UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
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x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
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OR
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
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Commission
File Number
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Registrant, State of Incorporation
Address and Telephone Number
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IRS Employer
Identification No.
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0-30512
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CH Energy Group, Inc.
(Incorporated in New York)
284 South Avenue
Poughkeepsie, New York 12601-4839
(845) 452-2000
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14-1804460
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1-3268
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Central Hudson Gas & Electric Corporation
(Incorporated in New York)
284 South Avenue
Poughkeepsie, New York 12601-4839
(845) 452-2000
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14-0555980
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Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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CH Energy Group, Inc.
Common Stock, $0.10 par value
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
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Title of each class
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Central Hudson Gas & Electric Corporation Cumulative Preferred Stock
4.50% Series
4.75% Series
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Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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CH Energy Group, Inc.
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Yes þ
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No o
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Central Hudson Gas & Electric Corporation
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Yes o
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No þ
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Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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CH Energy Group, Inc.
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Yes o
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No þ
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Central Hudson Gas & Electric Corporation
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Yes o
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No þ
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Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
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CH Energy Group, Inc.
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Yes þ
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No o
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Central Hudson Gas & Electric Corporation
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Yes þ
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No o
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Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
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CH Energy Group, Inc.
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Yes þ
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No o
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Central Hudson Gas & Electric Corporation
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Yes þ
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No o
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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 the Registrant 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):
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CH Energy Group, Inc.
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Central Hudson Gas & Electric Corporation
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Large Accelerated Filer þ
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Large Accelerated Filer o
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Accelerated Filer o
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Accelerated Filer o
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Non-Accelerated Filer o
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Non-Accelerated Filer þ
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Smaller Reporting Company o
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Smaller Reporting Company o
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Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):
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CH Energy Group, Inc.
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Yes o
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No þ
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Central Hudson Gas & Electric Corporation
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Yes o
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No þ
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The aggregate market value of the voting and non-voting common equity of CH Energy Group held by non-affiliates as of February 1, 2012, was $860,353,783 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, 2011, the last business day of CH Energy Group’s most recently completed second fiscal quarter, was $821,719,300 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, 2011 was zero.
The number of shares outstanding of CH Energy Group’s Common Stock, as of February 1, 2012, was 14,897,901.
The number of shares outstanding of Central Hudson’s Common Stock, as of February 1, 2012, 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 24, 2012, 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.
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CH Energy Group Companies and Investments
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CHEC
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Central Hudson Enterprises Corporation (the parent company of Griffith Energy Services, Inc. (not regulated by the PSC) and wholly owned subsidiary of CH Energy Group)
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Griffith
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Griffith Energy Services, Inc. (a wholly owned subsidiary of CHEC)
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Lyonsdale
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Lyonsdale Biomass, LLC (a formerly wholly owned subsidiary of CHEC)
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CH-Auburn
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CH-Auburn Energy, LLC (a formerly wholly owned subsidiary of CHEC)
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CH-Greentree
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CH-Greentree, LLC (a formerly wholly owned subsidiary of CHEC)
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CH Shirley Wind
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CH Shirley Wind, LLC (a formerly wholly owned subsidiary of CHEC which owned 90% controlling interest in Shirley Delaware, which owned 100% interest in Shirley Wind)
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Shirley Delaware
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Shirley Wind (Delaware), LLC (100% owner of Shirley Wind)
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Shirley Wind
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Shirley Wind, LLC (a 20 megawatt wind project)
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Cornhusker Holdings
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Cornhusker Energy Lexington Holdings, LLC (a CHEC investment)
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JB Wind
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JB Wind Holdings, LLC (a CH-Community Wind investee company)
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Regulators
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NYS
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New York State
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PSC
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NYS Public Service Commission
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FERC
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Federal Energy Regulatory Commission
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DEC
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NYS Department of Environmental Conservation
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Terms Related to Business Operations Used By CH Energy Group
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1993 PSC Policy
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PSC’s 1993 Statement of Policy regarding pension and other post-employment benefits
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2006 Rate Order
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Order Establishing Rate Plan issued by the PSC to Central Hudson on July 24, 2006
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(i)
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2009 Rate Order
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Order Establishing Rate Plan issued by the PSC to Central Hudson on June 22, 2009
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2010 Rate Order
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Order Establishing Rate Plan issued by the PSC to Central Hudson on June 18, 2010
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Dth
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Decatherms
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Distributed Generation
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An electrical generating facility located at a customer’s point of delivery which may be connected in parallel operation to the utility system
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kWh
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Kilowatt-hour(s)
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Mcf
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Thousand Cubic Feet
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MGP
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Manufactured Gas Plant
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MW / MWh
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Megawatt(s) / Megawatt-hour(s)
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OPEB
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Other Post-Employment Benefits
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RDMs
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Revenue Decoupling Mechanisms
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Retirement Plan
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Central Hudson’s Non-Contributory Defined Benefit Retirement Income Plan
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ROE
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Return on Equity
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ROW
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Right-of-Way
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Settlement Agreement
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Amended and Restated Settlement Agreement dated January 2, 1998, and thereafter amended, among Central Hudson, PSC Staff, and Certain Other Parties
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Temporary State
Assessment
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New York State Temporary State Energy and Utility Service Conservation Assessment required to be collected from April 4, 2009 to March 31, 2014
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Other
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COSO
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Committee of Sponsoring Organizations of the Treadway Commission
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EITF
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FASB Emerging Issues Task Force
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Exchange Act
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Securities Exchange Act of 1934
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GAAP
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Accounting Principles Generally Accepted in the United States of America
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NYISO
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New York Independent System Operator
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NYSERDA
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New York State Energy Research and Development Authority
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Registrants
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CH Energy Group and Central Hudson
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(ii)
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PART I
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PAGE
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BUSINESS
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2
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RISK FACTORS
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11
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UNRESOLVED STAFF COMMENTS
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14
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PROPERTIES
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14
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LEGAL PROCEEDINGS
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16
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| ITEM 4 | MINE SAFETY DISCLOSURES | 16 |
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PART II
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MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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16
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SELECTED FINANCIAL DATA OF CH ENERGY GROUP AND ITS SUBSIDIARIES
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20
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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22
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QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
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84
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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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86
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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
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192
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CONTROLS AND PROCEDURES
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192
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OTHER INFORMATION
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192
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PART III
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DIRECTORS AND EXECUTIVE OFFICERS OF CH ENERGY GROUP
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193
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EXECUTIVE COMPENSATION
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194
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
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194
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
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194
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PRINCIPAL ACCOUNTANT FEES AND SERVICES
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195
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PART IV
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EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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195
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PART I
FILING FORMAT
This 10-K Annual Report for the fiscal year ended December 31, 2011, 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 include Central Hudson and CHEC. For additional information, see the sub-caption “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, investment valuations, 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; energy supply and demand; potential future acquisitions; legislative, regulatory, and competitive developments; interest rates; access to capital; market risks; electric and natural gas industry restructuring and cost recovery; the ability to obtain adequate and timely rate relief; changes in fuel supply or costs 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 one wholly owned subsidiary, Griffith Energy Services, Inc. (“Griffith”). CHEC also has ownership interests in certain subsidiaries that are less than 100% owned. For more information, see sub-caption “Other Subsidiaries and Investments” under caption “CHEC and Its Subsidiaries and Investments.” 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. 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.
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 comprising approximately 2,600 square miles in the Hudson Valley, with a population estimated at 680,000. 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, 2011, was 838.
Central Hudson’s territory reflects a diversified economy, including manufacturing industries, governmental agencies, public and private institutions, wholesale and retail trade operations, research firms, farms and resorts.
Seasonality and Other Weather Impacts
Central Hudson’s delivery revenues have historically varied seasonally in response to weather. Sales of electricity are 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 annual sales volumes. Effective July 1, 2009 and continuing in the 2010 Rate Order through June 30, 2013, Central Hudson’s delivery rate structure includes 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 a result of weather or other factors as compared to those forecasted in rate proceedings no longer have a significant impact on earnings. However, variations between actual expenses incurred due to storm activity and the amount set in rates may impact Central Hudson’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 adverse impact on earnings for higher storm expenses should be limited to non-material amounts, as long as the other criteria for deferral accounting are met.
Competition
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. 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.
Regulation
Central Hudson is subject to regulation by the PSC regarding, among other things, services rendered (including the rates charged), major transmission facility siting, accounting 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.
Rates
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. Both transmission rates and rates for electricity sold for resale which involve interstate commerce are regulated by FERC.
Since July 2009, Central Hudson’s rates have included RDMs which 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 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.
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 2011, the average price of electricity for full service customers was 14.48 cents per kWh as compared to an average of 14.94 cents per kWh in 2010. 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 2011 was 5.60 cents per kWh and 5.26 cents per kWh in 2010. The increase in delivery price was primarily due to the implementation of new rates as part of the 2010 Rate Order. The average delivery price in 2011 also includes a surcharge resulting from the Electric RDM.
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 2011, the average price of natural gas for full-service customers was $15.50 per Mcf as compared to an average of $14.86 per Mcf in 2010. 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 for retail and full service in 2011 was $6.94 per Mcf and $6.67 per Mcf in 2010. The increase in delivery price was primarily due to the implementation of new rates as part of the 2010 Rate Order and increases associated with surcharges to cover additional assessments from New York State agencies. The average delivery price in 2011 includes a surcharge resulting from the Gas RDM.
For further information regarding the terms of the 2006 Rate Order, 2009 Rate Order and 2010 Rate Order under which Central Hudson operated during the current reporting period, see Note 2 - “Regulatory Matters” under the caption “2006, 2009 and 2010 Rate Orders.”
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 sub-caption “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 sub-caption “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, 2011, the sources and related costs of purchased electricity and electric generation for Central Hudson were as follows (In Thousands):
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Sources of Energy
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Aggregate Percentage of Energy Requirements
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Costs in 2011
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Purchased Electricity
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96.8 | % | $ | 196,009 | ||||
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Hydroelectric and Other
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3.2 | % | 374 | |||||
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100.0 | % | ||||||
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Deferred Electricity Cost
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9,777 | |||||||
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Total
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$ | 206,160 | ||||||
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 $2.1 million in 2011, $3.1 million in 2010 and $3.9 million in 2009. 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. The decrease in total R&D expenditures in 2011 as compared to the prior two periods is a result of a PSC Order to cease the collection from customers and payment to NYSERDA of certain energy efficiency research funds in the current year. There is no impact on earnings related to this change and the collections and payments have resumed in 2012. R&D expenditures are provided for in Central Hudson’s rates charged to customers for electric and natural gas delivery service, with any differences between R&D expense and the rate allowances deferred 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 519 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, 2011, and remains effective through April 30, 2016.
CHEC and Its Subsidiaries and Investments
CHEC, a New York corporation, is a wholly owned subsidiary of CH Energy Group. CHEC’s wholly owned subsidiary Griffith is engaged in the business of marketing petroleum products and related services to retail and wholesale customers. For further discussion of certain energy-related projects within other subsidiaries and investments, see Note 5 - “Acquisitions, Divestitures and Investments.”
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. The number of Griffith employees at December 31, 2011 was 403.
Other Subsidiaries and Investments
Pursuant to the strategy shift announced in 2010, during 2011, CH Energy Group sold its four largest renewable energy investments; Lyonsdale, Shirley Wind, CH-Auburn and the molecular gate owned by CH-Greentree. See Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" under the caption "Executive Summary" for further discussion.
Seasonality
A substantial portion of CHEC’s revenues vary seasonally, as Griffith’s fuel oil deliveries are directly related to use for space heating and are highest during the winter months.
Competition
Griffith participates in a competitive fuel distribution industry that is subject to different risks than those found in the businesses of the regulated utility, Central Hudson. 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 and Griffith 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 and Griffith 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 and Griffith 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 2011, except as noted in Note 12 – “Commitments and Contingencies” under the caption “Environmental Matters” of this 10-K Annual Report.
Air Quality
The Clean Air Act Amendments of 1990 address attainment and maintenance of national air quality standards and impact Central Hudson electric generating facilities in South Cairo and Coxsackie, NY. 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.
Prior to the sale of CH-Auburn, a Notice of Violation of its air permit was received from the NYS DEC in 2010. CH-Auburn reached an agreement with the NYS DEC to resolve this issue and paid a civil penalty of approximately $30,000 in the first quarter of 2011. There were no outstanding violations at the time of sale.
Water Quality
The Clean Water Act established the basic framework for federal and state regulation of water pollution control and requires facilities that discharge waste or storm water into the waters of the United States to obtain permits. Central Hudson and Griffith have permits regulating pollutant discharges for relevant locations.
Industrial & Hazardous Substances and Wastes
Central Hudson and Griffith 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. 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.
Environmental Expenditures
2011 actual and 2012 estimated expenditures attributable in whole or in substantial part to environmental considerations are detailed in the table below:
| Central Hudson | Griffith | |||
| 2011 - $2.1 million | 2011 - $0.8 million | |||
| 2012 - $6.8 million | 2012 - $0.5 million |
Prior to their sale in 2011, actual environmental expenditures by CH-Auburn and Lyonsdale were not material.
Central Hudson and Griffith 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 nor Griffith 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 and Central Hudson file annual, quarterly, and current reports and other information with the SEC. CH Energy Group also files proxy statements. 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 and Central Hudson make available free of charge at www.CHEnergyGroup.com their 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. CH Energy Group’s proxy statements, governance guidelines, Code of Business Conduct and Ethics, and the charters of its Audit, Compensation, Governance and Nominating, and Strategy and Finance Committees are also available 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, 2011) are as follows:
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Date Commenced
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Executive Officers
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Age
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Current
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and Prior Positions
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CH Energy Group
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Central Hudson
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CHEC
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Steven V. Lant
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54
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Chairman of the Board
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Apr 2004
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May 2004
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May 2004
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Chief Executive Officer
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Jul 2003
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Jul 2003
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Jul 2003
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President
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Jul 2003
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Jul 2003
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Director
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Feb 2002
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Dec 1999
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Dec 1999
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James P. Laurito(1)
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55
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President
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Jan 2010
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Executive Vice President
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Nov 2009
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Nov 2009
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Director
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Nov 2009
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Nov 2009
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Christopher M. Capone
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49
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President
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Sep 2010
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Executive Vice President
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Jan 2007
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Jan 2007
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Director
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Mar 2005
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Mar 2007
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Chief Financial Officer
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Sep 2003
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Sep 2003
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Sep 2003
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Treasurer
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Apr 2003
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Jun 2001
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Apr 2003
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John E. Gould(2)
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67
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Executive Vice President and General Counsel
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Oct 2009
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Jan 2010
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Jan 2010
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Secretary
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Mar 2007
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Jun 2007
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Jun 2007
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Assistant Secretary
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Nov 1999
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Jan 2000
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Denise D. VanBuren
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50
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Secretary
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Dec 2009
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Jan 2010
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Jan 2010
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Vice President - Corporate Communications
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Dec 2009
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Jan 2010
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Vice President - Public Affairs and Energy Efficiency
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Aug 2007
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Aug 2007
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Vice President - Corporate Communications and Community Relations
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Nov 2000
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Nov 2000
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Charles A. Freni, Jr.
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52
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Director
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Mar 2011
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Senior Vice President - Customer Services
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Jan 2005 | |||||||||||
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W. Randolph Groft
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50
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Executive Vice President
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Jan 2003
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Director
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Jan 2003
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Kimberly J. Wright
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44
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Vice President - Accounting and Controller
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May 2008
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Controller
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Oct 2006
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(1)
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From 2003 to August 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.
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(2)
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Before October 2009, served as a partner of the law firm of Thompson Hine LLP.
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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 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:
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Storms, natural disasters, wars, terrorist acts, failure of critical equipment and other catastrophic events occurring both within and outside Central Hudson’s and Griffith’s service territories.
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Bulk power system and gas transmission pipeline system capacity constraints could impact Central Hudson.
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Unfavorable developments in the world oil markets could impact Griffith.
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Third-party facility owner or supplier financial distress.
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Unfavorable governmental actions or judicial orders.
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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’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 three year rate order plan approved by the PSC effective July 1, 2010. The following could unfavorably impact Central Hudson’s financial results:
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·
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Higher expenses than reflected in current rates. Higher expenses could result from, among other things, increases in taxes and assessments, unrecoverable storm restoration expense, labor, health care benefits or other expense components.
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Penalties imposed by the PSC for the failure to achieve performance metrics established in rate proceedings, or violation of PSC Orders.
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Higher electric and natural gas capital project costs resulting from escalation of labor, material and equipment prices, as well as potential delays in the siting and legislative and/or regulatory approval requirements associated with these projects.
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A determination by the PSC that the cost to place a project in service is above a level which is deemed prudent.
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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 MAY ADVERSELY IMPACT EARNINGS
Description and Sources of Risk
Lower sales can occur for various reasons, including the following:
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Changes in customers’ usage patterns driven by customer responses to product prices,
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·
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Economic conditions,
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Energy efficiency programs, and/or
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·
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The loss of major customers, the loss of a large number of residential customers, or the addition of fewer new customers than expected.
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Significant volatility in wholesale oil prices could negatively impact margins and/or cause current and/or prospective full service customers to reduce their usage and/or purchase fuel from discount distributors.
Potential Impacts
Any one or more of the following could result from these events:
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·
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An adverse impact on Griffith’s ability to attract new full-service residential customers and retain existing full-service residential customers.
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Further sales volume reductions, and/or compressed margins.
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·
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Increased working capital requirements stemming from an increase in oil and/or propane prices.
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These events could materially reduce Griffith’s contribution to CH Energy Group’s earnings and cash flow.
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, remediation costs, court decisions and settlements resulting from any litigation could reduce earnings and cash flows.
Additional Information
See Note 12 - “Commitments and Contingencies” and in particular the sub-captions in Note 12 regarding “Asbestos Litigation” and “Former Manufactured Gas Plant Facilities” under the caption “Environmental Matters.”
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.
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Type of Electric Generating Plant
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Year Placed in Service/Refurbished
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MW(1) Net Capability
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Hydroelectric (3 stations)
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1920-1986
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22.4
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Gas turbine (2 stations)
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1969-1970
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42.5
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Total
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64.9
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(1) Reflects maximum one-hour net capability (winter rating as of December 31, 2011) of Central Hudson’s electric generating plants and therefore does not include firm purchases or sales.
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Central Hudson owns substations having an aggregate transformer capacity of 5.0 million kilovolt amperes. Central Hudson’s electric transmission system consists of 629 pole miles of line. The electric distribution system consists of approximately 7,300 pole miles of overhead lines and 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, 2011, occurred on July 22, 2011, and amounted to 1,225 MW. In prior summer periods peak electric demand has reached 1,295 MW which occurred on August 2, 2006. Central Hudson’s maximum one-hour demand for electricity within its own territory for that part of the 2011-2012 winter capability period through January 18, 2012, occurred on December 18, 2011, and amounted to 840 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 1,185 miles of distribution pipelines, as well as customer service lines and meters. For the year ended December 31, 2011, the total amount of natural gas purchased by Central Hudson from all sources was 11,456,822 Mcf. Central Hudson owns two propane-air mixing facilities, one located in Poughkeepsie, New York, and the other in Newburgh, New York. As of December 31, 2011, these facilities are no longer in service and are in the process of being dismantled. The cost to be incurred associated with the retirement of these facilities is not expected to be material and will have no impact on earnings.
The peak daily demand for natural gas of Central Hudson’s customers for the year ended December 31, 2011, and for that part of the 2011-2012 heating season through January 30, 2012, occurred on January 23, 2011 and amounted to 115,807 Mcf. In prior years, winter period daily peak demand has reached 125,496 Mcf which occurred on January 27, 2005. Central Hudson’s firm peak day natural gas capability in the 2011-2012 heating season was 134,484 Mcf.
Other Central Hudson Matters
Central Hudson owns its corporate headquarters located in Poughkeepsie, New York, as well as several district offices located throughout the Hudson Valley. 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, 2011, Central Hudson made gross property additions of $244.8 million and property retirements and adjustments of $40.4 million, resulting in a net increase (including construction work in progress) in gross utility plant of $204.4 million, or 16%.
CHEC
As of December 31, 2011, CHEC owned a 100% interest in Griffith. As of December 31, 2011, 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.
For information about developments regarding certain legal proceedings, see Note 12 - “Commitments and Contingencies” of this 10-K Annual Report.
Not applicable.
PART II
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 caption “Capital Resources and Liquidity - Financing Program” 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.
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Indexed Returns
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Base Period
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Years Ending
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Dec
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Dec
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Dec
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Dec
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Dec
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Dec
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||||||||||||||||||
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Company / Index
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2006
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2007
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2008
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2009
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2010
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2011
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CH Energy Group, Inc.
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$ | 100 | $ | 88.27 | $ | 107.80 | $ | 93.44 | $ | 113.08 | $ | 140.76 | ||||||||||||
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S&P 500 Index
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$ | 100 | $ | 105.49 | $ | 66.46 | $ | 84.05 | $ | 96.71 | $ | 98.76 | ||||||||||||
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EEI Index
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$ | 100 | $ | 116.56 | $ | 86.37 | $ | 95.62 | $ | 102.34 | $ | 122.80 | ||||||||||||
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COMMON STOCK DIVIDENDS AND PRICE RANGES
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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, 2011 and December 31, 2010 was $58.38 and $48.89, respectively. The price ranges and the dividends paid for each quarterly period during the last two fiscal years are as follows:
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2011
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2010
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High
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Low
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Dividend
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High
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Low
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Dividend
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||||||||||||||||||
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1st Quarter
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$ | 50.75 | $ | 47.44 | $ | 0.540 | $ | 43.57 | $ | 38.25 | $ | 0.540 | ||||||||||||
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2nd Quarter
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$ | 54.44 | $ | 48.76 | $ | 0.540 | $ | 43.47 | $ | 37.75 | $ | 0.540 | ||||||||||||
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3rd Quarter
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$ | 57.12 | $ | 48.00 | $ | 0.540 | $ | 44.77 | $ | 38.60 | $ | 0.540 | ||||||||||||
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4th Quarter
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$ | 59.67 | $ | 50.55 | $ | 0.555 | $ | 50.33 | $ | 43.72 | $ | 0.540 | ||||||||||||
In the third and fourth quarters of 2011, the Board of Directors of CH Energy Group declared a quarterly dividend of 55.5 cents per share. This dividend is an increase from the 54 cents per share declared to shareholders each quarter since 1998. This increase is consistent with CH Energy Group’s strategy which targets stable and predictable earnings, with growth trend expectations of 5% or more per year off a base of $2.76 in 2009 and the expectation to provide an annualized common stock dividend that is the higher of $2.22 per share or 65% to 70% of annual earnings. In declaring future dividends, CH Energy Group will evaluate all circumstances at the time of making such decisions, including business, financial, and regulatory considerations.
