured medium-term
notes.
|
(5)
|
Issued
pursuant to a 2004 PSC Order approving the issuance by Central Hudson
prior to December 31, 2006, of up to $85 million of unsecured medium-term
notes.
|
The PSC
issued an Order in September 2006 authorizing Central Hudson to issue
medium-term notes of up to $140 million over the three-year period ending
December 31, 2009. With this authorization, Central Hudson
established its Series F notes and issued $120 million during that
period. A summary of Series F issuances follows:
Date
|
|
Amount
of Issuance
|
|
Term,
Rate
|
|
Proceeds
Used for:
|
March
23, 2007
|
|
$33,000,000
|
|
30-year,
5.80%
|
|
Redemption
at maturity of $33,000,000 5-year, 5.87% Series D Notes
|
|
|
|
|
|
|
|
September
14, 2007
|
|
$33,000,000
|
|
10-year,
6.028%
|
|
Financing
ongoing investments in electric and natural gas systems
|
|
|
|
|
|
|
|
November
18, 2008
|
|
$30,000,000
|
|
5-year,
6.854%
|
|
Financing
ongoing investments in electric and natural gas systems
|
|
|
|
|
|
|
|
September
30, 2009
|
|
$24,000,000
|
|
30-year,
5.80%
|
|
Financing
ongoing investments in electric and natural gas
systems
|
On
September 22, 2009, the PSC authorized Central Hudson to issue up to $250
million of long-term debt through December 31, 2012. The Order
authorizes Central Hudson to issue and sell $250 million of long-term debt to
finance its construction expenditures, refund maturing long-term debt, and
potentially refinance its 1999 NYSERDA Bonds, Series B, C and D. On
November 20, 2009, Central Hudson registered a new series of notes, Series G,
pursuant to the authority granted by the PSC. An amended registration
statement was filed on December 23, 2009 and the registration of the Series G
notes became effective on January 6, 2010.
Central
Hudson’s current senior unsecured debt rating/outlook is ‘A’/stable by both
Standard & Poor’s Rating Services (“Standard & Poor’s”) and Fitch
Ratings and ‘A3’/negative by Moody’s Investors Service (“Moody’s”).4 On
September 9, 2009, Moody’s downgraded Central Hudson’s senior unsecured debt and
issuer ratings to ‘A3’ from ‘A2,’ with a continued negative outlook, to reflect
their view of the current weakness in our credit metrics and the ongoing need
for rate relief to support planned capital expenditures. Moody’s
analysis focused on four key rating factors that they identified as being
important determinants in assigning ratings; (1) regulatory framework, (2)
ability to recover costs and earn returns, (3) diversification, and (4)
financial strength, liquidity and key financial metrics. The
downgrade is not expected to have a material impact on Central Hudson’s
financial performance.
_________________________________
4 These
ratings reflect only the views of the rating agency issuing the rating, are not
recommendations to buy, sell, or hold securities of Central Hudson and may be
subject to revision or withdrawal at any time by the rating agency issuing the
rating. Each rating should be evaluated independently of any other
rating.
Griffith
had no third-party long-term debt outstanding as of December 31, 2009 or
2008.
In the
second quarter of 2009, CH Energy Group privately placed $50 million of senior
unsecured notes. The notes bear interest at the rate of 6.58% per
annum and mature on April 17, 2014. CH Energy Group completed the
sale of $35 million in principal amount of the notes on April 17, 2009, and $15
million in principal amount on June 15, 2009. CH Energy Group used a
portion of the proceeds from the sale of the notes to repay short-term debt and
retains the remainder for general corporate purposes. On December 15,
2009, following the divestiture of select operations of Griffith, CH Energy
Group entered into a supplemental note purchase agreement for the issuance of
$23.5 million of new senior notes and redeemed $23.5 million of the notes placed
during the second quarter of 2009. The newly issued notes bear
interest at the rate of 6.80% per annum and mature on December 15,
2025. Interest is payable semi-annually and, commencing June 15,
2011, with semi-annual payments of principal. The mortgage style
amortization of principal results in the final payment of principal and interest
upon maturity. CH Energy Group intends to use the proceeds from the
sale of the supplemental notes to fund a portion of its investment in Shirley
Wind.
Long-Term
Debt Maturities
See Note
15 - “Fair Value Measurements” for a schedule of long-term debt maturing or to
be redeemed during the next five years and thereafter.
NYSERDA
Central
Hudson has five debt series that were issued in conjunction with the sale of
tax-exempt pollution control revenue bonds by New York State Energy Research and
Development Authority (“NYSERDA”). These NYSERDA bonds are insured by
Ambac Assurance Corporation (“Ambac”) and the ratings on these bonds reflect the
higher of the credit rating of Ambac or Central Hudson. The current
underlying rating and outlook on these bonds and Central Hudson’s other senior
unsecured debt is ‘A’/stable by Standard & Poor’s and Fitch Ratings and
‘A3’/negative by Moody’s.5
Central
Hudson’s 1998 NYSERDA Series A Bonds, totaling $16.7 million, were re-marketed
on December 1, 2008. Under the terms of the applicable indenture,
Central Hudson converted the bonds to a fixed rate of 6.5%, which will continue
until their maturity in December 2028. Prior to the December 1, 2008
re-marketing, the bonds bore interest at a term rate of 3.0%.
Central
Hudson’s 1999 NYSERDA Series A Bonds, totaling $33.4 million, have an interest
rate that is fixed to maturity in 2027 at 5.45%.
_________________________________
5 These ratings reflect only the views of
the rating agency issuing the rating, are not recommendations to buy, sell, or
hold securities of Central Hudson and may be subject to revision or withdrawal
at any time by the rating agency issuing the rating. Each rating
should be evaluated independently of any other rating.
Central
Hudson’s 1999 NYSERDA Bonds, Series B, C, and D, totaling $115.9 million, are
multi-modal bonds that are currently in auction rate mode. Beginning
in 1999 when the bonds were issued, the bonds’ interest rate has been reset
every 35 days in a Dutch auction. Auctions in the market for
municipal auction rate securities have experienced widespread failures since
early in 2008. Generally, an auction failure occurs because there is
an insufficient level of demand to purchase the bonds and the bondholders who
want to sell must hold the bonds for the next interest rate
period. Since February 2008, all auctions for Central Hudson’s three
series of auction rate bonds have failed. As a consequence, the
interest rate paid to the bondholders has been set to the then prevailing
maximum rate defined in the trust indenture. Central Hudson’s maximum
rate results in interest rates that are generally higher than expected results
from the auction process. For the foreseeable future, Central Hudson
expects the interest rate to be set at the maximum rate, determined on the date
of each auction as 175% of the yield on an index of tax-exempt short-term debt,
or its approximate equivalent. In 2009, the average maximum rate
applicable on the bonds was 0.80%. In its Orders, the PSC has
authorized deferral accounting treatment for the interest costs from Central
Hudson’s three series of variable rate 1999 NYSERDA Bonds. As a
result, variations in interest rates on these bonds are deferred for future
recovery from or refund to customers and Central Hudson does not expect the
auction failures to have any adverse impact on earnings. To mitigate
the potential impact of unexpected increases in short-term interest rates,
Central Hudson purchases interest rate caps based on an index for short-term
tax-exempt debt. Central Hudson replaced the cap that expired on March 31, 2009
with a one-year cap, effective April 1, 2009 set at 4.375%. The cap
is based on the monthly weighted average of an index of tax-exempt variable rate
debt, multiplied by 175% to align with the maximum rate formula of the three
series of variable rate 1999 NYSERDA Bonds. Central Hudson would
receive a payout if the bonds reset at rates above 4.375%. During
2009 and 2008, the average did not exceed the cap rate and therefore no payments
were received.
Central
Hudson is currently evaluating what actions, if any, it may take in the future
in connection with its 1999 NYSERDA Bonds, Series B, C and
D. Potential actions may include converting the debt from auction
rate to another interest rate mode or refinancing with taxable
bonds.
Debt
Expense
Expenses
incurred in connection with CH Energy Group’s or 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.
Debt
Covenants
CH Energy
Group’s $50 million of privately placed notes require compliance with certain
restrictive covenants including maintaining a ratio of total consolidated debt
to total consolidated capitalization of no more than 0.65 to 1.00 and not
permitting certain debt, other than the privately placed notes, associated with
the unregulated operations of CH Energy Group to exceed 10% of total
consolidated assets. Currently, CH Energy Group is in compliance with
all of these debt covenants.
Pension
Benefits
Central
Hudson has a non-contributory Retirement Income Plan (“Retirement Plan”)
covering substantially all of its employees hired before January 1,
2008. The Retirement Plan is a defined benefit plan, which provides
pension benefits based on an employee’s compensation and years of
service. In 2007, Central Hudson amended the Retirement Plan to
eliminate these benefits for managerial, professional, and supervisory employees
hired on or after January 1, 2008. The Retirement Plan for unionized
employees was similarly amended for all employees hired on or after May 1,
2008. The Retirement Plan’s assets are held in a trust fund (“Trust
Fund”). Central Hudson has provided periodic updates to the benefit
formulas stated in the Retirement Plan.
In
accordance with the measurement date provisions of current accounting guidance
related to pensions (ASC 715-20), Central Hudson changed its measurement date
for its pension plan (the “Retirement Plan”) from September 30 to December 31
for its financial statements for the year ended December 31,
2008. Central Hudson elected the “15-month-transition approach” and
recorded an adjustment in the first quarter of 2008 to recognize the effects of
the change in measurement date. This adjustment represented 3/15ths
of the net periodic pension cost determined for the period from October 1, 2007
to December 31, 2008; the remaining 12/15ths of the net periodic pension cost
was recorded over the twelve months ended December 31, 2008. The
recording of this adjustment increased Central Hudson’s pension liability by
$0.4 million, comprised of the following components (In Thousands):
Adjustment
for 3/15ths of net periodic pension costs
|
|
$ |
2,788 |
|
Adjustment
for amortization of prior service costs and actuarial losses (1)
|
|
|
(2,426 |
) |
Net
increase to pension liability
|
|
$ |
362 |
|
|
(1)
|
Liability
recognized previously on Consolidated Balance Sheet upon initial
implementation of ASC 715-20.
|
Decisions
to fund Central Hudson’s Retirement Plan are based on several factors, including
corporate resources, projected investment returns, actual investment returns,
inflation, the value of plan assets relative to plan liabilities, regulatory
considerations, interest rate assumptions and legislative
requirements. As a result of volatile conditions in the economy and
financial markets over the past two years, Central Hudson’s Retirement Plan
assets have significantly decreased relative to the plan
liabilities. Although the financial markets have seen a positive
trend over the past 12 months, the liability has been increased by the lower
discount rate used in the current year to determine benefit obligations and the
accruing of additional benefits. Central Hudson considers the
provisions of the Pension Protection Act of 2006 in determining its funding for
the Retirement Plan for the near-term and future
periods. Contributions to the Retirement Plan during the years ended
December 31, 2009 and 2008 were $22.6 million and $12.5 million,
respectively.
As noted
above, the value of the plan assets have increased in 2009, however, plan
liabilities increased as a result of a decline in the plan discount
rate. The net impact was a reduction in the unfunded liability.
Contributions for 2010 are expected to be approximately $30-$55
million. On January 22, 2010, Central Hudson contributed $30 million
to its retirement plan. The actual contributions could vary
significantly based upon corporate resources, projected investment returns,
actual investment returns, inflation, the value of plan assets relative to plan
liabilities, interest rate assumptions, regulatory considerations and
legislative requirements.
In
accordance with current accounting guidance related to pensions (ASC 715-20),
Central Hudson’s pension liability balance (i.e., the funded status) at December
31, 2009 and December 31, 2008 was $153.0 million, $162.2 million,
respectively. These balances include recognition for the difference
between the projected benefit obligation (“PBO”) for pensions and the market
value of the pension assets, as well as consideration for non-qualified
executive plans. As a result of volatile conditions in the economy
and financial markets over the past two years, Central Hudson’s Retirement Plan
assets have significantly decreased relative to the plan
liabilities.
The
following reflects the impact of the recording of funding status adjustments on
the Balance Sheets of CH Energy Group and Central Hudson (In
Thousands):
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
Prefunded
(accrued) pension costs prior to funding status adjustment
|
|
$ |
11,661 |
|
|
$ |
29,884 |
|
Additional
liability required
|
|
|
(164,644 |
) |
|
|
(192,084 |
) |
Total
accrued pension liability
|
|
$ |
(152,983 |
) |
|
$ |
(162,200 |
) |
|
|
|
|
|
|
|
|
|
Total
offset to additional liability - Regulatory assets - Retirement
Plan
|
|
$ |
164,644 |
|
|
$ |
192,084 |
|
Pursuant
to current accounting guidance related to pensions (ASC 715-20), gains or losses
and prior service costs or credits that arise during the period but are not
recognized as components of net periodic pension cost would typically be
recognized as a component of other comprehensive income, net of
tax. However, Central Hudson records regulatory assets rather than
adjusting comprehensive income to offset the additional
liability. The recording of a regulatory asset is consistent with the
PSC’s 1993 Statement of Policy regarding pensions and OPEB (“1993 PSC
Policy”). Under the 1993 PSC Policy, differences between pension
expense and rate allowances covering these costs are deferred for future
recovery from or return to customers with carrying charges accrued on cash
differences.
The
valuation of the PBO was determined as of the measurement date of December 31,
2009, using a 5.7% discount rate (as determined using the Citigroup Pension
Discount Curve reflecting projected pension cash flows). The discount
rate on the prior measurement date of December 31, 2008 was
6.2%. Declines in the market value of the Trust Fund’s investment
portfolio, which occurred from 2000 through 2002, and are amortized over a 10
year period as per PSC policy, and a reduction in the discount rate during that
period used to determine the benefit obligation for pensions have resulted in a
significant increase in pension costs since 2001.
Similarly,
declines in the market value of the Trust Fund’s investment portfolio in 2008
resulted in increased future pension costs since losses (and gains) are
amortized over a 10 year period. The 2009 Rate Order includes an
increase in the rate allowance for pension and OPEB expense which more closely
approximates the recent cost of providing these
benefits. Authorization remains in effect for the deferral of any
differences between rate allowances and actual costs under the 1993 PSC Policy
to counteract the volatility of these costs. The 2009 Rate Order
again authorized Central Hudson to offset significant deferred balances for
pension and OPEB expense for the electric department with available deferred
credit balances due to customers. The 2009 Rate Order also authorized
the continuation of the amortization of natural gas department deferred pension
and OPEB costs. The accumulated deferred balance of these costs at
June 30, 2009 is being recovered via a five-year amortization that began July 1,
2009.
The 2006
Rate Order included an increase in the rate allowances for pension and OPEB
expense that more closely approximated the recent cost of providing these
benefits. However, due to the expected volatility of these costs,
authorization remained in effect for the deferral of any differences between
rate allowances and actual costs under the 1993 PSC Policy. The 2006
Rate Order also authorized Central Hudson to offset significant deferred
balances for pension and OPEB expense for the electric department with available
deferred credit balances due to customers. Deferred pension and OPEB
balances accumulated through June 30, 2006, for the natural gas department are
being recovered via a seven-year amortization that began on July 1,
2007.
Central
Hudson accounts for pension activity in accordance with PSC-prescribed
provisions, which among other things, require a ten-year amortization of
actuarial gains and losses.
In
addition to the Retirement Plan, CH Energy Group’s and Central Hudson’s
executives are covered under a non-qualified Supplemental Executive Retirement
Plan.
Estimates
of Long-Term Rates of Return
The
expected long-term rate of return on Retirement Plan assets is 7.75%, net of
investment expense. In determining the expected long-term rate of
return on these assets, Central Hudson considered the current level of expected
returns on risk-free investments (primarily United States government bonds), the
historical level of risk premiums associated with other asset classes, and the
expectations of future returns over a 20-year time horizon on each asset class,
based on the views of leading financial advisors and economists. The
expected return for each asset class was then weighted based on the Retirement
Plan’s target asset allocation. Central Hudson monitors actual
performance against target asset allocations and adjusts actual allocations and
targets in accordance with the Retirement Plan strategy.
Retirement
Plan Policy and Strategy
The
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.
The asset
allocation strategy employed in the Retirement Plan reflects Central Hudson’s
return objectives and risk tolerance. Asset allocation targets,
expressed as a percentage of the market value of the Retirement Plan, are
summarized in the table below:
Asset
Class
|
|
Minimum
|
|
|
Target
Average
|
|
|
Maximum
|
|
Equity
Securities
|
|
|
55 |
% |
|
|
60 |
% |
|
|
65 |
% |
Debt
Securities
|
|
|
30 |
% |
|
|
35 |
% |
|
|
40 |
% |
Alternative
Investments
|
|
|
- |
% |
|
|
5 |
% |
|
|
7 |
% |
Due to
the dynamic nature of market value fluctuations, Retirement Plan assets will
require rebalancing from time-to-time to maintain the target asset
allocation. The Retirement Plan recognizes the importance of
maintaining a long-term strategic allocation and does not intend any tactical
asset allocation or market timing asset allocation shifts.
The
Retirement Plan seeks to earn a return commensurate with the risk of its
underlying assets. The benchmark index is currently comprised of 33%
Russell 1000 Stock Index; 12% Russell 2500 Stock Index; 15% Morgan Stanley
Capital International Europe, Australasia and Far East (MSCI EAFE) International
Stock Index (Net); 5% Russell Open-End Real Estate Mean; and 35% LB Aggregate
Bond Index. The Retirement Plan seeks to exceed the average annual
return of this benchmark 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.
The
Retirement Plan uses outside consultants and outside investment managers to aid
in the determination of asset allocation and the management of actual plan
assets, respectively.
Management
is reviewing changes to the Plan’s investment strategy to reduce the
year-to-year volatility of the funded status and the level of
contributions. Options being considered include extending the
duration of the Plan’s investments as well as changes to the target asset
allocation to more closely align with the Plan’s long-term
obligations.
Investment
Valuation
The
Retirement Plan assets are valued under the current fair value
framework. See Note 15 - “Fair Value Measurements” for further
discussion regarding the definition and levels of fair value hierarchy
established by guidance (ASC 820).
The
inputs or methodology used for valuing securities are not necessarily an
indication of the risk associated with investing in those
securities. Below is a listing of the major categories of plan assets
held as of December 31, 2009, as well as the associated level within the fair
value hierarchy in which the fair value measurements in their entirety fall
(based on the lowest level input that is significant to the fair value
measurement in its entirety) (Dollars in Thousands):
Investment
Type
|
|
Market
Value at 12/31/09
|
|
|
%
of Total
|
|
Level
2
|
|
|
|
|
|
|
Investment
Funds - Equities
|
|
$ |
199,442 |
|
|
|
63 |
% |
Investment
Funds - Fixed Income
|
|
|
100,312 |
|
|
|
32 |
% |
Level
3
|
|
|
|
|
|
|
|
|
Alternative
Investment - Real Estate
|
|
|
14,498 |
|
|
|
5 |
% |
|
|
$ |
314,252 |
|
|
|
100 |
% |
The table
listed below provides a reconciliation of the beginning and ending net balances
for assets and liabilities measured at fair value and classified as Level 3 in
the fair value hierarchy (In Thousands):
|
|
Year
Ended
December
31, 2009
|
|
Balance
at Beginning of Period
|
|
$ |
24,129 |
|
Unrealized
gains/(losses)
|
|
|
(8,555 |
) |
Realized
losses
|
|
|
195 |
|
Purchases,
issuances, sales and settlements
|
|
|
(204 |
) |
Transfers
in and/or out of Level 3
|
|
|
(1,067 |
) |
Balance
at End of Period
|
|
$ |
14,498 |
|
The funds
that have been determined to be Level 2 investments within the fair value
hierarchy are priced using indirectly observable (market-based)
information. The Level 2 funds do not have market data available;
however, the underlying securities held by those funds do have published market
data available.
The funds
that have been determined to be Level 3 investments within the fair value
hierarchy are priced using unobservable inputs. There are three
valuation techniques that can be used, the market, income or cost
approach. The appropriateness of each valuation technique depends on
the type of asset or business being valued. Key inputs used to
determine fair value include, among others, revenue and expense growth rates,
terminal capitalization rates and discount rates.
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 unionized employees and managerial, professional and
supervisory employees (“non-union”) hired prior to January 1, 2008, may become
eligible for these benefits if they reach retirement age while employed by
Central Hudson. Central Hudson amended its OPEB programs for existing
non-union and certain retired employees effective January 1,
2008. Benefit plans for non-union active employees were similarly
amended. Programs were also amended to eliminate post-retirement
benefits for non-union employees hired on or after January 1,
2008. In order to reduce the total costs of these benefits, plan
changes were negotiated with the IBEW Local 320 for unionized employees and
certain retired employees effective May 1, 2008. Plans were also
amended to eliminate post-retirement benefits for union employees hired on or
after May 1, 2008. Benefits for retirees and active employees are
provided through insurance companies whose premiums are based on the benefits
paid during the year.