CH Energy Group’s ability to pay dividends to common shareholders is affected by the ability of its subsidiaries to pay dividends to the parent company. 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, 2011, Central Hudson would be able to pay a maximum of $44.6 million in dividends to CH Energy Group without violating the restrictions imposed 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. During the year ended December 31, 2011, Central Hudson declared and paid dividends of $43.0 million to CH Energy Group. CH Energy Group’s other subsidiaries do not have express restrictions on their ability to pay dividends.
The number of registered holders of Common Stock of CH Energy Group as of December 31, 2011 was 13,980.
All of the outstanding Common Stock of Central Hudson and all of the outstanding Common Stock of CHEC are held by CH Energy Group.
Beginning in the fourth quarter of 2010 CH Energy Group, using excess liquidity largely related to proceeds from divestitures, repurchased shares of its own common stock. For more information regarding CH Energy Group’s stock repurchase program, see the “Anticipated Sources and Uses of Cash” section of Item 7 - Management Discussion and Analysis.
The following table provides a summary of shares repurchased by CH Energy Group for the quarter ended December 31, 2011:
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Total Number of Shares Purchased
(1)
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Average Price
Paid per Share
(2)
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Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
(3)
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Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs
(3)
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October 1-31, 2011
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1,042
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$
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52.17
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-
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1,051,324
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November 1-30, 2011
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377
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$
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54.58
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-
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1,051,324
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December 1-31, 2011
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-
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$
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-
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-
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1,051,324
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Total
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1,419
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$
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52.81
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-
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(1)
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Consists of shares surrendered to CH Energy Group in satisfaction of tax withholdings on the vesting of restricted shares.
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(2)
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Value at which reacquired shares of CH Energy Group's common stock credited on the date the stock was surrendered.
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(3)
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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.
|
|||||||||
FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS AND SELECTED FINANCIAL DATA(1)
(CH ENERGY GROUP)
(In Thousands, except per share data)
|
2011
|
2010
|
2009
|
2008
|
2007
|
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Operating Revenues
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Electric - Delivery
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$ | 332,388 | $ | 317,023 | $ | 275,167 | $ | 242,334 | $ | 233,033 | ||||||||||
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Electric - Supply
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206,160 | 246,116 | 261,003 | 365,827 | 383,806 | |||||||||||||||
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Natural Gas - Delivery
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85,196 | 81,606 | 66,916 | 59,897 | 55,326 | |||||||||||||||
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Natural Gas - Supply
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76,778 | 75,189 | 107,221 | 129,649 | 110,123 | |||||||||||||||
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Competitive business subsidiaries
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284,998 | 240,174 | 211,250 | 330,254 | 287,882 | |||||||||||||||
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Total
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985,520 | 960,108 | 921,557 | 1,127,961 | 1,070,170 | |||||||||||||||
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Operating Income
|
99,589 | 99,303 | 81,585 | 70,701 | 76,426 | |||||||||||||||
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Income from continuing operations
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43,184 | 40,330 | 33,597 | 30,968 | 41,143 | |||||||||||||||
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Income (Loss) from discontinued operations, net of tax
|
3,126 | (1,128 | ) | 10,681 | 5,186 | 2,343 | ||||||||||||||
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Dividends declared on Preferred Stock of subsidiary
|
970 | 970 | 970 | 970 | 970 | |||||||||||||||
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Net Income attributable to CH Energy Group
|
45,340 | 38,504 | 43,484 | 35,081 | 42,636 | |||||||||||||||
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Dividends Declared on Common Stock
|
33,291 | 34,161 | 34,119 | 34,086 | 34,052 | |||||||||||||||
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Change in Retained Earnings
|
12,049 | 4,343 | 9,365 | 995 | 8,584 | |||||||||||||||
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Retained Earnings - beginning of year
|
230,342 | 225,999 | 216,634 | 215,639 | 207,055 | |||||||||||||||
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Retained Earnings - end of year
|
$ | 242,391 | $ | 230,342 | $ | 225,999 | $ | 216,634 | $ | 215,639 | ||||||||||
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Common Share Data:
|
||||||||||||||||||||
|
Average shares outstanding - basic
|
15,278 | 15,785 | 15,775 | 15,768 | 15,762 | |||||||||||||||
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Income from continuing operations - basic
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$ | 2.77 | $ | 2.51 | $ | 2.08 | $ | 1.89 | $ | 2.55 | ||||||||||
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Income from discontinued operations - basic
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$ | 0.20 | $ | (0.07 | ) | $ | 0.68 | $ | 0.33 | $ | 0.15 | |||||||||
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Net Income attributable to CH Energy Group - basic
|
$ | 2.97 | $ | 2.44 | $ | 2.76 | $ | 2.22 | $ | 2.70 | ||||||||||
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Average shares outstanding - diluted
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15,481 | 15,952 | 15,881 | 15,805 | 15,779 | |||||||||||||||
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Income from continuing operations - diluted
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$ | 2.73 | $ | 2.48 | $ | 2.07 | $ | 1.89 | $ | 1.89 | ||||||||||
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Income from discontinued operations - diluted
|
$ | 0.20 | $ | (0.07 | ) | $ | 0.68 | $ | 0.33 | $ | 0.15 | |||||||||
|
Net Income attributable to CH Energy Group - diluted
|
$ | 2.93 | $ | 2.41 | $ | 2.74 | $ | 2.22 | $ | 2.04 | ||||||||||
|
Dividends declared per share
|
$ | 2.19 | $ | 2.16 | $ | 2.16 | $ | 2.16 | $ | 2.16 | ||||||||||
|
Book value per share (at year-end)
|
$ | 32.88 | $ | 34.03 | $ | 33.76 | $ | 33.17 | $ | 33.19 | ||||||||||
|
Total Assets (at year-end)
|
$ | 1,730,112 | $ | 1,729,275 | $ | 1,697,883 | $ | 1,730,183 | $ | 1,494,748 | ||||||||||
|
Long-term Debt (at year-end)(2)
|
$ | 446,003 | $ | 502,959 | $ | 463,897 | $ | 413,894 | $ | 403,892 | ||||||||||
|
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)
|
$ | 502,248 | $ | 537,804 | $ | 553,502 | $ | 523,534 | $ | 523,148 | ||||||||||
|
(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)
|
2011
|
2010
|
2009
|
2008
|
2007
|
||||||||||||||||
|
Operating Revenues
|
|
|
|
|
|
|||||||||||||||
|
Electric - Delivery
|
$ | 332,388 | $ | 317,023 | $ | 275,167 | $ | 242,334 | $ | 233,033 | ||||||||||
|
Electric - Supply
|
206,160 | 246,116 | 261,003 | 365,827 | 383,806 | |||||||||||||||
|
Natural Gas - Delivery
|
85,196 | 81,606 | 66,916 | 59,897 | 55,326 | |||||||||||||||
|
Natural Gas - Supply
|
76,778 | 75,189 | 107,221 | 129,649 | 110,123 | |||||||||||||||
|
Total
|
700,522 | 719,934 | 710,307 | 797,707 | 782,288 | |||||||||||||||
|
Operating Income
|
95,526 | 94,848 | 76,338 | 67,344 | 71,406 | |||||||||||||||
|
Net Income
|
45,037 | 46,118 | 32,776 | 27,238 | 33,436 | |||||||||||||||
|
Dividends Declared on Cumulative Preferred Stock
|
970 | 970 | 970 | 970 | 970 | |||||||||||||||
|
Income Available for Common Stock
|
44,067 | 45,148 | 31,806 | 26,268 | 32,466 | |||||||||||||||
|
Dividends Declared to Parent - CH Energy Group
|
43,000 | 31,000 | - | - | 8,500 | |||||||||||||||
|
Change in Retained Earnings
|
1,067 | 14,148 | 31,806 | 26,268 | 23,966 | |||||||||||||||
|
Retained Earnings - beginning of year
|
164,898 | 150,750 | 118,944 | 92,676 | 68,710 | |||||||||||||||
|
Retained Earnings - end of year
|
$ | 165,965 | $ | 164,898 | $ | 150,750 | $ | 118,944 | $ | 92,676 | ||||||||||
|
Total Assets (at year-end)
|
$ | 1,602,381 | $ | 1,539,074 | $ | 1,485,600 | $ | 1,492,196 | $ | 1,252,694 | ||||||||||
|
Long-term Debt (at year-end)(2)
|
$ | 417,950 | $ | 453,900 | $ | 413,897 | $ | 413,894 | $ | 403,892 | ||||||||||
|
Cumulative Preferred Stock (at year-end)
|
$ | 21,027 | $ | 21,027 | $ | 21,027 | $ | 21,027 | $ | 21,027 | ||||||||||
|
Total Equity (at year-end)
|
$ | 445,295 | $ | 444,228 | $ | 430,080 | $ | 373,274 | $ | 347,006 | ||||||||||
|
(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.
|
INTRODUCTION
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations are 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 renewable energy investments and the holding company’s activities, which consist primarily of financing its subsidiaries.
|
|||
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 appreciation that is expected to result from earnings and dividend growth over the long-term.
Mission and Strategy
CH Energy Group’s mission is to provide electricity, natural gas, petroleum and related services to an expanding customer base in a safe, reliable, courteous and affordable manner; to produce growing financial returns for shareholders; to foster a culture that encourages employees to reach their full potential; and to be a good corporate citizen.
CH Energy Group endeavors to fulfill its mission, providing an attractive risk adjusted return to CH Energy Group shareholders, by executing our plan to:
|
·
|
Concentrate on energy distribution through Central Hudson in the Mid-Hudson Valley and through Griffith in the Mid-Atlantic region
|
|
·
|
Invest primarily in utility electric and natural gas transmission and distribution
|
|
·
|
Focus on risk management
|
|
·
|
Limit commodity exposure
|
|
·
|
Manage regulatory affairs effectively
|
|
·
|
Maintain a financial profile that supports a credit rating in the “A” category
|
|
·
|
Target stable and predictable earnings, with growth trend expectations of 5% or more per year off a base of $2.76 per share in 2009
|
|
·
|
Provide an annualized common stock dividend that is the higher of $2.22 per share or 65% to 70% of annual earnings
|
Implementation and Achievements
CH Energy Group has effectively completed the strategy transition announced in October 2010, reducing earnings risk and volatility while strengthening the foundation for future earnings growth. During 2011, CH Energy Group divested its significant renewable energy investments, repurchased $50 million of CH Energy Group Common Stock, repaid $20 million of CH Energy Group long-term debt, invested over $85 million in Central Hudson’s infrastructure, increased Central Hudson’s core earnings and invested approximately $4.5 million in new tuck-in acquisitions at Griffith. Based on the results of the strategy implementation, the Board of Directors of CH Energy Group approved an increase to the dividend in the third quarter of 2011 by approximately 3%; the first increase since 1998. The following charts depict the asset composition of CH Energy Group as of December 31, 2011 and 2010 which demonstrate the implementation of the announced strategy shift.
CH Energy Group Assets at December 31, 2011 and 2010
| Central Hudson | Griffith | Other Businesses and Investments |
During 2011, CH Energy Group has divested CHEC’s four largest renewable energy investments; Lyonsdale, Shirley Wind, CH-Auburn and CH-Greentree. The sale of these investments increased earnings by $2.3 million in 2011. Proceeds from the sales of these investments were used primarily for the repurchase of outstanding Common Stock of CH Energy Group and debt repayment. During 2011, approximately 949,000 shares, or 6% of CH Energy Group’s outstanding Common Stock, were repurchased. Additionally, a portion of the proceeds from the sale of Shirley Wind was used to pay down $20 million of CH Energy Group private placement debt.
Central Hudson’s electric and natural gas infrastructure are the core growth drivers of CH Energy Group. Central Hudson’s capital expenditures have grown over the past 5 years, totaling approximately $400 million over that period. Central Hudson expects to invest $300 million during the current three-year rate plan between July 1, 2010 and June 30, 2013, and similar or higher levels of capital expenditures beyond the three-year rate agreement.
Additionally, Griffith’s tuck-in acquisitions are expected to increase this business unit’s contributions to CH Energy Group’s earnings. Griffith resumed its acquisition activity at the end of 2010 and has successfully acquired 7 new businesses as of December 31, 2011. Additionally, Griffith was able to effectively manage costs to offset inflation and increase margins in an environment of high commodity prices and contracting customer demand for petroleum products.
With the successful implementation of the strategy transition, CH Energy Group’s management believes that it is well positioned to achieve its goal of a 5% earnings growth trend starting with 2009 as a base year.
The following information outlines the strategies for each of CH Energy Group’s business units, including a description of the business core competencies, investment opportunities, potential risks, and notable activity during 2011. Business unit contributions to operating revenues and net income for the years ended December 31, 2011, 2010 and 2009 are discussed in the Results of Operations section of this Management’s Discussion and Analysis.
Central Hudson
Business Description and Strategy
Central Hudson’s earnings are derived primarily from the revenue it generates from delivering energy to approximately 300,000 electric customers and 75,000 natural gas customers. The delivery rates Central Hudson charges its customers are set by the PSC and are designed to recover the cost of providing safe and reliable service to Central Hudson’s customers while providing the opportunity to earn a fair and reasonable return on the capital invested by shareholders.
Central Hudson’s strategy is to provide exceptional value to its customers by:
|
-
|
practicing continuous improvement in everything we do;
|
|
-
|
investing in transmission and infrastructure to enhance reliability, improve customer satisfaction and reduce risk;
|
|
-
|
moderating cost pressures that increase customer bill levels and variability; and
|
|
-
|
advocating on behalf of customers and other stakeholders.
|
Central Hudson believes that it has strong competencies in safe and efficient utility operations, financial management, risk management and regulatory affairs which will facilitate the achievement of its strategy. Central Hudson has bolstered its strategic and business planning processes and has formalized the goal alignment throughout all levels of the organization in an effort to meet or exceed the expectations of its key stakeholders.
Opportunities and Risks
Earnings growth is primarily expected to come from increases in net utility plant. Central Hudson invests significant capital on an annual basis to attach new customers to the system and to replace aging infrastructure. Central Hudson’s investments enhance safety and reliability, and improve customer satisfaction and reduce risk. Opportunities to enhance transmission and distribution systems and information systems technologies are evaluated and prioritized based on their designed benefits, projected costs, and estimated risks. Management continually monitors and evaluates its capital expenditure forecasts and project priorities, which include certain long-term investment opportunities in the system’s distribution infrastructure and potentially in gas and electric transmission.
Central Hudson continues to advance its cost management efforts and seek opportunities to improve existing business processes utilizing Lean Six Sigma techniques, which is a data driven approach to eliminating waste as well as improving efficiency and service quality. These incremental process improvements focus on producing more revenue, providing cost savings and creating quality improvements, thereby providing benefits for both CH Energy Group shareholders and Central Hudson customers. Central Hudson also recognizes the importance of innovation and encourages employees to create new value and opportunities to reduce costs and improve quality through event driven activities.
The key risks Management sees in achieving this strategy are the regulatory environment, cost management and the economy in Central Hudson’s service territory.
Central Hudson’s ability to meet its financial objectives is largely dependent on the consistency and appropriateness of the PSC’s ratemaking practices. Risks related to these practices include reduced allowed returns on equity and/or reduced probabilities of achieving allowed returns, an inability to recover the full costs of doing business, declining support for strong capital structures and credit ratings, changes in deferral accounting that increase volatility of earnings and/or defer cash recovery of our costs, elimination of RDMs and changes in the mechanisms currently in place for recovery of our commodity purchases. Additionally, lower interest rates could lead to a decrease in the authorized ROE in a future rate proceeding. Management believes Central Hudson’s commitments to providing safe and reliable service, customer satisfaction, operational excellence and promoting positive customer and regulatory relations are important for supportive regulatory relationships and obtaining full cost recovery and competitive returns for shareholders.
The current three-year rate plan, which commenced on July 1, 2010, reduces uncertainty and risk and supports investment in Central Hudson’s infrastructure to improve the quality of service to customers. The key provisions of the rate plan include an authorized regulatory return on equity of 10.0% and a 48% regulatory equity ratio; the continuation of a RDM; full recovery and deferral provisions for purchased electric and gas, MGP site remediation, pension and OPEB expenses. The rate plan also contains a number of service quality thresholds; performance below these thresholds entails financial penalties. Additionally, PSC staff approved and incorporated in the development of rates, Central Hudson’s capital expenditure budget for the term of the three-year rate plan, subject to the achievement of certain defined Net Plant targets. The PSC’s regulations also provide an opportunity to recover certain extraordinary expenditures that are not reflected in rates. However, the 3-pronged test criteria required for approval may limit Central Hudson from recovering some or all of such costs, reducing earnings for shareholders. Management believes the current rate plan and other regulatory orders under which Central Hudson operates demonstrate a constructive relationship with New York State regulators and the willingness of regulators to enable Central Hudson to earn stable, predictable returns while providing reliable, high quality service and fulfilling New York State energy policy objectives.
The impacts of laws and other regulations represent another risk to the Central Hudson strategy. In addition to the recovery of costs of operation, Central Hudson’s current rate structure includes a return on the utility’s projected rate base. Rate base represents Central Hudson’s investment in its utility infrastructure adjusted for certain required regulatory items. Changes in tax legislation or accounting can reduce the amount of Central Hudson rate base, reducing Central Hudson’s future rates and potential earnings. Central Hudson’s election to utilize bonus depreciation as it has been made available in recent years has had just such an impact. In addition, Central Hudson’s change to the accounting tax method related to costs to repair and maintain utility assets has resulted in an increase in its deferred tax liability and a decrease to rate base. For additional discussion of these tax items, see Note 4 – “Income Tax.”
Another risk is the ability to effectively manage costs, which is a key component of Central Hudson’s strategy. The continued implementation of Lean Six Sigma techniques to create value in existing business processes and innovation to create new value will play critical roles in managing the costs of doing business in a sustainable manner as well as result in continuous improvement in services provided to customers.
The fourth risk, the economy in Central Hudson’s service territory, affects the ability to collect receivables and the growth of utility rate base and earnings through a direct relationship to customer additions and peak demand growth. Management believes the economy in Central Hudson’s service territory has good long-term growth prospects, but unexpected prolonged downturns could inhibit its ability to meet long term business objectives.
Other Notable 2011 Activity
During 2011, Central Hudson experienced several significant weather related events which disrupted service to our customers and resulted in extensive damage to our infrastructure. Central Hudson’s dedicated management team and skilled labor force demonstrated their capabilities in executing organized and efficient emergency response and service restoration, while maintaining a strong focus on safety. Two of these weather related events, Tropical Storm Irene and the late October Snowfall event, were the second and third largest storms in Central Hudson’s history and Management’s current estimate for recoverable incremental costs associated with the electric service restoration efforts of these storms have been deferred for future recovery from customers. Central Hudson also incurred incremental costs associated with weather related gas emergencies early in 2011 and as a result of the impacts of Tropical Storm Irene; however these costs have not been deferred as of December 31, 2011 as they did not individually meet the PSC criteria for deferral accounting. Despite these severe weather events, Central Hudson was able to improve its service quality and customer satisfaction metrics significantly in 2011.
Additionally during 2011, Central Hudson earned energy efficiency incentives of $2.7 million based on calculated energy savings for completed and committed projects with residential and commercial customers compared to 2008-2011 cumulative savings targets as approved and defined by PSC Order through the Energy Efficiency Portfolio Standard (“EEPS”) proceedings.
For further discussions relating to the extraordinary storm events and earned Energy Efficiency Incentives, see Note 2 – “Regulatory Matters.”
Griffith
Business Description and Strategy
Griffith provides fuel distribution products and services to approximately 56,000 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 (“HVAC”) equipment. For a breakdown of Griffith’s gross profit by product and service line for the years ended December 31, 2011, 2010 and 2009, see the chart in the Results of Operations under the caption – “Griffith.”
Griffith’s strategy is to provide premium service to customers and to increase its profitability by:
|
-
|
practicing continuous improvement in everything we do;
|
|
-
|
growing through selective tuck-in acquisitions; and
|
|
-
|
expanding its service offerings.
|
Opportunities and Risks
Griffith has a strong regional brand that Management believes stands for quality, reliability, and value. Griffith intends to continue its marketing efforts and focus on customer satisfaction, which Management believes will help to minimize customer attrition. With reduced commodity-related volatility of earnings and cash flows following the 2009 divestiture of certain of its operations, Management has focused its attention on improving the profitability of operations and expanding products and services in the Mid-Atlantic region.
Griffith also continues to seek selective “tuck-in” acquisitions to be funded from internally generated cash. This growth strategy focuses on acquiring and retaining customers in geographic areas that overlap Griffith’s existing operations. Griffith expects to generate additional earnings and cash flow as a result of the expansion of its HVAC business. These growth strategies are not expected to result in the growth of CH Energy Group’s total invested capital in Griffith.
Management sees two key risks associated with this strategy. The primary factor that could prevent Griffith from achieving earnings growth is a sustained, significant increase in wholesale oil prices, which could reduce residential sales volumes, put downward pressure on margins and increase bad debt expense. While Management believes that margin expansion would still be possible in this environment as competitors would be forced to increase their prices to cover their costs, Management expects that this result would lag the increase in commodity prices. Additionally, weakness in the economy of the Mid-Atlantic region could limit Griffith’s ability to expand margins since customers’ willingness and ability to pay are typically tied to income levels and unemployment rates. Griffith limits the impact of weather on its business through the purchase of weather derivative instruments.
Notable 2011 Activity
In 2011, Griffith acquired six fuel distribution and service businesses and acquired one additional business effective January 1, 2012. These strategic acquisitions have already begun contributing to Griffith’s earnings and cash flows. However, during 2011 Griffith’s earnings were adversely impacted by both a weak economy and high fuel prices. The combination of both these events is not typical and resulted in increased customer conservation and attrition in 2011. Griffith also experienced a decline in the number of service installations under its expanded HVAC program in 2011, which Management believes resulted from increased installation activity at the end of 2010 driven by the expiration of federal tax credits. Despite the unfavorable environment, Management was successful in continuing its trend of increasing margins. Additionally, Griffith continues to implement effective cost management measures, which have successfully offset inflationary cost pressures. Management believes the current state of the economy and the reduced HVAC installations are temporary situations and that the long-term outlook of the economy in Griffith’s service territory continues to be strong with a stable pool of current and prospective customers that value quality service at a fair price.