The
significant assumptions used to account for these benefits are the discount
rate, the expected long-term rate of return on plan assets and the health care
cost trend rate. Central Hudson selects the discount rate using the
Citigroup Pension Discount Curve reflecting projected cash flows. The
estimates of long-term rates of return and the investment policy and strategy
for these plan assets are similar to those used for pension benefits previously
discussed in this Note. The estimates of health care cost trend rates
are based on a review of actual recent trends and projected future
trends.
Central
Hudson fully recovers its net periodic post-retirement benefit costs in
accordance with the 1993 PSC Policy. 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 actuarial
consultant in accordance with current accounting guidance related to other post
employment benefits (ASC 715-60) is deferred as either a regulatory asset or a
regulatory liability, as appropriate.
The
effect of the Medicare Act of 2003 was reflected in 2009 and 2008, assuming that
Central Hudson will continue to provide a prescription drug benefit to retirees
that are at least actuarially equivalent to Medicare Act of 2003 and that
Central Hudson will receive the federal subsidy.
In
accordance with the current accounting guidance related to other post employment
benefits (ASC 715-60), Central Hudson’s liability (i.e. the funded status) for
OPEB at December 31, 2009, was $46.2 million and at December 31, 2008, was $52.6
million, including recognition for the difference between the Accumulated
Benefit Obligation (“ABO”) and the market value of other post-retirement
assets. The change to the liability for the difference between the
ABO and the market value of other post-retirement assets at December 31, 2009
and 2008 was a decrease of $1.2 million and an increase of $10.4 million,
respectively and was offset by recording a regulatory asset in accordance with
the 1993 PSC Policy.
Central
Hudson and Griffith each participate in a 401(k) retirement plan for their
employees. Griffith also provides a discretionary profit-sharing
benefit for their employees. The 401(k) plans provide for employee
tax-deferred salary deductions for participating employees and their respective
employer matches contributions made by participating employees. The
matching benefit varies by employer and employee group. For Central
Hudson, the cost of its matching contributions was $1.8 million for 2009, $1.7
million for 2008, and $1.6 million for 2007. For Griffith, the cost
of its matching contributions was $884,000 for 2009, $869,000 for 2008, and
$783,000 for 2007. Profit-sharing contributions made by Griffith were
$594,000, $557,000, and $665,000, for 2009, 2008, and 2007,
respectively.
Estimates
of Long-Term Rates of Return
The
expected long-term rate of return on OPEB assets is 8.0%, net of investment
expense. In determining the expected long-term rate of return on
these assets, Central Hudson considered the current level of expected returns on
risk-free investments (primarily United States government bonds), the historical
level of risk premiums associated with other asset classes, and the expectations
of future returns over a 20-year time horizon on each asset class, based on the
views of leading financial advisors and economists. The expected
return for each asset class was then weighted based on the respective Plans’
target asset allocation. Central Hudson monitors actual performance
against target asset allocations and adjusts actual allocations and targets as
deemed appropriate in accordance with the Plan’s strategy.
OPEB
Policy and Strategy
The OPEB
Plans adopted an investment objective of long-term capital appreciation for each
VEBA. OPEB Plan assets are invested in accordance with sound
investment practices that emphasize long-term investment
fundamentals. The OPEB Plans seek to achieve a positive rate of
return for each VEBA over the long-term that contributes to meeting each VEBA’s
current and future obligations.
The asset
allocation strategy employed in the OPEB Plan reflects Central Hudson’s return
objectives and risk tolerance. The mix of assets shall be broadly
diversified by asset class and investment styles within asset classes, based on
the following asset allocation targets, expressed as a percentage of the market
value of the OPEB Plan, summarized in the table below:
Asset
Class
|
|
Minimum
|
|
|
Target
Average
|
|
|
Maximum
|
|
Equity
Securities
|
|
|
55 |
% |
|
|
65 |
% |
|
|
75 |
% |
Debt
Securities
|
|
|
25 |
% |
|
|
35 |
% |
|
|
35 |
% |
Investment
Valuation
The OPEB
Plan assets are valued under the current fair value framework. See Note 15 -
“Fair Value Measurements” for further discussion regarding the definition and
levels of fair value hierarchy established by guidance (ASC 820).
The
inputs or methodology used for valuing securities are not necessarily an
indication of the risk associated with investing in those
securities. Below is a listing of the major categories of plan assets
held as of December 31, 2009, as well as the associated level within the fair
value hierarchy in which the fair value measurements in their entirety fall
(based on the lowest level input that is significant to the fair value
measurement in its entirety).
401 (h) Plan Assets
|
|
|
|
|
|
|
(Dollars
in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
Type
|
|
Market
Value at 12/31/09
|
|
|
%
of Total
|
|
Level
2
|
|
|
|
|
|
|
Investment
Funds - Equities
|
|
$ |
4,191 |
|
|
|
63 |
% |
Investment
Funds - Fixed Income
|
|
|
2,108 |
|
|
|
32 |
% |
Level
3
|
|
|
|
|
|
|
|
|
Alternative
Investment - (Real Estate)
|
|
|
305 |
|
|
|
5 |
% |
|
|
$ |
6,604 |
|
|
|
100 |
% |
The table
listed below provides a reconciliation of the beginning and ending net balances
for assets and liabilities measured at fair value and classified as Level 3 in
the fair value hierarchy (In Thousands):
|
|
Year
Ended December 31, 2009
|
|
Balance
at Beginning of Period
|
|
$ |
507 |
|
Unrealized
gains/(losses)
|
|
|
(180 |
) |
Realized
losses
|
|
|
4 |
|
Purchases,
issuances, sales and settlements
|
|
|
(4 |
) |
Transfers
in and/or out of Level 3
|
|
|
(22 |
) |
Balance
at End of Period
|
|
$ |
305 |
|
Management VEBA Plan
Assets
(Dollars
In Thousands)
Investment
Type
|
|
Market
Value at 12/31/09
|
|
|
%
of Total
|
|
Level
1
|
|
|
|
|
|
|
Investment
Funds - Money Market Mutual Fund
|
|
$ |
6 |
|
|
|
- |
% |
Investment
Funds - Fixed Income Mutual Funds
|
|
|
640 |
|
|
|
35 |
% |
Investment
Funds - Equity Securities Mutual Funds
|
|
|
824 |
|
|
|
45 |
% |
Level
2
|
|
|
|
|
|
|
|
|
Investment
Funds - Equity Securities Commingled Fund
|
|
|
366 |
|
|
|
20 |
% |
|
|
$ |
1,836 |
|
|
|
100 |
% |
Union VEBA Plan
Assets
(Dollars
In Thousands)
|
|
|
|
|
|
|
Investment
Type
|
|
Market
Value at 12/31/09
|
|
|
%
of Total
|
|
Level
1
|
|
|
|
|
|
|
Investment
Funds - Money Market Mutual Fund
|
|
$ |
618 |
|
|
|
1 |
% |
Investment
Funds - Fixed Income Mutual Funds
|
|
|
14,611 |
|
|
|
20 |
% |
Investment
Funds - Equity Securities Mutual Funds
|
|
|
32,322 |
|
|
|
45 |
% |
Level
2
|
|
|
|
|
|
|
|
|
Fixed
Income Commingled Fund
|
|
|
10,443 |
|
|
|
14 |
% |
Investment
Funds - Equity Securities Commingled Fund
|
|
|
14,419 |
|
|
|
20 |
% |
|
|
$ |
72,413 |
|
|
|
100 |
% |
The funds
that have been determined to be Level 1 investments within the fair value
hierarchy are valued on the basis of available market quotations in active
markets.
The funds
that have been determined to be Level 2 investments within the fair value
hierarchy are priced using indirectly observable (market-based)
information. The Level 2 funds do not have market data available;
however, the underlying securities held by those funds do have published market
data available.
The funds
that have been determined to be Level 3 investments within the fair value
hierarchy are priced using unobservable inputs. There are three
valuation techniques that can be used, the market, income or cost
approach. The appropriateness of each valuation technique depends on
the type of asset or business being valued. Key inputs used to
determine fair value include, among others, revenue and expense growth rates,
terminal capitalization rates and discount rates.
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 are reported on the
following chart (Dollars In Thousands):
|
Pension
Benefits
|
|
|
Other
Benefits
|
|
|
2009
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Change
in Benefit Obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit
obligation at beginning of year
|
|
$ |
423,538 |
|
$ |
408,886 |
|
|
|
$ |
119,001 |
|
|
$ |
148,215 |
|
Service
cost
|
|
|
7,825 |
|
|
9,645 |
|
(1) |
|
|
2,125 |
|
|
|
2,415 |
|
Interest
cost
|
|
|
25,819 |
|
|
31,109 |
|
(1) |
|
|
6,846 |
|
|
|
7,547 |
|
Participant
contributions
|
|
|
- |
|
|
- |
|
(1) |
|
|
473 |
|
|
|
492 |
|
Plan
amendments
|
|
|
- |
|
|
1,371 |
|
(1) |
|
|
- |
|
|
|
(25,771 |
) |
Benefits
paid
|
|
|
(24,655 |
) |
|
(30,157 |
) |
(1) |
|
|
(6,455 |
) |
|
|
(6,216 |
) |
Actuarial
(gain) loss
|
|
|
34,708 |
|
|
2,684 |
|
(1) |
|
|
5,104 |
|
|
|
(7,681 |
) |
Benefit
Obligation at End of Plan Year
|
|
$ |
467,235 |
|
$ |
423,538 |
|
|
|
$ |
127,094 |
|
|
$ |
119,001 |
|
Change
in Plan Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value of plan assets at beginning of year
|
|
$ |
261,338 |
|
$ |
397,157 |
|
|
|
$ |
66,356 |
|
|
$ |
92,655 |
|
Adjustment
/ other
|
|
|
- |
|
|
- |
|
(1) |
|
|
(106 |
) |
|
|
36 |
|
Actual
return on plan assets
|
|
|
56,191 |
|
|
(116,020 |
) |
(1) |
|
|
17,192 |
|
|
|
(24,576 |
) |
Employer
contributions
|
|
|
23,124 |
|
|
13,027 |
|
(1) |
|
|
3,485 |
|
|
|
4,200 |
|
Participant
contributions
|
|
|
- |
|
|
- |
|
(1) |
|
|
473 |
|
|
|
492 |
|
Benefits
paid
|
|
|
(24,655 |
) |
|
(30,157 |
) |
(1) |
|
|
(6,455 |
) |
|
|
(6,216 |
) |
Administrative
expenses
|
|
|
(1,746 |
) |
|
(2,669 |
) |
(1) |
|
|
(92 |
) |
|
|
(235 |
) |
Fair
Value of Plan Assets at End of Plan Year
|
|
$ |
314,252 |
|
$ |
261,338 |
|
|
|
$ |
80,853 |
|
|
$ |
66,356 |
|
Reconciliation
of Funded Status:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
Status at end of year
|
|
$ |
(152,983 |
) |
$ |
(162,200 |
) |
|
|
$ |
(46,241 |
) |
|
$ |
(52,645 |
) |
Employer
Contributions between measurement date and fiscal year-end
|
|
|
- |
|
|
- |
|
|
|
|
- |
|
|
|
- |
|
Amounts
Recognized on Consolidated Balance Sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
(600 |
) |
|
(526 |
) |
|
|
|
- |
|
|
|
- |
|
Noncurrent
liabilities
|
|
|
(152,383 |
) |
|
(161,674 |
) |
|
|
|
(46,241 |
) |
|
|
(52,645 |
) |
Net
amount recognized on Consolidated Balance Sheet
|
|
|
(152,983 |
) |
|
(162,200 |
) |
|
|
|
(46,241 |
) |
|
|
(52,645 |
) |
Regulatory
asset:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-Net
loss
|
|
|
152,079 |
|
|
177,342 |
|
|
|
|
42,487 |
|
|
|
57,439 |
|
-Prior
service costs (credit)
|
|
|
12,565 |
|
|
14,742 |
|
|
|
|
(51,372 |
) |
|
|
(57,240 |
) |
-Transition
obligation
|
|
|
- |
|
|
- |
|
|
|
|
7,685 |
|
|
|
10,250 |
|
Components
of Net Periodic Benefit Cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$ |
7,825 |
|
$ |
9,645 |
|
|
|
$ |
2,125 |
|
|
$ |
2,415 |
|
Interest
cost
|
|
|
25,819 |
|
|
31,109 |
|
|
|
|
6,846 |
|
|
|
7,547 |
|
Expected
return on plan assets
|
|
|
(19,874 |
) |
|
(37,889 |
) |
|
|
|
(5,067 |
) |
|
|
(7,006 |
) |
Amortization
of prior service cost (credit)
|
|
|
2,177 |
|
|
2,658 |
|
|
|
|
(5,868 |
) |
|
|
(5,100 |
) |
Amortization
of transitional obligation
|
|
|
- |
|
|
- |
|
|
|
|
2,566 |
|
|
|
2,566 |
|
Amortization
of net (gain) loss
|
|
|
25,400 |
|
|
14,318 |
|
|
|
|
8,292 |
|
|
|
5,723 |
|
Net
Periodic Benefit Cost
|
|
$ |
41,347 |
|
$ |
19,841 |
|
|
|
$ |
8,894 |
|
|
$ |
6,145 |
|
(1)
|
Due
to measurement date change for pension benefits to December 31 from
September 30, amount reflects 15 months of
activity.
|
|
|
Pension
Benefits
|
|
|
Other
Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Other Changes in Plan Assets and
Benefit Obligation Recognized in Regulatory
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss (gain)
|
|
$ |
137 |
|
|
$ |
159,262 |
|
|
$ |
(6,660 |
) |
|
$ |
23,824 |
|
Amortization
of net (loss) gain
|
|
|
(25,400 |
) |
|
|
(14,318 |
) |
|
|
(8,292 |
) |
|
|
(5,723 |
) |
Prior
service cost (credit)
|
|
|
- |
|
|
|
1,371 |
|
|
|
- |
|
|
|
(25,771 |
) |
Amortization
of prior service cost
|
|
|
(2,177 |
) |
|
|
(2,658 |
) |
|
|
5,868 |
|
|
|
5,100 |
|
Transitional
obligation
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Amortization
of transitional obligation
|
|
|
- |
|
|
|
- |
|
|
|
(2,566 |
) |
|
|
(2,566 |
) |
Regulatory
asset attributable to change from prior year
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
recognized in regulatory asset
|
|
|
(27,440 |
) |
|
|
143,657 |
|
|
|
(11,650 |
) |
|
|
(5,136 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
recognized in net periodic benefit cost and regulatory
asset
|
|
$ |
13,907 |
|
|
$ |
163,498 |
|
|
$ |
(2,756 |
) |
|
$ |
1,009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average
assumptions used to determine benefit obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
5.70 |
% |
|
|
6.20 |
% |
|
|
5.70 |
% |
|
|
6.20 |
% |
Rate
of compensation increase
|
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
Measurement
date
|
|
12/31/09
|
|
|
12/31/08
|
|
|
12/31/09
|
|
|
12/31/08
|
|
Weighted-average
assumptions used to determine net periodic benefit cost for years ended
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
6.20 |
% |
|
|
6.20 |
% |
|
|
6.20 |
% |
|
|
6.40 |
% |
Expected
long-term rate of return on plan assets
|
|
|
8.00 |
% |
|
|
8.00 |
% |
|
|
8.00 |
% |
|
|
7.75 |
% |
Rate
of compensation increase
|
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumed
health care cost trend rates at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Health
care cost trend rate assumed for next year
|
|
|
N/A |
|
|
|
N/A |
|
|
|
8.57 |
% |
|
|
9.00 |
% |
Rate
to which the cost trend rate is assumed to decline (the ultimate trend
rate)
|
|
|
N/A |
|
|
|
N/A |
|
|
|
4.50 |
% |
|
|
5.00 |
% |
Year
that the rate reaches the ultimate trend rate
|
|
|
N/A |
|
|
|
N/A |
|
|
|
2029 |
|
|
|
2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
plans with accumulated benefit obligations in excess of plan
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected
benefit obligation
|
|
$ |
467,234 |
|
|
$ |
423,538 |
|
|
|
N/A |
|
|
|
N/A |
|
Accumulated
benefit obligation
|
|
|
426,255 |
|
|
|
389,144 |
|
|
|
N/A |
|
|
|
N/A |
|
Fair
Value of plan assets
|
|
|
314,252 |
|
|
|
261,338 |
|
|
|
N/A |
|
|
|
N/A |
|
The ABO
for defined benefit pension plans was $426.3 million and $389.1 million at
December 31, 2009 and 2008, respectively.
The
estimated net loss and prior service cost for the defined benefit pension plans
that will be amortized from regulatory assets into net periodic benefit cost
over the next fiscal year are $29.5 million and $2.2 million, respectively. The
estimated net loss, prior service cost (credit) and transitional obligation for
the other defined benefit post-retirement plans that will be amortized from
regulatory assets into net periodic benefit cost over the next fiscal year is
$10.4 million, $(5.9) million, and $2.6 million, respectively.
Central
Hudson’s pension and other post-retirement plans’ weighted average asset
allocations at December 31, 2009 and 2008, by asset category are as
follows:
|
|
Pension
Plan
|
|
|
Other
Plans
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Equity
Securities
|
|
|
62.8 |
% |
|
|
48.7 |
% |
|
|
64.5 |
% |
|
|
65.6 |
% |
Debt
Securities
|
|
|
31.9 |
% |
|
|
41.3 |
% |
|
|
34.7 |
% |
|
|
34.1 |
% |
Alternate
Investment
|
|
|
4.6 |
% |
|
|
9.2 |
% |
|
|
0.0 |
% |
|
|
0.0 |
% |
Other
|
|
|
0.7 |
% |
|
|
0.8 |
% |
|
|
0.8 |
% |
|
|
0.3 |
% |
Total
|
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
For the
pension plan and other benefit plans, equity securities do not include CH Energy
Group Common Stock at December 31, 2009, and 2008, respectively.
Assumed
health care cost trend rates have a significant effect on the amounts reported
for the health care plan. A 1% change in assumed health care cost
trend rates would have the following effects (In Thousands):
|
One
Percentage
|
|
One
Percentage
|
|
|
Point
Increase
|
|
Point
Decrease
|
|
Effect
on total of service and interest cost components for 2009
|
|
$ |
447 |
|
|
$ |
(385 |
) |
|
|
|
|
|
|
|
|
|
Effect
on year-end 2009 post-retirement benefit obligation
|
|
$ |
4,217 |
|
|
$ |
(3,722 |
) |
Employer
contributions for OPEB totaled $3.5 million and $4.2 million during the year
ended December 31, 2009, and December 31, 2008,
respectively. Contribution levels are determined by various factors
including the discount rate, expected return on plan assets, medical claims
assumptions used, mortality assumptions used, benefit changes, and corporate
resources.
Estimated
Future Benefit Payments
The
following benefit payments, which reflect expected future service as
appropriate, are expected to be paid (In Thousands):
Year
|
|
Pension
Benefits - Gross
|
|
|
Other
Benefits - Gross
|
|
|
Other
Benefits - Net(1)
|
|
2010
|
|
$ |
28,064 |
|
|
$ |
7,272 |
|
|
$ |
6,722 |
|
2011
|
|
|
28,379 |
|
|
|
7,791 |
|
|
|
7,211 |
|
2012
|
|
|
29,056 |
|
|
|
8,181 |
|
|
|
7,563 |
|
2013
|
|
|
29,689 |
|
|
|
8,454 |
|
|
|
7,792 |
|
2014
|
|
|
30,024 |
|
|
|
8,887 |
|
|
|
8,191 |
|
2015
- 2019
|
|
|
160,096 |
|
|
|
47,329 |
|
|
|
43,274 |
|
(1) Estimated benefit
payments reduced by estimated gross amount of Medicare Act of 2003 subsidy
receipts expected.
NOTE 11 -
EQUITY-BASED COMPENSATION
CH Energy
Group’s Long-Term Performance-Based Incentive Plan (“2000 Plan”), adopted in
2000 and amended in 2001 and 2003, reserves 500,000 shares of CH Energy Group’s
Common Stock for awards to be granted under the 2000 Plan. The 2000
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 2000 Plan. Stock options granted
to officers of CH Energy Group and its subsidiaries are exercisable over a
period of ten years, with 40% of the options vesting after two years and 20% of
the options vesting each year thereafter for the following three
years. Stock options granted to non-employee Directors are
immediately exercisable.
The 2000
Plan was amended in the third quarter of 2003. The amendment allows
executives to defer receipt of performance shares and performance units in
accordance with the terms of CH Energy Group’s Directors and Executives Deferred
Compensation Plan. Also, an amendment to the previously effective
Stock Plan for Outside Directors provided for shares of stock previously accrued
for retired Directors to be paid in the form of cash and provides that active
Directors could elect to transfer previously accrued shares payable to them to
CH Energy Group’s Directors and Executives Deferred Compensation
Plan. In addition, the amendment freezes future participation and
future accruals under the 2000 Plan.
In 2006,
CH Energy Group adopted a Long-Term Equity Incentive Plan (“2006 Plan”) to
replace the 2000 Plan. The 2006 Plan was approved by CH Energy
Group’s shareholders on April 25, 2006. The 2000 Plan has been
terminated, with no new awards to be granted under such
plan. Outstanding awards granted under the 2000 Plan will continue in
accordance with their terms and the provisions of the 2000 Plan.
The 2006
Plan reserves up to a maximum of 300,000 shares of CH Energy Group’s Common
Stock for awards to be granted under the 2006 Plan. Awards may
consist of stock option rights, stock appreciation rights, performance shares,
performance units, restricted shares, restricted stock units, and other awards
that CH Energy Group’s Compensation Committee of its Board of Directors
(“Compensation Committee”) may authorize. The Compensation Committee
may also, from time-to-time and upon such terms and conditions as it may
determine, authorize the granting to non-employee Directors of stock option
rights, stock appreciation rights, restricted shares, and restricted stock
units.
In
addition to the aggregate limit in the awards described above, the 2006 Plan
imposes various sub-limits on the number of shares of CH Energy Group’s Common
Stock that may be issued or transferred under the 2006 Plan. The
aggregate number of shares of Common Stock actually issued or transferred by CH
Energy Group upon the exercise of incentive stock options shall not exceed
300,000 shares. No participant may be granted stock option rights and
stock appreciation rights, in aggregate, for more than 15,000 shares of Common
Stock during any calendar year. No participant in any calendar year
may receive an award of performance shares or restricted shares that specify
management objectives, in the aggregate, for more than 20,000 shares of Common
Stock, or performance units having an aggregate maximum value as of their
respective date of grant in excess of $1 million. The number of
shares of Common Stock issued as stock appreciation rights, restricted shares,
and restricted stock units (after taking forfeitures into account) may not
exceed, in the aggregate, 100,000 shares of common stock.
As of
December 31, 2009, CH Energy Group had stock options outstanding, which were
issued under the 2000 Plan, as well as performance shares, restricted shares and
restricted stock units outstanding, which were issued under the 2006
Plan.
Stock
Options
The
following table summarizes information concerning stock options granted through
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Number
of
|
|
|
Number
of
|
|
|
Average
|
|
|
Number
of
|
|
|
Exercise
|
|
|
Options
|
|
|
Options
|
|
|
Remaining
|
|
|
Options
|
|
Date
of Grant
|
Price
|
|
|
Granted
|
|
|
Outstanding
|
|
|
Life
in Years
|
|
|
Exercisable
|
|
January
1, 2000
|
|
$ |
31.94 |
|
|
|
30,300 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
January
1, 2001
|
|
$ |
44.06 |
|
|
|
59,900 |
|
|
|
18,560 |
|
|
|
1.00 |
|
|
|
18,560 |
|
January
1, 2003
|
|
$ |
48.62 |
|
|
|
36,900 |
|
|
|
17,420 |
|
|
|
3.00 |
|
|
|
17,420 |
|
|
|
|
|
|
|
|
127,100 |
|
|
|
35,980 |
|
|
|
1.97 |
|
|
|
35,980 |
|
All
options were fully vested as of December 31, 2007. The fair market
values per option of CH Energy Group stock options granted in 2003, 2001, and
2000 are $6.51, $4.41, 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
|
|
|
2001
|
|
|
2000
|
|
Risk-free
interest rate
|
|
|
4.40 |
% |
|
|
4.78 |
% |
|
|
6.36 |
% |
Expected
life - in years
|
|
|
10 |
|
|
|
5 |
|
|
|
5 |
|
Expected
stock volatility
|
|
|
17.50 |
% |
|
|
20.06 |
% |
|
|
15.59 |
% |
Dividend
yield
|
|
|
4.4 |
% |
|
|
5.4 |
% |
|
|
5.4 |
% |
A summary
of the status of stock options awarded to executives and non-employee Directors
of CH Energy Group and its subsidiaries under the 2000 Plan is as
follows:
|
|
|
|
|
Weighted
|
|
|
|
Weighted
|
|
Average
|
|
Stock
Option
|
|
Average
|
|
Remaining
Life
|
|
Shares
|
|
Exercise
Price
|
|
in
Years
|
Outstanding
at 12/31/08
|
40,300
|
|
$
|
46.05
|
|
3.91
|
Granted
|
-
|
|
|
-
|
|
|
Exercised
|
4,320
|
|
|
44.22
|
|
|
Expired
/ Forfeited
|
-
|
|
|
-
|
|
|
Outstanding
at 12/31/09 |
35,980
|
|
$
|
46.27
|
|
1.97
|
|
|
|
|
|
|
|
Total
CH Energy Group Shares Outstanding
|
|
15,804,562
|
|
|
Potential
Dilution
|
|
|
0.2
|
%
|
|
Compensation
expense related to stock options for the years ended December 31, 2009, 2008 and
2007 was not material. The balance accrued for outstanding options
was $0.1 million as of December 31, 2009 and 2008. The intrinsic
value of outstanding options was not material as of December 31, 2009 and
2008.
Performance
Shares
A summary
of the status of performance shares granted to executives under the 2006 Plan is
as follows:
|
|
|
|
|
|
|
|
|
|
Performance
Shares
|
|
|
|
|
Grant
Date
|
|
|
Performance
Shares
|
|
|
Outstanding
at
|
|
Grant
Date
|
|
|
Fair
Value
|
|
|
Granted
|
|
|
December
31, 2009
|
|
January
25, 2007
|
|
|
|
$ |
50.56 |
|
|
|
21,330 |
|
|
|
19,380 |
|
January
24, 2008
|
|
|
|
$ |
35.76 |
|
|
|
33,440 |
|
|
|
31,900 |
|
January
26, 2009
|
|
|
|
$ |
49.29 |
|
|
|
36,730 |
|
|
|
36,730 |
|
The
ultimate number of shares earned under the awards is based on metrics
established by the Compensation Committee at the beginning of the award
cycle. Compensation expense is recorded as performance shares are
earned over the relevant three-year life of the performance share grant prior to
its award. The portion of the compensation expense related to an
employee who retires during the performance period is the amount recognized up
to the date of retirement.
On May 1,
2009, performance shares earned as of December 31, 2008 for the award cycle with
a grant date of April 25, 2006 were issued to participants. Those
recipients electing not to defer this compensation under the CH Energy Group
Directors and Executives Deferred Compensation Plan received shares issued from
CH Energy Group's treasury stock. A total of 4,560 shares were issued
from CH Energy Group's treasury stock on May 1, 2009. Additionally,
due to the retirement of one of Central Hudson's executive officers on January
1, 2009, a pro-rated number of shares under the January 25, 2007 and January 24,
2008 grants were paid to this individual on July 2, 2009. An
additional 294 shares were issued from CH Energy Group's treasury stock on this
date in satisfaction of these awards.
The total
compensation expense recognized for performance shares was $1.1 million for the
year ended December 31, 2009, $0.5 million for the year ended December 31, 2008,
and $0.5 million for the year ended December 31, 2007.
The
determination of compensation expense for performance shares in prior years was
based on the use of the binomial method, which reflected the following
assumptions:
|
|
For
the year ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
Stock
price
|
|
$ |
51.39 |
|
|
$ |
44.54 |
|
Dividend
yield
|
|
|
4.2 |
% |
|
|
4.8 |
% |
Performance
period (in years)
|
|
|
3 |
|
|
|
3 |
|
Risk-free
rates of return:
|
|
|
|
|
|
|
|
|
One
year
|
|
|
0.37 |
% |
|
|
3.34 |
% |
Two
year
|
|
|
0.76 |
% |
|
|
3.05 |
% |
Three
year
|
|
|
1.00 |
% |
|
|
3.07 |
% |
Other
considerations in the determination of compensation expense for performance
shares included the grant price for each individual grant, estimated
forfeitures, and historical percentile performance rank.
Commencing
in 2009, CH Energy Group ceased using a binomial model and recorded compensation
expense for performance shares based on the fair value of the awards at the end
of each reporting period. This fair value is determined based on the
shares' current market value at the end of each reporting period, estimated
forfeitures for each grant, expected payout based on historical performance in
accordance with the defined metrics of each grant, and the time elapsed within
each grant's performance period.
Restricted
Shares and Restricted Stock Units
The
following table summarizes information concerning restricted shares and stock
units granted through December 31, 2009:
Grant
Date
|
|
Type
of Award
|
|
Shares
or
Stock
Units Granted
|
|
Grant
Date
Fair
Value
|
|
Vesting
Terms
|
|
Unvested
Shares Outstanding at December 31, 2009
|
|
January
2, 2008
|
|
Shares
|
|
10,000
|
|
$
|
44.32
|
|
End
of 3 years
|
|
8,900
|
(1)
|
January
2, 2008
|
|
Shares
|
|
2,100
|
|
$
|
44.32
|
|
Ratably
over 3 years
|
|
1,400
|
|
January
26, 2009
|
|
Shares
|
|
2,930
|
|
$
|
49.29
|
|
End
of 3 years
|
|
2,680
|
(2)
|
October
1, 2009
|
|
Shares
|
|
14,375
|
|
$
|
43.86
|
|
Ratably
over 5 years
|
|
14,375
|
|
November
20, 2009
|
|
Stock
Units
|
|
13,900
|
|
$
|
41.43
|
|
1/3
each year in
Years
5, 6 and 7
|
|
13,900
|
|
(1)
|
500
shares were forfeited upon resignation of the employee holding the shares
and the vesting of 600 shares was accelerated upon a change in control for
an individual resulting from the sale of certain assets of
Griffith.
|
(2)
|
The
vesting of 250 shares was accelerated upon a change in control for an
individual resulting from the sale of certain assets of
Griffith.
|
The above
shares granted were issued from CH Energy Group’s treasury. In
accordance with current accounting guidance related to equity based compensation
(ASC 718-40), unvested restricted shares do not impact the number of common
shares outstanding used in the basic EPS calculation. Shares will not
be issued with respect to restricted stock units until a specified future date
defined within the individual agreement. The total unvested
outstanding restricted shares and stock units noted above have been included in
the diluted EPS calculation as of December 31, 2009 and 2008. The
total compensation expense recognized for these restricted shares and stock
units was $0.2 million and $0.1 million for the years ended December 31, 2009
and 2008, respectively. Total recognized tax benefits related to
these restricted shares and stock units was not material for the years ended
December 31, 2009 and 2008.
Phantom
Shares
CH Energy
Group provides equity compensation for its non-employee
Directors. The equity component of annual compensation for each
non-employee Director is fixed at a number of phantom shares of CH Energy Group
Common Stock. These phantom shares are deferred until the Director’s
termination of service. Effective January 1, 2008, CH Energy Group
adopted new director stock ownership guidelines, which require each Director to
accumulate within 5 years, and to hold during his or her service on the Board,
at least 6,000 shares of CH Energy Group’s Common Stock (which may be in the
form of phantom shares). This amendment to the plan provides that if
a Director satisfies this required level of stock ownership, he or she will
receive the cash value of equity compensation in lieu of additional phantom
shares. This value will either be paid in cash or deferred under CH
Energy Group’s Directors and Executives Deferred Compensation Plan, at the
election of the Director.
Through
June 30, 2008, the annual equity compensation for each non-employee Director was
the equivalent of $55,000. Effective July 1, 2008, this compensation
was increased to $65,000 per year. Total equity compensation expense
to non-employee Directors recognized by CH Energy Group was $0.5 million for the
year ended December 31, 2009 and $0.4 million for the years ended December 31,
2008 and 2007.
For
additional discussion regarding the dilutive effects of equity-based
compensation, see Note 1 - “Summary of Significant Accounting Policies” under
the caption “Earnings Per Share.”
Electricity
Purchase Commitments
Central
Hudson is obligated to supply electricity to its retail electric
customers. Under the Settlement Agreement, Central Hudson's retail
customers may elect to procure electricity from third-party suppliers or may
continue to rely on Central Hudson. As part of its efforts to supply
customers who continue to rely on Central Hudson for their energy supply,
Central Hudson entered into an agreement with Constellation to purchase capacity
and energy, comprising approximately 8% of the output of Unit No. 2 of the Nine
Mile Point Nuclear Generating Station (“Nine Mile 2
Plant”) at negotiated prices during the ten-year period beginning on 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. Following the expiration of this purchase agreement, a
revenue sharing agreement with Constellation will begin, which will provide
Central Hudson with a hedge against electricity price increases and could
provide additional future revenue for Central Hudson through 2021. In
the Constellation agreements, electricity is purchased at defined prices that
escalate over the life of the contract. The capacity and energy
supplied under the agreement with Constellation in 2009 was sufficient to supply
approximately 14% of Central Hudson’s total system requirements and cost
approximately $27.9 million. For the years 2008 and 2007, the energy
supplied under this agreement cost approximately $25.2 million and $25.0
million, respectively.
On March
6, 2007, Central Hudson
entered into an agreement with Entergy Nuclear Power Marketing, LLC to purchase
electricity (but not capacity) on a unit-contingent basis at defined prices from
January 1, 2008 through December 31, 2010. On an annual basis, the
electricity purchased through the Entergy contract represents approximately 23%
of Central Hudson’s full-service customer requirements and for the year ended
December 31, 2009 energy supplied under this agreement cost approximately $55.3
million. For the years ended December 31, 2008 and 2007, the energy
supplied under this agreement cost approximately $57.5 million and $29.9
million, respectively.
Purchases
under the Entergy and Nine Mile 2 Plant contracts are supplemented by
shorter-term contracts, such as the Dynegy contract discussed below, contracts
for differences, and by purchases from the NYISO, which oversees the bulk
electricity transmission system, and the capacity market in New York State, and
other parties. On January 30, 2008, Central Hudson entered into an
11-month agreement with Dynegy Power Marketing, Inc. to purchase 589,200 MWh of
electricity on a unit-contingent basis at defined prices from February 1, 2008
to December 31, 2008. The electricity purchased through the Dynegy
contract represented approximately 15% of Central Hudson’s full-service customer
requirements for the eleven-month period and cost approximately $50.0
million.
In the
event the above noted counterparties are unable to fulfill their commitments to
deliver under the terms of the agreements, Central Hudson would obtain the
supply from the NYISO market, and under Central Hudson’s current ratemaking
treatment, recover the full cost from customers. As such, there would
be no impact on earnings.
Central
Hudson must also acquire sufficient peak load capacity to meet the peak load
requirements of its full service customers. This capacity is made up
of its own generating capacity, contracts with capacity providers, and purchases
from the NYISO capacity market.
Operating
Leases
CH Energy
Group and its subsidiaries have entered into agreements with various companies
which provide products and services to be used in their normal
operations. These agreements include operating leases for the use of
data processing and office equipment, vehicles, office space, and bulk petroleum
storage locations. The provisions of these leases generally provide
for renewal options and some contain escalation clauses.
Operating
lease rental payment amounts charged to expense by CH Energy Group and its
subsidiaries were $2.8 million in 2009, $3.4 million in 2008, and $3.5 million
in 2007. Included in these amounts are payments for contingent
rentals, which are operating lease agreements that contain provisions for a
change in lease payments subsequent to the inception of the
lease. Contingent rental payments amounted to $563,000 in 2008 and
$555,000 in 2007. CH Energy Group did not have any payments for
contingent rentals in 2009.
Operating
lease rental payment amounts charged to expense by Central Hudson were $1.5
million in 2009, $2.1 million in 2008, and $2.4 million in
2007. Included in these amounts are payments for contingent rentals,
which amounted to $0.6 million in 2008, and $0.6 million in
2007. Central Hudson did not have any payments for contingent rentals
in 2009.
Future
minimum lease payments excluding executory costs, such as property taxes and
insurance, are included in the following table of Other
Commitments. All leases are non-cancelable, and rent expense is
recognized on a straight-line basis over the minimum lease
term.
Other
Commitments
The
following is a summary of commitments for CH Energy Group and its affiliates as
of December 31, 2009 (In Thousands):
Projected Payments Due By
Period
|
|
Less
than
1
year
|
|
|
Year
Ending
2011
|
|
|
Year
Ending
2012
|
|
|
Year
Ending
2013
|
|
|
Year
Ending
2014
|
|
|
Total
|
|
Operating
Leases
|
|
$ |
2,450 |
|
|
$ |
2,559 |
|
|
$ |
2,345 |
|
|
$ |
2,170 |
|
|
$ |
2,395 |
|
|
$ |
11,919 |
|
Construction/Maintenance
& Other Projects(1)
|
|
|
79,307 |
|
|
|
22,768 |
|
|
|
7,081 |
|
|
|
4,815 |
|
|
|
2,848 |
|
|
|
116,819 |
|
Purchased
Electric Contracts(2)
|
|
|
109,732 |
|
|
|
36,356 |
|
|
|
3,999 |
|
|
|
3,999 |
|
|
|
3,999 |
|
|
|
158,085 |
|
Purchased
Natural Gas Contracts(2)
|
|
|
55,369 |
|
|
|
31,465 |
|
|
|
21,945 |
|
|
|
11,452 |
|
|
|
11,172 |
|
|
|
131,403 |
|
Purchased
Fixed Liquid Petroleum Contracts(3)
|
|
|
3,959 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,959 |
|
Total
|
|
$ |
250,817 |
|
|
$ |
93,148 |
|
|
$ |
35,370 |
|
|
$ |
22,436 |
|
|
$ |
20,414 |
|
|
$ |
422,185 |
|
(1)
|
Including
Specific, Term, and 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 purchased natural gas costs for Central Hudson are fully
recovered via their respective regulatory cost adjustment
mechanisms.
|
(3)
|
Estimated
based on pricing on December 31,
2009.
|
The
following is a summary of commitments for Central Hudson as of December 31, 2009
(In Thousands):
Projected Payments Due By
Period
|
|
Less
than
1
year
|
|
|
Year
Ending
2011
|
|
|
Year
Ending
2012
|
|
|
Year
Ending
2013
|
|
|
Year
Ending
2014
|
|
|
Total
|
|
Operating
Leases
|
|
$ |
1,546 |
|
|
$ |
1,534 |
|
|
$ |
1,479 |
|
|
$ |
1,457 |
|
|
$ |
1,450 |
|
|
$ |
7,466 |
|
Construction/Maintenance
& Other Projects(1)
|
|
|
52,022 |
|
|
|
22,730 |
|
|
|
7,043 |
|
|
|
4,777 |
|
|
|
2,810 |
|
|
|
89,382 |
|
Purchased
Electric Contracts(2)
|
|
|
109,732 |
|
|
|
36,356 |
|
|
|
3,999 |
|
|
|
3,999 |
|
|
|
3,999 |
|
|
|
158,085 |
|
Purchased
Natural Gas Contracts(2)
|
|
|
55,369 |
|
|
|
31,465 |
|
|
|
21,945 |
|
|
|
11,452 |
|
|
|
11,172 |
|
|
|
131,403 |
|
Total
|
|
$ |
218,669 |
|
|
$ |
92,085 |
|
|
$ |
34,466 |
|
|
$ |
21,685 |
|
|
$ |
19,431 |
|
|
$ |
386,336 |
|
(1)
|
Including
Specific, Term, and Service Contracts, as defined in footnote (1) of the
preceding chart.
|
(2)
|
Purchased
electric and purchased natural gas costs for Central Hudson are fully
recovered via their respective regulatory cost adjustment
mechanisms.
|
Central
Hudson has an obligation to meet its contractual benefit payment
obligations. Decisions about how to fund the Retirement Plan to meet
these obligations are made annually and are primarily affected by the discount
rate used to determine benefit obligations, current asset values and the
projection of Retirement Plan assets. Based on the funding
requirements of the Pension Protection Act, Central Hudson plans to make
contributions that maintain the target funded percentage at 80% or
higher. On January 22, 2010, Central Hudson contributed $30 million
to its Retirement Plan. Central Hudson’s contributions for 2010 are
expected to total approximately $30-$55 million, resulting in a funded status
that meets Central Hudson’s objective. The actual contributions could
vary significantly based upon economic growth, projected investment returns,
inflation, and interest rate assumptions. Actual funded status could
vary significantly based on asset returns and changes in the discount rate used
to estimate the present value of future obligations.
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. Eight separate lawsuits arising out of this
incident have been commenced against Central Hudson and other defendants. The
basis for the claimed liability of Central Hudson in these actions is that it
was allegedly negligent in the supply of natural gas. The suits seek
an aggregate of $528 million in compensatory damages. Central Hudson has
notified its insurance carrier, denied liability, and defended the
lawsuits. On December 10, 2008, Central Hudson entered into a
settlement agreement with the plaintiffs and one remaining
defendant. Under the settlement agreement, Central Hudson has agreed
to make payments to the plaintiffs that will not be material in the
aggregate. The settlement agreement is subject to final approval by
the Court.