Other Businesses and Investments
CHEC’s remaining two investments in renewable energy have zero fair value as of December 31, 2011. CHEC also has investments in 2 cogeneration partnerships and an energy sector venture capital fund totaling approximately $2.8 million as of December 31, 2011. These investments are not considered a part of the core business, are not expected to require significant management oversight, and no further capital investment in them is planned. Management intends to retain these remaining investments, but will continue to monitor market conditions to evaluate the fair market value of these investments and consider whether the opportunity exists to create greater shareholder value through divestitures. For further discussions relating to CHEC’s renewable energy investments, see Note 5 – “Acquisitions, Divestitures and Investments.”
EARNINGS PER SHARE AND OVERVIEW OF YEAR-TO-DATE RESULTS
The following discussion and analyses include explanations of significant changes in revenues and expenses between the year ended December 31, 2011, and 2010 and the year ended December 31, 2010, and 2009, 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 outstanding share of CH Energy Group’s Common Stock. Management believes that expressing the results in terms of the impact on shares of CH Energy Group is useful to investors because it shows the relative contribution of the various business units to CH Energy Group’s earnings. 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. Additionally, Management believes that the disclosure of Significant Events within each business unit provides investors with the context around the Company's results that is important in enabling them to ascertain the likelihood that past performance is indicative of future performance. 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):
|
|
2011
|
2010
|
2009
|
|||||||||
|
Average shares outstanding:
|
|
|
|
|||||||||
|
Basic
|
15,278 | 15,785 | 15,775 | |||||||||
|
Diluted
|
15,481 | 15,952 | 15,881 | |||||||||
|
|
||||||||||||
|
Earnings per share from continuing operations:
|
||||||||||||
|
Basic
|
$ | 2.77 | $ | 2.51 | $ | 2.08 | ||||||
|
Diluted
|
$ | 2.73 | $ | 2.48 | $ | 2.07 | ||||||
|
|
||||||||||||
|
Earnings per share from discontinued operations:
|
||||||||||||
|
Basic
|
$ | 0.20 | $ | (0.07 | ) | $ | 0.68 | |||||
|
Diluted
|
$ | 0.20 | $ | (0.07 | ) | $ | 0.67 | |||||
|
|
||||||||||||
|
Earnings per share:
|
||||||||||||
|
Basic
|
$ | 2.97 | $ | 2.44 | $ | 2.76 | ||||||
|
Diluted
|
$ | 2.93 | $ | 2.41 | $ | 2.74 | ||||||
|
|
||||||||||||
|
Return earned on average common equity
|
9.1 | % | 7.4 | % | 8.6 | % | ||||||
2011 AS COMPARED TO 2010
CH Energy Group Consolidated
Earnings per Share (Basic)
|
|
Year Ended December 31,
|
|
||||||||||
|
|
2011
|
2010
|
Change
|
|||||||||
|
Central Hudson - Electric
|
$ | 2.22 | $ | 2.10 | $ | 0.12 | ||||||
|
Central Hudson - Natural Gas
|
0.66 | 0.76 | (0.10 | ) | ||||||||
|
Griffith
|
0.10 | 0.11 | (0.01 | ) | ||||||||
|
Other Businesses and Investments
|
(0.01 | ) | (0.53 | ) | 0.52 | |||||||
|
Total CH Energy Group Consolidated Earnings, as reported
|
$ | 2.97 | $ | 2.44 | $ | 0.53 | ||||||
|
|
||||||||||||
|
Significant Events:
|
||||||||||||
|
Central Hudson
|
$ | (0.12 | ) | $ | 0.12 | $ | (0.24 | ) | ||||
|
Griffith
|
- | (0.02 | ) | 0.02 | ||||||||
|
Other Businesses and Investments
|
(0.06 | ) | (0.44 | ) | 0.38 | |||||||
|
Total Significant Events
|
$ | (0.18 | ) | $ | (0.34 | ) | $ | 0.16 | ||||
|
|
||||||||||||
|
CH Energy Group Consolidated Adjusted Earnings Per Share (non-GAAP):
|
||||||||||||
|
Central Hudson
|
$ | 3.00 | $ | 2.74 | $ | 0.26 | ||||||
|
Griffith
|
0.10 | 0.13 | (0.03 | ) | ||||||||
|
Other Businesses and Investments
|
0.05 | (0.09 | ) | 0.14 | ||||||||
|
Total CH Energy Group Consolidated Adjusted Earnings Per Share (non-GAAP)
|
$ | 3.15 | $ | 2.78 | $ | 0.37 | ||||||
Earnings for CH Energy Group totaled $2.97 per share in 2011, an increase of $0.53 per share from the same period in 2010 when earnings had been negatively impacted by impairments on two of its non-utility assets.
Details by business unit were as follows:
Central Hudson
Earnings per Share (Basic)
|
Year Ended December 31,
|
|
||||||||
|
2011
|
2010
|
Change
|
|||||||
|
Central Hudson - Electric
|
$ | 2.22 | $ | 2.10 | $ | 0.12 | |||
|
Central Hudson - Natural Gas
|
0.66 | 0.76 | (0.10 | ) | |||||
|
Total Central Hudson Earnings
|
$ | 2.88 | $ | 2.86 | $ | 0.02 | |||
|
Significant Events:
|
|||||||||
|
Uncollectible deferral in 2010
|
$ | - | $ | 0.12 | $ | (0.12 | ) | ||
|
Higher weather related restoration costs(1)
|
(0.31 | ) | - | (0.31 | ) | ||||
|
Energy efficiency incentives
|
0.10 | - | 0.10 | ||||||
|
Share accretion
|
0.09 | - | 0.09 | ||||||
|
Central Hudson Adjusted Earnings Per Share
|
$ | 3.00 | $ | 2.74 | $ | 0.26 | |||
|
Change
|
|||||||||
|
Delivery revenue
|
$ | 0.42 | |||||||
|
Higher property and other taxes
|
(0.12 | ) | |||||||
|
Higher depreciation
|
(0.11 | ) | |||||||
|
Higher trimming costs
|
(0.02 | ) | |||||||
|
Other
|
0.09 | ||||||||
| $ | 0.26 | ||||||||
|
(1)
|
Amount represents incremental costs incurred for weather related service restoration, including costs for outside contractor assistance in restoration efforts and higher than average internal expenses (such as overtime and materials), which did not meet the PSC criteria for deferral and therefore have not been deferred for future recovery from customers.
|
Earnings from Central Hudson's electric and natural gas operations increased in the year ended December 31, 2011 compared to 2010. After adjusting Central Hudson's earnings per share for the significant items displayed above, including incremental weather related restoration costs, earnings were $0.26 per share higher year-over-year. The single largest driver was an increase in delivery revenue resulting from mid-year delivery rate increases in both 2011 and 2010. This additional revenue was needed for increased operating costs such as those noted above and to provide a reasonable return to shareholders.
Griffith
Earnings per Share (Basic)
|
Year Ended December 31,
|
|
||||||||
|
2011
|
2010
|
Change
|
|||||||
|
Griffith - Fuel Distribution Earnings
|
$ | 0.10 | $ | 0.11 | $ | (0.01 | ) | ||
|
Significant Events:
|
|||||||||
|
Discontinued operations
|
$ | 0.02 | $ | - | $ | 0.02 | |||
|
Weather impact on sales
|
(0.02 | ) | (0.02 | ) | - | ||||
|
Griffith Adjusted Earnings Per Share
|
$ | 0.10 | $ | 0.13 | $ | (0.03 | ) | ||
|
Change
|
|||||||||
|
Weather-normalized sales (including conservation)
|
$ | (0.13 | ) | ||||||
|
Gross margin on petroleum sales
|
0.09 | ||||||||
|
Operating expenses
|
0.03 | ||||||||
|
Other
|
(0.02 | ) | |||||||
| $ | (0.03 | ) | |||||||
Griffith’s earnings decreased for the year ended December 31, 2011 compared to the same period in 2010. This decrease was primarily attributable to contractions in volume due to customer conservation that was brought on by a combination of the continued weak economy and higher wholesale fuel prices. Improved margins and lower operating costs offset a majority of this impact.
Other Businesses and Investments
Earnings per Share (Basic)
|
|
Year Ended December 31,
|
|
||||||||||
|
|
2011
|
2010
|
Change
|
|||||||||
|
Other Businesses & Investments Earnings
|
$ | (0.01 | ) | $ | (0.53 | ) | $ | 0.52 | ||||
|
|
||||||||||||
|
Significant Events:
|
||||||||||||
|
Renewable Investments:
|
||||||||||||
|
Ethanol investment impairment in 2010
|
$ | - | $ | (0.44 | ) | $ | 0.44 | |||||
|
Biomass impairment in 2010
|
- | (0.08 | ) | 0.08 | ||||||||
|
Wind investment impairment in 2011
|
(0.14 | ) | - | (0.14 | ) | |||||||
|
Gain from sales of renewable investments
|
0.17 | - | 0.17 | |||||||||
|
Pre-payment penalty on early retirement of debt following 2011 divestiture
|
(0.11 | ) | - | (0.11 | ) | |||||||
|
Operations
|
(0.02 | ) | (0.03 | ) | 0.01 | |||||||
|
Tax impacts
|
0.02 | - | 0.02 | |||||||||
|
|
||||||||||||
|
Income taxes related to deductions for prior periods
|
0.02 | 0.11 | (0.09 | ) | ||||||||
|
Other Businesses and Investments Adjusted Earnings Per Share
|
$ | 0.05 | $ | (0.09 | ) | $ | 0.14 | |||||
|
|
||||||||||||
| Change | ||||||||||||
|
Higher interest income
|
$ | 0.05 | ||||||||||
|
Lower interest expense
|
0.02 | |||||||||||
|
Lower income taxes
|
0.05 | |||||||||||
|
Other
|
0.02 | |||||||||||
|
|
$ | 0.14 | ||||||||||
The earnings activity of CH Energy Group (the holding company) and CHEC’s partnerships and other investments increased in the year ended December 31, 2011 compared to the same period in 2010. Net of the impacts of renewable investment activity and prior period income tax adjustments noted above, Other Businesses and Investments adjusted earnings per share increased $0.14 per share. This increase was primarily due to higher interest income related to intercompany debt and lower interest expense related to the pay down of debt with the proceeds from the sale of renewable investments.
2010 AS COMPARED TO 2009
CH Energy Group Consolidated
Earnings per Share (Basic)
|
|
Year Ended December 31,
|
|
||||||||||
|
|
2010
|
2009
|
Change
|
|||||||||
|
Central Hudson - Electric
|
$ | 2.10 | $ | 1.60 | $ | 0.50 | ||||||
|
Central Hudson - Natural Gas
|
0.76 | 0.42 | 0.34 | |||||||||
|
Griffith
|
0.11 | 0.76 | (0.65 | ) | ||||||||
|
Other Businesses and Investments
|
(0.53 | ) | (0.02 | ) | (0.51 | ) | ||||||
|
|
$ | 2.44 | $ | 2.76 | $ | (0.32 | ) | |||||
|
|
||||||||||||
|
Significant Events:
|
||||||||||||
|
Central Hudson
|
$ | 0.12 | $ | 0.26 | $ | (0.14 | ) | |||||
|
Griffith
|
(0.02 | ) | 0.63 | (0.65 | ) | |||||||
|
Other Businesses and Investments
|
(0.41 | ) | (0.06 | ) | (0.35 | ) | ||||||
|
Total CH Energy Group Consolidated Adjusted Earnings Per Share (non-GAAP)
|
$ | 2.75 | $ | 1.93 | $ | 0.82 | ||||||
Earnings for CH Energy Group totaled $2.44 per share in 2010, a decrease of $0.32 per share from the same period in 2009. The decrease in year-over-year earnings per share were driven primarily by the $0.34 2009 gain and $0.23 of discontinued operations from the Griffith divestiture and the 2010 impairments in two renewable energy investments, partially reduced by increased delivery rates at Central Hudson.
Detail by business unit were as follows:
Central Hudson
Earnings per Share (Basic)
|
Year Ended December 31,
|
|
||||||||||
|
2010
|
2009
|
Change
|
|||||||||
|
Central Hudson - Electric
|
$ | 2.10 | $ | 1.60 | $ | 0.50 | |||||
|
Central Hudson - Natural Gas
|
0.76 | 0.42 | 0.34 | ||||||||
|
Total Central Hudson Earnings
|
$ | 2.86 | $ | 2.02 | $ | 0.84 | |||||
|
Significant Events:
|
|||||||||||
|
Uncollectible deferral
|
$ | 0.12 | $ | 0.13 | $ | (0.01 | ) | ||||
|
Weather impact on sales
|
- | 0.13 | (0.13 | ) | |||||||
|
Central Hudson Adjusted Earnings Per Share
|
$ | 2.74 | $ | 1.76 | $ | 0.98 | |||||
|
Change
|
|||||||||||
|
Delivery revenue
|
$ | 1.22 | |||||||||
|
Lower uncollectible reserves
|
0.17 | ||||||||||
|
Higher trimming costs
|
(0.06 | ) | |||||||||
|
Higher storm restoration expense(1)
|
(0.13 | ) | |||||||||
|
Higher depreciation
|
(0.11 | ) | |||||||||
|
Higher property and other taxes
|
(0.17 | ) | |||||||||
|
Other
|
0.06 | ||||||||||
| $ | 0.98 | ||||||||||
|
(1)
|
Excludes incremental costs incurred associated with the severe storms that occurred in late February 2010, which have been deferred for future recovery from customers.
|
Earnings from Central Hudson's electric and natural gas operations increased in the year ended December 31, 2010 compared to 2009 primarily due to the increases in electric and natural gas delivery rates, including the RDM, which became effective July 1, 2009 and 2010. These increases provided revenues that better align with Central Hudson's costs of providing safe and reliable service to customers and provide an opportunity to earn an appropriate return for shareholders. Higher operating expenses partially offset the favorable impacts of delivery rate increases. The net increase in year-over-year results includes the impact of lower earnings during the first six months of 2009 resulting from the sales shortfall under the expiring 2006 Rate Order.
Griffith
Earnings per Share (Basic)
|
Year Ended December 31,
|
|
||||||||||
|
2010
|
2009
|
Change
|
|||||||||
|
Griffith - Fuel Distribution Earnings
|
$ | 0.11 | $ | 0.76 | $ | (0.65 | ) | ||||
|
Significant Events:
|
|||||||||||
|
Discontinued operations
|
$ | - | $ | 0.23 | $ | (0.23 | ) | ||||
| Weather impact on sales (including hedging) | (0.02 | ) | 0.02 | (0.04 | ) | ||||||
|
Gain on sale of Northeast operations(1)
|
- | 0.40 | (0.40 | ) | |||||||
|
Griffith Adjusted Earnings Per Share
|
$ | 0.13 | $ | 0.11 | $ | 0.02 | |||||
|
Change
|
|||||||||||
|
Margin on petroleum sales and services
|
$ | 0.01 | |||||||||
|
Weather normalized sales (including conservation)
|
(0.05 | ) | |||||||||
|
Lower operating expenses
|
0.06 | ||||||||||
|
Lower uncollectible accounts
|
0.04 | ||||||||||
|
Other
|
(0.04 | ) | |||||||||
| $ | 0.02 | ||||||||||
|
(1) See additional taxes owed by CH Energy Group within Other Businesses & Investments
|
Griffith’s earnings decreased for the year ended December 31, 2010 compared to the same period in 2009. This decrease was primarily attributable to the sale of operations in certain geographic locations at the end of 2009. The gain recorded as a result of the sale and the decreased customer base resulted in a decrease in 2010 earnings as compared to 2009. Unfavorable impacts of weather and continued customer conservation also contributed to the decreased earnings, but were offset by lower operating expenses resulting from cost reductions implemented by Management to align its cost structure to its smaller size following the partial divestiture. Lower uncollectible accounts also favorably impacted 2010 results.
Other Businesses and Investments
Earnings per Share (Basic)
|
|
Year Ended December 31,
|
|
|||||||||
|
|
2010
|
2009
|
Change
|
||||||||
|
Other Businesses & Investment Earnings
|
$ | (0.53 | ) | $ | (0.02 | ) | $ | (0.51 | ) | ||
|
|
|||||||||||
|
Significant Events:
|
|||||||||||
|
Ethanol investment impairment
|
$ | (0.44 | ) | $ | - | $ | (0.44 | ) | |||
|
Biomass investment impairment
|
(0.08 | ) | - | (0.08 | ) | ||||||
|
Lower income taxes
|
0.11 | - | 0.11 | ||||||||
|
Holding company's income taxes on Griffith sale
|
- | (0.06 | ) | 0.06 | |||||||
|
Other Businesses and Investments Adjusted Earnings Per Share
|
$ | (0.12 | ) | $ | 0.04 | $ | (0.16 | ) | |||
|
|
|||||||||||
|
|
Change
|
||||||||||
|
Renewable Energy Investments
|
$ | (0.11 | ) | ||||||||
|
Holding company interest expense
|
(0.05 | ) | |||||||||
|
|
$ | (0.16 | ) | ||||||||
The earnings activity of CH Energy Group (the holding company) and CHEC’s partnerships and other investments decreased in the year ended December 31, 2010 compared to the same period in 2009 primarily due to 2010 impairment charges for CHEC's ethanol and biomass investments. The expiration of production tax credits related to CHEC’s biomass investment on December 31, 2009 and a repair to the plant's steam turbine also negatively impacted earnings. CHEC's earnings from its ethanol investment were also lower in 2010 due to lower crush margins and lower prices for one of the byproducts of the production process. These decreases were partially reduced by a favorable change to the effective tax rate of the consolidated entity resulting in overall lower tax expense. The additional taxes in 2009 related to Griffith's partial divestiture.
RESULTS OF OPERATIONS
A breakdown by business unit of CH Energy Group's operating revenues (net of divestitures) and net income for the year ended December 31, 2011 and 2010 are illustrated below (Dollars in Thousands):
|
Year Ended December 31, 2011
|
Year Ended December 31, 2010
|
|||||||||||||||||||||||||||||||
|
Business Unit
|
Operating
Revenues
|
Net Income (loss) attributable to CH Energy Group
|
Operating
Revenues
|
Net Income (loss) attributable to CH Energy Group
|
||||||||||||||||||||||||||||
|
Electric(1)
|
$ | 538,548 | 55 | % | $ | 33,936 | 75 | % | $ | 563,139 | 59 | % | $ | 33,125 | 86 | % | ||||||||||||||||
|
Gas(1)
|
161,974 | 16 | % | 10,131 | 23 | % | 156,795 | 16 | % | 12,023 | 31 | % | ||||||||||||||||||||
|
Total Central Hudson
|
700,522 | 71 | % | 44,067 | 98 | % | 719,934 | 75 | % | 45,148 | 117 | % | ||||||||||||||||||||
|
Griffith(1), (2)
|
284,998 | 29 | % | 1,503 | 3 | % | 240,174 | 25 | % | 1,774 | 5 | % | ||||||||||||||||||||
|
Other Businesses and Investments(3)
|
- | - | % | (230 | ) | (1 | ) % | - | - | % | (8,418 | ) | (22 | ) % | ||||||||||||||||||
|
Total CH Energy Group
|
$ | 985,520 | 100 | % | $ | 45,340 | 100 | % | $ | 960,108 | 100 | % | $ | 38,504 | 100 | % | ||||||||||||||||
|
(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 2011: 21% cost recovery revenues + 34% other revenues = 55%
|
|
|
|
Electric 2010: 26% cost recovery revenues + 33% other revenues = 59%
|
|
|
|
Natural Gas 2011: 8% cost recovery revenues + 8% other revenues = 16%
|
|
|
|
Natural Gas 2010: 8% cost recovery revenues + 8% other revenues = 16%
|
|
|
|
Griffith 2011: 23% cost recovery revenues + 6% other revenues = 29%
|
|
|
|
Griffith 2010: 19% cost recovery revenues + 6% other revenues = 25%
|
|
|
(2)
|
Net income for Griffith for the year ended December 31, 2011 includes net income from discontinued operations of $277.
|
|
|
(3)
|
Net income for Other Businesses and Investments for the years ended December 31, 2011 and 2010 includes net income/(loss) from discontinued operations of $2,849 and ($1,128), respectively.
|
|
Central Hudson
The following discussions and analyses include explanations of significant changes in operating revenues, operating expenses, volumes delivered, other income, interest charges, and income taxes between the years ended December 31, 2011 and 2010, and December 31, 2010 and 2009 for Central Hudson’s regulated electric and natural gas businesses.
Income Statement Variances
(Dollars In Thousands)
|
|
Year Ended December 31,
|
Increase/(Decrease) in
|
||||||||||||||
|
|
2011
|
2010
|
Amount
|
Percent
|
||||||||||||
|
Operating Revenues
|
$ | 700,522 | $ | 719,934 | $ | (19,412 | ) | (2.7 | ) % | |||||||
|
|
||||||||||||||||
|
Operating Expenses:
|
||||||||||||||||
|
Purchased electricity, fuel and natural gas
|
282,938 | 321,305 | (38,367 | ) | (11.9 | ) % | ||||||||||
|
Depreciation and amortization
|
35,475 | 33,815 | 1,660 | 4.9 | % | |||||||||||
|
Other operating expenses
|
286,583 | 269,966 | 16,617 | 6.2 | % | |||||||||||
|
Total Operating Expenses
|
604,996 | 625,086 | (20,090 | ) | (3.2 | ) % | ||||||||||
|
Operating Income
|
95,526 | 94,848 | 678 | 0.7 | % | |||||||||||
|
Other Income, net
|
6,879 | 3,282 | 3,597 | 109.6 | % | |||||||||||
|
Interest Charges
|
29,191 | 25,848 | 3,343 | 12.9 | % | |||||||||||
|
Income before income taxes
|
73,214 | 72,282 | 932 | 1.3 | % | |||||||||||
|
Income Taxes
|
28,177 | 26,164 | 2,013 | 7.7 | % | |||||||||||
|
Net income
|
$ | 45,037 | $ | 46,118 | $ | (1,081 | ) | (2.3 | ) % | |||||||
|
|
Year Ended December 31,
|
Increase/(Decrease) in
|
||||||||||||||
|
|
2010
|
2009
|
Amount
|
Percent
|
||||||||||||
|
Operating Revenues
|
$ | 719,934 | $ | 710,307 | $ | 9,627 | 1.4 | % | ||||||||
|
|
||||||||||||||||
|
Operating Expenses:
|
||||||||||||||||
|
Purchased electricity, fuel and natural gas
|
321,305 | 368,224 | (46,919 | ) | (12.7 | ) % | ||||||||||
|
Depreciation and amortization
|
33,815 | 32,094 | 1,721 | 5.4 | % | |||||||||||
|
Other operating expenses
|
269,966 | 233,651 | 36,315 | 15.5 | % | |||||||||||
|
Total Operating Expenses
|
625,086 | 633,969 | (8,883 | ) | (1.4 | ) % | ||||||||||
|
Operating Income
|
94,848 | 76,338 | 18,510 | 24.2 | % | |||||||||||
|
Other Income, net
|
3,282 | 2,465 | 817 | 33.1 | % | |||||||||||
|
Interest Charges
|
25,848 | 24,885 | 963 | 3.9 | % | |||||||||||
|
Income before income taxes
|
72,282 | 53,918 | 18,364 | 34.1 | % | |||||||||||
|
Income Taxes
|
26,164 | 21,142 | 5,022 | 23.8 | % | |||||||||||
|
Net income
|
$ | 46,118 | $ | 32,776 | $ | 13,342 | 40.7 | % | ||||||||
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 2011 compared to 2010, and in 2010 compared to 2009. Deliveries of electricity and natural gas to residential and commercial customers have historically contributed the most to Central Hudson's earnings. Industrial sales and interruptible sales have a negligible impact on earnings. Beginning July 1, 2009, Central Hudson’s delivery rate structure includes a RDM 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 do not have a significant impact on Central Hudson’s earnings.