Environmental
Matters
Central
Hudson
In
October 1999, Central Hudson was informed by the New York State Attorney General
(“Attorney General”) that the Danskammer Point Steam Electric Generating Station
(“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.” In March 2000,
the Environmental Protection Agency (“EPA”) assumed responsibility for the
investigation. Central Hudson has completed its production of
documents requested by the Attorney General, the New York State Department of
Environmental Conservation (“DEC”), and the EPA, 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. In
March 2009, Dynegy notified Central Hudson that Dynegy had received an
information request pursuant to the Clean Air Act from the EPA for the
Danskammer Plant covering the period beginning January 2000 to
present. At that time, Dynegy also submitted to Central Hudson a
demand for indemnification for any fines, penalties or other losses that may be
incurred by Dynegy arising from the period that Central Hudson owned the
Danskammer Plant. Central Hudson presently has insufficient
information with which to predict the outcome of this matter.
|
Ø
|
Former Manufactured Gas Plant
Facilities
|
Like most
late 19th and
early 20th
century utilities in the Northeastern United States, Central Hudson and its
predecessors owned and operated manufactured gas plants (“MGPs”) to serve their
customers’ heating and lighting needs. MGPs manufactured gas from
coal and oil. This process produced certain by-products that may pose
risks to human health and the environment.
The DEC,
which regulates the timing and extent of remediation of MGP sites in New York
State, has notified Central Hudson that it believes Central Hudson or its
predecessors at one time owned and/or operated MGPs at eight sites in Central
Hudson’s franchise territory. The DEC has further requested that
Central Hudson investigate and, if necessary, remediate these sites under a
Consent Order, Voluntary Cleanup Agreement, or Brownfield Cleanup
Agreement. The DEC has placed seven of these sites on the New York
State Environmental Site Remediation Database. A number of the sites
are now owned by third parties and have been redeveloped for other
uses. The DEC has recently begun inquiries regarding a ninth
site. The status of the sites is as follows:
Site
|
|
Status
|
#1
|
|
Beacon,
NY
|
|
Interim
Remediation work complete. Final Report Approved by the
DEC. Awaiting Decision Document from the DEC and an
environmental easement from the property owner.
|
#2
|
|
Newburgh,
NY
|
|
Remediation
complete in one area under the terms of the DEC-approved
plan. The final Construction Completion Report on this area has
been filed with the DEC. For the remaining areas, remediation
began in the 4th
quarter of 2009.
|
#3
|
|
Laurel
Street
Poughkeepsie,
NY
|
|
Remediation
work is complete. Preparing Final Report and post-remediation
Site Management Plan. Additional monitoring/recovery wells
requested by the DEC will be completed in the 1st
quarter of 2010.
|
#4
|
|
North
Water Street
Poughkeepsie,
NY
|
|
Additional
land and river investigations have been requested by the DEC. A
work plan for this investigation work was submitted to the DEC on January
7, 2010. In 2009, visible oil sheens associated with this site
occurred in the Hudson River. The DEC has not notified Central
Hudson regarding any investigation or remediation related to these oil
sheens.
|
#5
|
|
Kingston,
NY
|
|
Brownfield
Cleanup Agreement was executed and the Citizen Participation Plan (“CPP”)
was submitted to the DEC. Additional land and river
investigations have been approved by the DEC. This additional
land and river investigation work will begin in 2010.
|
#6
|
|
Catskill,
NY
|
|
Site
investigation continues under the DEC-approved Brownfield Cleanup
Agreement. Access agreements for additional investigation work
have been executed and the work began on October 5,
2009.
|
#7
|
|
Saugerties,
NY
|
|
This
site has been removed from the DEC listing of sites in which Central
Hudson has remedial responsibility.
|
#8
|
|
Bayeaux
Street
Poughkeepsie,
NY
|
|
Central
Hudson does not believe it has any further liability for this
site.
|
#9
|
|
Broad
Street
Newburgh,
NY
|
|
The
DEC has recently made inquiries about this additional
site. Central Hudson does not believe it has any liability for
this site and has responded to the DEC on June 22, 2009 confirming this
position.
|
In the
second quarter of 2008, Central Hudson updated the estimate of potential
remediation and future operating, maintenance and monitoring costs for sites #
2, 3, 4, 5 and 6 indicating that the total cost for the five sites could exceed
$165 million over the next 30 years. The estimates for sites # 2 and
3 are currently based on the actual completed or contracted remediation
costs. However, these estimates are subject to change based on the
current investigations, final remedial design (and associated engineering
estimates), DEC and New York State Department of Health (“NYSDOH”) comments and
requests, remedial design changes/negotiations and changed or unforeseen
conditions during the remediation or additional requirements following the
remediation. The estimates for sites # 4, 5 and 6 were based on
partially completed remedial investigations and current DEC and NYSDOH
preferences related to site remediation, and are considered conceptual and
preliminary. The cost estimate involves assumptions relating to
investigation expenses, remediation costs, potential future liabilities, and
post-remedial operating, maintenance and monitoring costs, and is based on a
variety of factors including projections regarding the amount and extent of
contamination, the location, size and use of the sites, proximity to sensitive
resources, status of regulatory investigations, and information regarding
remediation activities at other MGP sites in New York State. This
cost estimate also assumes that proposed or anticipated remediation techniques
are technically feasible and that proposed remediation plans receive DEC and
NYSDOH approval. Further, the updated estimate could change
materially based on changes to technology relating to remedial alternatives and
changes to current laws and regulations.
Prior to
2009, Central Hudson recorded a $24.7 million estimated liability for sites # 2
and 3 based on estimates of remediation costs for the proposed clean-up
plans. As of December 31, 2009, $18.6 million of this recorded
estimated liability has not been spent; $15.9 million of this recorded estimated
liability is expected to be spent over the next twelve months.
No
amounts have been recorded in connection with the physical remediation of sites
# 4, 5 and 6, for which Central Hudson has developed estimated future costs
based on conceptual and preliminary plans. Absent DEC-approved
remediation plans, management cannot reasonably estimate what cost, if any, will
actually be incurred. The portion of the $165 million referenced
above that is related to these three sites is approximately $121
million. Prior to 2009, Central Hudson had recorded a $1.5 million
estimated liability in connection with estimated costs for preliminary
investigations, site testing and development of remediation plans for sites # 4,
5 and 6 through 2010. Based on the latest forecast of activities at
these sites, this estimated liability has been increased in 2009 to $1.7
million. As of December 31, 2009, none of this recorded estimated
liability has been spent; $1.1 million of this recorded estimated liability is
expected to be spent over the next twelve months. This estimated
amount may change in the future as additional information is obtained regarding
the results of site-testing, the scope of site investigation plans approved by
the DEC and NYSDOH, and the evolving development of new
technologies. Central Hudson cannot predict the results of site
testing, the nature, timing or extent of comments from the DEC and NYSDOH, or
changes in technology. The impact of these uncertainties on the
estimate cannot be determined.
With
regard to sites # 7, 8 and 9, Central Hudson does not have sufficient
information to estimate its potential remediation cost if any; as previously
stated, Central Hudson believes that it has no liability for these
sites.
Pursuant
to the 2006 Rate Order, Central Hudson is permitted to defer for future recovery
the differences between actual costs for MGP site investigation and remediation
and the associated rate allowances, with carrying charges to be accrued on the
deferred balances at the authorized pre-tax rate of return. Central
Hudson spent $5.9 million in the twelve months ended December 31, 2009 related
to site investigation and remediation for sites #2, 3, 4, 5 and
6. Based on the 2006 Rate Order, on July 1, 2007, Central Hudson
started the recovery of a rate allowance for MGP Site Investigation and
Remediation Costs. The 2009 Rate Order provided for an increase in
this rate allowance to an amount of $2.8 million during the July 2009 through
June 2010 rate year. Additionally, the 2009 Rate Order authorized
recovery of amounts spent over the rate allowance from the net electric
regulatory liability balance and authorizes continued deferral for all other MGP
site remediation expenditures. The total MGP Site Investigation and
Remediation costs recovered from July 1, 2007 through December 31, 2009 was
approximately $6.1 million, with $3.6 million recovered in 2009.
Central
Hudson has put its insurers on notice and intends to seek reimbursement from its
insurers for the costs of any liabilities. Certain of these insurers
have denied coverage.
Future
remediation activities, including operating, maintenance and monitoring and
related costs may vary significantly from the assumptions used in Central
Hudson’s current cost estimates, and these costs could have a material adverse
effect (the extent of which cannot be reasonably determined) on the financial
condition, results of operations and cash flows of CH Energy Group and Central
Hudson if Central Hudson were unable to recover all or a substantial portion of
these costs via collection in rates from customers and/or through
insurance.
In
December 1977, Central Hudson purchased property at 610 Little Britain Road, New
Windsor, New York. In 1992, the DEC informed Central Hudson that the
DEC was preparing to conduct a Preliminary Site Assessment (“PSA”) of the site
and in 1995, the DEC issued an Order of Consent in which Central Hudson agreed
to conduct the PSA. In 2000, following completion of the PSA, Central
Hudson and the DEC entered into a Voluntary Cleanup Agreement (“VCA”) whereby
Central Hudson removed approximately 3,100 tons of soil and conducted
groundwater sampling. Central Hudson believes that it has fulfilled
its obligations under the VCA and should receive the release provided for in the
VCA, but DEC has proposed that additional ground water work be done to address
groundwater sampling results that showed the presence of certain contaminants at
levels exceeding DEC criteria. Central Hudson believes that such work
is not necessary and has completed a soil vapor intrusion study showing that
indoor air at the facility met Occupational Safety and Health Administration
(“OSHA”) and NYSDOH standards and in addition, in 2008, it also installed an
indoor air vapor mitigation system (that continues to operate). At
this time Central Hudson does not have sufficient information to estimate the
need for additional remediation or potential remediation
costs. 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. Central Hudson cannot predict the
outcome of this matter.
|
Ø
|
Newburgh Consolidated Iron
Works
|
In 2001,
Central Hudson was served by USEPA with a Request For Information pursuant to
the Comprehensive Environmental Response, Compensation and Liability Act
(“CERCLA”) regarding shipments of scrap or waste materials that Central Hudson
may have made to Consolidated Iron and Metal Co., Inc. (“Consolidated Iron”), a
Superfund site located in Newburgh, New York. In December 2008 Central
Hudson entered into a settlement agreement with the Joint Defense Group (“JDG”)
and joined as a party to the consent decree. The consent decree has now been
signed and entered by the court. Central Hudson does not anticipate any
further activity on this matter.
Since
1987, Central Hudson, along with many other parties, has been joined as a
defendant or third-party defendant in 3,319 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 two formerly owned electric generating plants; the
Roseton Electric Generating Plant and the Danskammer Point Steam Electric
Generating Station.
As of
December 31, 2009, of the 3,319 asbestos cases brought against Central Hudson,
1,188 remain pending. Of the cases no longer pending against Central
Hudson, 1,979 have been dismissed or discontinued without payment by Central
Hudson, and Central Hudson has settled 152 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 the costs
which may be incurred in connection with the remaining lawsuits will not have a
material adverse effect on the financial position, results of operations or cash
flows of either CH Energy Group or Central Hudson.
CHEC
During
the twelve months ended December 31, 2009, Griffith spent $0.1 million on
remediation efforts in Maryland, Virginia and Connecticut.
Griffith
has a reserve for environmental remediation which is $3.5 million as of December
31, 2009, of which $0.4 million is expected to be spent in the next twelve
months.
As part
of the divestiture of operations in certain geographic locations, Griffith
provided an indemnification of $5.7 million to the purchaser for any claims,
losses, expenses, or legal proceedings arising out of or resulting from any
inaccuracy of representation, non-fulfillment of covenants, breach of warranty,
environmental remediation, certain expenses incurred for the repair of buildings
and vehicles, or events prior to the date of divestiture. Of this
indemnification, the Company has reserved $2.6 million specifically for
environmental remediation costs. Excluding environmental remediation
costs, the indemnification is subject to a $0.8 million
deductible. Such claims could include, but not be limited to, certain
truck repairs incurred up to 60 days from the date of divestiture, certain
building repairs, and product warranty claims. Management believes
that no payment will be required as a result of the indemnification beyond the
environmental reserve of $2.6 million.
Other
Matters
Central
Hudson and Griffith are involved in various other legal and administrative
proceedings incidental to their businesses, which are in various
stages. While these matters collectively could involve substantial
amounts, it is the opinion of Management that their ultimate resolution will not
have a material adverse effect on either of CH Energy Group’s or the individual
segment’s financial positions, results of operations, or cash
flows.
NOTE 13 -
SEGMENTS AND RELATED INFORMATION
CH Energy
Group's reportable operating segments are the regulated electric utility
business and regulated natural gas utility business of Central Hudson and the
unregulated fuel distribution business of Griffith. Other activities
of CH Energy Group, which do not constitute a business segment include the
investment, financing, and business development activities of CH Energy Group
and the renewable energy and investment activities of CHEC, including its
ownership interests in ethanol, wind, landfill gas and biomass energy projects
and are reported under the heading “Other Businesses and
Investments.”
Central
Hudson purchases, sells at wholesale, and distributes electricity and natural
gas at retail in New York State’s Mid-Hudson River Valley. 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 certain outlying and intervening
territories. Central Hudson also generates a small portion of its
electricity requirements.
Griffith
is engaged in fuel distribution including heating oil, gasoline, diesel fuel,
kerosene, and propane, and the installation and maintenance of heating,
ventilating, and air conditioning equipment in Virginia, West Virginia,
Maryland, Delaware, Pennsylvania, and Washington, D.C. Management
regularly reviews Griffith’s operating results as a standalone component of CH
Energy Group and assesses its performance as a basis for allocating
resources.
Certain
additional information regarding these segments is set forth in the following
tables. General corporate expenses, Central Hudson property common to
both electric and natural gas segments, and the depreciation of Central Hudson’s
common property have been allocated in accordance with practices established for
regulatory purposes.
Central
Hudson’s and Griffith’s operations are seasonal in nature and
weather-sensitive. Demand for electricity typically peaks during the
summer, while demand for natural gas and heating oil typically peaks during the
winter.
CH
Energy Group Segment Disclosure
(In
Thousands)
|
|
Year
Ended December 31, 2009
|
|
|
|
Segments
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Central
Hudson
|
|
|
|
|
|
Businesses
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
and
|
|
|
|
|
|
|
|
|
Electric
|
|
|
Gas
|
|
|
Griffith
|
|
|
Investments
|
|
|
Eliminations
|
|
|
Total
|
|
Revenues
from external customers
|
|
$ |
536,170 |
|
|
$ |
174,137 |
|
|
$ |
211,229 |
|
|
$ |
10,053 |
|
|
$ |
- |
|
|
$ |
931,589 |
|
Intersegment
revenues
|
|
|
12 |
|
|
|
308 |
|
|
|
- |
|
|
|
- |
|
|
|
(320 |
) |
|
|
- |
|
Total
revenues
|
|
|
536,182 |
|
|
|
174,445 |
|
|
|
211,229 |
|
|
|
10,053 |
|
|
|
(320 |
) |
|
|
931,589 |
|
Depreciation
and amortization
|
|
|
25,269 |
|
|
|
6,825 |
|
|
|
4,488 |
|
|
|
1,121 |
|
|
|
- |
|
|
|
37,703 |
|
Operating
income
|
|
|
60,289 |
|
|
|
16,049 |
|
|
|
5,587 |
|
|
|
(1,526 |
) |
|
|
- |
|
|
|
80,399 |
|
Interest
and investment income
|
|
|
3,303 |
|
|
|
1,727 |
|
|
|
15 |
|
|
|
4,996 |
|
|
|
(4,117 |
) |
(1) |
|
5,924 |
|
Interest
charges
|
|
|
19,806 |
|
|
|
5,079 |
|
|
|
2,405 |
|
|
|
2,623 |
|
|
|
(4,117 |
) |
(1) |
|
25,796 |
|
Earnings
before income taxes
|
|
|
41,703 |
|
|
|
12,215 |
|
|
|
3,456 |
|
|
|
(2,555 |
) |
|
|
- |
|
|
|
54,819 |
|
Income
tax expense
|
|
|
15,743 |
|
|
|
5,399 |
|
|
|
1,332 |
|
|
|
(2,082 |
) |
|
|
- |
|
|
|
20,392 |
|
Net
income attributable to CH Energy Group
|
|
|
25,217 |
|
|
|
6,589 |
|
|
|
11,975 |
|
(3) |
|
(297 |
) |
|
|
- |
|
|
|
43,484 |
|
Segment
assets at December 31
|
|
|
1,132,341 |
|
|
|
353,259 |
|
|
|
103,915 |
|
|
|
109,930 |
|
|
|
(1,562 |
) |
(2) |
|
1,697,883 |
|
Goodwill
|
|
|
- |
|
|
|
- |
|
|
|
35,651 |
|
|
|
- |
|
|
|
- |
|
|
|
35,651 |
|
Capital
expenditures
|
|
|
78,585 |
|
|
|
18,255 |
|
|
|
1,920 |
|
|
|
5,192 |
|
|
|
- |
|
|
|
103,952 |
|
(1)
|
This
represents the elimination of inter-company interest income (expense)
generated from temporary lending activities between CH Energy Group (the
holding company), and its subsidiaries (CHEC and
Griffith).
|
(2)
|
Includes
non-controlling owner's interest of $1,385 related to
Lyonsdale.
|
(3)
|
Includes
income from discontinued operations of
$9,777.
|
CH
Energy Group Segment Disclosure
(In
Thousands)
|
|
Year
Ended December 31, 2008
|
|
|
|
Segments
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Central
Hudson
|
|
|
|
|
|
Businesses
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
and
|
|
|
|
|
|
|
|
|
Electric
|
|
|
Gas
|
|
|
Griffith
|
|
|
Investments
|
|
|
Eliminations
|
|
|
Total
|
|
Revenues
from external customers
|
|
$ |
608,161 |
|
|
$ |
189,546 |
|
|
$ |
330,204 |
|
|
$ |
11,290 |
|
|
$ |
- |
|
|
$ |
1,139,201 |
|
Intersegment
revenues
|
|
|
16 |
|
|
|
323 |
|
|
|
- |
|
|
|
- |
|
|
|
(339 |
) |
|
|
- |
|
Total
revenues
|
|
|
608,177 |
|
|
|
189,869 |
|
|
|
330,204 |
|
|
|
11,290 |
|
|
|
(339 |
) |
|
|
1,139,201 |
|
Depreciation
and amortization
|
|
|
23,592 |
|
|
|
6,220 |
|
|
|
4,609 |
|
|
|
837 |
|
|
|
- |
|
|
|
35,258 |
|
Operating
income
|
|
|
53,396 |
|
|
|
13,948 |
|
|
|
3,655 |
|
|
|
(47 |
) |
|
|
- |
|
|
|
70,952 |
|
Interest
and investment income
|
|
|
1,605 |
|
|
|
1,566 |
|
|
|
82 |
|
|
|
5,929 |
|
|
|
(4,515 |
) |
(1) |
|
4,667 |
|
Interest
charges
|
|
|
19,975 |
|
|
|
5,451 |
|
|
|
2,890 |
|
|
|
491 |
|
|
|
(4,515 |
) |
(1) |
|
24,292 |
|
Earnings
before income taxes
|
|
|
36,056 |
|
|
|
10,455 |
|
|
|
1,138 |
|
|
|
4,274 |
|
|
|
- |
|
|
|
51,923 |
|
Income
tax expense
|
|
|
14,334 |
|
|
|
4,939 |
|
|
|
515 |
|
|
|
(474 |
) |
|
|
- |
|
|
|
19,314 |
|
Net
income attributable to CH Energy Group
|
|
|
20,977 |
|
|
|
5,291 |
|
|
|
4,169 |
|
(3) |
|
4,644 |
|
|
|
- |
|
|
|
35,081 |
|
Segment
assets at December 31
|
|
|
1,106,505 |
|
|
|
385,691 |
|
|
|
190,464 |
|
|
|
47,494 |
|
|
|
29 |
|
(2) |
|
1,730,183 |
|
Goodwill
|
|
|
- |
|
|
|
- |
|
|
|
67,455 |
|
|
|
- |
|
|
|
- |
|
|
|
67,455 |
|
Capital
expenditures
|
|
|
58,827 |
|
|
|
19,503 |
|
|
|
2,706 |
|
|
|
2,562 |
|
|
|
- |
|
|
|
83,598 |
|
(1)
|
This
represents the elimination of inter-company interest income (expense)
generated from temporary lending activities between CH Energy Group (the
holding company), and its subsidiaries (CHEC and
Griffith).
|
(2)
|
Includes
non-controlling owner's interest of $1,449 related to
Lyonsdale.