Electric Deliveries
(In Gigawatt-Hours)
|
Actual Deliveries
|
Weather Normalized Deliveries(1)
|
||||||||||||||||||||||||||||||||
|
Year Ended
|
|
|
Year Ended
|
|
|
||||||||||||||||||||||||||||
|
December 31,
|
Variation in
|
December 31,
|
Variation in
|
||||||||||||||||||||||||||||||
|
2011
|
2010
|
Amount
|
Percent
|
2011
|
2010
|
Amount
|
Percent
|
||||||||||||||||||||||||||
|
Residential
|
2,105 | 2,098 | 7 | - | % | 2,055 | 2,058 | (3 | ) | - |
%
|
||||||||||||||||||||||
|
Commercial
|
1,962 | 1,968 | (6 | ) | - | % | 1,939 | 1,945 | (6 | ) | - |
%
|
|||||||||||||||||||||
|
Industrial and other
|
1,113 | 1,149 | (36 | ) | (3 | ) % | 1,111 | 1,150 | (39 | ) | (3 | ) |
%
|
||||||||||||||||||||
|
Total Deliveries
|
5,180 | 5,215 | (35 | ) | (1 | ) % | 5,105 | 5,153 | (48 | ) | (1 | ) |
%
|
||||||||||||||||||||
|
Actual Deliveries
|
Weather Normalized Deliveries(1)
|
||||||||||||||||||||||||||||||||
|
Year Ended
|
|
|
Year Ended
|
|
|
||||||||||||||||||||||||||||
|
December 31,
|
Variation in
|
December 31,
|
Variation in
|
||||||||||||||||||||||||||||||
|
2010
|
2009
|
Amount
|
Percent
|
2010
|
2009
|
Amount
|
Percent
|
||||||||||||||||||||||||||
|
Residential
|
2,098 | 2,023 | 75 | 4 | % | 2,058 | 2,076 | (18 | ) | (1 | ) |
%
|
|||||||||||||||||||||
|
Commercial
|
1,968 | 1,945 | 23 | 1 | % | 1,945 | 1,970 | (25 | ) | (1 | ) |
%
|
|||||||||||||||||||||
|
Industrial and other
|
1,149 | 1,206 | (57 | ) | (5 | ) % | 1,150 | 1,208 | (58 | ) | (5 | ) |
%
|
||||||||||||||||||||
|
Total Deliveries
|
5,215 | 5,174 | 41 | 1 | % | 5,153 | 5,254 | (101 | ) | (2 | ) |
%
|
|||||||||||||||||||||
|
(1)
|
Central Hudson uses an internal analysis based on historical weather data to remove the estimated impacts of weather on delivery volumes.
|
Natural Gas Deliveries
(In Million Cubic Feet)
|
Actual Deliveries
|
Weather Normalized Deliveries(1)
|
||||||||||||||||||||||||||||||||
|
Year Ended
|
|
|
Year Ended
|
|
|
||||||||||||||||||||||||||||
|
December 31,
|
Variation in
|
December 31,
|
Variation in
|
||||||||||||||||||||||||||||||
|
2011
|
2010
|
Amount
|
Percent
|
2011
|
2010
|
Amount
|
Percent
|
||||||||||||||||||||||||||
|
Residential
|
5,126 | 4,828 | 298 | 6 | % | 5,229 | 5,087 | 142 | 3 |
%
|
|||||||||||||||||||||||
|
Commercial
|
6,538 | 5,899 | 639 | 11 | % | 6,668 | 6,136 | 532 | 9 |
%
|
|||||||||||||||||||||||
|
Industrial and other(2)
|
6,490 | 8,645 | (2,155 | ) | (25 | ) % | 2,088 | 2,264 | (176 | ) | (8 | ) |
%
|
||||||||||||||||||||
|
Total Deliveries
|
18,154 | 19,372 | (1,218 | ) | (6 | ) % | 13,985 | 13,487 | 498 | 4 |
%
|
||||||||||||||||||||||
|
Actual Deliveries
|
Weather Normalized Deliveries(1)
|
||||||||||||||||||||||||||||||||
|
Year Ended
|
|
|
Year Ended
|
|
|
||||||||||||||||||||||||||||
|
December 31,
|
Variation in
|
December 31,
|
Variation in
|
||||||||||||||||||||||||||||||
|
2010
|
2009
|
Amount
|
Percent
|
2010
|
2009
|
Amount
|
Percent
|
||||||||||||||||||||||||||
|
Residential
|
4,828 | 5,125 | (297 | ) | (6 | ) % | 5,087 | 5,024 | 63 | 1 |
%
|
||||||||||||||||||||||
|
Commercial
|
5,899 | 6,284 | (385 | ) | (6 | ) % | 6,136 | 6,151 | (15 | ) | - |
%
|
|||||||||||||||||||||
|
Industrial and other(2)
|
8,645 | 4,652 | 3,993 | 86 | % | 2,264 | 2,043 | 221 | 11 |
%
|
|||||||||||||||||||||||
|
Total Deliveries
|
19,372 | 16,061 | 3,311 | 21 | % | 13,487 | 13,218 | 269 | 2 |
%
|
|||||||||||||||||||||||
|
(1)
|
Central Hudson uses an internal analysis based on historical weather data to remove the estimated impacts of weather on delivery volumes.
|
|
(2)
|
Actual deliveries include interruptible natural gas deliveries. Weather normalized deliveries exclude interruptible natural gas deliveries.
|
2011 vs. 2010
Total electric deliveries to residential, commercial, and industrial customers were essentially unchanged for the year ended December 31, 2011 as compared to the prior year. The favorable impacts of colder weather in the first half of the year were offset by unfavorable impacts of cooler weather during the summer compared to the prior year as well as warmer weather at the end of 2011 compared to 2010.
Total natural gas deliveries to residential and commercial customers increased during the year ended December 31, 2011 as compared to 2010 which is due to both an increase in sales per customer as well as the favorable impact of colder weather experienced during heating season peak months in the first half of 2011 compared to 2010.
The decrease in natural gas industrial and other deliveries in 2011 compared to 2010 was driven primarily by a decrease in transportation delivery volumes to electric generation facilities, which sell their electricity to the NYISO market. The output of the facilities increased in 2010 to meet the increased electric demand during that period.
2010 vs. 2009
Electric deliveries to residential and commercial customers increased during the year ended December 31, 2010 as compared to the prior year primarily as a result of the year-over-year impact of both the warmer than normal summer of 2010 and cooler than normal summer weather in 2009 partially offset by lower use per customer.
Natural gas deliveries to residential and commercial customers decreased during the year ended December 31, 2010 as compared to 2009 primarily as a result of unfavorable warmer than normal weather during the first quarter of 2010, despite a weather normalized increased use per customer during the year.
The increase in natural gas industrial and other deliveries for the year ended December 31, 2010 as compared to the prior year was primarily driven by an increase in transportation delivery volumes to electric generation facilities, which sell their electricity to the NYISO market.
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 - Electric
(In Thousands)
|
Year Ended
|
|
Year Ended
|
|
|||||||||||||||||||||
|
December 31,
|
Increase /
|
December 31,
|
Increase /
|
|||||||||||||||||||||
|
2011
|
2010
|
(Decrease)
|
2010
|
2009
|
(Decrease)
|
|||||||||||||||||||
|
Revenues with Matching Expense Offsets:(1)
|
|
|
|
|
|
|
||||||||||||||||||
|
Energy cost adjustment
|
$ | 201,731 | $ | 241,709 | $ | (39,978 | ) | $ | 241,709 | $ | 256,959 | $ | (15,250 | ) | ||||||||||
|
Sales to others for resale
|
4,429 | 4,407 | 22 | 4,407 | 4,044 | 363 | ||||||||||||||||||
|
Other revenues with matching offsets
|
83,533 | 81,678 | 1,855 | 81,678 | 60,594 | 21,084 | ||||||||||||||||||
|
Subtotal
|
289,693 | 327,794 | (38,101 | ) | 327,794 | 321,597 | 6,197 | |||||||||||||||||
|
Revenues Impacting Earnings:
|
||||||||||||||||||||||||
|
Customer sales
|
230,272 | 220,338 | 9,934 | 220,338 | 196,884 | 23,454 | ||||||||||||||||||
|
Energy efficiency incentives
|
2,719 | - | 2,719 | - | - | - | ||||||||||||||||||
|
RDM and other regulatory mechanisms
|
5,652 | 4,753 | 899 | 4,753 | 8,876 | (4,123 | ) | |||||||||||||||||
|
Pole attachments and other rents
|
4,215 | 4,085 | 130 | 4,085 | 3,956 | 129 | ||||||||||||||||||
|
Finance charges
|
3,428 | 3,297 | 131 | 3,297 | 3,388 | (91 | ) | |||||||||||||||||
|
Other revenues
|
2,569 | 2,872 | (303 | ) | 2,872 | 1,469 | 1,403 | |||||||||||||||||
|
Subtotal
|
248,855 | 235,345 | 13,510 | 235,345 | 214,573 | 20,772 | ||||||||||||||||||
|
Total Electric Revenues
|
$ | 538,548 | $ | 563,139 | $ | (24,591 | ) | $ | 563,139 | $ | 536,170 | $ | 26,969 | |||||||||||
|
(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 costs. Other related costs include authorized business expenses recovered through rates and the cost of special programs authorized by the PSC and 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.
|
Change in Central Hudson Revenues - Natural Gas
(In Thousands)
|
Year Ended
|
|
Year Ended
|
|
|||||||||||||||||||||
|
December 31,
|
Increase /
|
December 31,
|
Increase /
|
|||||||||||||||||||||
|
2011
|
2010
|
(Decrease)
|
2010
|
2009
|
(Decrease)
|
|||||||||||||||||||
|
Revenues with Matching Expense Offsets:(1)
|
|
|
|
|
|
|
||||||||||||||||||
|
Energy cost adjustment
|
$ | 54,264 | $ | 50,236 | $ | 4,028 | $ | 50,236 | $ | 78,766 | $ | (28,530 | ) | |||||||||||
|
Sales to others for resale
|
20,228 | 23,023 | (2,795 | ) | 23,023 | 26,968 | (3,945 | ) | ||||||||||||||||
|
Other revenues with matching offsets
|
21,420 | 19,360 | 2,060 | 19,360 | 13,176 | 6,184 | ||||||||||||||||||
|
Subtotal
|
95,912 | 92,619 | 3,293 | 92,619 | 118,910 | (26,291 | ) | |||||||||||||||||
|
Revenues Impacting Earnings:
|
||||||||||||||||||||||||
|
Customer sales
|
60,059 | 52,665 | 7,394 | 52,665 | 46,359 | 6,306 | ||||||||||||||||||
|
RDM and other regulatory mechanisms
|
(192 | ) | 5,398 | (5,590 | ) | 5,398 | 3,722 | 1,676 | ||||||||||||||||
|
Interruptible profits
|
2,527 | 2,325 | 202 | 2,325 | 1,591 | 734 | ||||||||||||||||||
|
Finance charges
|
1,117 | 1,005 | 112 | 1,005 | 1,140 | (135 | ) | |||||||||||||||||
|
Other revenues
|
2,551 | 2,783 | (232 | ) | 2,783 | 2,415 | 368 | |||||||||||||||||
|
Subtotal
|
66,062 | 64,176 | 1,886 | 64,176 | 55,227 | 8,949 | ||||||||||||||||||
|
Total Natural Gas Revenues
|
$ | 161,974 | $ | 156,795 | $ | 5,179 | $ | 156,795 | $ | 174,137 | $ | (17,342 | ) | |||||||||||
|
(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 natural gas costs. Other related costs include authorized business expenses recovered through rates and the cost of special programs authorized by the PSC and funded with certain available credits. For natural gas sales to other entities for resale, 85% of such profits are returned to customers.
|
Electric revenues decreased for the year ended December 31, 2011 as compared to 2010, primarily due to lower energy cost adjustment revenues. The lower energy cost adjustment revenues are due to lower wholesale prices, and to a lesser extent, lower purchased volumes, partially reduced by an increase in revenues required to be recovered for previously deferred purchased electricity costs. An increase in delivery revenues as a result of higher delivery rates as prescribed in the 2010 Rate Order, and the 2011 incentive earned through the Energy Efficiency Portfolio Standard also partially offset the decrease in electric revenues.
Electric revenues increased for the year ended December 31, 2010 as compared to the same period in 2009 primarily due to higher delivery rates and higher other revenues with matching offsets. These increases were reduced by a decrease in regulatory revenue recovery mechanisms primarily RDMs, and lower energy cost adjustment revenues as a result of lower purchased volumes and wholesale prices, as well as a decrease in revenues required to be recovered for previously deferred purchased electric costs.
Natural gas revenues increased for the year ended December 31, 2011 as compared to the same period in 2010 primarily due to higher customer sales, energy cost adjustment revenues and other revenues with matching offsets. These increases were partially reduced by lower regulatory recovery revenue, primarily RDMs, and lower sales to others for resale. Increased gas revenues from customer sales are due to higher delivery rates as prescribed in the 2010 Rate Order. The higher gas energy cost adjustment revenues for 2011 resulted primarily from higher revenues required to be recovered from previously deferred gas costs partially reduced by lower purchased volumes and lower wholesale gas prices. Negative RDMs in 2011 are a result of an excess of actual delivery revenue in the current year over the levels provided in PSC approved rates. Positive RDMs in 2010 are a result of a deficit of actual delivery revenues compared to levels provided in PSC approved rates for that period. These amounts are set aside for future recovery from or return to customers.
Natural gas revenues decreased for the year ended December 31, 2010 as compared to the same period in 2009 primarily due to lower energy cost adjustment revenues and lower sales to others for resale partially reduced by higher delivery rates, higher other revenues with matching offsets and higher revenues related to regulatory revenue recovery mechanisms, primarily RDMs. Lower energy cost adjustment revenues resulted primarily from lower natural gas prices, as well as a decrease in purchased volume and revenues required to be recovered for previously deferred purchased natural gas costs.
Higher other revenues with matching offsets for both periods and for both electric and gas revenues were primarily driven by the Temporary State Assessment and New York State (“NYS”) energy efficiency programs. During 2010, an increase in rates compared to 2009 related to increased pension costs also contributed to higher other revenues with matching offsets for both electric and gas revenues.
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 and customer satisfaction.
The net results of these and previous earnings sharing arrangements had the effect of increasing pre-tax earnings by $0.8 million in 2011, $0.5 million in 2010, and $0.1 million in 2009.
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. For the period from July 1, 2009 through June 30, 2010, Central Hudson was no longer required per the 2009 Rate Order to share earnings. Beginning July 1, 2010 through June 30, 2013, per the 2010 Rate Order, Central Hudson is once again required to share with customers earnings over an earned ROE of 10.5% on the equity portion of Central Hudson’s rate base. Central Hudson did not record shared earnings in 2011, 2010 or 2009. See Note 2 - “Regulatory Matters” of this 10-K Annual Report under the captions “2006 Rate Order” and “2010 Rate Order” for a description of earnings sharing formulas approved by the PSC for Central Hudson.
During 2009 and 2010, Central Hudson received approval through the Energy Efficiency Portfolio Standard (“EEPS”) proceedings to implement various programs to electric and natural gas residential and commercial customers. In December 2010, the PSC issued an order combining energy savings targets to create a single 2008-2011 target and continuing the system of utility shareholder financial incentives established in the EEPS proceeding. As of December 31, 2011, Central Hudson achieved enough projected savings through committed contracts with residential and commercial customers to earn $2.7 million in incentives under the 2008-2011 defined targets.
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 pensions and OPEBs, the Temporary State Assessment, and NYS energy efficiency programs.
Total utility operating expenses decreased 3% in 2011 compared to the same period in 2010 and decreased 1.5% in 2010 as compared to 2009. The following summarizes the change in operating expenses:
Change in Central Hudson Operating Expenses
(In Thousands)
|
Year Ended
|
|
Year Ended
|
|
|||||||||||||||||||||
|
December 31,
|
Increase /
|
December 31,
|
Increase /
|
|||||||||||||||||||||
|
2011
|
2010
|
(Decrease)
|
2010
|
2009
|
(Decrease)
|
|||||||||||||||||||
|
Expenses Currently Matched to Revenues:(1)
|
|
|
|
|
|
|
||||||||||||||||||
|
Purchased electricity
|
$ | 206,160 | $ | 246,116 | $ | (39,956 | ) | $ | 246,116 | $ | 261,003 | $ | (14,887 | ) | ||||||||||
|
Purchased natural gas
|
74,492 | 73,259 | 1,233 | 73,259 | 105,734 | (32,475 | ) | |||||||||||||||||
|
Temporary State Assessment
|
20,524 | 18,781 | 1,743 | 18,781 | 7,115 | 11,666 | ||||||||||||||||||
|
Pension
|
25,826 | 28,539 | (2,713 | ) | 28,539 | 20,139 | 8,400 | |||||||||||||||||
|
OPEB
|
6,634 | 6,722 | (88 | ) | 6,722 | 8,316 | (1,594 | ) | ||||||||||||||||
|
NYS energy programs
|
27,722 | 25,640 | 2,082 | 25,640 | 20,253 | 5,387 | ||||||||||||||||||
|
MGP site remediations
|
4,488 | 3,624 | 864 | 3,624 | 2,188 | 1,436 | ||||||||||||||||||
|
Other matched expenses
|
19,759 | 17,732 | 2,027 | 17,732 | 15,759 | 1,973 | ||||||||||||||||||
|
Subtotal
|
385,605 | 420,413 | (34,808 | ) | 420,413 | 440,507 | (20,094 | ) | ||||||||||||||||
|
Other Expense Variations:
|
||||||||||||||||||||||||
|
Tree trimming
|
14,898 | 14,354 | 544 | 14,354 | 12,914 | 1,440 | ||||||||||||||||||
|
Property and school taxes(2)
|
35,064 | 31,173 | 3,891 | 31,173 | 27,787 | 3,386 | ||||||||||||||||||
|
Weather related service restoration (3)
|
15,090 | 7,062 | 8,028 | 7,062 | 3,584 | 3,478 | ||||||||||||||||||
|
Depreciation
|
35,475 | 33,815 | 1,660 | 33,815 | 32,094 | 1,721 | ||||||||||||||||||
|
Uncollectible expense
|
7,157 | 7,644 | (487 | ) | 7,644 | 12,160 | (4,516 | ) | ||||||||||||||||
|
Uncollectible deferrals
|
- | (3,702 | ) | 3,702 | (3,702 | ) | (3,327 | ) | (375 | ) | ||||||||||||||
|
Purchased natural gas incentive arrangements
|
2,286 | 1,930 | 356 | 1,930 | 1,487 | 443 | ||||||||||||||||||
|
Other expenses
|
109,421 | 112,397 | (2,976 | ) | 112,397 | 106,763 | 5,634 | |||||||||||||||||
|
Subtotal
|
219,391 | 204,673 | 14,718 | 204,673 | 193,462 | 11,211 | ||||||||||||||||||
|
Total Operating Expenses
|
$ | 604,996 | $ | 625,086 | $ | (20,090 | ) | $ | 625,086 | $ | 633,969 | $ | (8,883 | ) | ||||||||||
|
(1)
|
Includes expenses that, in accordance with the 2009 and 2010 Rate Orders, are adjusted in the current period to equal the revenues earned for the applicable expenses.
|
|
(2)
|
In accordance with the 2010 Rate Order, Central Hudson is authorized to defer 90% of any difference between actual property tax expense and the amounts provided in rates for each Rate Year.
|
|
(3)
|
Year ended December 31, 2011 does not include $11.2 million and $4.1 million of incremental costs related to Tropical Storm Irene and the October 2011 Snowfall, respectively. In addition, December 31, 2010 does not include $19.7 million in incremental costs related to the February 2010 significant storm event. These costs were deferred for future recovery from customers. See further discussion below of significant storm events during 2011 and 2010.
|
In addition to the required adjustment to match revenues collected from customers, the decrease in purchased electricity for the year ended December 31, 2011 compared to the same period in the prior year was driven primarily by lower wholesale prices and purchased volumes, partially offset by higher costs recognized as revenues that are collected for the recovery of previously deferred costs. The increase in purchased natural gas was driven by the same factors as purchased electricity with higher costs recognized as revenues that are collected for the recovery of previously deferred costs more than offsetting the decreases in wholesale prices and purchased volumes.
The decrease in purchased electricity and purchased natural gas for the year ended December 31, 2010 compared to the prior year was driven primarily by lower wholesale prices and purchased volumes, as well as lower costs recognized as revenues that are collected for the recovery of previously deferred costs.
Variations in costs associated with pension, OPEBs, NYS energy programs, MGP site remediation and other matched expenses in 2011 as compared to 2010 and 2010 as compared to 2009 are due to a change in the level of expenses recorded, with a corresponding change in revenues, incorporated in delivery rates as authorized in the 2009 and 2010 Rate Orders. In addition, a new Temporary State Assessment was instituted in April 2009 and effective July 1, 2009 collected from customers.