|
(3)
|
Includes
income from discontinued operations of
$3,449.
|
CH
Energy Group Segment Disclosure
(In
Thousands)
|
|
Year
Ended December 31, 2007
|
|
|
|
Segments
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
Central
Hudson
|
|
|
|
|
|
Businesses
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
and
|
|
|
|
|
|
|
|
|
Electric
|
|
|
Gas
|
|
|
Griffith
|
|
|
Investments
|
|
|
Eliminations
|
|
|
Total
|
|
Revenues
from external customers
|
|
$ |
616,839 |
|
|
$ |
165,449 |
|
|
$ |
287,763 |
|
|
$ |
8,716 |
|
|
$ |
- |
|
|
$ |
1,078,767 |
|
Intersegment
revenues
|
|
|
15 |
|
|
|
301 |
|
|
|
- |
|
|
|
- |
|
|
|
(316 |
) |
|
|
- |
|
Total
revenues
|
|
|
616,854 |
|
|
|
165,750 |
|
|
|
287,763 |
|
|
|
8,716 |
|
|
|
(316 |
) |
|
|
1,078,767 |
|
Depreciation
and amortization
|
|
|
22,251 |
|
|
|
6,148 |
|
|
|
4,694 |
|
|
|
809 |
|
|
|
- |
|
|
|
33,902 |
|
Operating
income
|
|
|
57,135 |
|
|
|
14,271 |
|
|
|
5,065 |
|
|
|
(812 |
) |
|
|
- |
|
|
|
75,659 |
|
Interest
and investment income
|
|
|
3,770 |
|
|
|
1,973 |
|
|
|
115 |
|
|
|
7,082 |
|
|
|
(4,534 |
) |
(1) |
|
8,406 |
|
Interest
charges
|
|
|
17,535 |
|
|
|
5,372 |
|
|
|
2,901 |
|
|
|
443 |
|
|
|
(4,534 |
) |
(1) |
|
21,717 |
|
Earnings
before income taxes
|
|
|
42,898 |
|
|
|
10,864 |
|
|
|
2,752 |
|
|
|
6,450 |
|
|
|
- |
|
|
|
62,964 |
|
Income
tax expense
|
|
|
16,018 |
|
|
|
4,308 |
|
|
|
1,067 |
|
|
|
(433 |
) |
|
|
- |
|
|
|
20,960 |
|
Net
income attributable to CH Energy Group
|
|
|
26,141 |
|
|
|
6,325 |
|
|
|
3,166 |
|
(3) |
|
7,004 |
|
|
|
- |
|
|
|
42,636 |
|
Segment
assets at December 31
|
|
|
926,223 |
|
|
|
326,471 |
|
|
|
197,425 |
|
|
|
44,655 |
|
|
|
(26 |
) |
(2) |
|
1,494,748 |
|
Goodwill
|
|
|
- |
|
|
|
- |
|
|
|
63,433 |
|
|
|
- |
|
|
|
- |
|
|
|
63,433 |
|
Capital
expenditures
|
|
|
65,548 |
|
|
|
17,215 |
|
|
|
2,253 |
|
|
|
1,060 |
|
|
|
- |
|
|
|
86,076 |
|
(1)
|
This
represents the elimination of inter-company interest income (expense)
generated from temporary lending activities between CH Energy Group (the
holding company), and its subsidiaries (CHEC and
Griffith).
|
(2)
|
Includes
non-controlling owner's interest of $1,345 related to
Lyonsdale.
|
(3)
|
Includes
income from discontinued operations of
$2,053.
|
Central
Hudson Segment Disclosure
(In
Thousands)
|
|
Year
Ended December 31, 2009
|
|
|
|
Electric
|
|
|
Natural
Gas
|
|
|
Eliminations
|
|
|
Total
|
|
Revenues
from external customers
|
|
$ |
536,170 |
|
|
$ |
174,137 |
|
|
$ |
- |
|
|
$ |
710,307 |
|
Intersegment
revenues
|
|
|
12 |
|
|
|
308 |
|
|
|
(320 |
) |
|
|
- |
|
Total
revenues
|
|
|
536,182 |
|
|
|
174,445 |
|
|
|
(320 |
) |
|
|
710,307 |
|
Depreciation
and amortization
|
|
|
25,269 |
|
|
|
6,825 |
|
|
|
- |
|
|
|
32,094 |
|
Operating
income
|
|
|
60,289 |
|
|
|
16,049 |
|
|
|
- |
|
|
|
76,338 |
|
Interest
and investment income
|
|
|
3,303 |
|
|
|
1,727 |
|
|
|
- |
|
|
|
5,030 |
|
Interest
charges
|
|
|
19,806 |
|
|
|
5,079 |
|
|
|
- |
|
|
|
24,885 |
|
Income
tax expense
|
|
|
15,743 |
|
|
|
5,399 |
|
|
|
- |
|
|
|
21,142 |
|
Income
available for common stock
|
|
|
25,217 |
|
|
|
6,589 |
|
|
|
- |
|
|
|
31,806 |
|
Segment
assets at December 31
|
|
|
1,132,341 |
|
|
|
353,259 |
|
|
|
- |
|
|
|
1,485,600 |
|
Capital
expenditures
|
|
|
78,585 |
|
|
|
18,255 |
|
|
|
- |
|
|
|
96,840 |
|
Central
Hudson Segment Disclosure
(In
Thousands)
|
|
Year
Ended December 31, 2008
|
|
|
|
Electric
|
|
|
Natural
Gas
|
|
|
Eliminations
|
|
|
Total
|
|
Revenues
from external customers
|
|
$ |
608,161 |
|
|
$ |
189,546 |
|
|
$ |
- |
|
|
$ |
797,707 |
|
Intersegment
revenues
|
|
|
16 |
|
|
|
323 |
|
|
|
(339 |
) |
|
|
- |
|
Total
revenues
|
|
|
608,177 |
|
|
|
189,869 |
|
|
|
(339 |
) |
|
|
797,707 |
|
Depreciation
and amortization
|
|
|
23,592 |
|
|
|
6,220 |
|
|
|
- |
|
|
|
29,812 |
|
Operating
income
|
|
|
53,396 |
|
|
|
13,948 |
|
|
|
- |
|
|
|
67,344 |
|
Interest
and investment income
|
|
|
1,605 |
|
|
|
1,566 |
|
|
|
- |
|
|
|
3,171 |
|
Interest
charges
|
|
|
19,975 |
|
|
|
5,451 |
|
|
|
- |
|
|
|
25,426 |
|
Income
tax expense
|
|
|
14,334 |
|
|
|
4,939 |
|
|
|
- |
|
|
|
19,273 |
|
Income
available for common stock
|
|
|
20,977 |
|
|
|
5,291 |
|
|
|
- |
|
|
|
26,268 |
|
Segment
assets at December 31
|
|
|
1,106,505 |
|
|
|
385,691 |
|
|
|
- |
|
|
|
1,492,196 |
|
Capital
expenditures
|
|
|
58,827 |
|
|
|
19,503 |
|
|
|
- |
|
|
|
78,330 |
|
Central
Hudson Segment Disclosure
(In
Thousands)
|
|
Year
Ended December 31, 2007
|
|
|
|
Electric
|
|
|
Natural
Gas
|
|
|
Eliminations
|
|
|
Total
|
|
Revenues
from external customers
|
|
$ |
616,839 |
|
|
$ |
165,449 |
|
|
$ |
- |
|
|
$ |
782,288 |
|
Intersegment
revenues
|
|
|
15 |
|
|
|
301 |
|
|
|
(316 |
) |
|
|
- |
|
Total
revenues
|
|
|
616,854 |
|
|
|
165,750 |
|
|
|
(316 |
) |
|
|
782,288 |
|
Depreciation
and amortization
|
|
|
22,251 |
|
|
|
6,148 |
|
|
|
- |
|
|
|
28,399 |
|
Operating
income
|
|
|
57,135 |
|
|
|
14,271 |
|
|
|
- |
|
|
|
71,406 |
|
Interest
and investment income
|
|
|
3,770 |
|
|
|
1,973 |
|
|
|
- |
|
|
|
5,743 |
|
Interest
charges
|
|
|
17,535 |
|
|
|
5,372 |
|
|
|
- |
|
|
|
22,907 |
|
Income
tax expense
|
|
|
16,018 |
|
|
|
4,308 |
|
|
|
- |
|
|
|
20,326 |
|
Income
available for common stock
|
|
|
26,141 |
|
|
|
6,325 |
|
|
|
- |
|
|
|
32,466 |
|
Segment
assets at December 31
|
|
|
926,223 |
|
|
|
326,471 |
|
|
|
- |
|
|
|
1,252,694 |
|
Capital
expenditures
|
|
|
65,548 |
|
|
|
17,215 |
|
|
|
- |
|
|
|
82,763 |
|
|
ACCOUNTING FOR
DERIVATIVE INSTRUMENTS AND HEDGING
ACTIVITIES
|
Purpose
of Derivatives
CH Energy
Group and its subsidiaries enter into derivative contracts in conjunction with
the Company’s energy risk management program to hedge certain risk exposure
related to its business operations. The derivative contracts are
typically either exchange-traded or over-the-counter (“OTC”)
instruments. The primary risks the Company seeks to manage by using
derivative instruments are interest rate risk and commodity price
risk. Central Hudson uses derivative contracts to hedge exposure to
volatility in the prices of natural gas and electricity and to hedge exposure to
volatility in interest rates for its variable rate long-term
debt. Griffith uses derivative instruments to hedge volatility in the
price of heating oil purchased for delivery to its customers. All
hedging transactions are associated with commodity purchases and are not used
for speculative purposes. CH Energy Group and its subsidiaries cash
flow hedging programs are as follows:
|
·
|
Interest
rate caps are used to hedge interest rate risks and to improve the
matching of assets and liabilities. An interest rate cap is an
interest rate option agreement in which payments are made by the seller of
the option when the reference rate exceeds the specified strike rate (or
the set rate at which the option contract can be
exercised). The purpose of these agreements is to hedge against
rising interest rates while still having the ability to take advantage of
falling interest rates by putting a “cap” on the interest rate Central
Hudson pays on debt for which such caps are
purchased.
|
|
·
|
Natural
gas futures are used to hedge natural gas purchases. A natural
gas futures contract is a standardized contract to buy or sell a specified
commodity (natural gas) of standardized quality at a certain date in the
future, at a market determined price (the futures
price). Central Hudson’s reason for purchasing these contracts
is to hedge against the risk of price fluctuations related to natural gas
and to reduce the impact of volatility in the commodity markets on its
customers.
|
|
·
|
Natural
gas swaps and contracts for differences (electricity swaps) are used to
hedge natural gas and electricity purchases. A swap contract or
a contract for difference is the exchange of two payment streams between
two counterparties where the cash flows are dependant on the price of the
underlying commodity. One party’s payment stream is based on a
fixed price and the other party’s payment stream is based on a floating
(market) price. The purpose of these types of contracts is to
hedge against the risk of price fluctuations related to purchasing natural
gas and electricity supplies for Central Hudson’s customers. In
an effort to moderate volatility by locking in prices, Central Hudson
always takes the fixed side of the transaction, agreeing to pay the
counterparty a fixed payment stream. In return, Central Hudson
receives payments based on the market price for the commodity
involved.
|
At
December 31, 2009, Central Hudson had open derivative contracts to hedge natural
gas prices during January 2010 - March 2010, covering approximately 40.4% of
Central Hudson's projected total natural gas supply requirements during this
period. In 2009, derivative transactions were used to economically
hedge 37.4% of Central Hudson’s total natural gas supply requirements as
compared to 34.6% in 2008.
Additionally,
Central Hudson had open derivative contracts at December 31, 2009 to hedge the
price of approximately 20.9%, 21.6% and 22.1% of its projected electricity
requirements in each of the years 2010, 2011, and 2012,
respectively. In 2009, Central Hudson economically hedged
approximately 24.8% of its total electricity supply requirements with OTC
derivative contracts as compared to 8.1% in 2008.
|
·
|
Option
contracts on heating oil are used to establish ceiling prices to limit
Griffith’s exposure to changes in heating oil prices for forecasted
heating oil supply requirements for capped price programs that are not
hedged by firm purchase commitments. An option contract is the
right, but not the obligation, to buy (for a call option) or sell (for a
put option) a specific amount of the given commodity, at a specified price
(the strike price) during a specified period of
time.
|
At
December 31, 2009, Griffith had open OTC call option positions covering
approximately 1.0% of its anticipated fuel oil supply requirements for the
period January 2010 – April 2010. The percentage of anticipated fuel
oil supply requirements that were hedged at December 31, 2008, for the period
January 2009 through June 2009 was 4.3%. In 2009, derivative instruments
were used to hedge 3.6% of total fuel oil requirements as compared to 5.2% in
2008.
|
·
|
Weather
derivative contracts are used to limit the effect on earnings of
significant variances in weather conditions from normal
patterns. Weather derivatives are financial instruments that
can be used as part of a risk management strategy to reduce risk
associated with adverse or unexpected weather conditions. The
difference from other derivatives is that the underlying asset
(rain/temperature/snow) has no direct value to price the weather
derivative.
|
Accounting
for Derivatives
Current
accounting guidance for derivative instruments and hedging activities (ASC 815)
requires that an entity recognize the fair value of all derivative instruments
as either assets or liabilities on the balance sheet with the corresponding
unrealized gains or losses recognized in earnings. The guidance notes
that the change in the fair value of the derivative is allocated, in accordance
with the hedge documentation, into three possible components: the “effective
portion,” the “ineffective portion,” and “the excluded
portion.” Changes in the ineffective and excluded portions are always
recognized immediately in earnings, regardless of the type of hedging
relationship. The guidance permits the deferral of the effective
portion of unrealized gains and losses on derivatives that are properly
designated as hedges.
Central
Hudson has been authorized to fully recover risk management costs as a component
for its natural gas and electricity cost adjustment charge
clauses. 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." The related gains and losses associated with Central
Hudson’s derivatives are included as part of Central Hudson's commodity cost
and/or price-reconciled in its natural gas and electricity cost adjustment
charge clauses, and are not designated as hedges.
Griffith
purchases call option contracts to establish ceiling prices to limit its
earnings cash flow exposure to changes in commodity prices for meeting its
heating oil supply requirements for capped price programs that are not hedged by
firm purchase commitments. The change in fair value of the options is
included in the cost of sales as the hedged transactions occur.
On
December 11, 2009, Griffith completed the sale of operations in certain
geographic locations, which serviced approximately 45,000
customers. On that date, Griffith held 38 call option contracts that
were purchased to mitigate the price risk on forecasted purchases of heating oil
relating to fixed cap price customers within the Northeast territory during the
2009-2010 heating season. Prior to this sale, all of Griffith’s call
option contracts were designated at inception and accounted for as cash flow
hedges. Griffith has removed the designation of the cash flow hedge on these 38
option contracts as the underlying transactions (i.e. the purchase of heating
oil for these customers) will no longer occur at Griffith and therefore Griffith
is no longer exposed to the price risk associated with these
transactions. The effective date of this de-designation is October 1,
2009 for those contracts entered into prior to that date. Any
contracts that were purchased on or after October 1, 2009, were designated at
inception as derivatives not accounted for as hedges. Current
accounting guidance specific to removing the designation of a hedge (ASC
815-30-40) requires that Griffith discontinue the hedge accounting treatment
prospectively for the 38 call options once it removes the designation of the
cash flow hedge and retain the net unrealized gain or loss associated with these
contracts in accumulated other comprehensive income until the contract
settles.
Additionally,
on December 11, 2009, Griffith entered into a new derivative financial
instrument with the purchaser of operations in select geographic
locations. Griffith agreed to pay the counterparty an amount equal to
the economic benefit realized upon the settlement of the 38 call option
contracts discussed above and recorded a liability on December 11, 2009, equal
to the fair value of these underlying contracts. This liability will
be recorded at fair value each reporting period and the change in fair value
will be recognized in the income statement. This change in fair value
of the liability instrument will offset the change in the fair value of the 38
underlying option contracts in an asset position, resulting in no net impact on
Griffith’s earnings.
As of
December 31, 2009, in addition to the 38 contracts noted above, Griffith held 5
other call option contracts that were initially designated and accounted for as
cash flow hedges. Effective October 1, 2009, Griffith has also
removed the designation of the cash flow hedge on these remaining 5 option
contracts, as it is Management’s position that it is no longer cost effective to
perform on-going effectiveness tests and documentation to comply with current
accounting guidance for derivative instruments and hedging activities (ASC 815),
based on the immateriality of these remaining contracts. In
accordance with current accounting guidance specific to removing the designation
of a hedge (ASC 815-30-40), Griffith will prospectively discontinue the hedge
accounting treatment for these 5 call options and the net unrealized gain or
loss associated with these contracts will remain in accumulated other
comprehensive income until the contract settles.
Derivative
Risks
The basic
types of risks associated with derivatives are market risk (that the value of
the derivative will be adversely impacted by changes in the market, primarily
the change in interest and exchange rates) and credit risk (that the
counterparty will not perform according to the terms of the
contract). The market risk of the derivatives generally offset the
market risk associated with the hedged commodity. For more
information regarding considerations of credit risk in determining the fair
value of derivative contracts, see Note 15 – “Fair Value
Measurements.”
The
majority of Central Hudson and Griffith’s derivative instruments contain
provisions that require the company to maintain specified issuer credit ratings
and financial strength ratings. Should the company’s ratings fall
below these specified levels, it would be in violation of the provisions, and
the derivatives’ counterparties could terminate the contracts and request
immediate payment.
To help
limit the credit exposure of their derivatives, Central Hudson and Griffith
enter into master netting agreements with counterparties whereby contracts in a
gain position can be offset against contracts in a loss
position. Central Hudson and Griffith both hold contracts for
derivative instruments under master netting agreements. Of the
fifteen total agreements held by both companies, eleven contain credit-risk
related contingent features. As of December 31, 2009, there were 37
open derivative contracts under these eleven master netting agreements
containing credit-risk related contingent features. The circumstances
that could trigger these features, the aggregate fair value of the derivative
contracts that contain contingent features and the amount that would be required
to settle these instruments on December 31, 2009 if the contingent features were
triggered, are described below.
Contingent
Contracts
(Dollars
In Thousands)
|
|
As
of December 31, 2009
|
|
Triggering
Event
|
|
#
of Contracts Containing the Triggering Feature
|
|
|
Gross
Fair Value of Contract
|
|
|
Cost
to Settle if Contingent Feature is Triggered
(net
of collateral)
|
|
|
|
|
|
|
|
|
|
|
|
Central Hudson:
|
|
|
|
|
|
|
|
|
|
Change
in Ownership (CHEG ownership of CHG&E falls below 51%)
|
|
|
6 |
|
|
$ |
(381 |
) |
|
$ |
(381 |
) |
Credit
Rating Downgrade (to below BBB-)
|
|
|
2 |
|
|
|
1 |
|
|
|
1 |
|
Adequate
Assurance(1)
|
|
|
1 |
|
|
|
(3,069 |
) |
|
|
(3,069 |
) |
Total
Central Hudson
|
|
|
9 |
|
|
|
(3,449 |
) |
|
|
(3,449 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Griffith:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in Ownership (CHEG ownership of CHEC falls below 51%)
|
|
|
10 |
|
|
|
172 |
|
|
|
172 |
|
Adequate
Assurance(1)
|
|
|
18 |
|
|
|
176 |
|
|
|
176 |
|
Total
Griffith
|
|
|
28 |
|
|
|
348 |
|
|
|
348 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
CH Energy Group
|
|
|
37 |
|
|
$ |
(3,101 |
) |
|
$ |
(3,101 |
) |
(1)
|
If
the counterparty has reasonable grounds to believe CHG&E's or
Griffith's creditworthiness or performance has become unsatisfactory, it
can request collateral in an amount determined by the counterparty, not to
exceed the amount required to settle the
contract.
|
CH Energy
Group has elected gross presentation for its derivative contracts under master
netting agreements. On December 31, 2009, neither Central Hudson nor
Griffith had collateral posted against the fair value amount of derivatives
under any of these agreements. If collateral were posted, CH Energy
Group’s policy is to also report the collateral positions on a gross
basis.
The fair
value of CH Energy Group’s and Central Hudson’s derivative instruments and their
location in the respective Balance Sheets are described below, followed by a
description of their effect on the respective Statements of
Income. For additional information regarding Central Hudson’s
physical hedges, see the discussion following the caption “Electricity Purchase
Commitments” in Note 12 - “Commitments and Contingencies.” For
additional information regarding the fair value of Central Hudson’s and
Griffith’s outstanding derivative contracts, see Note 15 – “Fair Value
Measurements.”