Uncollectible deferral activity and the resulting variances year-over-year include Central Hudson’s 2010 deferrals for future recovery of $2.6 million in electric uncollectible expense incurred in excess of amounts provided in rates and the recognition of an additional deferral of $1.1 million of gas uncollectible expense based on the PSC Order issued in May 2010, which provided recovery of expenses based on the calendar year 2009 rather than the rate year ended June 30, 2009 as requested by Central Hudson. Additionally, Central Hudson deferred $3.3 million of uncollectible expense in 2009, which included $0.5 million related to gas uncollectible expense for the calendar year ended December 31, 2008 and $2.8 million related to the twelve months ended June 30, 2009 for electric and six months ended June 30, 2009 for gas. Central Hudson did not record uncollectible deferrals in 2011.
Uncollectible expense decreased in the year ended December 31, 2010 as compared to the same period in 2009 primarily as a result of lower write-offs of customer receivables and a decrease in the amount recorded as a reserve for future uncollectible accounts. Management believes this is a result of enhanced collection efforts, including increased resources and improved planning. Central Hudson was able to maintain this level of collections in 2011.
Weather related service restoration costs can fluctuate from year-to-year based on changes in the number and severity of storms each year. This expense includes all costs of the service restoration effort, including labor and repairs to damaged infrastructure, which have not been deferred. Incremental costs incurred for certain significant storm events which meet the PSC criteria, such as overtime incurred and outside crews employed to expedite the restoration effort, are deferred for future recovery from customers. During 2010 and 2011, Central Hudson’s service territory experienced disruption from the three largest storm events in its history; February 2010 storm, Tropical Storm Irene in August 2011 and an October 2011 Snowfall. The 2010 and 2011 costs do not include amounts related to incremental costs from these major storm events which, based on the PSC’s three prong criteria, Management believes are probable of future recovery from customers and therefore have been deferred. Incremental costs include such items as the costs of mutual aid crews and contractors from other areas and overtime costs for Central Hudson crews.
For the February 2010 storm, Central Hudson filed a petition with the PSC for approval and recovery on September 23, 2010. Based on the results of the 2011 proceedings on this case, Central Hudson recorded $0.5 million of additional storm costs in 2011 related to the February 2010 storm, which were not approved for recovery by the PSC.
For Tropical Storm Irene, Central Hudson filed a petition on November 28, 2011 with the PSC seeking approval of deferred incremental electric restoration costs for future recovery with carrying charges. Central Hudson will finalize its measure of materiality and utility earnings based upon the calendar year ended December 31, 2011 results. Based on current estimates and assumptions, Management believes these incremental costs deferred meet the PSC’s criteria for deferral accounting and therefore are probable of future recovery.
Central Hudson also incurred incremental costs associated with gas emergencies as a result of the impacts of Tropical Storm Irene; however these costs have not been deferred as of December 31, 2011. As of December 31, 2011, approximately $0.8 million has been incurred related to these gas emergencies and additional costs are expected as a result of on-going repairs to damaged infrastructure.
For the October 2011 Snowfall event, Central Hudson has deferred $4.1 million of estimated recoverable incremental storm restoration costs as of December 31, 2011. Central Hudson anticipates filing a petition to defer for future recovery all incremental storm restoration costs totaling approximately $8 million, subject to the criteria the PSC has established for consideration and approval of deferral authorization requests. Based on current estimates and assumptions, Management believes a minimum of $4.1 million of incremental costs deferred meet the accounting standard of being probable of future recovery.
In addition to these significant weather events, the increase in weather related restoration costs in 2011 compared to 2010 includes costs associated with weather related gas emergencies as a result of other severe weather experienced early in 2011. These events did not individually meet the PSC criteria for deferral accounting and as such the incremental costs have not been deferred.
The higher storm restoration costs in 2010 as compared to 2009 were primarily the result of the most significant storm event in the Company’s history during the last week of February 2010 discussed above.
Other Income
Other income and deductions for Central Hudson for the year ended December 31, 2011, increased $3.6 million, compared to the same period in 2010, due primarily to increases in regulatory adjustments related to changes in interest costs on Central Hudson’s variable rate debt resulting from the redemption of Series C and D notes in December 2010 with proceeds from the Series G medium-term notes. Additional increases during 2011 resulted from increases in regulatory carrying charges from customers related to pension costs, MGP and property taxes, as well as interest on undercollected gas cost adjustments and 2011 earnings on Deferred Compensation Plan assets. These increases were partially reduced by decreases in carrying charges from customers relating to deferred uncollectible expense, and under collected Temporary State Assessment and RDM balances.
Other income and deductions for Central Hudson for the year ended December 31, 2010, increased $0.8 million, compared to the same period in 2009, due to several factors, including an increase in regulatory carrying charges due from customers related to the Temporary State Assessment, February 2010 storm event and deferred uncollectible expense, as well as a regulatory adjustment resulting from changes in interest costs on Central Hudson’s variable rate long-term debt. These increases were partially offset by lower earnings on Deferred Compensation Plan assets.
Interest Charges
Central Hudson’s interest charges increased $3.3 million for the year ended December 31, 2011, compared to the same period in December 31, 2010, primarily due to higher interest rates on debt, a higher average debt balance and the net impact of carrying charges due to customers. The higher interest rates associated with the $82.2 million medium-term notes issued in December 2010 compared to the $82.2 million variable rate series C and D notes retired in December 2010 increased interest expense year-over-year. In addition, a full year of interest was recorded in 2011 on $40 million of Series A and B notes issued in September 2010. The net increase in carrying charges due to customers was primarily related to an increase in the underlying reserve balance for OPEBs and the impact of the tax repair project on rate base partially reduced by the impacts of a lower net regulatory electric liability set aside for customer benefit.
Central Hudson’s interest charges increased $1.0 million for the year ended December 31, 2010, compared to the same period in December 31, 2009. The increase is primarily the result of a medium-term note issuance of $24 million in October 2009 and the issuance of $40 million of 2010 Series A and B notes in September of 2010 discussed above. These debt issuances were partially offset by the redemption of $24 million of medium-term notes in September 2010. These issuances and redemptions resulted in a net increase in average debt outstanding during the year.
The following table sets forth pertinent data on Central Hudson’s outstanding debt (Dollars in Thousands):
|
|
2011
|
2010
|
2009
|
|||||||||
|
Long-Term Debt:
|
|
|
|
|||||||||
|
Debt retired
|
$ | 33,400 | $ | 106,150 | $ | 20,000 | ||||||
|
Debt issued
|
$ | 33,400 | $ | 122,150 | $ | 24,000 | ||||||
|
Outstanding at year end:
|
||||||||||||
|
Amount (including current portion)
|
$ | 453,950 | $ | 453,900 | $ | 437,897 | ||||||
|
Weighted average interest rate
|
5.12 | % | 5.28 | % | 4.52 | % | ||||||
|
Short-Term Debt:
|
||||||||||||
|
Average daily amount outstanding
|
$ | 1,151 | $ | 12,007 | $ | 21,962 | ||||||
|
Weighted average interest rate
|
0.72 | % | 0.61 | % | 0.98 | % | ||||||
|
Overall weighted average interest rate
|
4.82 | % | 5.16 | % | 4.39 | % | ||||||
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 $2.0 million for the year ended December 31, 2011 when compared to the same period in 2010. In 2010, a one-time reclassification of funded deferred taxes to a regulatory liability account was recorded, resulting in a reduction to the tax provision of $2.3 million.
Income taxes increased $5.0 million in 2010 when compared to 2009. The increase was primarily due to an increase in pre-tax book income.
CH Energy Group
In addition to the impacts on 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,
|
Increase/(Decrease) in
|
||||||||||||||
|
|
2011
|
2010
|
Amount
|
Percent
|
||||||||||||
|
Operating Revenues
|
$ | 985,520 | $ | 960,108 | $ | 25,412 | 2.6 | % | ||||||||
|
Operating Expenses:
|
||||||||||||||||
|
Purchased electricity, fuel, natural gas and petroleum
|
511,094 | 504,058 | 7,036 | 1.4 | % | |||||||||||
|
Depreciation and amortization
|
40,055 | 38,275 | 1,780 | 4.7 | % | |||||||||||
|
Other operating expenses
|
334,782 | 318,472 | 16,310 | 5.1 | % | |||||||||||
|
Total Operating Expenses
|
885,931 | 860,805 | 25,126 | 2.9 | % | |||||||||||
|
Operating Income
|
99,589 | 99,303 | 286 | 0.3 | % | |||||||||||
|
Other Income (Deductions), net
|
2,566 | (10,674 | ) | 13,240 | 124.0 | % | ||||||||||
|
Interest Charges
|
35,158 | 29,085 | 6,073 | 20.9 | % | |||||||||||
|
Income before income taxes, non-controlling interest and preferred dividends of subsidiary
|
66,997 | 59,544 | 7,453 | 12.5 | % | |||||||||||
|
Income Taxes
|
23,813 | 19,214 | 4,599 | 23.9 | % | |||||||||||
|
Net income from continuing operations
|
43,184 | 40,330 | 2,854 | 7.1 | % | |||||||||||
|
Net income (loss) from discontinued operations, net of tax
|
3,126 | (1,128 | ) | 4,254 | 377.1 | % | ||||||||||
|
Non-controlling interest in subsidiary
|
- | (272 | ) | 272 | 100.0 | % | ||||||||||
|
Dividends declared on Preferred Stock of subsidiary
|
970 | 970 | - | - | % | |||||||||||
|
Net income attributable to CH Energy Group
|
$ | 45,340 | $ | 38,504 | $ | 6,836 | 17.8 | % | ||||||||
|
|
Year Ended December 31,
|
Increase/(Decrease) in
|
||||||||||||||
|
|
2010
|
2009
|
Amount
|
Percent
|
||||||||||||
|
Operating Revenues
|
$ | 960,108 | $ | 921,557 | $ | 38,551 | 4.2 | % | ||||||||
|
Operating Expenses:
|
||||||||||||||||
|
Purchased electricity, fuel, natural gas and petroleum
|
504,058 | 519,635 | (15,577 | ) | (3.0 | ) % | ||||||||||
|
Depreciation and amortization
|
38,275 | 36,582 | 1,693 | 4.6 | % | |||||||||||
|
Other operating expenses
|
318,472 | 283,755 | 34,717 | 12.2 | % | |||||||||||
|
Total Operating Expenses
|
860,805 | 839,972 | 20,833 | 2.5 | % | |||||||||||
|
Operating Income
|
99,303 | 81,585 | 17,718 | 21.7 | % | |||||||||||
|
Other Income (Deductions), net
|
(10,674 | ) | 77 | (10,751 | ) | ▲ |
%
|
|||||||||
|
Interest Charges
|
29,085 | 25,796 | 3,289 | 12.8 | % | |||||||||||
|
Income before income taxes, non-controlling interest and preferred dividends of subsidiary
|
59,544 | 55,866 | 3,678 | 6.6 | % | |||||||||||
|
Income Taxes
|
19,214 | 22,269 | (3,055 | ) | (13.7 | ) % | ||||||||||
|
Net income from continuing operations
|
40,330 | 33,597 | 6,733 | 20.0 | % | |||||||||||
|
Net income (loss) from discontinued operations, net of tax
|
(1,128 | ) | 10,681 | (11,809 | ) | (110.6 | ) % | |||||||||
|
Non-controlling interest in subsidiary
|
(272 | ) | (176 | ) | (96 | ) | (54.5 | ) % | ||||||||
|
Dividends declared on Preferred Stock of subsidiary
|
970 | 970 | - | - | % | |||||||||||
|
Net income attributable to CH Energy Group
|
$ | 38,504 | $ | 43,484 | $ | (4,980 | ) | (11.5 | ) % | |||||||
|
▲ Percentage change greater than 500%.
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Griffith
Sales Volumes
Delivery and sales volumes for Griffith vary in response to weather conditions, changes in our customer base 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 & Weather Normalized Deliveries
(In Thousands of Gallons)
|
Actual Deliveries
|
Weather Normalized Deliveries(1)
|
|||||||||||||||||||||||||||||||
|
Year Ended
December 31,
|
Increase /
(Decrease) in
|
Year Ended
December 31,
|
Increase /
(Decrease) in
|
|||||||||||||||||||||||||||||
|
2011
|
2010
|
Amount
|
Percent
|
2011
|
2010
|
Amount
|
Percent
|
|||||||||||||||||||||||||
|
Heating Oil
|
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||||||||||||||||||||||||
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Base company volume(2)
|
29,891 | 35,189 | (5,298 | ) | (15 | ) % | 31,256 | 35,048 | (3,792 | ) | (11 | ) % | ||||||||||||||||||||
|
Acquisitions volume
|
830 | 179 | 651 | 364 | % | 869 | 178 | 691 | 388 | % | ||||||||||||||||||||||
|
Total Heating Oil
|
30,721 | 35,368 | (4,647 | ) | (13 | ) % | 32,125 | 35,226 | (3,101 | ) | (9 | ) % | ||||||||||||||||||||
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Motor Fuels
|
||||||||||||||||||||||||||||||||
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Base company volume(2)
|
42,257 | 45,774 | (3,517 | ) | (8 | ) % | 42,257 | 45,774 | (3,517 | ) | (8 | ) % | ||||||||||||||||||||
|
Acquisitions volume
|
2,989 | 22 | 2,967 | ▲ | % | 2,989 | 22 | 2,967 | ▲ | % | ||||||||||||||||||||||
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Total Motor Fuels
|
45,246 | 45,796 | (550 | ) | (1 | ) % | 45,246 | 45,796 | (550 | ) | (1 | ) % | ||||||||||||||||||||
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Propane and Other
|
||||||||||||||||||||||||||||||||
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Base company volume(2)
|
1,012 | 1,104 | (92 | ) | (8 | ) % | 1,055 | 1,100 | (45 | ) | (4 | ) % | ||||||||||||||||||||
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Total Propane and Other
|
1,012 | 1,104 | (92 | ) | (8 | ) % | 1,055 | 1,100 | (45 | ) | (4 | ) % | ||||||||||||||||||||
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Total
|
||||||||||||||||||||||||||||||||
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Base company volume(2)
|
73,160 | 82,067 | (8,907 | ) | (11 | ) % | 74,568 | 81,922 | (7,354 | ) | (9 | ) % | ||||||||||||||||||||
|
Acquisitions volume
|
3,819 | 201 | 3,618 | ▲ | % | 3,858 | 200 | 3,658 | ▲ | % | ||||||||||||||||||||||
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Total
|
76,979 | 82,268 | (5,289 | ) | (6 | ) % | 78,426 | 82,122 | (3,696 | ) | (5 | ) % | ||||||||||||||||||||
|
(1)
|
Griffith uses an internal analysis based on historical weather data to remove the estimated impacts of weather on delivery volumes.
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(2)
|
For the purpose of this chart, "Base company” excludes any impact from acquisitions made by Griffith in 2011 and 2010.
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▲
|
Percentage change greater than 500%
|
|
Actual & Weather Normalized Deliveries
(In Thousands of Gallons)
|
Actual Deliveries
|
Weather Normalized Deliveries(1)
|
|||||||||||||||||||||||||||||||
|
Year Ended December 31,
|
Increase /
(Decrease) in
|
Year Ended December 31,
|
Increase /
(Decrease) in
|
|||||||||||||||||||||||||||||
|
2010
|
2009
|
Amount
|
Percent
|
2010
|
2009
|
Amount
|
Percent
|
|||||||||||||||||||||||||
|
Heating Oil
|
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|
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|
||||||||||||||||||||||||
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Base company volume(2)
|
35,189 | 38,449 | (3,260 | ) | (8 | ) % | 35,048 | 37,493 | (2,445 | ) | (7 | ) % | ||||||||||||||||||||
|
Acquisitions volume
|
179 | - | 179 | 100 | % | 178 | - | 178 | 100 | % | ||||||||||||||||||||||
|
Divested volume
|
- | 32,334 | (32,334 | ) | (100 | ) % | - | 31,630 | (31,630 | ) | (100 | ) % | ||||||||||||||||||||
|
Total Heating Oil
|
35,368 | 70,783 | (35,415 | ) | (50 | ) % | 35,226 | 69,123 | (33,897 | ) | (49 | ) % | ||||||||||||||||||||
|
Motor Fuels
|
||||||||||||||||||||||||||||||||
|
Base company volume(2)
|
45,774 | 47,805 | (2,031 | ) | (4 | ) % | 45,774 | 47,805 | (2,031 | ) | (4 | ) % | ||||||||||||||||||||
|
Acquisitions volume
|
22 | - | 22 | 100 | % | 22 | - | 22 | 100 | % | ||||||||||||||||||||||
|
Divested volume
|
- | 12,806 | (12,806 | ) | (100 | ) % | - | 12,806 | (12,806 | ) | (100 | ) % | ||||||||||||||||||||
|
Total Motor Fuels
|
45,796 | 60,611 | (14,815 | ) | (24 | ) % | 45,796 | 60,611 | (14,815 | ) | (24 | ) % | ||||||||||||||||||||
|
Propane and Other
|
||||||||||||||||||||||||||||||||
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Base company volume(2)
|
1,104 | 1,278 | (174 | ) | (14 | ) % | 1,100 | 1,248 | (148 | ) | (12 | ) % | ||||||||||||||||||||
|
Divested volume
|
- | 1,579 | (1,579 | ) | (100 | ) % | - | 1,536 | (1,536 | ) | (100 | ) % | ||||||||||||||||||||
|
Total Propane and Other
|
1,104 | 2,857 | (1,753 | ) | (61 | ) % | 1,100 | 2,784 | (1,684 | ) | (60 | ) % | ||||||||||||||||||||
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Total
|
||||||||||||||||||||||||||||||||
|
Base company volume(2)
|
82,067 | 87,532 | (5,465 | ) | (6 | ) % | 81,922 | 86,546 | (4,624 | ) | (5 | ) % | ||||||||||||||||||||
|
Acquisitions volume
|
201 | - | 201 | 100 | % | 200 | - | 200 | 100 | % | ||||||||||||||||||||||
|
Divested volume
|
- | 46,719 | (46,719 | ) | (100 | ) % | - | 45,972 | (45,972 | ) | (100 | ) % | ||||||||||||||||||||
|
Total
|
82,268 | 134,251 | (51,983 | ) | (39 | ) % | 82,122 | 132,518 | (50,396 | ) | (38 | ) % | ||||||||||||||||||||
|
(1)
|
Griffith uses an internal analysis based on historical weather data to remove the estimated impacts of weather on delivery volumes.
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|
|
(2)
|
For the purpose of this chart, "Base company” excludes any impact from acquisitions made by Griffith in 2010 as well as volumes associated with operations divested in December 2009.
|
|
Actual and Weather Normalized Delivery Volumes as % of Total Volumes
|
|
Year Ended December 31,
|
|||||||||||||||||||||||
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|
2011
|
2010
|
2009
|
|||||||||||||||||||||
|
|
Actual
|
Weather
Normalized
|
Actual
|
Weather
Normalized
|
Actual
|
Weather
Normalized
|
||||||||||||||||||
|
Heating Oil
|
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|
||||||||||||||||||
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Base Company
|
39 | % | 40 | % | 43 | % | 43 | % | 53 | % | 52 | % | ||||||||||||
|
Acquisitions
|
1 | % | 1 | % | - | % | - | % | - | % | - | % | ||||||||||||
|
Motor Fuels
|
||||||||||||||||||||||||
|
Base Company
|
55 | % | 54 | % | 56 | % | 56 | % | 45 | % | 46 | % | ||||||||||||
|
Acquisitions
|
4 | % | 4 | % | - | % | - | % | - | % | - | % | ||||||||||||
|
Propane and Other
|
||||||||||||||||||||||||
|
Base Company
|
1 | % | 1 | % | 1 | % | 1 | % | 2 | % | 2 | % | ||||||||||||
|
Total
|
100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||||
Sales of petroleum products decreased 6% in the year ended December 31, 2011 compared to the same period in 2010. The decrease was due primarily to customer conservation in response to higher oil prices and a decrease in motor fuels volume which continues to be depressed by the sluggish economy. These decreases were partially offset by an increase in sales related to acquisitions.
Sales of petroleum products decreased 39% in the year ended December 31, 2010 compared to the same period in 2009. The decrease was due primarily to the sale of operations in certain geographic locations. Excluding the impact of the partial divestiture, sales were lower primarily due to reduced sales to commercial customers who can burn both natural gas and oil due to the unfavorable price relationship between heating oil and natural gas. Additionally, sales of residential and commercial heating oil were lower due to weather that was 2% warmer in the twelve months ended December 31, 2010, compared to the same period in 2009, as measured by heating degree days.