Gross
Fair Value of Derivative Instruments
(In
Thousands)
|
|
December
31,
2009
|
|
|
December
31,
2008
|
|
Derivatives in an Asset
Position:
|
|
|
|
|
|
|
Not
Designated as Hedging Instruments:(1)
|
|
|
|
|
|
|
Central
Hudson electricity swap contracts
|
|
$ |
314 |
|
|
$ |
- |
|
Central
Hudson natural gas swap contracts
|
|
|
79 |
|
|
|
- |
|
Central
Hudson interest rate cap contract
|
|
|
- |
|
|
|
- |
|
Total
Central Hudson Derivatives in an Asset Position
|
|
|
393 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Griffith
heating oil call option contracts
|
|
|
348 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Total
CH Energy Group Derivatives in Asset Position
|
|
$ |
741 |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
Derivatives in a Liability
Position:
|
|
|
|
|
|
|
|
|
Not
Designated as Hedging Instruments:(1)
|
|
|
|
|
|
|
|
|
Central
Hudson electricity swap contracts
|
|
$ |
(12,297 |
) |
|
$ |
(5,538 |
) |
Central
Hudson natural gas swap contracts
|
|
|
(1,256 |
) |
|
|
(10,221 |
) |
Total
Central Hudson Derivatives in a Liability Position
|
|
|
(13,553 |
) |
|
|
(15,759 |
) |
|
|
|
|
|
|
|
|
|
Griffith
other derivative financial instrument
|
|
|
(284 |
) |
|
|
- |
|
|
|
|
|
|
|
|
|
|
Total
CH Energy Group Derivatives in Liability Position
|
|
$ |
(13,837 |
) |
|
$ |
(15,759 |
) |
(1)
|
See
discussion following tables for additional information regarding
regulatory treatment of gains and losses on Central Hudson's derivative
contracts.
|
The
Effect of Derivative Instruments on the Statements of Income
(In
Thousands)
CH Energy
Group
Designated
as Hedging Instruments:
Cash
Flow Hedge
Derivative
Instruments
|
|
Amount
of Gain/(Loss) Recognized in OCI on Derivative
|
|
|
Amount
of Gain/(Loss) Reclassified from Accumulated OCI into
Income
|
|
Location
of Gain/(Loss) Reclassified from Accumulated OCI into Income
|
|
|
Year
Ended
|
|
|
Year
Ended
|
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Griffith
heating oil call option contracts
|
|
$ |
(10 |
) |
|
$ |
477 |
|
|
$ |
44 |
|
|
$ |
(1,208 |
) |
Purchased
petroleum
|
Total
|
|
$ |
(10 |
) |
|
$ |
477 |
|
|
$ |
44 |
|
|
$ |
(1,208 |
) |
|
For the
years ended December 31, 2009 and 2008, the amount of loss recognized in income
for Griffith heating oil call option contracts designated as hedging instruments
was $0.3 million and $0.7 million, respectively. The loss
reclassified from Accumulated OCI into income for Griffith's heating oil call
option contracts for all periods presented is located in purchased
petroleum.
Not
Designated as Hedging Instruments:
|
|
Amount
of Gain/(Loss) Recognized as Increase/(Decrease) in the Income
Statement
|
|
Location
of Gain/(Loss)
|
|
|
Year
Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Central
Hudson electricity swap
contracts
|
|
$ |
(26,018 |
) |
|
$ |
(6,553 |
) |
Regulatory
asset(1)
|
Central
Hudson natural gas
swap contracts
|
|
|
(13,758 |
) |
|
|
(6,500 |
) |
Regulatory
asset(1)
|
Central
Hudson interest rate
cap contract
|
|
|
- |
|
|
|
- |
|
Regulatory
asset(1)
|
Griffith
heating oil call option
contracts
|
|
|
54 |
|
|
|
- |
|
Purchased
petroleum
|
Griffith
other derivative financial
instrument
|
|
|
(73 |
) |
|
|
- |
|
Purchased
petroleum
|
Total
|
|
$ |
(39,795 |
) |
|
$ |
(13,053 |
) |
|
Central
Hudson
Designated
as Hedging Instruments:
None
Not
Designated as Hedging Instruments:
|
Amount
of Gain/(Loss) Recognized as Increase/(Decrease) in Purchased Electric and
Purchased Natural Gas
|
|
Location
of Gain/(Loss)
|
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
2008
|
|
|
Electricity
swap contracts
|
|
$ |
(26,018 |
) |
|
$ |
(6,553 |
) |
Regulatory
asset(1)
|
Natural
gas swap contracts
|
|
|
(13,758 |
) |
|
|
(6,500 |
) |
Regulatory
asset(1)
|
Interest
rate cap contract
|
|
|
- |
|
|
|
- |
|
Regulatory
asset(1)
|
Total
|
|
$ |
(39,776 |
) |
|
$ |
(13,053 |
) |
|
(1)
|
Realized
gains and losses on Central Hudson’s derivative instruments are conveyed
to or recovered from customers through PSC authorized deferral accounting
mechanisms, with an offset in revenue and on the balance sheet, and no
impact on results of
operations.
|
Central
Hudson recorded actual net losses of $39.8 million on such hedging activities
for the year ended December 31, 2009, as compared to net losses of $13.1 million
in the same period in 2008.
In the
years ended December 31, 2009 and 2008, Griffith’s call options were effective
with immaterial gains or losses from ineffectiveness. The assessment
of hedge effectiveness for these hedges excludes the change in the fair value of
the premium paid for these derivative instruments. The total fair
value of open derivative instruments at December 31, 2009 was approximately $0.1
million. The total fair value at December 31, 2008 was less than $0.1
million. These amounts were recorded in each period as part of the
cost or price of the related commodity transactions. The fair values
of call options are determined based on the market value of the underlying
commodity. The total net loss including premium expense was $0.3
million in the year ended December 31, 2009. Unrealized losses
expected to be reclassified into earnings over the next twelve months are not
material. A total net gain including premium expense of $0.7 million
was recorded in the year ended December 31, 2008.
In
addition to the above, Griffith uses weather derivative contracts to hedge the
effect on earnings of significant variances in weather conditions from normal
patterns, if such contracts can be obtained on reasonable
terms. Weather derivative contracts are accounted for in accordance
with guidance specific to accounting for weather derivatives (ASC
815-45). In the year ended December 31, 2009, Griffith made a
settlement payment of $0.2 million to a counterparty. In the year
ended December 31, 2008, Griffith did not make or receive settlement payments to
or from counterparties.
Assets
and Liabilities Recorded at Fair Value
Current
accounting guidance related to fair value measurements (ASC 820) establishes a
fair value hierarchy to prioritize the inputs used in valuation techniques based
on observable and unobservable data, but not the valuation techniques
themselves. Observable inputs are inputs that reflect the assumptions
market participants would use in pricing the asset or
liability. Unobservable inputs are inputs that reflect the reporting
entity’s own assumptions about the assumptions market participants would use in
pricing an asset or a liability. Classification of inputs is
determined based on the lowest level input that is significant to the overall
valuation. The fair value hierarchy prioritizes the inputs to
valuation techniques into the three categories described below:
|
·
|
Level 1
Inputs: Quoted prices (unadjusted) in active markets for
identical assets or liabilities.
|
|
·
|
Level 2
Inputs: Directly or indirectly observable (market-based)
information. This includes quoted prices for similar assets or
liabilities in active markets and quoted prices for identical or similar
assets or liabilities in markets that are not
active.
|
|
·
|
Level 3
Inputs: Unobservable inputs for the asset or liability
for which there is either no market data, or for which asset and liability
values are not correlated with market
value.
|
On
December 31, 2009, CH Energy Group reported one major category of assets and
liabilities at fair value; derivative contracts. Derivative contracts
are measured on a recurring basis. The fair value of CH Energy
Group's reportable assets and liabilities at December 31, 2009 and December 31,
2008 by category and hierarchy level follows (In Thousands):
Asset
or Liability Category
|
|
Fair
Value
|
|
|
Quoted
Prices in Active Markets for Identical Assets (Level 1)
|
|
|
Significant
Other Observable Inputs (Level 2)
|
|
|
Significant
Unobservable Inputs
(Level
3)
|
|
As
of December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
Hudson - electric
|
|
$ |
314 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
314 |
|
Central
Hudson - natural gas
|
|
|
79 |
|
|
|
79 |
|
|
|
- |
|
|
|
- |
|
Griffith
- heating oil
|
|
|
348 |
|
|
|
348 |
|
|
|
- |
|
|
|
- |
|
Central
Hudson - interest rate cap
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
Assets
|
|
$ |
741 |
|
|
$ |
427 |
|
|
$ |
- |
|
|
$ |
314 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
Hudson - electric
|
|
$ |
(12,297 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(12,297 |
) |
Central
Hudson - natural gas
|
|
|
(1,256 |
) |
|
|
(1,256 |
) |
|
|
- |
|
|
|
- |
|
Griffith
- other derivative financial instrument
|
|
|
(284 |
) |
|
|
- |
|
|
|
(284 |
) |
|
|
- |
|
Total
Liabilities
|
|
$ |
(13,837 |
) |
|
$ |
(1,256 |
) |
|
$ |
(284 |
) |
|
$ |
(12,297 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
Hudson - electric
|
|
$ |
(5,538 |
) |
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(5,538 |
) |
Central
Hudson - natural gas
|
|
|
(10,221 |
) |
|
|
(10,221 |
) |
|
|
- |
|
|
|
- |
|
Central
Hudson - interest rate cap
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
Liabilities
|
|
$ |
(15,759 |
) |
|
$ |
(10,221 |
) |
|
$ |
- |
|
|
$ |
(5,538 |
) |
The table
listed below provides a reconciliation of the beginning and ending net balances
for assets and liabilities measured at fair value and classified as Level 3 in
the fair value hierarchy (In Thousands):
|
|
Year
Ended
|
|
|
|
December
31, 2009
|
|
|
December
31, 2008
|
|
Balance
at Beginning of Period
|
|
$ |
(5,538 |
) |
|
$ |
77 |
|
Unrealized
gains/(losses)
|
|
|
(6,445 |
) |
|
|
(5,615 |
) |
Realized
losses
|
|
|
(26,018 |
) |
|
|
(6,553 |
) |
Purchases,
issuances, sales and settlements
|
|
|
26,018 |
|
|
|
6,553 |
|
Transfers
in and/or out of Level 3
|
|
|
- |
|
|
|
- |
|
Balance
at End of Period
|
|
$ |
(11,983 |
) |
|
$ |
(5,538 |
) |
|
|
|
|
|
|
|
|
|
The
amount of total gains or losses for the period included in earnings
attributable to the change in unrealized gains or losses relating to
derivatives still held at end of period
|
|
$ |
- |
|
|
$ |
- |
|
Derivative Contracts
- CH Energy Group’s derivative contracts are typically either exchange-traded or
over-the-counter (“OTC”) instruments. Exchange-traded and OTC
derivatives are valued based on listed market prices. On December 31,
2009, Central Hudson’s derivative contracts were comprised of swap contracts for
electricity and natural gas. Electric swap contracts are valued using
the New York Independent System Operator (“NYISO”) Swap Futures Closing Price as
posted on NYMEX Clearport and have been classified as Level 3 assets in the fair
value hierarchy, since Clearport uses unobservable inputs in its determination
of the futures closing price. Management believes these prices
approximate fair value for these instruments. Natural gas swap
contracts are valued using the NYMEX Natural Gas Futures Closing Price plus the
NYMEX Clearport Natural Gas Basis Swap Futures Closing Price for Tennessee,
Columbia and Dawn pipeline locations, and have been classified within Level 1 of
the fair value hierarchy. For natural gas swap contracts valued using
the NYMEX Natural Gas Futures Closing Price plus the NYMEX Clearport Natural Gas
Basis Swap Futures Closing Price, the latter component is
immaterial. As of December 31, 2009, 10 of Central Hudson’s open
derivative contracts were in a liability position totaling $13.6 million while 8
contracts were in an asset position totaling $0.4 million. The credit
risk considered in the fair value assessment of contracts in a liability
position is that associated with Central Hudson. Based on Central
Hudson’s current senior unsecured debt ratings by Moody’s, S&P and Fitch,
Management has concluded that the credit risk associated with Central Hudson’s
non-performance related to these instruments is not significant, and therefore,
no adjustment was made to the fair value. For those contracts in an
asset position, Management believes the credit risk of non-performance by
counterparties is not significant due to the fact that Central Hudson utilizes
multiple counterparties, all of which have ratings by Moody’s, S&P and
Fitch, which denote expectations of a low default risk. Additionally,
unrealized gains and losses on Central Hudson’s derivative contracts have no
impact on earnings. Therefore, no adjustment related to credit risk
has been made to the fair value of contracts in an asset
position. Realized gains and losses on Central Hudson’s derivative
instruments are conveyed to or recovered from customers through PSC authorized
deferral accounting mechanisms, with no material impact on cash flows, results
of operations or liquidity. Realized gains and losses on Central
Hudson’s Level 3 energy derivative assets are reported as part of purchased
electricity and fuel used in electric generation in Central Hudson’s
Consolidated Statement of Income as the corresponding amounts are either
recovered from or returned to customers through electric cost adjustment clauses
in revenues.
Griffith
has open call options purchased from two counterparties that were in an asset
position on December 31, 2009 totaling $0.3 million, while its other derivative
financial instrument was in a liability position totaling $0.3
million. Based on the credit ratings by Moody’s, S&P and Fitch of
the two counterparties, Management has concluded that the credit risk associated
with the counterparties’ non-performance on call options in an asset position is
not significant and no adjustment was made to fair value. Griffith’s
other derivative financial instrument resulted from a contractual obligation
entered into as a result of the sale of operations in select geographic
locations on December 11, 2009. The adjustment to fair value from
credit risk associated with Griffith’s non-performance on the derivative
financial instrument in a liability position is not material at December 31,
2009.
For
additional information about CH Energy Group’s derivative contracts, see Note 14
- “Accounting for Derivative Instruments and Hedging Activities.”
Other
Fair Value Disclosures
Financial
instruments are recorded at carrying value in the financial statements, however,
the fair value of these instruments is disclosed below in accordance with
current accounting guidance related to financial instruments (ASC
825).
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 Cash
Equivalents: 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 CH Energy
Group or 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.
Notes
Receivable: To estimate the fair value of debt instruments, CH
Energy Group performed a discounted cash flow analysis, specifically the Gross
Yield Method (“GYM”). The GYM discounts the contractual cash flows at
an estimated market or risk-adjusted yield. The cash flows from the
note receivable include the estimated quarterly payments based on the
contractual cash coupon payment and payment-in-kind (“PIK”)
feature. The estimated risk adjusted yield was based on the
following: (i) the total contractual coupon payment, (ii) the change in option
adjusted spreads (“OAS”) between the amendment date and year-end, and (iii) a
risk adjustment to account for the additional risk due to the PIK
feature. The estimated fair value of the note receivable was
calculated as the sum of the present value of all quarterly payments and the
final principal repayment. Based on the assumptions and methodologies
described, the fair value of the note receivable as of December 31, 2009 is
$10.3 million. The carrying amount of this note receivable as of
December 31, 2009 that is reported in the balance sheet is $10.2
million.
CH
Energy Group
Long-term Debt Maturities
and Fair Value
(Dollars
in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected
Maturity Date
|
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
Thereafter
|
|
Total
|
|
Fair
Value
|
|
Fixed
Rate:
|
|
$ |
24,000 |
|
|
$ |
941 |
|
|
$ |
37,007 |
|
|
$ |
31,076 |
|
|
$ |
41,650 |
|
|
$ |
237,373 |
|
|
$ |
372,047 |
|
|
$ |
385,527 |
|
Estimated
Effective Interest Rate
|
|
|
4.38 |
% |
|
|
6.86 |
% |
|
|
6.71 |
% |
|
|
6.92 |
% |
|
|
6.02 |
% |
|
|
5.94 |
% |
|
|
6.01 |
% |
|
|
|
|
Variable
Rate:
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
Estimated
Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.82 |
% |
|
|
0.82 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt Outstanding
|
|
|
|
|
|
$ |
487,897 |
|
|
$ |
501,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Effective Interest Rate
|
|
|
|
4.78 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected
Maturity Date
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
2012
|
|
2013
|
|
Thereafter
|
|
|
Total
|
|
|
Fair
Value
|
|
Fixed
Rate:
|
|
$ |
20,000 |
|
|
$ |
24,000 |
|
|
$ |
- |
|
|
$ |
36,000 |
|
|
$ |
30,000 |
|
|
$ |
208,044 |
|
|
$ |
318,044 |
|
|
$ |
296,086 |
|
Estimated
Effective Interest Rate
|
|
|
6.06 |
% |
|
|
4.38 |
% |
|
|
- |
% |
|
|
6.71 |
% |
|
|
6.92 |
% |
|
|
5.79 |
% |
|
|
5.91 |
% |
|
|
|
|
Variable
Rate:
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
Estimated
Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.10 |
% |
|
|
4.10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt Outstanding
|
|
|
|
|
|
$ |
433,894 |
|
|
$ |
411,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Effective Interest Rate
|
|
|
|
5.43 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected
Maturity Date
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
2011
|
|
2012
|
|
Thereafter
|
|
|
Total
|
|
|
Fair
Value
|
|
Fixed
Rate:
|
|
$ |
- |
|
|
$ |
20,000 |
|
|
$ |
24,000 |
|
|
$ |
- |
|
|
$ |
36,000 |
|
|
$ |
208,042 |
|
|
$ |
288,042 |
|
|
$ |
287,308 |
|
Estimated
Effective Interest Rate
|
|
|
- |
% |
|
|
6.07 |
% |
|
|
4.38 |
% |
|
|
- |
% |
|
|
6.64 |
% |
|
|
5.48 |
% |
|
|
6.30 |
% |
|
|
|
|
Variable
Rate:
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
Estimated
Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.69 |
% |
|
|
3.69 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt Outstanding
|
|
|
|
|
|
$ |
403,892 |
|
|
$ |
403,158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Effective Interest Rate
|
|
|
|
5.49 |
% |
|
|
|
|
Central
Hudson
|
|
Long-term Debt Maturities and Fair
Value
|
|
(Dollars
in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected
Maturity Date
|
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
Thereafter
|
|
Total
|
|
Fair
Value
|
|
Fixed
Rate:
|
|
$ |
24,000 |
|
|
$ |
- |
|
|
$ |
36,000 |
|
|
$ |
30,000 |
|
|
$ |
14,000 |
|
|
$ |
218,047 |
|
|
$ |
322,047 |
|
|
$ |
332,908 |
|
Estimated
Effective Interest Rate
|
|
|
4.38 |
% |
|
|
- |
% |
|
|
6.71 |
% |
|
|
6.93 |
% |
|
|
4.81 |
% |
|
|
5.86 |
% |
|
|
5.90 |
% |
|
|
|
|
Variable
Rate:
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
Estimated
Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.82 |
% |
|
|
0.82 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt Outstanding
|
|
|
$ |
437,897 |
|
|
$ |
448,758 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Effective Interest Rate
|
|
|
|
4.56 |
% |
|
|
|
|
December
31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected
Maturity Date
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
2012
|
|
2013
|
|
Thereafter
|
|
|
Total
|
|
|
Fair
Value
|
|
Fixed
Rate:
|
|
$ |
20,000 |
|
|
$ |
24,000 |
|
|
$ |
- |
|
|
$ |
36,000 |
|
|
$ |
30,000 |
|
|
$ |
208,044 |
|
|
$ |
318,044 |
|
|
$ |
296,086 |
|
Estimated
Effective Interest Rate
|
|
|
6.06 |
% |
|
|
4.38 |
% |
|
|
- |
% |
|
|
6.71 |
% |
|
|
6.92 |
% |
|
|
5.79 |
% |
|
|
5.91 |
% |
|
|
|
|
Variable
Rate:
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
Estimated
Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.10 |
% |
|
|
4.10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt Outstanding
|
|
|
$ |
433,894 |
|
|
$ |
411,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Effective Interest Rate
|
|
|
|
5.43 |
% |
|
|
|
|
December
31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected
Maturity Date
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
2011
|
|
2012
|
|
Thereafter
|
|
|
Total
|
|
|
Fair
Value
|
|
Fixed
Rate:
|
|
$ |
- |
|
|
$ |
20,000 |
|
|
$ |
24,000 |
|
|
$ |
- |
|
|
$ |
36,000 |
|
|
$ |
208,042 |
|
|
$ |
288,042 |
|
|
$ |
287,308 |
|
Estimated
Effective Interest Rate
|
|
|
- |
% |
|
|
6.07 |
% |
|
|
4.38 |
% |
|
|
- |
% |
|
|
6.64 |
% |
|
|
5.48 |
% |
|
|
6.30 |
% |
|
|
|
|
Variable
Rate:
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
|
$ |
115,850 |
|
Estimated
Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.69 |
% |
|
|
3.69 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Debt Outstanding
|
|
|
$ |
403,892 |
|
|
$ |
403,158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Effective Interest Rate
|
|
|
|
5.49 |
% |
|
|
|
|
CH Energy
Group has performed an evaluation of subsequent events through February 10,
2010, the date the financial statements were issued, and noted one event
occurring subsequent to December 31, 2009 and through the date of our evaluation
requiring disclosure. On January 22, 2010, Central Hudson contributed
$30 million to its Retirement Plan.
SELECTED QUARTERLY FINANCIAL DATA
(UNAUDITED) - CH ENERGY GROUP(1)
Selected
financial data for each quarterly period within 2009 and 2008 are presented
below (In Thousands, except per share data):
|
|
Operating
Revenues
|
|
|
Operating
Income
|
|
|
Net
Income/(Loss) from Continuing Operations
|
|
|
Net
Income/(Loss) from Discontinued Operations, Net of Tax
|
|
|
Earnings
Per Average Share of Common
Stock
(Diluted) Outstanding
|
|
Quarter
Ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31
|
|
$ |
322,096 |
|
|
$ |
36,900 |
|
|
$ |
18,955 |
|
|
$ |
4,376 |
|
|
$ |
1.46 |
|
June
30
|
|
|
178,619 |
|
|
|
4,064 |
|
|
|
(988 |
) |
|
|
(384 |
) |
|
|
(0.09 |
) |
September
30
|
|
|
195,947 |
|
|
|
17,651 |
|
|
|
6,633 |
|
|
|
(991 |
) |
|
|
0.34 |
|
December
31
|
|
|
234,927 |
|
|
|
21,784 |
|
|
|
9,827 |
|
|
|
6,850 |
|
|
|
1.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31
|
|
$ |
334,079 |
|
|
$ |
31,857 |
|
|
$ |
17,545 |
|
|
$ |
2,082 |
|
|
$ |
1.22 |
|
June
30
|
|
|
273,045 |
|
|
|
9,036 |
|
|
|
2,772 |
|
|
|
(882 |
) |
|
|
0.11 |
|
September
30
|
|
|
270,371 |
|
|
|
10,944 |
|
|
|
4,323 |
|
|
|
(1,127 |
) |
|
|
0.18 |
|
December
31
|
|
|
261,706 |
|
|
|
19,115 |
|
|
|
7,969 |
|
|
|
3,472 |
|
|
|
0.71 |
|
(1)
|
Amounts
differ from those previously reported as a result of the presentation of
discontinued operations due to meeting certain criteria requiring this
presentation in the fourth quarter
2009.
|
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) - CENTRAL
HUDSON
Selected
financial data for each quarterly period within 2009 and 2008 are presented
below (In Thousands):
|
|
Operating
Revenues
|
|
|
Operating
Income
|
|
|
Income
Available for Common Stock
|
|
Quarter
Ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
March
31
|
|
$ |
246,876 |
|
|
$ |
27,231 |
|
|
$ |
12,351 |
|
June
30
|
|
|
139,653 |
|
|
|
7,368 |
|
|
|
975 |
|
September
30
|
|
|
154,928 |
|
|
|
20,920 |
|
|
|
8,629 |
|
December
31
|
|
|
168,850 |
|
|
|
20,819 |
|
|
|
9,851 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31
|
|
$ |
220,033 |
|
|
$ |
24,710 |
|
|
$ |
11,505 |
|
June
30
|
|
|
190,119 |
|
|
|
11,680 |
|
|
|
3,949 |
|
September
30
|
|
|
200,774 |
|
|
|
15,691 |
|
|
|
5,885 |
|
December
31
|
|
|
186,781 |
|
|
|
15,263 |
|
|
|
4,929 |
|
SCHEDULE I - CONDENSED FINANCIAL INFORMATION
|
|
CH
ENERGY GROUP - (PARENT COMPANY ONLY)
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENT OF INCOME
|
|
(In
Thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Business
development costs
|
|
$ |
(2,012 |
) |
|
$ |
(1,589 |
) |
|
$ |
(1,451 |
) |
Interest
income
|
|
|
4,131 |
|
|
|
4,543 |
|
|
|
6,045 |
|
Other
income (deductions)
|
|
|
(2,380 |
) |
|
|
(185 |
) |
|
|
(93 |
) |
Income
before equity in earnings of subsidiaries and income taxes
|
|
|
(261 |
) |
|
|
2,769 |
|
|
|
4,501 |
|
Equity
in earnings of subsidiaries
|
|
|
44,298 |
|
|
|
32,859 |
|
|
|
38,275 |
|
Income
before income taxes
|
|
|
44,037 |
|
|
|
35,628 |
|
|
|
42,776 |
|
Income
taxes
|
|
|
553 |
|
|
|
547 |
|
|
|
140 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
$ |
43,484 |
|
|
$ |
35,081 |
|
|
$ |
42,636 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
15,775 |
|
|
|
15,768 |
|
|
|
15,762 |
|
Diluted
|
|
|
15,881 |
|
|
|
15,805 |
|
|
|
15,779 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
2.76 |
|
|
$ |
2.22 |
|
|
$ |
2.70 |
|
Diluted
|
|
$ |
2.74 |
|
|
$ |
2.22 |
|
|
$ |
2.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
declared per share
|
|
$ |
2.16 |
|
|
$ |
2.16 |
|
|
$ |
2.16 |
|
SCHEDULE
I - CONDENSED FINANCIAL INFORMATION
|
|
CH
ENERGY GROUP - (PARENT COMPANY ONLY)
|
|
|
|
|
|
|
|
|
|
|
|
STATEMENT OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Operating
Activities:
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
43,484 |
|
|
$ |
35,081 |
|
|
$ |
42,636 |
|
Equity
in earnings of subsidiary companies
|
|
|
(45,092 |
) |
|
|
(32,859 |
) |
|
|
(38,275 |
) |
Changes
in current assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
dividends received from subsidiaries
|
|
|
5,000 |
|
|
|
3,250 |
|
|
|
18,500 |
|
Accrued
taxes
|
|
|
(493 |
) |
|
|
3,001 |
|
|
|
(2,999 |
) |
Other
- net
|
|
|
220 |
|
|
|
378 |
|
|
|
539 |
|
Net
cash flows provided by operating activities
|
|
|
3,119 |
|
|
|
8,851 |
|
|
|
20,401 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
in subsidiaries
|
|
|
30,950 |
|
|
|
29,854 |
|
|
|
(40,060 |
) |
Purchase
of short-term investments
|
|
|
- |
|
|
|
- |
|
|
|
(69,293 |
) |
Proceeds
from issuance of long-term debt
|
|
|
50,000 |
|
|
|
- |
|
|
|
- |
|
Proceeds
from sale of short-term investments
|
|
|
- |
|
|
|
3,545 |
|
|
|
108,359 |
|
Net
cash flows provided by/(used in) investing activities
|
|
|
80,950 |
|
|
|
33,399 |
|
|
|
(994 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing
Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
dividends on common shares
|
|
|
(34,107 |
) |
|
|
(34,081 |
) |
|
|
(34,046 |
) |
Net
cash flows used in financing activities
|
|
|
(34,107 |
) |
|
|
(34,081 |
) |
|
|
(34,046 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
change in cash and cash equivalents
|
|
|
49,962 |
|
|
|
8,169 |
|
|
|
(14,639 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents - beginning of the year
|
|
|
11,329 |
|
|
|
3,160 |
|
|
|
17,799 |
|
Cash
and cash equivalents - end of the year
|
|
$ |
61,291 |
|
|
$ |
11,329 |
|
|
$ |
3,160 |
|
SCHEDULE
I - CONDENSED FINANCIAL INFORMATION
|
|
CH
ENERGY GROUP - (PARENT COMPANY ONLY)
|
|
|
|
|
|
|
|
|
BALANCE SHEET
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
December
31, 2009
|
|
|
December
31, 2008
|
|
ASSETS
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
61,291 |
|
|
$ |
11,329 |
|
Prepaid
income tax
|
|
|
1,863 |
|
|
|
- |
|
Prepayments
|
|
|
808 |
|
|
|
266 |
|
Accounts
receivable from subsidiaries
|
|
|
362 |
|
|
|
775 |
|
Other
|
|
|
26 |
|
|
|
13 |
|
Total
Current Assets
|
|
|
64,350 |
|
|
|
12,383 |
|
|
|
|
|
|
|
|
|
|
Other
Assets
|
|
|
|
|
|
|
|
|
Investments
in subsidiaries
|
|
|
528,743 |
|
|
|
520,150 |
|
Total
Other Assets
|
|
|
528,743 |
|
|
|
520,150 |
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
593,093 |
|
|
$ |
532,533 |
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION
AND LIABILITIES
|
|
|
|
|
|
|
|
|
Capitalization
|
|
|
|
|
|
|
|
|
Common
stock
|
|
$ |
1,686 |
|
|
$ |
1,686 |
|
Paid-in
capital
|
|
|
350,483 |
|
|
|
350,873 |
|
Retained
earnings
|
|
|
225,999 |
|
|
|
216,634 |
|
Treasury
stock
|
|
|
(44,406 |
) |
|
|
(45,386 |
) |
Accumulated
other comprehensive income
|
|
|
184 |
|
|
|
55 |
|
Capital
stock expense
|
|
|
(328 |
) |
|
|
(328 |
) |
Total
Capitalization
|
|
|
533,618 |
|
|
|
523,534 |
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
|
|
Dividends
payable
|
|
|
8,534 |
|
|
|
8,523 |
|
Accounts
payable
|
|
|
511 |
|
|
|
36 |
|
Accrued
taxes
|
|
|
- |
|
|
|
440 |
|
Accrued
interest
|
|
|
430 |
|
|
|
- |
|
Total
Current Liabilities
|
|
|
9,475 |
|
|
|
8,999 |
|
|
|
|
|
|
|
|
|
|
Long
Term Liabilities
|
|
|
|
|
|
|
|
|
Private
Placement Debt
|
|
|
50,000 |
|
|
|
- |
|
Total
Long Term Liabilities
|
|
|
50,000 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
Total
Capitalization and Liabilities
|
|
$ |
593,093 |
|
|
$ |
532,533 |
|
NOTES
TO CONDENSED FINANCIAL STATEMENTS
NOTE 1 - BASIS OF
PRESENTATION
CH Energy
Group (Parent Company only) has accounted for wholly owned subsidiaries using
the equity method. These financial statements are presented on a
condensed basis. Additional disclosures relating to the parent
company financial statements are included under the combined notes to our
financial statements under Part II, Item 8, of this report.
SCHEDULE II - RESERVES - CH ENERGY GROUP
|
|
|
|
|
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
|
Charged
to Cost and Expenses
|
|
|
Charged
to Other Accounts
|
|
|
Payments
and Other Reductions to Reserves
|
|
|
Balance
at
End
of
Period
|
|
YEAR
ENDED DECEMBER 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Reserves
|
|
$ |
5,155 |
|
|
$ |
1,265 |
|
|
$ |
125 |
|
|
$ |
1,789 |
|
|
$ |
4,756 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve
for Uncollectible Accounts
|
|
$ |
8,816 |
|
|
$ |
11,515 |
|
|
$ |
2,453 |
|
|
$ |
15,048 |
|
|
$ |
7,736 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
YEAR
ENDED DECEMBER 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Reserves
|
|
$ |
5,212 |
|
|
$ |
1,834 |
|
|
$ |
165 |
|
|
$ |
2,056 |
|
|
$ |
5,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve
for Uncollectible Accounts
|
|
$ |
4,829 |
|
|
$ |
12,470 |
|
|
$ |
- |
|
|
$ |
8,483 |
|
|
$ |
8,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
YEAR
ENDED DECEMBER 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Reserves
|
|
$ |
4,906 |
|
|
$ |
1,879 |
|
|
$ |
65 |
|
|
$ |
1,638 |
|
|
$ |
5,212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve
for Uncollectible Accounts
|
|
$ |
5,761 |
|
|
$ |
5,853 |
|
|
$ |
- |
|
|
$ |
6,785 |
|
|
$ |
4,829 |
|
|
|
|
|
|
|
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description
|
|
Balance
at Beginning of Period
|
|
|
Charged
to Cost and Expenses
|
|
|
Charged
to Other Accounts
|
|
|
Payments
and Other Reductions to Reserves
|
|
|
Balance
at
End
of
Period
|
|
YEAR
ENDED DECEMBER 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Reserves
|
|
$ |
3,898 |
|
|
$ |
713 |
|
|
$ |
125 |
|
|
$ |
1,233 |
|
|
$ |
3,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve
for Uncollectible Accounts
|
|
$ |
4,000 |
|
|
$ |
8,833 |
|
|
$ |
3,327 |
|
|
$ |
10,360 |
|
|
$ |
5,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
YEAR
ENDED DECEMBER 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Reserves
|
|
$ |
4,243 |
|
|
$ |
921 |
|
|
$ |
165 |
|
|
$ |
1,431 |
|
|
$ |
3,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve
for Uncollectible Accounts
|
|
$ |
2,761 |
|
|
$ |
7,892 |
|
|
$ |
- |
|
|
$ |
6,653 |
|
|
$ |
4,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
YEAR
ENDED DECEMBER 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Reserves
|
|
$ |
3,936 |
|
|
$ |
991 |
|
|
$ |
65 |
|
|
$ |
749 |
|
|
$ |
4,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve
for Uncollectible Accounts
|
|
$ |
3,800 |
|
|
$ |
4,850 |
|
|
$ |
- |
|
|
$ |
5,889 |
|
|
$ |
2,761 |
|
|
CHANGES IN AND
DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
|
The Chief
Executive Officer and Chief Financial Officer of CH Energy Group and Central
Hudson evaluated the effectiveness of the disclosure controls and procedures (as
defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended)
as of the end of the period covered by this Annual Report on Form 10-K and based
on the evaluation, concluded that, as of the end of the period covered by this
Annual Report on Form 10-K, the Registrants’ controls and procedures are
effective.
For
additional discussion, see the Report of Independent Registered Public
Accounting Firm and the Report of Management on Internal Control Over Financial
Reporting included in this 10-K Annual Report.
None.
PART III
|
DIRECTORS AND
EXECUTIVE OFFICERS OF CH ENERGY
GROUP
|
Other
information required hereunder for Directors and executive officers of CH Energy
Group is incorporated by reference to the CH Energy Group’s definitive proxy
statement (“Proxy Statement”), which will be filed with the SEC.
The
information on those Directors of CH Energy Group standing for election by
shareholders at the Annual Meeting of Shareholders to be held on April 27, 2010,
is incorporated by reference to the caption “Election of Directors” in the Proxy
Statement.
The
information on the executive officers of CH Energy Group required hereunder is
incorporated by reference to Item 1 - “Business” of this 10-K Annual Report
under the caption “Executive Officers.”
CH Energy
Group 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 and Item 406 of Regulation S-K, constitutes CH Energy
Group’s Code of Ethics for Senior Financial Officers. This section,
in conjunction with the remainder of the Code, is 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 CH Energy
Group’s Internet website at www.CHEnergyGroup.com.
If CH
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 CH Energy
Group’s periodic reports filed with the SEC, CH Energy Group will post such
information on its Internet website at www.CHEnergyGroup.com.
CH Energy
Group’s governance guidelines, Code, and the charters of its Audit,
Compensation, Governance and Nominating, and Strategy and Finance Committees are
available on CH Energy Group’s Internet website at www.CHEnergyGroup.com.
The
governance guidelines, the Code, and the charters may also be obtained by
writing to the Corporate Secretary, CH Energy Group, Inc., 284 South Avenue,
Poughkeepsie, New York 12601-4839.
The
information required hereunder for Directors and executive officers of CH Energy
Group is incorporated by reference to the section captioned “Executive
Compensation” of the Proxy Statement.
|
SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER
MATTERS
|
Equity-Based
Compensation Plan Information
The
following table sets forth information concerning CH Energy Group’s compensation
plans (including individual compensation arrangements) as of December 31, 2009,
under which equity securities of CH Energy Group are authorized for
issuance:
Plan
Category
|
|
|
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights
(a)
|
|
|
Weighted
average exercise price of outstanding options, warrants and
rights
(b)
|
|
|
Number
of securities remaining available for future issuance under equity-based
compensation plans (excluding securities reflected in column
(a))
(c)
|
|
Equity
compensation plans
approved by security holders
|
|
|
|
35,980 |
(1) |
|
$ |
46.27 |
|
|
|
143,619 |
(2) |
Equity
compensation plans
not approved by security holders
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
|
35,980 |
|
|
$ |
46.27 |
|
|
|
143,619 |
|
(1) This
includes only stock options granted under the 2000 Plan.
(2) Pertains
to the 2006 Plan only, and excludes 112,210 performance shares and 44,171
restricted shares and share units (including re-invested dividends) granted
under the 2006 Plan through December 31, 2009. Effective April 25,
2006, securities can no longer be issued under the 2000 Plan.
The
information required hereunder regarding equity ownership in CH Energy Group by
its Directors and executive officers is incorporated by reference to the section
captioned “Beneficial Ownership” of the Proxy Statement.
|
CERTAIN RELATIONSHIPS
AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
|
See Note
1 - “Summary of Significant Accounting Policies” under the caption “Related
Party Transactions.” The information required hereunder regarding Director
independence is incorporated by reference to the section captioned “Director
Independence” of the Proxy Statement.
|
PRINCIPAL ACCOUNTANT
FEES AND SERVICES
|
The
information required by this Item regarding CH Energy Group’s Audit Committee’s
policies and procedures and annual fees rendered to CH Energy Group’s principal
accountants is incorporated by reference to the Report of the Audit Committee
and to the caption “Principal Accountant Fees and Services,” both of which are
included in the Proxy Statement.
The
following information is provided for Central Hudson:
PRINCIPAL
ACCOUNTANT FEES AND SERVICES
|
|
|
|
|
|
|
|
|
|
|
|
PricewaterhouseCoopers
LLP
|
|
2009
|
|
|
2008
|
|
Audit
Fees
|
|
$ |
785,969 |
|
|
$ |
758,441 |
|
Tax
Fees
|
|
|
|
|
|
|
|
|
Includes
review of federal and state income tax returns and tax
research
|
|
|
10,700 |
|
|
|
14,200 |
|
All
Other Fees
|
|
|
|
|
|
|
|
|
Includes
software licensing fee for accounting research tool
|
|
|
- |
|
|
|
750 |
|
TOTAL
|
|
$ |
796,669 |
|
|
$ |
773,391 |
|
PART IV
|
EXHIBITS AND FINANCIAL
STATEMENT SCHEDULES
|
(a)
|
Documents filed as
part of this 10-K Annual
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 - “Financial
Statements and Supplementary Data” 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, which is
located immediately after the signature pages to this report.
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/
Steven V. Lant
|
|
|
|
Steven
V. Lant
|
|
|
|
Chairman
of the Board,
|
|
|
|
President
and
|
|
|
|
Chief
Executive Officer
|
|
|
|
|
|
Dated: February
10, 2010
|
|
|
|
|
|
|
|
|
CENTRAL
HUDSON GAS &
|
|
ELECTRIC
CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By
|
/s/
Steven V. Lant
|
|
|
|
Steven
V. Lant
|
|
|
|
Chairman
of the Board and
|
|
|
|
Chief
Executive Officer
|
|
|
|
|
|
Dated: February
10, 2010
|
|
|
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this 10-K Annual
Report has been signed below by the following persons 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:
|
|
|
|
|
|
|
|
/s/
Steven V. Lant
|
|
|
|
|
(Steven
V. Lant)
|
|
Chairman
of the Board,
President
and
Chief
Executive Officer
of
CH Energy Group, Inc.
and
Chairman of the Board
and
Chief Executive Officer
of
Central Hudson Gas
&
Electric Corporation
|
|
February
10, 2010
|
|
|
|
|
|
(b) Principal
Accounting Officer:
|
|
|
|
|
|
|
|
/s/
Kimberly J. Wright
|
|
|
|
|
(Kimberly
J. Wright)
|
|
Vice
President -
Accounting
and
Controller
of
CH
Energy Group, Inc.;
Controller
of
Central
Hudson Gas
&
Electric Corporation
|
|
February
10, 2010
|
|
|
|
|
|
(c)
Principal Financial Officer:
|
|
|
|
|
|
|
|
/s/
Christopher M. Capone
|
|
|
|
|
(Christopher
M. Capone)
|
|
Executive
Vice President and
Chief
Financial Officer
of
CH Energy Group, Inc.
and
Central Hudson Gas
&
Electric Corporation
|
|
February
10, 2010
|
(d) A
majority of Directors of CH Energy Group, Inc.:
Steven V.
Lant*, Margarita K. Dilley*, Steven M. Fetter*, Stanley J. Grubel*, Manuel J.
Iraola*, E. Michel Kruse*, Edward T. Tokar*, Jeffrey D. Tranen*, and
Ernest R. Verebelyi*, Directors
By
|
/s/
Steven V. Lant
|
|
|
|
(Steven
V. Lant)
|
|
February
10, 2010
|
(e) A
majority of Directors of Central Hudson Gas & Electric
Corporation:
Steven V.