Gross Profit
A breakdown of Griffith's gross profit by product and service line for the years ended December 31, 2011, 2010 and 2009 are illustrated below (Dollars in Thousands):
|
|
Year Ended December 31,
|
|||||||||||||||||||||||
|
Product and Service Line
|
2011
|
2010
|
2009
|
|||||||||||||||||||||
|
Heating oil - Base Company
|
$ | 23,404 | 46 | % | $ | 25,220 | 50 | % | $ | 26,627 | 50 | % | ||||||||||||
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Heating oil - Acquisitions
|
552 | 1 | % | 121 | - | % | - | - | % | |||||||||||||||
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Motor fuels - Base Company
|
10,059 | 20 | % | 10,406 | 20 | % | 11,271 | 21 | % | |||||||||||||||
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Motor fuels - Acquisitions
|
805 | 2 | % | 9 | - | % | - | - | % | |||||||||||||||
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Propane and Other - Base Company
|
1,292 | 3 | % | 1,467 | 3 | % | 1,650 | 3 | % | |||||||||||||||
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Service and installations - Base Company
|
12,424 | 25 | % | 13,124 | 26 | % | 12,186 | 23 | % | |||||||||||||||
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Service and installations - Acquisitions
|
174 | - | % | 32 | - | % | - | - | % | |||||||||||||||
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Other - Base Company
|
1,798 | 3 | % | 543 | 1 | % | 1,846 | 3 | % | |||||||||||||||
|
Total
|
$ | 50,508 | 100 | % | $ | 50,922 | 100 | % | $ | 53,580 | 100 | % | ||||||||||||
|
Gross profit from discontinued operations of $35.1 million by product and service lines for the years ended December 31, 2009 excluded from the chart above are as follows:
|
|
|||||||
|
|
Heating oil: $19.2 million, or 55%
|
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Motor fuels: $3.2 million, or 9%
|
|
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Other fuels: $1.3 million, or 4%
|
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Service and installations: $10.9 million, or 31%
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Other: $0.5 million, or 1%
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Revenues
Change in Griffith Revenues
(In Thousands)
|
Year Ended
|
|
Year Ended
|
|
|||||||||||||||||
|
December 31,
|
Increase /
|
December 31,
|
Increase /
|
|||||||||||||||||
|
2011
|
2010
|
(Decrease)
|
2010
|
2009
|
(Decrease)
|
|||||||||||||||
|
Revenues
|
|
|
|
|
|
|
||||||||||||||
|
Heating Oil(1)
|
$ | 110,627 | $ | 104,496 | $ | 6,131 | $ | 104,496 | $ | 92,364 | $ | 12,132 | ||||||||
|
Heating Oil - Acquisitions
|
3,012 | 548 | 2,464 | 548 | - | 548 | ||||||||||||||
|
Motor Fuels(1)
|
137,518 | 111,771 | 25,747 | 111,771 | 96,112 | 15,659 | ||||||||||||||
|
Motor Fuels - Acquisitions
|
9,844 | 60 | 9,784 | 60 | - | 60 | ||||||||||||||
|
Other(1)
|
5,065 | 3,643 | 1,422 | 3,643 | 4,812 | (1,169 | ) | |||||||||||||
|
Service Revenues(1)
|
18,658 | 19,580 | (922 | ) | 19,580 | 17,941 | 1,639 | |||||||||||||
|
Service Revenues - Acquisitions
|
274 | 76 | 198 | 76 | - | 76 | ||||||||||||||
|
Total
|
$ | 284,998 | $ | 240,174 | $ | 44,824 | $ | 240,174 | $ | 211,229 | $ | 28,945 | ||||||||
|
Discontinued Operations(2)
|
||||||||||||||||||||
|
Heating Oil
|
$ | 76,776 | ||||||||||||||||||
|
Motor Fuels
|
25,859 | |||||||||||||||||||
|
Other
|
3,557 | |||||||||||||||||||
|
Service Revenues
|
16,483 | |||||||||||||||||||
|
Total Discontinued Operations
|
$ | 122,675 | ||||||||||||||||||
|
Reconciliation to Income Statement
|
||||||||||||||||||||
|
Total Revenue from discontinued operations
|
$ | 122,675 | ||||||||||||||||||
|
Gain from sale of discontinued operations
|
10,767 | |||||||||||||||||||
|
Expenses of discontinued operations
|
116,602 | |||||||||||||||||||
|
Income tax expense from discontinued operations
|
6,989 | |||||||||||||||||||
|
Net Income from discontinued operations
|
$ | 9,851 | ||||||||||||||||||
|
(1)
|
These line items exclude the impact of acquisitions made by Griffith in 2011 and 2010 for the analysis which compares December 31, 2011 to 2010 and 2010 for the analysis which compares December 31, 2010 to 2009.
|
|
(2)
|
The revenue by product line information of the Discontinued Operations is considered a non-GAAP financial measure; however, Management believes this information is useful in understanding the portion of operations disposed of as compared to the business retained. A reconciliation to net income from Discontinued Operations, the most comparable GAAP measure as shown on the CH Energy Group Consolidated Statement of Income, is provided.
|
Revenues, net of the effect of weather hedging contracts increased in the year ended December 31, 2011 compared to the same periods in 2010, due primarily to an increase in wholesale prices partially offset by a decline in sales volume.
Revenues, net of the effect of weather hedging contracts decreased in the year ended December 31, 2010 compared to the same periods in 2009, due to the sale of operations in certain geographic locations.
Operating Expenses
For the year ended December 31, 2011, operating expenses, increased $45.6 million, or 19%, from $234.7 million in 2010 to $280.3 million in 2011. The cost of petroleum products increased $45.2 million, or 24%, due to higher wholesale market prices, partially offset by a decline in sales volume.
For the year ended December 31, 2010, operating expenses, net of divested operations, increased $29.1 million, or 14%, from $205.6 million in 2009 to $234.7 million in 2010. The cost of petroleum products increased $31.3 million, or 21%, due to higher wholesale market prices for petroleum products.
Other operating expenses, net of divested operations, decreased $2.2 million for the year ended December 31, 2010 due primarily to a decrease in operating expenses related to reduced volumes, savings related to an overall cost reduction plan, and a reduction in uncollectible accounts.
Other Businesses and Investments
Revenues and Operating Expenses
All revenue and operating expenses of other businesses and investments, including Lyonsdale, CH Shirley Wind, CH-Auburn and CH-Greentree during the years ended December 31, 2011, 2010 and 2009 are included in discontinued operations section in the Consolidated Financial Statements of CH Energy Group as a result of the divestitures during 2011.
Revenues and operating expenses included in discontinued operations decreased $5.2 million and $8.9 million for the year ended December 31, 2011 compared to 2010. The primary driver of these results was the sale of CHEC’s four largest renewable energy investments in 2011, partially reduced by operations of CH Shirley Wind, which began in December 2010.
Results included in discontinued operations for the year ended December 31, 2010 compared to the same period in 2009 reflect an increase in operating revenues of $2.2 million and an increase in operating expenses of $3.8 million. The increase in revenues and a portion of the increase in operating expenses relate to CH-Greentree, which began commercial operation in the second half of 2009, and CH-Auburn, which became operational in February 2010. Additionally impacting the increases in operating expenses was an impairment of Lyonsdale assets of $2.1 million recorded in December 2010.
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) for the year ended December 31, 2011 increased by $6.5 million and decreased $0.4 million as compared to the same period in 2010, respectively. The increase in other income and deductions was primarily the result of impairment charges for 100% of CHEC’s subordinated debt, accrued interest and equity investment in Cornhusker Holdings of $11.4 million in the third quarter of 2010 and a wind investment in the third quarter of 2011 of $3.6 million. In addition, following the sale of Shirley Wind, CH Energy Group Holding Company paid down $20 million of its 2009 Series A private placement debt. As a result, a prepayment penalty of approximately $3.0 million was incurred. The additional increase in 2011 compared to the prior period is due to the losses incurred during 2010 related to Cornhusker operations as compared to modest income in 2011 which related to CHEC’s share of a small ethanol producer’s tax credit. The decrease in interest charges is due to the $20 million repayment of Series A private placement debt discussed above.
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) for the year ended December 31, 2010 decreased by $10.6 million and increased $1.2 million, respectively, as compared to the same period in 2009. The decrease in other income and deductions is primarily the result of an impairment charge for 100% of CHEC’s subordinated debt, accrued interest and equity investment in Cornhusker Holdings totaling $11.4 million. This decrease in earnings was partially reduced by an increase in year-over-year results related to the write-off of $1.3 million recorded in the first quarter of 2009 related to a development project of CHEC. The increase in interest charges was due to the private placement of debt by the holding company in the second quarter of 2009 to fund unregulated portions of CH Energy Group.
CH Energy Group – Income Taxes
Income taxes on income from continuing operations for CH Energy Group increased $4.6 million for the year ended December 31, 2011, compared to the same period in 2010, primarily due to an increase in pre-tax book income. Also, in 2010, a one-time reclassification of funded deferred taxes to a regulatory liability account was recorded, resulting in a reduction to the tax provision of $2.3 million.
Income taxes on income from continuing operations for CH Energy Group decreased $3.1 million for the year ended December 31, 2010, compared to the same period in 2009, primarily due to the 2010 impact of a one-time reclassification of funded deferred taxes to a regulatory liability discussed above.
CAPITAL RESOURCES AND LIQUIDITY
Cash Flow Summary - CH Energy Group and Central Hudson
Changes in CH Energy Group’s and Central Hudson's cash and cash equivalents resulting from operating, investing, and financing activities are summarized in the following chart (In Millions):
|
|
CH Energy Group
|
Central Hudson
|
|||||||||||||||||||
|
|
Year Ended December 31,
|
Year Ended December 31,
|
|||||||||||||||||||
|
|
2011
|
2010
|
2009
|
2011
|
2010
|
2009
|
|||||||||||||||
|
Net Cash Provided By/(Used In):
|
|
|
|
|
|||||||||||||||||
|
Operating Activities
|
$ | 120.9 | $ | 87.0 | $ | 126.4 | $ | 123.9 | $ | 99.1 | $ | 107.5 | |||||||||
|
Investing Activities
|
(36.7 | ) | (108.6 | ) | (55.7 | ) | (87.9 | ) | (76.5 | ) | (107.3 | ) | |||||||||
|
Financing Activities
|
(98.3 | ) | (22.4 | ) | (17.1 | ) | (43.1 | ) | (17.8 | ) | 2.1 | ||||||||||
|
Net change for the period
|
(14.1 | ) | (44.0 | ) | 53.6 | (7.1 | ) | 4.8 | 2.3 | ||||||||||||
|
Balance at beginning of period
|
29.4 | 73.4 | 19.8 | 9.6 | 4.8 | 2.5 | |||||||||||||||
|
Balance at end of period
|
$ | 15.3 | $ | 29.4 | $ | 73.4 | $ | 2.5 | $ | 9.6 | $ | 4.8 | |||||||||
For all three periods, both CH Energy Group and Central Hudson’s working capital needs were provided by cash from operations and in 2011, supplemented with short-term financing as needed. Capital expenditures in all three years, as well as investments in 2010 and 2009, were funded primarily with excess cash from operations and long-term financing. In 2011, proceeds from the sale of CHEC’s investments in renewable energy and the related receipt of federal grants were used to repurchase CH Energy Group Common Stock and to repay debt at CH Energy Group Holding Company. In 2010, strong cash flows resulting from a decrease in working capital needs at the end of 2009 and cash received from Federal and NYS income tax refunds enabled Central Hudson to accelerate the funding of its pension plan. Cash from the Griffith divestiture in 2009 was used to fund capital expenditures for Shirley Wind in 2010. Additional discussions regarding cash flow from operating, investing and financing activities for each period are provided below.
For all three years and for both CH Energy Group and Central Hudson, cash provided by sales exceeded the period’s expenses and working capital needs, including the incremental storm restoration costs paid by Central Hudson for several storm events in 2011 and 2010. The estimated recoverable incremental storm restoration costs associated with three significant storm events in these years, which met the PSC criteria, have been deferred for future recovery from customers. As of December 31, 2011 there is approximately $7.6 million for invoices not yet received or paid related to storm restoration costs included in liabilities resulting from the impact of Tropical Storm Irene and the late October 2011 Snowfall on Central Hudson’s service territory. Other significant operating activities in each period presented include:
|
|
|
·
|
Central Hudson utilized cash from operations in excess of working capital needs to fund contributions to its pension and OPEB plans. Additional funding was made in 2010 utilizing income tax refunds received as a result of a change in tax accounting method for repair and maintenance costs of Central Hudson’s utility assets. Pension and OPEB contributions totaled $33.9 million, $69.6 million, and $26.6 million for the years ended December 31, 2011, 2010, and 2009 respectively.
|
|
·
|
Costs spent for MGP remediation efforts in excess of amounts collected in rates during the years ended December 31, 2010 and 2009 of approximately $12.2 million and $2.3 million, respectively, also impacted the cash from operations. Increased costs in 2010 for the completion of remediation at the Newburgh site were funded partially through an increase in delivery rates effective July 1, 2010. Costs above the amount provided in rates have been deferred for future recovery from customers. In 2011, amounts collected in rates for MGP site remediation were greater than remediation costs as a result of the completion of remediation efforts at Newburgh. These amounts were applied against the accumulated undercollected balance for MGP site remediation.
|
|
·
|
In 2009, Central Hudson’s cash from operations was also impacted by payments made to the PSC for a NYS Temporary State Assessment in advance of cash collections from customers.
|
|
·
|
In addition to this activity at Central Hudson, net cash provided by operating activities at CH Energy Group was negatively impacted during the years ended December 31, 2011, 2010, and 2009 primarily due to an increase in Griffith’s working capital needs.
|
Net cash used in investing activities was primarily related to investments in Central Hudson’s electric and natural gas transmission and distribution systems. Net cash used in investing activities at CH Energy Group also included proceeds from the sale of CHEC investments in renewable energy, including Lyonsdale, Shirley Wind, CH-Auburn, and CH-Greentree and proceeds from the receipt of federal grants related to Shirley Wind and CH-Auburn in 2011. Capital expenditures at Shirley Wind totaling $29.6 million in 2010 were funded primarily with cash from Griffith’s partial divestiture in December 2009 and $13.3 million in 2009 were funded with long term debt issued by the CH Energy Group Holding Company. CH Energy Group’s investing activities also include Griffith’s fuel distribution acquisitions in 2011 and 2010, as well as modest investments in Griffith's property and plant in all three years.
Financing activities at CH Energy Group and Central Hudson were used primarily to fund capital expenditures and to refinance maturing and redeemed debt. Significant financing activities in each period presented include:
|
·
|
In 2011, Central Hudson issued $33.4 million of medium term notes, the proceeds of which were used to refund the 1999 NYSERDA Series A bonds in November of 2011.
|
|
·
|
In 2010, proceeds from the sale of medium term notes at fixed interest rates were used to retire Central Hudson’s 1999 NYSERDA Series C and D variable rate debt prior to maturity.
|
|
·
|
In 2009, Central Hudson received $25 million in capital contributions from CH Energy Group, which was used to supplement the funding of investing activities. After retaining earnings for several years to increase its equity ratio, Central Hudson began paying dividends to parent CH Energy Group in 2010. Central Hudson paid dividends of $43 million and $31 million to parent CH Energy Group during the years ended December 31, 2011 and 2010, respectively.
|
In addition to Central Hudson activity, CH Energy Group’s financing activities include:
|
·
|
Payment of annual dividends to holders of Common Stock totaled $33.6 million, $34.2 million and $34.1 million in 2011, 2010 and 2009, respectively. The decrease in the current period is a result of lower shares outstanding due to the share repurchase program.
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|
·
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CH Energy Group’s short term borrowings for the year ended December 31, 2011 were used primarily to supplement working capital.
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·
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In 2011, CH Energy Group used the proceeds from the sale of CHEC renewable energy investments to repay $20 million of debt at CH Energy Group Holding Company and to repurchase Common Stock outstanding. CH Energy Group repurchased approximately $48.7 million, totaling 949,000 shares of outstanding CH Energy Group Common Stock and returned the shares to treasury during the year ended December 31, 2011.
|
In 2009, CH Energy Group’s Holding Company sold $50 million of fixed rate notes to provide financing for non-regulated subsidiaries.
Capitalization – Issuance of Treasury Stock
Effective July 1, 2011, employer matching contributions to the Savings Incentive Plan (“SIP”) are paid either in cash or in CH Energy Group Common Stock. During the third quarter of 2011, CH Energy Group began making employer matching contributions to the SIP by issuing treasury shares. During 2011, employer matching contributions issued from treasury totaled 19,556 shares. Management expects to continue making employer matching contributions to the SIP in stock, which it estimates will be approximately 48,000 shares per year.
Due to the retirement of one of Central Hudson’s executive officers on January 1, 2011, a pro-rated number of shares under the January 26, 2009 and February 8, 2010 Performance Share grants were paid to this individual on July 6, 2011. For the pro-rata payout, 2,374 shares were issued from CH Energy Group’s treasury stock on this date in satisfaction of these awards.
For information regarding equity compensation and the purchase of treasury shares, see Note 11 - “Equity Based Compensation” of this Annual Report on Form 10-K.
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.
Central Hudson gradually increased its equity ratio in recent years 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, 2010, Central Hudson began operating under the 2010 Rate Order, and delivery rates are based on a capital structure that reflects 48% common equity. This ratio is calculated according to a PSC methodology, which excludes short-term debt and includes customer deposits.
Central Hudson paid common stock dividends of $43 million to CH Energy Group in 2011. Future dividends are expected to correspond to maintenance of a target equity ratio, excluding short-term debt of approximately 48% or higher.
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’/stable by Moody’s Investors Service (“Moody’s”).1
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
|
2011
|
2010
|
2009
|
||||||||||
|
Long-term debt(1)
|
48.0 | % | 47.4 | % | 46.8 | % | ||||||
|
Short-term debt
|
- | % | - | % | - | % | ||||||
|
Preferred stock
|
2.1 | % | 2.0 | % | 2.0 | % | ||||||
|
Common equity
|
49.9 | % | 50.6 | % | 51.2 | % | ||||||
| 100.0 | % | 100.0 | % | 100.0 | % | |||||||
Central Hudson
|
2011
|
2010
|
2009
|
||||||||||
|
Long-term debt
|
49.3 | % | 49.4 | % | 49.2 | % | ||||||
|
Short-term debt(2)
|
- | % | - | % | - | % | ||||||
|
Preferred stock
|
2.3 | % | 2.3 | % | 2.4 | % | ||||||
|
Common equity
|
48.4 | % | 48.3 | % | 48.4 | % | ||||||
| 100.0 | % | 100.0 | % | 100.0 | % | |||||||
CHEC
|
2011
|
2010
|
2009
|
||||||||||
|
Long-term debt(1)
|
42.4 | % | 49.9 | % | 32.1 | % | ||||||
|
Short-term debt
|
- | % | - | % | - | % | ||||||
|
Preferred stock
|
- | % | - | % | - | % | ||||||
|
Common equity
|
57.6 | % | 50.1 | % | 67.9 | % | ||||||
| 100.0 | % | 100.0 | % | 100.0 | % | |||||||
|
(1)
|
Based on stand-alone financial statements and including intercompany balances which are eliminated upon consolidation.
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|
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(2)
|
Excluded from the common equity ratio under the PSC’s methodology for Central Hudson delivery rates.
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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, 2011 (In Thousands):
|
Projected Payments Due By Period
|
||||||||||||||||||||
|
Less than
1 year
|
Years
Ending
2013-2014
|
Years
Ending
2015-2016
|
Thereafter
|
Total
|
||||||||||||||||
|
Long-Term Debt(1)
|
$ | 37,006 | $ | 52,725 | $ | 10,547 | $ | 382,731 | $ | 483,009 | ||||||||||
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Interest Payments - Long-Term Debt(1)
|
24,444 | 44,023 | 38,035 | 245,122 | 351,624 | |||||||||||||||
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Operating Leases
|
2,237 | 3,955 | 3,667 | 2,918 | 12,777 | |||||||||||||||
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Construction/Maintenance & Other Projects(2)
|
34,883 | 49,672 | 17,352 | 4,604 | 106,511 | |||||||||||||||
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Purchased Electric Contracts(3)
|
28,104 | 33,285 | 6,238 | 12,237 | 79,864 | |||||||||||||||
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Purchased Natural Gas Contracts(3)
|
29,446 | 33,914 | 20,719 | 28,411 | 112,490 | |||||||||||||||
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Purchased Fixed Liquid Petroleum Contracts(4)
|
1,259 | - | - | - | 1,259 | |||||||||||||||
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Purchased Variable Liquid Petroleum Contracts(4)
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60,365 | - | - | - | 60,365 | |||||||||||||||
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Total Contractual Obligations(5)
|
$ | 217,744 | $ | 217,574 | $ | 96,558 | $ | 676,023 | $ | 1,207,899 | ||||||||||
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(1)
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Includes fixed rate obligations and variable interest rate bonds with estimated variable interest payments based on the actual interest paid in 2011.
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(2)
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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.
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(3)
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Purchased electric and purchased natural gas costs for Central Hudson are fully recovered via their respective regulatory cost adjustment mechanisms.
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(4)
|
Estimated based on pricing on December 31, 2011.
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|
(5)
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The estimated present value of CH Energy Group’s total contractual obligations is $783 million, assuming a discount rate of 5.5%.
|
The following is a summary of the contractual obligations for Central Hudson as of December 31, 2011 (In Thousands):
|
Projected Payments Due By Period
|
||||||||||||||||||||
|
Less than
1 year
|
Years
Ending
2013-2014
|
Years
Ending
2015-2016
|
Thereafter
|
Total
|
||||||||||||||||
|
Long-Term Debt(1)
|
$ | 36,000 | $ | 44,000 | $ | 8,000 | $ | 365,950 | $ | 453,950 | ||||||||||
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Interest Payments - Long-Term Debt(1)
|
21,183 | 38,587 | 35,533 | 239,195 | 334,498 | |||||||||||||||
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Operating Leases
|
1,500 | 2,961 | 2,920 | 2,918 | 10,299 | |||||||||||||||
|
Construction/Maintenance & Other Projects(2)
|
34,883 | 49,672 | 17,352 | 4,604 | 106,511 | |||||||||||||||
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Purchased Electric Contracts(3)
|
28,104 | 33,285 | 6,238 | 12,237 | 79,864 | |||||||||||||||
|
Purchased Natural Gas Contracts(3)
|
29,446 | 33,914 | 20,719 | 28,411 | 112,490 | |||||||||||||||
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Total Contractual Obligations(4)
|
$ | 151,116 | $ | 202,419 | $ | 90,762 | $ | 653,315 | $ | 1,097,612 | ||||||||||
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(1)
|
Includes fixed rate obligations and variable interest rate bonds with estimated variable interest payments based on the actual interest paid in 2011.
|
|
(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 $689 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 at least annually and are primarily affected by the discount rate used to determine benefit obligations, current asset values, the projection of Retirement Plan assets and corporate resources. Based on the funding requirements of the Pension Protection Act, Central Hudson plans to make contributions that maintain the funded percentage at 80% or higher. Central Hudson’s contribution in 2011 to fund the Retirement Plan was $32.0 million and its 2012 contribution is expected to total approximately $28.0 million, resulting in a funded status that meets Central Hudson’s objective. The actual contributions could vary significantly based upon actual and projected investment returns, interest rate assumptions and corporate resources. 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.
Central Hudson’s contributions in 2011 to fund OPEBs were $1.2 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 year are expected to be $3.3 million.
During 2011, the value of the Retirement Plan and OPEB assets increased by $35.2 million and decreased by $2.1 million, respectively. However, the decrease in discount rates from 2009 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. 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. During the first quarter of 2010, Management began a transition to a long-duration investment strategy that is intended to reduce the year-to-year volatility of the funded status of the plan and of the level of contributions by more closely aligning the characteristics of plan assets and liabilities. Management cannot currently predict what impact future financial market volatility may have on the funded status of the plan or future funding decisions.
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 loans.
Central Hudson’s planned capital expenditures for construction and removal during 2012 total approximately $108 million. Central Hudson expects to fund capital expenditures 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.
Central Hudson intends to fund growth in its long-lived assets in a manner that maintains an equity ratio of approximately 48% or higher excluding short-term debt balances. Central Hudson plans 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 from its current level of working capital.
Excluding acquisitions, capital expenditures at Griffith are expected to be approximately $2.5 million during 2012. In accordance with its business strategy, Griffith expects to fund any acquisitions from internally generated cash flow.