Lant*, Christopher M. Capone*, Joseph J. DeVirgilio, Jr.*, and James P.
Laurito*, Directors
By
|
/s/
Steven V. Lant
|
|
|
|
(Steven
V. Lant)
|
|
February
10, 2010
|
_______________________
*Steven
V. Lant, 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 United States Securities and Exchange Commission as Exhibit 24
hereof.
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:
Exhibit
No.
(Regulation
S-K
Item
601
(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. (Incorporated herein by reference to Energy
Group's Annual Report, on Form 10-K, for the fiscal year ended December
31, 2000; Exhibit 2(i))
|
|
(ii)
|
Agreement
and Plan of Exchange by and between Central Hudson Gas & Electric
Corporation and CH Energy Group, Inc. (Incorporated herein by reference to
Central Hudson's Current Report on Form 8-K dated December 15, 1999;
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. (Incorporated herein by reference to Central Hudson's
Current Report on Form 8-K filed on November 18, 2009; Exhibit
3(i).1)
|
|
(ii)
|
By-laws
of CH Energy Group, Inc. in effect on the date of this Report.
(Incorporated herein by reference to CH Energy Group’s Current Report on
Form 8-K filed on November 18, 2009; Exhibit
3(ii).1)
|
|
(iii)
|
Composite
Restated Certificate of Incorporation of Central Hudson Gas & Electric
Corporation, as amended, through October 8, 1993 dated May 2, 2008
(Incorporated herein by reference to Central Hudson’s Quarterly Report on
10-Q for the fiscal quarter ended March 31, 2008; Exhibit
3(iii)(1)).
|
|
(iv)
|
By-laws
of Central Hudson Gas & Electric Corporation in effect on the date of
this Report. (Incorporated herein by reference to Central
Hudson’s Current Report on Form 8-K filed on January 5, 2010; Exhibit
3(ii).1)
|
(4)
|
Instruments
defining the rights of security holders, including indentures (see also
Exhibits (3)(i) and (ii) above):
|
|
(ii)
|
1--
Indenture, dated as of April 1, 1992, between
Central Hudson and U.S. Bank Trust National Association (formerly known as
First Trust of New York, National Association) (as successor trustee to
Morgan Guaranty Trust Company of New York), as Trustee related to
unsecured Medium-Term Notes.
|
|
(ii)
|
2--
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 thereto, as filed pursuant to Rule 424 (b) in
connection with Registration Statement No. 33-83542, and, as applicable to
a tranche of such Medium-Term Notes, each of the
following:
|
|
(a)
|
Pricing
Supplement No. 2, dated March 25, 2002, as filed pursuant to Rule
424(b).
|
|
(b)
|
Pricing
Supplement No. 3, dated September 17, 2003, as filed pursuant to Rule
424(b).
|
|
(c)
|
Pricing
Supplement No. 4, dated February 24, 2004, as filed pursuant to Rule
424(b).
|
|
(ii)
|
3--
Prospectus Supplement dated October 28, 2004 (to
Prospectus dated October 22, 2004) relating to $85,000,000 principal
amount of Medium-Term Notes, Series E, and the Prospectus dated October
22, 2004, relating to $85,000,000 principal amount of Central Hudson's
debt securities attached thereto, as filed pursuant to Rule 424(b) in
connection with Registration Statement No. 333-116286, and, as applicable
to a tranche of such Medium-Term Notes, each of the
following:
|
|
(a)
|
Pricing
Supplement No. 1, dated October 29, 2004, as filed pursuant to Rule
424(b).
|
|
(b)
|
Pricing
Supplement No. 2, dated November 2, 2004, as filed pursuant to Rule
424(b).
|
|
(c)
|
Pricing
Supplement No. 3, dated November 30, 2005, as filed pursuant to Rule
424(b).
|
|
(d)
|
Pricing
Supplement No. 4, dated November 17, 2006, as filed pursuant to Rule
424(b).
|
|
(ii)
|
4--
Prospectus Supplement dated March 20, 2007
(to Prospectus dated December 1, 2006) relating to $140,000,000 principal
amount of Medium-Term Notes, Series F, and the Prospectus dated December
1, 2006 relating to $140,000,000 principal amount of Central Hudson’s debt
securities attached thereto, as filed on March 20, 2007, pursuant to Rule
424(b) in connection with Registration Statement No. 333-138510, and, as
applicable to a tranche of such Medium-Term Notes, each of the
following:
|
|
(a)
|
Pricing
Supplement No. 1, Dated March 20, 2007 filed on March 21, 2007, pursuant
to Rule 424(b).
|
|
(b)
|
Pricing
Supplement No. 2, Dated September 14, 2007 filed on September 14, 2007,
pursuant to Rule 424(b).
|
|
(c)
|
Pricing
Supplement No. 3, Dated November 18, 2008 filed on November 18, 2008,
pursuant to Rule 424(b).
|
|
(d)
|
Pricing
Supplement No. 4, Dated September 30, 2009 filed on October 1, 2009,
pursuant to Rule 424(b).
|
|
(ii)
|
5
– Note
Purchase Agreement, dated as of April 17, 2009, between CH Energy Group
and the purchasers of its 6.58% Senior Notes, Series A, due April 17, 2014
(Incorporated herein by reference to CH Energy Group’s Current Report on
Form 8-K, filed April 20, 2009; Exhibit
10.1)
|
|
(ii)
|
6
– Guaranty
Agreement by Central Hudson Enterprises Corporation dated as of April 17,
2009 (Incorporated herein by reference to CH Energy Group’s Current Report
on Form 8-K, filed April 20, 2009; Exhibit
10.2)
|
|
(ii)
|
7
–
Supplemental Note Purchase Agreement, dated as of December 15, 2009,
between CH Energy Group and the purchasers of its 6.8% Senior Notes,
Series B, due December 11, 2025 (Incorporated herein by reference to CH
Energy Group’s Current Report on Form 8-K, filed December 16, 2009;
Exhibit 10.2)
|
|
(ii)
|
8
-- 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.
|
|
(i)
|
1--
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). (Incorporated herein by reference to Central Hudson's
Annual Report on Form 10-K/A for the fiscal year ended December 31, 1992;
Exhibit (10)(i)37)
|
|
(i)
|
2--
Amended and Restated Credit Agreement
effective as of January 2, 2007 among Central Hudson, certain lenders
described therein and JPMorgan Chase Bank, N.A., as arranger and
administrative agent. (Incorporated herein by reference to
Central Hudson's Current Report on Form 8-K filed on December 20, 2006;
Exhibit 1)
|
|
(i)
|
3--
Second Amendment with Respect to the Amended and
Restated Credit Agreement among Central Hudson, certain lenders described
therein and JPMorgan Chase Bank, N.A., as arranger and administrative
agent. (Incorporated herein by reference to Central Hudson's
Current Report on Form 8-K filed on February 6, 2008; Exhibit
10.1)
|
|
(i)
|
4--
Distribution Agreement dated March 19, 2007 between the
Company, and Banc of America Securities LLC, J.P. Morgan Securities Inc.
and McDonald Investments Inc., as agents. (Incorporated herein
by reference to Central Hudson's Current Report on Form 8-K filed on March
19, 2007; Exhibit 1)
|
|
(i)
|
5--
Amended and Restated Credit Agreement among CH Energy
Group, Inc., Central Hudson Enterprises Corporation and Certain Lending
Institutions (Keybank National Association, JP Morgan Chase Bank, N.A.,
Bank of America, N.A., and HSBC Bank USA) dated February 21,
2008. (Incorporated herein by reference to CH Energy Group’s
Current Report on Form 8-K filed on February 26, 2008; Exhibit
10.1)
|
|
(i)
|
6--
Amendment No. 1 to the Amended and Restated
Credit Agreement among CH Energy Group, Inc., Central Hudson Enterprises
Corporation and Certain Lending Institutions (Keybank National
Association, JP Morgan Chase Bank, N.A., Bank of America, N.A., and HSBC
Bank USA) dated February 4, 2009. (Incorporated herein by
reference to CH Energy Group’s Current Report on Form 8-K filed on
February 6, 2009; Exhibit 10.1)
|
|
(i)
|
7--
Promissory Note of Central Hudson Gas &
Electric Corporation, dated April 23, 2008, payable to the order of
JPMorgan Chase Bank, N.A. (Incorporated herein by reference to
CH Energy Group’s Annual Report on Form 10-K for the year ended December
31, 2008; Exhibit (10)(i)7)
|
|
(i)
|
8
-- Promissory
Note of Central Hudson Gas & Electric Corporation, dated February 20,
2008, payable to the order of Bank of America,
N.A. (Incorporated herein by reference to CH Energy Group’s
Annual Report on Form 10-K for the year ended December 31, 2008; Exhibit
(10)(i)8)
|
|
(iii)1
|
1--
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. (Incorporated herein by
reference to Energy Group's Annual Report on Form 10-K for the fiscal year
ended December 31, 1999; Exhibit
(10)(iii)26)
|
|
(iii)
|
2--
Amendment to CH Energy Group, Inc. Directors and
Executives Deferred Compensation Plan Trust Agreement (Incorporated herein
by reference to Energy Group's Annual Report on Form 10-K for the fiscal
year ended December 31, 2003; Exhibit
(10)(iii)29)
|
|
(iii)
|
3--
Amended and Restated CH Energy Group, Inc. Directors and
Executives Deferred Compensation Plan (Part One), Effective September 26,
2003. (Incorporated herein by reference to Energy Group’s Form
S-8 filed on October 30, 2003; Exhibit
(10)(iii)26)
|
|
(iii)
|
4--
Amendment to CH Energy Group, Inc. Directors and
Executives Deferred Compensation Plan. (Incorporated herein by
reference to Energy Group’s Current Report on Form 8-K filed on June 1,
2006; Exhibit (10)(iii)44)
|
|
(iii)
|
5--
Amended and Restated CH Energy Group, Inc.
Directors and Executives Deferred Compensation Plan (Part Two), effective
as of January 1, 2008, (dated December 31, 2007). (Incorporated
herein by reference to Energy Group’s Annual Report on Form 10-K for the
year ended December 31, 2007; Exhibit
(10)(iii)31)
|
|
(iii)
|
6--
Amendment and Restatement of Central Hudson
Gas & Electric Corporation Retirement Benefit Restoration Plan (Part
One) effective June 22, 2001. (Incorporated herein by reference
to Energy Group's Annual Report on Form 10-K, for the fiscal year ended
December 31, 2001; Exhibit
(10)(iii)24)
|
|
(iii)
|
7--
Amendment to Central Hudson Gas & Electric
Corporation Retirement Benefit Restoration Plan. (Incorporated herein by
reference to Energy Group’s Current Report on Form 8-K filed on December
21, 2005; Exhibit (10)(iii)42)
|
____________________________
1 Exhibits in Part (iii)
of this Section 10 are management contracts and compensatory plans and
arangements.
|
(iii)
|
8--
Amended and Restated Central Hudson Gas & Electric
Corporation Retirement Benefit Restoration Plan (Part Two) effective as of
January 1, 2008. (Incorporated herein by reference to Energy
Group’s Annual Report on Form 10-K for the year ended December 31, 2007;
Exhibit (10)(iii)39)
|
|
(iii)
|
9--
Amended and Restated CH Energy Group, Inc. Supplemental
Executive Retirement Plan effective as of January 1,
2008. (Incorporated herein by reference to Energy Group’s
Annual Report on Form 10-K for the year ended December 31, 2007; Exhibit
(10)(iii)37)
|
|
(iii)
|
10-- Amendment
to CH Energy Group, Inc. Supplemental Executive Retirement Plan.
(Incorporated herein by reference to CH Energy Group’s Quarterly Report on
Form 10-Q for the fiscal quarter ended June 30, 2008; Exhibit
(10)(iii)1)
|
|
(iii)
|
11-- Amendment
No. 1, effective January 1, 2001, to Energy Group's Long-Term
Performance-Based Incentive Plan. (Incorporated herein by reference to
Energy Group's Quarterly Report on Form 10-Q for the fiscal quarter ended
March 31, 2001; Exhibit (10)(iii)1)
|
|
(iii)
|
12-- Amendment
No. 2, effective January 1, 2002, to Energy Group's Long-Term
Performance-Based Incentive Plan. (Incorporated herein by
reference to Energy Group's Annual Report on Form 10-K, for the fiscal
year ended December 31, 2001; Exhibit
(10)(iii)20)
|
|
(iii)
|
13-- Amendment
to CH Energy Group, Inc. Long-Term Performance-Based Incentive Plan, dated
October 24, 2003, effective as of September 26,
2003. (Incorporated herein by reference to Energy Group's
Annual Report on Form 10-K, for the fiscal year ended December 31, 2003;
Exhibit (10)(iii)28)
|
|
(iii)
|
14-- Amendment
to CH Energy Group, Inc. Long-Term Performance-Based Incentive Plan
effective as of December 31, 2007. (Incorporated herein by
reference to Energy Group’s Annual Report on Form 10-K for the year ended
December 31, 2007; Exhibit
(10)(iii)35)
|
|
(iii)
|
15-- CH
Energy Group, Inc. Long-Term Equity Incentive Plan, effective as of April
25, 2006. (Incorporated herein by reference to Appendix A to
Energy Group's proxy statement filed on March 10, 2006; Appendix
A)
|
|
(iii)
|
16-- Amendment
to CH Energy Group, Inc. Long-Term Equity Incentive Plan effective as of
December 31, 2007. (Incorporated herein by reference to Energy
Group’s Annual Report on Form 10-K for the year ended December 31, 2007;
Exhibit (10)(iii)36)
|
|
(iii)
|
17-- Form
of CH Energy Group, Inc. Performance Shares Agreement. (Incorporated
herein by reference to Energy Group's Current Report on Form 8-K filed on
April 28, 2006; Exhibit
(10)(iii)43)
|
|
(iii)
|
18-- Amendment
to CH Energy Group, Inc. Performance Shares Agreements, effective as of
January 1, 2008. (Incorporated herein by reference to Energy
Group’s Annual Report on Form 10-K for the year ended December 31, 2007;
Exhibit (10)(iii)41)
|
|
(iii)
|
19--
Form
of CH Energy Group, Inc. Performance Shares
Agreement. (Incorporated herein by reference to CH Energy
Group’s Current Report on Form 8-K filed on January 30, 2008; Exhibit
10.1)
|
|
(iii)
|
20-- Form
of CH Energy Group, Inc. Performance Shares
Agreement. (Incorporated herein by reference to CH Energy
Group’s Current Report on Form 8-K filed on January 26, 2009; Exhibit
10.1)
|
|
(iii)
|
21-- Form
of CH Energy Group, Inc. Restricted Shares Agreement (for employees of
Griffith Energy Services, Inc.) (Incorporated herein by reference to CH
Energy Group’s Quarterly Report on 10-Q for the fiscal quarter ended March
31, 2008; Exhibit (10)(iii)3)
|
|
(iii)
|
22-- Form
of CH Energy Group, Inc. Restricted Shares Agreement (for officers of
Central Hudson Enterprises Corporation) (Incorporated herein by reference
to CH Energy Group’s Quarterly Report on Form 10-Q for the fiscal quarter
ended March 31, 2008; Exhibit
(10)(iii)4)
|
|
(iii)
|
23-- Form
of CH Energy Group, Inc. Restricted Stock Unit Agreement (Long-Term Equity
Incentive Plan) (Incorporated herein by reference to CH Energy Group’s
Current Report on Form 8-K filed on November 17, 2009; Exhibit
10.1)
|
|
(iii)
|
24-- Amended
and Restated Employment Agreement between CH Energy Group, Inc. and the
Chief Executive Officer effective as of January 1,
2008. (Incorporated herein by reference to Energy Group’s
Annual Report on Form 10-K for the year ended December 31, 2007; Exhibit
(10)(iii)32)
|
|
(iii)
|
25-- Amended
and Restated Employment Agreement between CH Energy Group, Inc. and the
three most senior executives (after Chief Executive Officer) effective as
of January 1, 2008. (Incorporated herein by reference to Energy
Group’s Annual Report on Form 10-K for the year ended December 31, 2007;
Exhibit (10)(iii)33)
|
|
(iii)
|
26-- Amended
and Restated Employment Agreement between CH Energy Group, Inc. and the
other executive officers effective as of January 1,
2008. (Incorporated herein by reference to Energy Group’s
Annual Report on Form 10-K for the year ended December 31, 2007; Exhibit
(10)(iii)34)
|
|
(iii)
|
27-- Amended
and Restated Employment Agreement between CH Energy Group, Inc. and
Griffith Energy Services, Inc. executive effective as of January 1,
2008. (Incorporated herein by reference to CH Energy Group’s
Annual Report on Form 10-K for the year ended December 31, 2007; Exhibit
(10)(iii)42)
|
|
|
28-- Employment
Agreement between CH Energy Group, Inc. and James P. Laurito, dated as of
November 16, 2009. (Incorporated herein by reference to CH Energy Group’s
Annual Report on Form 10-K for the year ended December 31, 2009, Exhibit
(10)(iii)28)
|
|
(iii)
|
29-- Form
of Amendment to Employment Agreement with executive officers, effective
December 31, 2008. (Incorporated herein by reference to CH
Energy Group’s Annual Report on Form 10-K for the year ended December 31,
2008; Exhibit (10)(iii)28)
|
|
(iii)
|
30-- Employment
Agreement, dated October 1, 2009, between CH Energy Group, Inc. and John
E. Gould. (Incorporated herein by reference to CH Energy
Group’s Quarterly Report on Form 10-Q for the fiscal quarter ended
September 30, 2009; Exhibit
(10)(iii)1)
|
|
(iii)
|
31-- Amended
and Restated CH Energy Group, Inc. Short-Term Incentive
Plan. (Incorporated herein by reference to CH Energy Group’s
Current Report on Form 8-K filed on May 27, 2009; Exhibit
10.1)
|
|
(iii)
|
32-- Form
of CH Energy Group, Inc. Indemnification Agreement (for officers of CH
Energy Group, Inc.) (Incorporated herein by reference to CH Energy Group’s
Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2009;
Exhibit (10)(iii)1)
|
|
(iii)
|
33-- Form
of Central Hudson Gas & Electric Corporation Indemnification Agreement
(for officers of Central Hudson Gas & Electric Corporation)
(Incorporated herein by reference to CH Energy Group’s Quarterly Report on
Form 10-Q for the fiscal quarter ended March 31, 2009; Exhibit
(10)(iii)2)
|
|
(iii)
|
34-- Form
of Central Hudson Enterprises Corporation Indemnification Agreement (for
officers of Central Hudson Enterprises Corporation) (Incorporated herein
by reference to CH Energy Group’s Quarterly Report on Form 10-Q for the
fiscal quarter ended March 31, 2009; Exhibit
(10)(iii)3)
|
|
(iii)
|
35-- Agreement,
dated as of April 27, 2009, by and between CH Energy Group, Inc. and GAMCO
Asset Management Inc. (Incorporated herein by reference to CH Energy
Group’s Current Report on Form 8-K, filed April 29, 2009; Exhibit
10.1)
|
(12)
|
(i)-- CH
Energy Group Statement showing the computation of the ratio of earnings to
fixed charges.
|
(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.
(21)--
|
Subsidiaries
of Energy Group and Central Hudson as of December 31,
2008.
|
(23)--
|
Consents
of Independent Registered Public Accounting
Firm.
|
1--
Consents of Independent Registered Public Accounting
Firm for incorporation by reference of Energy Group Inc.’s Registration
Statements on Form S-3 and S-8.
2--
Consents of Independent Registered Public
Accounting Firm for incorporation by reference of Central Hudson Gas &
Electric Corporation’s Registration Statement on Form S-3.
|
(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 Steven V. Lant.
|
|
(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
Steven V. Lant.
|
|
Rule
13a-14(a)/15d-14(a) Certifications.
|
|
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. (Incorporated herein by reference to
Central Hudson's Quarterly Report on Form 10-Q for the fiscal quarter
ended September 30, 1995; 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. (Incorporated herein by reference to Central
Hudson's Current Report on Form 8-K, dated January 7, 1998; Exhibit
(99)2)
|
|
(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. (Incorporated herein by
reference to Central Hudson's Current Report on Form 8-K, dated February
10, 1998; 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. (Incorporated herein by reference to Central Hudson's
Current Report on Form 8-K, dated July 24, 1998; Exhibit
(10)1)
|
|
(i)
|
5--
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. (Incorporated herein by reference to Energy Group's
Annual Report on Form 10-K, for the fiscal year ended December 31, 2002;
Exhibit (99)(i)10)
|
|
(i)
|
6--
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. (Incorporated herein by reference to Energy Group's
Annual Report on Form 10-K, for the fiscal year ended December 31, 2002;
Exhibit (99)(i)11)
|