Griffith is financed by intercompany loans and equity investments from CH Energy Group in a manner that maintains an equity ratio of approximately 55% before seasonal working capital needs. CH Energy Group plans to utilize short-term debt to fund seasonal and short-term variations in Griffith’s working capital needs. If wholesale energy prices increase, Griffith would expect a corresponding increase from its current level of working capital.
CH Energy Group believes cash generated from operations and funds obtained from its financing program will be sufficient in 2012 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. Recent strategic decisions, including the divestiture of CHEC’s four largest renewable energy investments in 2011, improved the stability of CH Energy Group’s cash flow and financing requirements.
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 2012 or the foreseeable future.
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. During 2011, CH Energy Group purchased 919,114 shares under the Repurchase Program. Subsequent to year-end and through February 1, 2012, CH Energy Group purchased no additional shares under the Repurchase Program. CH Energy Group may purchase additional shares under the Program during 2012. During 2010, 29,562 shares were purchased, and no shares were purchased under the Repurchase Program in 2009. CH Energy Group intends to set repurchase targets, if any, from time to time based on then prevailing circumstances.
Financing Program
CH Energy Group believes that it is well positioned with a strong balance sheet and strong liquidity. CH Energy Group entered 2012 with modest 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 various compensation plans, no equity issuance is currently planned for 2012.
During 2011, CH Energy Group acted upon its October 2010 announced strategy transition and began to divest its investments in the renewable energy industry through CHEC. In the course of the year, CHEC divested its four largest renewable energy investments: Lyondsale, Shirley Wind, CH-Auburn, and CH-Greentree. Proceeds from the sale of these investments were used primarily for the repurchase of outstanding Common Stock of CH Energy Group and debt repayment of $20 million of the holding company’s Series A private placement debt.
CH Energy Group maintains a $150 million revolving credit agreement with several commercial banks to provide committed liquidity beyond its cash balance. At December 31, 2011, CH Energy Group had $5 million in outstanding borrowings under its credit agreement.
On October 19, 2011, Central Hudson entered into a new $150 million committed revolving credit facility with JPMorgan Chase Bank, N.A., Bank of America, N.A., HSBC Bank USA, N.A., KeyBank National Association and RBS Citizens Bank, N.A. as the participating banks. The new credit facility has a term of five years. The previous $125 million facility was terminated as of the effective date of the new agreement. In addition to this credit facility, 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, 2011, Central Hudson had no outstanding balance under its uncommitted lines of credit and a $1.5 million outstanding balance under its committed credit facility.
The lenders under CH Energy Group's $150 million credit agreement include JPMorgan Chase Bank, N.A., Bank of America N.A., HSBC Bank USA, N.A., and KeyBank, N.A. 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 and privately placed debt. 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.
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 authorized Central Hudson to issue the long-term debt to finance its construction expenditures, refund maturing long-term debt, and refinance its 1999 NYSERDA Bonds, Series B, C and D. Under this provision, the Series C and D bonds were refinanced. A 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. The registration became effective on January 6, 2010.
On September 30, 2011, Central Hudson issued $33.4 million of its Series G registered unsecured medium term notes in two maturities. The first maturity bears interest at the rate of 3.378% per annum on a principal amount of $23.4 million and matures on April 1, 2022. The second maturity bears interest at the rate of 4.707% per annum on a principal amount of $10.0 million and matures on April 1, 2042. In November 2011, Central Hudson used the proceeds from the sale of the notes to redeem its 1999 Series A NYSERDA Bonds in the principal amount of $33.4 million bearing interest at the rate of 5.45%. No bonds of this 1999 Series A remained outstanding following the redemption.
Central Hudson has two outstanding series of tax-exempt pollution control revenue bonds, totaling $50.4 million in principal amount, which were issued through 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’/stable by Moody’s.1
Central Hudson’s Series B 1999 NYSERDA Bonds total $33.7 million and are tax-exempt multi-modal bonds that are currently in a variable rate mode. In its Orders, the PSC has authorized deferral accounting treatment for variations in the interest costs under these bonds. As such, variations between the actual interest rates on these bonds and the interest rate included in the current delivery rate structure for these bonds are deferred for future recovery from or refund to customers. As a result, variations in interest rates do not have any impact on earnings.
To mitigate the potential cash flow impact from unexpected increases in short-term interest rates on the Series B Bonds, Central Hudson purchased an interest rate cap based on an index of the short-term tax-exempt debt. The rate cap is two years in length with a notional amount aligned with the principal amount of the Series B and will expire on April 1, 2012. The cap is based on the monthly weighted average of an index of tax-exempt variable rate debt, multiplied by 175%. Central Hudson would receive a payout if the adjusted index exceeds 5.0% for a given month. As of December 31, 2011, no payout is expected and as such the fair value of this instrument is zero. Central Hudson expects to replace the expiring rate cap as needed.
Central Hudson is currently evaluating what actions, if any, it may take in the future in connection with its 1999 NYSERDA Series B Bonds. Potential actions may include converting the debt to another interest rate mode or refinancing with taxable bonds.
Central Hudson had an additional $33.4 million in notes outstanding in 2011 consisting of 1999 NYSERDA Series A Bonds. Central Hudson retired this Series on November 7, 2011 with the use of proceeds of its Series G Medium Term Notes discussed earlier. No bonds of this 1999 Series A remained outstanding following the redemption.
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.
In March 2012, outstanding medium term notes issued by Central Hudson totaling $36 million will mature. Central Hudson expects to refinance these notes under its Series G note program.
Costs incurred in the issuance of the unsecured Series G Medium Term Notes have been allocated proportionately across the issuances and will be amortized over their respective terms. Unamortized costs written off in the retirement of the 1999 Series A bonds have been deferred as a regulatory asset and will be amortized over the original term of the bonds. The amortization of debt costs for both outstanding and redeemed debt are incorporated in the revenue requirement for delivery rates as authorized by the PSC.
Griffith’s debt financing of $35.1 million, as of December 31, 2011, is provided by CH Energy Group through intercompany loans at market rates.
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 sub-caption “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.”
REGULATORY MATTERS – 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: New York State has established a goal of substantially reducing electricity usage and created a State Energy Planning Board which is authorized to create and implement a State Energy Plan (“SEP”). 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:
|
·
|
On January 7, 2009 Governor Patterson’s State of the State address included clean energy goals, including expanding the Renewable Portfolio Standard from 25% by 2013 to 30% by 2015 and decreasing electric usage by 15% by 2015.
|
|
·
|
During 2009 and 2010 Central Hudson received approval through the Energy Efficiency Portfolio Standard (“EEPS”) proceedings to implement various programs to electric and natural gas residential and commercial customers.
|
|
·
|
In December 2010, the PSC issued an Order combining energy savings targets to create a single 2008-2011 target and utility shareholder financial incentives established in the EEPS proceeding. Calendar year targets will be in effect for 2012 and beyond.
|
|
·
|
On October 25, 2011, the PSC’s statewide Order reauthorized Central Hudson’s EEPS programs subject to continuous improvement, for the four year period ending December 31, 2015 and directed the Secretary to initiate a process to establish individual utility performance positive incentives and statewide jurisdictional goals to be in effect 2012 through 2015.
|
|
·
|
In 2011, Central Hudson earned incentives of $2.7 million based on calculated energy savings for completed and committed projects with residential and commercial customers compared to 2008-2011 cumulative savings targets.
|
Potential Impacts: This PSC proceeding could result in opportunities for increased earnings from incentives associated with achieving energy efficiency targets for the 2012-2015 period. No prediction can be made regarding the final outcome of this matter.
Petition of Central Hudson Gas & Electric Corporation for Commission Approval of a Plan for Deferred Accounting for Future Recovery with Carrying Charges of Three Items and Funding These and Certain Other Deferrals through Balance Sheet Offsets
(Case 10-M-0473)
Background: On September 23, 2010, Central Hudson filed a petition with the PSC to defer for future recovery with carrying charges $19.4 million incremental electric storm restoration expense, $2.6 million incremental electric bad debt write-off expense, $1.9 million incremental electric property tax expense and $0.7 million incremental gas property tax expense above the respective rate allowances during the twelve months ended June 30, 2010. The petition also requested approval for recovery via offsets of the foregoing against significant tax refunds resulting from a change in the way Central Hudson treats certain capital expenditures for tax purposes. Additional offsets against other deferred items, notably including MGP site investigation and remediation costs were also included in the petition given the size of the tax refunds.
Notable Activity:
|
·
|
In December 2010, Central Hudson provided an update and amended the incremental storm expense deferral request to $19.7 million.
|
|
·
|
On April 14, 2011, the Commission issued an Order authorizing deferral of $18.8 million (denial of $0.8 million) of the incremental electric storm restoration expense and the $2.6 million of incremental bad debt expense and denying deferral of the Company’s $2.6 million of incremental electric and gas property tax expense. The PSC also approved the ratemaking treatment proposed by Central Hudson and the offsets were recorded as of March 31, 2011.
|
|
·
|
On May 13, 2011, Central Hudson filed a Petition for Clarification and Rehearing on the PSC’s April 14, 2011 Order. The petition sought clarification concerning recovery of the costs to achieve and rehearing for reconsideration and recovery of a portion of certain costs denied by the Commission related to the incremental electric storm restoration expense.
|
|
·
|
On November 22, 2011, the PSC issued an Order modifying the April 2011 Order to correct for a miscalculation error in the PSC’s analysis and increase the authorized deferral for storm restoration expense by approximately $0.3 million and to clarify that the Company is allowed to net the external costs to achieve against the federal income tax benefits.
|
SIR Proceeding
(Case 11-M-0034 – Proceeding on Motion of the Commission to Commence a Review and Evaluation of the Treatment of the States’ Regulated Utilities’ Site Investigation and Remediation (“SIR”) Costs)
Background: In February 2011, the PSC initiated a proceeding to review and evaluate the treatment of MGP SIR costs. The proceeding began with a data gathering phase from all utilities on the history of sites and efforts and also to address cost control issues, allocation of responsibility and alternate rate treatments.
Notable Activity:
|
·
|
The Administrative Law Judge established a case procedure and schedule, adopting a comment oriented proceeding that included issuance of a PSC Staff Policy Whitepaper in June and a Technical Conference in July.
|
|
·
|
PSC Staff Whitepaper reported that there does not appear to be any deficiency in utility cost control practices, with adequate controls in place. Staff also found that rate recovery for prudent and verifiable legally imposed clean up costs is a reasonable approach and warned that sharing or less than full recovery will have cost capital impacts.
|
|
·
|
On November 3, 2011, the ALJ issued a Recommended Decision (“RD”) against any generic ratepayer/shareholder policy, or any ratemaking cap on expenses based on cost estimates or denying recovery of any carrying charges on deferred balances. It also recommends adoption of additional annual reporting, new independent shareholder funded audits and development of best cost control practices for MGP remediation.
|
|
·
|
Briefs on Exceptions were filed on November 23, 2011 and Briefs Opposing Exceptions were filed on December 8, 2011.
|
Potential Impacts: A change to the current recovery structure of MGP SIR costs could have an adverse impact on Central Hudson earnings. For further discussion about Central Hudson’s SIR activities, see Note 12 – “Commitments and Contingencies” under the caption “Former Manufactured Gas Plant Facilities” to the Consolidated Financial Statements of this 10-K Annual Report. No prediction can be made regarding the outcome of the matter at this time.
Advanced Metering Infrastructure
(Case 09-M-0074 - Proceeding on Matter of Advanced Metering Infrastructure)
(Case 10-E-0285 - Proceeding on Motion of the Commission to Consider Regulatory Policies Regarding Smart Grid Systems and the Modernization of the Electric Grid)
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 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:
|
·
|
In July 2010, the PSC closed Case 09-M-0074 and initiated a new proceeding, Case 10-E-0285 to determine to what extent further development of regulatory policies should be made to encourage electric utilities to develop smart grid systems that can facilitate the integration of new technologies while optimizing their efficient use of facilities and resources, and producing equitable rates for electric customers.
|
|
·
|
On August 19, 2011, the PSC issued its Smart Grid Policy Statement that provides a policy framework to enable utilities to avail themselves of the opportunities in this area and to address challenges that will emerge during transition to a Smart Grid. This policy statement addresses implementation priorities/tracking, communications technology, benefit/cost analysis, cost uncertainty and cost recovery, interoperability and cyber security standards and customer data/privacy issues. It also encourages electric utilities to develop Smart Grid systems that integrate new intelligent technologies, while optimizing the use of existing facilities and resources and maintaining just and reasonable rates for customers.
|
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 the Office of Electricity Delivery and Energy Reliability (“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:
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In October 2009, NYISO was awarded $37.4 million for a Statewide Capacitor Installation Project and a Statewide Phasor Measurement Unit Project. Central Hudson’s portions of these projects are $1.6 million and $3.1 million, respectively.
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In October 2010, the PSC directed utilities to establish deferral accounting for the costs associated with approved stimulus projects.
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In August 2009, Central Hudson was approved for a $0.7 million grant to fund the incremental cost of Charging Station Hybrid technology for eight heavy duty line trucks. Implementation was completed in 2011.
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Management Audit
(Case 09-M-0764 – Comprehensive Management Audit of Central Hudson Gas & Electric Business)
Background: In February 2010, the PSC selected NorthStar Consulting Group (“NorthStar”) as the 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 allowed to audit New York utilities every five years.
Notable Activity:
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·
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In October 2010, the audit scope was expanded to examine affiliate transactions and accounting.
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On February 28, 2011, a final report of NorthStar’s findings and recommendations to the PSC was completed. On March 25, 2011, Central Hudson filed its audit comment letter with the PSC.
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On May 20, 2011, the Commission accepted NorthStar’s Audit Report and issued its Order directing Central Hudson to file an implementation plan based on the report’s twenty recommendations.
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On July 1, 2011, Central Hudson submitted its implementation plan to the Commission. The DPS Staff has initiated discovery on the implementation plan with a series of data requests.
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On September 15, 2011, Central Hudson presented an interim mid-term review to the DPS Staff to discuss the Company’s progress on the twenty recommendations.
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On November 1, 2011, Central Hudson filed its first Implementation Plan to report on its progress. Central Hudson reported that five of the twenty audit recommendations were complete.
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The next mid-term review with DPS Staff was held January 25, 2012 and will be followed by a March 1, 2012 Management Audit Implementation Plan report.
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Potential Impacts: Central Hudson will work with DPS Staff to develop a method to quantify qualitative improvements through a cost benefit analysis for those recommendations that were assigned cost savings. No prediction can be made regarding the outcome of the matter at this time.
Petition of Central Hudson Gas & Electric Corporation for Commission Approval of Deferred Incremental Costs Associated with Tropical Storm Irene
(Case 11-E-0651)
Background: On November 28, 2011, Central Hudson filed a petition with the PSC seeking approval for deferred costs for future recovery with carrying charges of $11.4 million of incremental electric storm restoration expense above the respective rate allowance during the calendar year ended December 31, 2011. These incremental costs represent the amount Central Hudson has deferred on its books as of October 31, 2011 based on actual costs incurred, bills received and an estimate for bills outstanding. The Company believes the incremental costs associated with this storm meet the PSC’s criteria for deferral: 1) amount is incremental to the amount in rates; 2) the incremental amount is material and extraordinary in nature; and 3) the utility’s earnings are below the authorized rate of return on common equity. Central Hudson will finalize its measure of materiality and utility earnings based upon the calendar year ended December 31, 2011 results.
Deferral of October 29, 2011 SnowFall Costs
Background: On October 29, 2011, Central Hudson experienced an unusual winter storm with snow accumulations of up to 20 inches in the service territory, resulting in electric service outages to over 150,000 customers, extensive damage to the electric system and significant restoration costs. Following Tropical Storm Irene, the October snowstorm represents the second extraordinary storm event that has occurred to date within the second rate year established by the PSC in its Rate Plan adopting the terms of a Joint Proposal in Case 09-E-0588. As of December 31, 2011, Central Hudson has deferred $4.1 million of estimated incremental storm restoration costs.
Potential Impacts: Central Hudson anticipates filing a petition seeking authority to defer for future recovery all incremental storm restoration costs totaling approximately $8 million, subject to the criteria the PSC has established for consideration and approval of deferral authorization requests. Based on current estimates and assumptions, Management believes the $4.1 million of incremental costs that have been deferred as of December 31, 2011, meet the accounting standard of being probable of future recovery.
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.”
OTHER MATTERS
Pension Protection Act
Under the Pension Protection Act signed into law in 2006, 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.
Off-Balance Sheet Arrangements
CH Energy Group and Central Hudson do not have any off-balance sheet arrangements.
Retirement Plan
See Note 10 – “Post-Employment Benefits” and Critical Accounting Policies for a discussion of the Retirement Plan.
Climate
While it is possible that some form of global climate change program will be adopted at the federal level in 2012, 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, mainly because the Company does not generate electricity in significant quantities and the electricity it does generate is primarily from zero emission hydroelectric plants. 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 RDMs 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. For additional information regarding regulatory accounting, see Note 2 – “Regulatory Matters.”
Use of Estimates
Preparation of the Consolidated Financial Statements in accordance with 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, tax 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, 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.”
During 2010, Central Hudson elected to change its tax return methodology for claiming deductions for incidental repair and maintenance expenditures on its utility assets. The change accelerates the recognition of the tax deduction from later periods. Although the Company believes that its methodology for claiming the deduction is consistent with the Internal Revenue Code and case law, it is unclear whether the Internal Revenue Service will accept the entirety of the deduction claimed. Accordingly, Central Hudson recorded a reserve in 2010 based upon the expected outcome on audit.
In August 2011, the IRS released Revenue Procedure 2011-43, which provides a safe harbor method of accounting for determining the amount of expenditures required to be capitalized. The Revenue Procedure applies to electric transmission and distribution property only. It also provides procedures for obtaining automatic consent to change to the safe harbor method of accounting. Central Hudson is still evaluating the impacts of the Revenue Procedure. As it is probable that Central Hudson will adopt this Revenue Procedure effective with the filing of its 2011 Federal Income Tax return, the electric portion of the reserve established in 2010 has been reclassified to deferred tax liability accounts. See Note 4 – “Income Tax” for further discussion of the tax reserve established.
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, 2011 and December 31, 2010 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, both goodwill and intangible assets not subject to amortization are reviewed 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 unit is compared to the carrying amount of assets. In the fourth quarter, Management performed a qualitative assessment of any potential impairment of Griffith’s goodwill. Based upon the qualitative analysis, management believes that it is more likely than not that the fair market value is more than the carrying value of Griffith and therefore, the first and second steps of the impairment test prescribed in the guidance was deemed not necessary. The carrying amount for goodwill was $37.5 million as of December 31, 2011 and $35.9 million as of December 31, 2010. If the operating cash flows of Griffith decline significantly relative to CH Energy Group’s investment in Griffith 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 last quantitative analysis of impairment was performed on September 30, 2010, which reflected that the fair value of Griffith exceeded its carrying value by approximately $34.2 million. 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 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 indicated market rate of return on equity; and 3) the current after-tax rate of return on debt. In valuing its goodwill for 2010, Griffith used an average risk-adjusted discount rate of 10.4%. Had the risk-adjusted discount rate been 25 basis points higher, the aggregate estimated fair value of the reporting units would have decreased by $1.2 million, or 1.4%. In addition, Griffith used an average expected terminal growth rate of 0.5%. If the expected terminal growth rate was 25 basis points lower, the aggregate estimated fair value of the reporting units would have decreased by $0.8 million, or 0.9%. 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 $0.2 million, or 0.3%.
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, 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 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 $2.4 million, $2.3 million and $4.0 million for each of the years ended December 31, 2011, 2010 and 2009, respectively. The estimated annual amortization expense for each of the next five years, assuming no new acquisitions, is approximately $2.1 million. The weighted average amortization period for all assets acquired in the current year is 14 years. The weighted average amortization periods for customer relationships and covenants not to compete are 15 years and 5 years, respectively. 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
In accordance with the terms of the 2006, 2009 and 2010 Rate Orders, Central Hudson is authorized to defer any differences between rate allowances and actual costs for both its Retirement and OPEB plans. As a result, Central Hudson expects to fully recover its net periodic pension and OPEB costs over time.
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 2011, the Projected Benefit Obligation (“PBO”) for Central Hudson’s Retirement Plan ($555 million) and its obligation for OPEB costs ($142 million) were determined using a 4.5% discount rate, respectively. These rates were determined using the Mercer 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 $17.8 million and the OPEB obligation by approximately $4.5 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 the years ended December 31, 2011 and 2010, Central Hudson contributed $32.0 million and $64.2 million to its Retirement Plan. The decrease in discount rates from 2010 increased the present value of the plans’ liabilities at December 31, 2011. The value of the Retirement Plan increased by $35.2 million and the OPEB plan decreased in value by $2.1 million. The net effect on the funded status of the plans from the lower discount rate, along with decreased contributions in 2011 increased the unfunded liability by $19.3 million and $7.7 million, respectively. A 0.25% change in the discount rate would impact the net periodic benefit cost by $1.6 million for the Retirement Plan and $0.4 million for OPEBs. Additional contributions will likely become necessary under the terms of the Pension Protection Act of 2006. Management expects that such contributions will continue to be incorporated in the rate making process over time. 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. 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.
Central Hudson’s pension and other post-retirement plans’ weighted average asset allocations at December 31, 2011 and 2010, by asset category are as follows:
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Pension Plan
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Other Plans
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2011
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2010
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2011
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2010
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Equity Securities
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35.8 | % | 54.8 | % | 60.4 | % | 64.4 | % | ||||||||
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Debt Securities
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54.4 | % | 44.0 | % | 38.1 | % | 35.5 | % | ||||||||
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Other
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9.8 | % | 1.2 | % | 1.5 | % | 0.1 | % | ||||||||
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Total
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100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||||||
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 $144.6 million, including losses for the years 2002 through 2011. Therefore, the future annual amortization of these losses will increase pension expense, determined in accordance with current accounting guidance related to pensions, from its current level unless there are offsetting future gains or other offsetting components of pension expense.
The expected long-term rate of return on Retirement Plan and OPEB assets are 7.0% and 7.9%, 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. In the previous three years, 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. In 2012, Central Hudson is transitioning Retirement Plan equity investments to index funds and therefore there will be no expected alpha for active management. The actual annual return on Central Hudson’s Retirement Plan and OPEB assets over the previous three years are summarized as follows:
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Calendar Year Performance
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2011
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2010
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2009
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Central Hudson Retirement Plan
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8.1 | % | 13.3 | % | 21.2 | % | ||||||
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Central Hudson OPEB (1)
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1.2 | % | 14.1 | % | 27.9 | % | ||||||
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Central Hudson OPEB (1)
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8.1 | % | 11.8 | % | 24.6 | % | ||||||
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(1) OPEB assets are comprised of two separate groups of investment funds.
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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 $1.0 million for the pension plan and $0.2 million for OPEBs. The expected long-term rate of return is reviewed annually in the fourth quarter and updated if the determinants have changed.
The estimates of health care cost trend rates are based on a review of actual recent trends and projected future trends. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A 1% change in assumed health care cost trend rates would have the following effects (In Thousands):
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One Percentage
Point Increase
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One Percentage
Point Decrease
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|||||||
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Effect on total of service and interest cost components for 2011
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$ | 491 | $ | (422 | ) | |||
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Effect on year-end 2011 post-retirement benefit obligation
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$ | 4,471 | $ | (3,931 | ) | |||
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.
| ITEM 7A - 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 sub-caption “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, 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, 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.” 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. Griffith may increase the prices charged for the commodities it sells in response to changes in costs; however, its ability to raise prices is generally limited by what the competitive market in which it participates will bear.
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.
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 an expiring rate cap, effective April 1, 2010, with two one-year rate cap agreements covering certain issues of variable rate 1999 NYSERDA Bonds and a two-year rate cap covering another issue of such debt. Two of the issues, 1999 Series C and D, were redeemed in December 2010 and refunded with debt from the Company’s Series G Medium Term Note program. The caps on these two issues were for terms of one year and expired on April 1, 2011.
The two-year interest rate 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 the 1999 NYSERDA Bonds. The cap is evaluated quarterly and Central Hudson would receive a payout if the variable rate for the bonds reset at rates above 5.0%. All three rate cap agreements were made with KeyBank National Association. Please refer to Note 9 - “Capitalization - Long-Term Debt,” Note 15 - “Other Fair Value Measurements” and Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the sub-caption “Capital Resources and Liquidity” for additional disclosure related to long-term debt.
I - INDEX TO FINANCIAL STATEMENTS:
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PAGE
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88
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92
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CH Energy Group
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96
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97
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98
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100
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102
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Central Hudson
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103
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103
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104
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105
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107
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Notes to Consolidated Financial Statements
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Summary of Significant Accounting Policies
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108
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Regulatory Matters
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119
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New Accounting Guidance
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127
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Income Tax
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128
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Acquisitions, Divestitures and Investments
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134
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Goodwill and Other Intangible Assets
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137
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Short-Term Borrowing Arrangements
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138
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Capitalization - Common and Preferred Stock
|
139
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Capitalization - Long-Term Debt
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142
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Post-Employment Benefits
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145
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Equity-Based Compensation
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156
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Commitments And Contingencies
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160
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Segments And Related Information
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170
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Accounting for Derivative Instruments and Hedging Activities
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172
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Other Fair Value Measurements
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182
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Subsequent Events
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186
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187
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Financial Statement Schedules
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188
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191
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191
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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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 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, 2011, 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
New York, New York
February 16, 2012
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, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011 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, 2011, 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
New York, New York
February 16, 2012
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, 2011. 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, 2011, the Corporation maintained effective internal control over financial reporting.
The effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
|
/s/ Steven V. Lant
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/s/ Christopher M. Capone
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||
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Steven V. Lant
|
Christopher M. Capone
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||
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Chairman of the Board, President and Chief Executive Officer
|
Executive Vice President and
Chief Financial Officer
|
February 16, 2012
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:
|
·
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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, 2011. 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, 2011, the Corporation maintained effective internal control over financial reporting.
The effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
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/s/ Steven V. Lant
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/s/ Christopher M. Capone
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Steven V. Lant
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Christopher M. Capone
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||
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Chairman of the Board and
Chief Executive Officer
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Executive Vice President and
Chief Financial Officer
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February 16, 2012
(In Thousands, except per share amounts)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Operating Revenues
|
|
|
|
|||||||||
|
Electric
|
$ | 538,548 | $ | 563,139 | $ | 536,170 | ||||||
|
Natural gas
|
161,974 | 156,795 | 174,137 | |||||||||
|
Competitive business subsidiaries:
|
||||||||||||
|
Petroleum products
|
266,066 | 220,518 | 193,288 | |||||||||
|
Other
|
18,932 | 19,656 | 17,962 | |||||||||
|
Total Operating Revenues
|
985,520 | 960,108 | 921,557 | |||||||||
|
Operating Expenses
|
||||||||||||
|
Operation:
|
||||||||||||
|
Purchased electricity and fuel used in electric generation
|
206,160 | 246,116 | 261,003 | |||||||||
|
Purchased natural gas
|
76,778 | 75,189 | 107,221 | |||||||||
|
Purchased petroleum
|
228,156 | 182,753 | 151,411 | |||||||||
|
Other expenses of operation - regulated activities
|
238,557 | 224,955 | 194,383 | |||||||||
|
Other expenses of operation - competitive business subsidiaries
|
47,474 | 45,429 | 49,771 | |||||||||
|
Impairment on long-lived assets
|
- | 2,116 | - | |||||||||
|
Depreciation and amortization
|
40,055 | 38,275 | 36,582 | |||||||||
|
Taxes, other than income tax
|
48,751 | 45,972 | 39,601 | |||||||||
|
Total Operating Expenses
|
885,931 | 860,805 | 839,972 | |||||||||
|
Operating Income
|
99,589 | 99,303 | 81,585 | |||||||||
|
Other Income and Deductions
|
||||||||||||
|
Income (loss) from unconsolidated affiliates
|
735 | (318 | ) | 228 | ||||||||
|
Interest on regulatory assets and other interest income
|
5,777 | 5,475 | 5,789 | |||||||||
|
Impairment of investments
|
(3,582 | ) | (11,408 | ) | (1,299 | ) | ||||||
|
Regulatory adjustments for interest costs
|
1,351 | (1,105 | ) | (1,366 | ) | |||||||
|
Business development costs
|
(1,222 | ) | (1,809 | ) | (2,012 | ) | ||||||
|
Other - net
|
(493 | ) | (1,509 | ) | (1,263 | ) | ||||||
|
Total Other Income (Deductions)
|
2,566 | (10,674 | ) | 77 | ||||||||
|
Interest Charges
|
||||||||||||
|
Interest on long-term debt
|
26,520 | 22,973 | 20,999 | |||||||||
|
Penalty for early retirement of debt
|
2,982 | - | - | |||||||||
|
Interest on regulatory liabilities and other interest
|
5,656 | 6,112 | 4,797 | |||||||||
|
Total Interest Charges
|
35,158 | 29,085 | 25,796 | |||||||||
|
|
||||||||||||
|
Income before income taxes, non-controlling interest and preferred dividends of subsidiary
|
66,997 | 59,544 | 55,866 | |||||||||
|
Income Taxes
|
23,813 | 19,214 | 22,269 | |||||||||
|
Net Income from Continuing Operations
|
43,184 | 40,330 | 33,597 | |||||||||
|
|
||||||||||||
|
Discontinued Operations
|
||||||||||||
|
Income (loss) from discontinued operations before tax
|
1,660 | (2,333 | ) | 5,026 | ||||||||
|
Gain (loss) from sale of discontinued operations
|
(457 | ) | - | 10,767 | ||||||||
|
Income tax (benefit) expense from discontinued operations
|
(1,923 | ) | (1,205 | ) | 5,112 | |||||||
|
Net Income (loss) from Discontinued Operations
|
3,126 | (1,128 | ) | 10,681 | ||||||||
|
|
||||||||||||
|
Net Income
|
46,310 | 39,202 | 44,278 | |||||||||
|
|
||||||||||||
|
Net Income (loss) attributable to non-controlling interest:
|
||||||||||||
|
Non-controlling interest in subsidiary
|
- | (272 | ) | (176 | ) | |||||||
|
Dividends declared on Preferred Stock of subsidiary
|
970 | 970 | 970 | |||||||||
|
Net Income Attributable to CH Energy Group
|
45,340 | 38,504 | 43,484 | |||||||||
|
|
||||||||||||
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Dividends declared on Common Stock
|
33,291 | 34,161 | 34,119 | |||||||||
|
Change in Retained Earnings
|
$ | 12,049 | $ | 4,343 | $ | 9,365 | ||||||
CH ENERGY GROUP CONSOLIDATED STATEMENT OF INCOME (CONT'D)
(In Thousands, except per share amounts)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Common Stock:
|
|
|
|
|||||||||
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Average shares outstanding - Basic
|
15,278 | 15,785 | 15,775 | |||||||||
|
Average shares outstanding - Diluted
|
15,481 | 15,952 | 15,881 | |||||||||
|
|
||||||||||||
|
Income from continuing operations attributable to CH Energy Group common shareholders
|
||||||||||||
|
Earnings per share - Basic
|
$ | 2.77 | $ | 2.51 | $ | 2.08 | ||||||
|
Earnings per share - Diluted
|
$ | 2.73 | $ | 2.48 | $ | 2.07 | ||||||
|
|
||||||||||||
|
Income (loss) from discontinued operations attributable to CH Energy Group common shareholders
|
||||||||||||
|
Earnings per share - Basic
|
$ | 0.20 | $ | (0.07 | ) | $ | 0.68 | |||||
|
Earnings per share - Diluted
|
$ | 0.20 | $ | (0.07 | ) | $ | 0.67 | |||||
|
|
||||||||||||
|
Amounts attributable to CH Energy Group common shareholders
|
||||||||||||
|
Earnings per share - Basic
|
$ | 2.97 | $ | 2.44 | $ | 2.76 | ||||||
|
Earnings per share - Diluted
|
$ | 2.93 | $ | 2.41 | $ | 2.74 | ||||||
|
Dividends Declared Per Share
|
$ | 2.19 | $ | 2.16 | $ | 2.16 | ||||||
(In Thousands)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Net Income
|
$ | 46,310 | $ | 39,202 | $ | 44,278 | ||||||
|
|
||||||||||||
|
Other Comprehensive Income:
|
||||||||||||
|
Fair value of cash flow hedges:
|
||||||||||||
|
Unrealized loss - net of tax of $0, $0 and $7
|
- | - | (10 | ) | ||||||||
|
Reclassification for (gain) loss realized in net income - net of tax of $0, $22 and ($29)
|
- | (34 | ) | 44 | ||||||||
|
Net unrealized gain (loss) on investments held by equity method investees - net of tax of $70, ($206) and ($63)
|
(105 | ) | 309 | 95 | ||||||||
|
|
||||||||||||
|
Other comprehensive (loss) income
|
(105 | ) | 275 | 129 | ||||||||
|
|
||||||||||||
|
Comprehensive Income
|
46,205 | 39,477 | 44,407 | |||||||||
|
|
||||||||||||
|
Comprehensive income attributable to non-controlling interest
|
970 | 698 | 794 | |||||||||
|
|
||||||||||||
|
Comprehensive income attributable to CH Energy Group
|
$ | 45,235 | $ | 38,779 | $ | 43,613 | ||||||
(In Thousands)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Operating Activities:
|
|
|
|
|||||||||
|
Net income
|
$ | 46,310 | $ | 39,202 | $ | 44,278 | ||||||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||||||
|
Depreciation
|
37,461 | 36,156 | 35,399 | |||||||||
|
Amortization
|
4,200 | 3,892 | 5,146 | |||||||||
|
Deferred income taxes - net
|
20,207 | 30,858 | 15,514 | |||||||||
|
Bad debt expense
|
8,516 | 4,692 | 11,515 | |||||||||
|
Impairment of investments
|
3,582 | 11,408 | 1,299 | |||||||||
|
Impairment on long-lived assets
|
- | 2,116 | - | |||||||||
|
Distributed (undistributed) equity in earnings of unconsolidated affiliates
|
(735 | ) | 863 | 829 | ||||||||
|
Pension expense
|
26,516 | 29,345 | 20,282 | |||||||||
|
Other post-employment benefits ("OPEB") expense
|
6,801 | 6,940 | 8,346 | |||||||||
|
Regulatory liability - rate moderation
|
(8,750 | ) | (16,789 | ) | (9,915 | ) | ||||||
|
Revenue decoupling mechanism recorded
|
1,371 | (3,843 | ) | (5,789 | ) | |||||||
|
Regulatory asset amortization
|
4,571 | 4,497 | 4,541 | |||||||||
|
Regulatory asset energy efficiency incentives
|
(2,719 | ) | - | - | ||||||||
|
Loss (gain) on sale of assets
|
283 | - | (10,778 | ) | ||||||||
|
Changes in operating assets and liabilities - net of business acquisitions:
|
||||||||||||
|
Accounts receivable, unbilled revenues and other receivables
|
(2,728 | ) | (10,033 | ) | 6,854 | |||||||
|
Fuel, materials and supplies
|
(417 | ) | (563 | ) | 9,187 | |||||||
|
Special deposits and prepayments
|
851 | (1,493 | ) | (305 | ) | |||||||
|
Income and other taxes
|
1,140 | 19,870 | (2,304 | ) | ||||||||
|
Accounts payable
|
(18,378 | ) | 11,138 | (3,875 | ) | |||||||
|
Accrued interest
|
(65 | ) | 331 | 168 | ||||||||
|
Customer advances
|
3,218 | (3,141 | ) | 1,839 | ||||||||
|
Pension plan contribution
|
(32,699 | ) | (64,805 | ) | (23,124 | ) | ||||||
|
OPEB contribution
|
(1,184 | ) | (4,800 | ) | (3,485 | ) | ||||||
|
Revenue decoupling mechanism collected
|
1,671 | 5,049 | 759 | |||||||||
|
Regulatory asset - storm deferral
|
(11,753 | ) | (19,667 | ) | - | |||||||
|
Regulatory asset - manufactured gas plant ("MGP") site remediation
|
4,412 | (12,216 | ) | (2,278 | ) | |||||||
|
Regulatory asset - Temporary State Assessment
|
2,342 | 1,445 | (10,947 | ) | ||||||||
|
Deferred natural gas and electric costs
|
19,545 | (2,709 | ) | 14,321 | ||||||||
|
Other - net
|
7,311 | 19,207 | 18,898 | |||||||||
|
Net cash provided by operating activities
|
120,880 | 86,950 | 126,375 | |||||||||
|
Investing Activities:
|
||||||||||||
|
Proceeds from sale of assets
|
45,472 | 82 | 74,659 | |||||||||
|
Additions to utility and other property and plant
|
(88,353 | ) | (103,111 | ) | (123,132 | ) | ||||||
|
Acquisitions made by competitive business subsidiaries
|
(4,451 | ) | (743 | ) | - | |||||||
|
Proceeds from federal grants
|
14,744 | - | - | |||||||||
|
Other - net
|
(4,151 | ) | (4,797 | ) | (7,249 | ) | ||||||
|
Net cash used in investing activities
|
(36,739 | ) | (108,569 | ) | (55,722 | ) | ||||||
|
Financing Activities:
|
||||||||||||
|
Redemption of long-term debt
|
(54,341 | ) | (106,150 | ) | (20,000 | ) | ||||||
|
Proceeds from issuance of long-term debt
|
33,400 | 122,150 | 74,000 | |||||||||
|
Borrowings of short-term debt - net
|
6,500 | - | (35,500 | ) | ||||||||
|
Dividends paid on Common Stock
|
(33,554 | ) | (34,164 | ) | (34,107 | ) | ||||||
|
Dividends paid on Preferred Stock of subsidiary
|
(970 | ) | (970 | ) | (970 | ) | ||||||
|
Shares repurchased
|
(48,687 | ) | (1,465 | ) | - | |||||||
|
Other - net
|
(628 | ) | (1,798 | ) | (465 | ) | ||||||
|
Net cash used in financing activities
|
(98,280 | ) | (22,397 | ) | (17,042 | ) | ||||||
|
Net Change in Cash and Cash Equivalents
|
(14,139 | ) | (44,016 | ) | 53,611 | |||||||
|
Cash and Cash Equivalents at Beginning of Period
|
29,420 | 73,436 | 19,825 | |||||||||
|
Cash and Cash Equivalents at End of Period
|
$ | 15,281 | $ | 29,420 | $ | 73,436 | ||||||
The Notes to Financial Statements are an integral part hereof.
CH ENERGY GROUP CONSOLIDATED STATEMENT OF CASH FLOWS (CONT'D)
(In Thousands)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Supplemental Disclosure of Cash Flow Information:
|
|
|
|
|||||||||
|
Interest paid
|
$ | 29,993 | $ | 23,462 | $ | 21,548 | ||||||
|
Federal and state income taxes paid
|
$ | 1,146 | $ | 5,554 | $ | 12,462 | ||||||
|
Additions to plant included in liabilities
|
$ | 6,172 | $ | 4,125 | $ | 2,235 | ||||||
|
Regulatory asset - storm deferral costs in liabilities
|
$ | 3,525 | $ | - | $ | - | ||||||
The Notes to Financial Statements are an integral part hereof.
(In Thousands)
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
ASSETS
|
|
|
||||||
|
Utility Plant
|
|
|
||||||
|
Electric
|
$ | 1,008,394 | $ | 963,261 | ||||
|
Natural gas
|
305,664 | 292,358 | ||||||
|
Common
|
147,286 | 142,255 | ||||||
|
Gross Utility Plant
|
1,461,344 | 1,397,874 | ||||||
|
|
||||||||
|
Less: Accumulated depreciation
|
388,784 | 395,776 | ||||||
|
Net
|
1,072,560 | 1,002,098 | ||||||
|
|
||||||||
|
Construction work in progress
|
58,847 | 52,607 | ||||||
|
Net Utility Plant
|
1,131,407 | 1,054,705 | ||||||
|
|
||||||||
|
Non-Utility Property & Plant
|
||||||||
|
Griffith non-utility property & plant
|
31,669 | 29,881 | ||||||
|
Other non-utility property & plant
|
524 | 64,059 | ||||||
|
Gross Non-Utility Property & Plant
|
32,193 | 93,940 | ||||||
|
|
||||||||
|
Less: Accumulated depreciation - Griffith
|
22,006 | 20,519 | ||||||
|
Less: Accumulated depreciation - other
|
- | 5,108 | ||||||
|
Net Non-Utility Property & Plant
|
10,187 | 68,313 | ||||||
|
|
||||||||
|
Current Assets
|
||||||||
|
Cash and cash equivalents
|
15,281 | 29,420 | ||||||
|
Accounts receivable from customers - net of allowance for doubtful accounts of $7.0 million and $6.7 million, respectively
|
90,937 | 99,402 | ||||||
|
Accrued unbilled utility revenues
|
15,299 | 16,233 | ||||||
|
Other receivables
|
9,512 | 8,006 | ||||||
|
Fuel, materials and supplies
|
25,114 | 25,447 | ||||||
|
Regulatory assets
|
49,526 | 89,905 | ||||||
|
Income tax receivable
|
432 | 2,802 | ||||||
|
Fair value of derivative instruments
|
349 | 146 | ||||||
|
Special deposits and prepayments
|
21,795 | 22,869 | ||||||
|
Accumulated deferred income tax
|
5,895 | - | ||||||
|
Total Current Assets
|
234,140 | 294,230 | ||||||
|
|
||||||||
|
Deferred Charges and Other Assets
|
||||||||
|
Regulatory assets - pension plan
|
159,020 | 142,647 | ||||||
|
Regulatory assets - other
|
114,980 | 90,264 | ||||||
|
Fair value of derivative instruments
|
931 | - | ||||||
|
Goodwill
|
37,512 | 35,940 | ||||||
|
Other intangible assets - net
|
13,173 | 12,867 | ||||||
|
Unamortized debt expense
|
4,535 | 4,774 | ||||||
|
Investments in unconsolidated affiliates
|
2,777 | 6,681 | ||||||
|
Other investments
|
14,461 | 12,883 | ||||||
|
Other
|
6,989 | 5,971 | ||||||
|
Total Deferred Charges and Other Assets
|
354,378 | 312,027 | ||||||
|
Total Assets
|
$ | 1,730,112 | $ | 1,729,275 | ||||
The Notes to Financial Statements are an integral part hereof.
CH ENERGY GROUP CONSOLIDATED BALANCE SHEET (CONT'D)
(In Thousands)
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
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) 14,894,964 shares and 15,799,262 shares outstanding, respectively
|
$ | 1,686 | $ | 1,686 | ||||
|
Paid-in capital
|
351,053 | 350,360 | ||||||
|
Retained earnings
|
242,391 | 230,342 | ||||||
|
Treasury stock - 1,967,123 shares and 1,062,825 shares, respectively
|
(92,908 | ) | (44,887 | ) | ||||
|
Accumulated other comprehensive income
|
354 | 459 | ||||||
|
Capital stock expense
|
(328 | ) | (328 | ) | ||||
|
Total CH Energy Group Common Shareholders' Equity
|
502,248 | 537,632 | ||||||
|
Non-controlling interest in subsidiary
|
- | 172 | ||||||
|
Total Equity
|
502,248 | 537,804 | ||||||
|
Preferred Stock of subsidiary
|
21,027 | 21,027 | ||||||
|
Long-term debt
|
446,003 | 502,959 | ||||||
|
Total Capitalization
|
969,278 | 1,061,790 | ||||||
|
Current Liabilities
|
||||||||
|
Current maturities of long-term debt
|
37,006 | 941 | ||||||
|
Notes payable
|
6,500 | - | ||||||
|
Accounts payable
|
43,904 | 57,059 | ||||||
|
Accrued interest
|
6,333 | 6,398 | ||||||
|
Dividends payable
|
8,511 | 8,774 | ||||||
|
Accrued vacation and payroll
|
6,702 | 6,663 | ||||||
|
Customer advances
|
22,527 | 19,309 | ||||||
|
Customer deposits
|
6,647 | 7,727 | ||||||
|
Regulatory liabilities
|
11,161 | 18,596 | ||||||
|
Fair value of derivative instruments
|
19,791 | 13,183 | ||||||
|
Accrued environmental remediation costs
|
6,652 | 2,233 | ||||||
|
Deferred revenues
|
4,801 | 4,650 | ||||||
|
Accumulated deferred income tax
|
- | 9,634 | ||||||
|
Other
|
17,905 | 18,961 | ||||||
|
Total Current Liabilities
|
198,440 | 174,128 | ||||||
|
Deferred Credits and Other Liabilities
|
||||||||
|
Regulatory liabilities - OPEB
|
6,988 | 6,976 | ||||||
|
Regulatory liabilities - other
|
108,887 | 98,370 | ||||||
|
Operating reserves
|
3,383 | 3,187 | ||||||
|
Fair value of derivative instruments
|
- | 11,698 | ||||||
|
Accrued environmental remediation costs
|
11,036 | 4,312 | ||||||
|
Accrued OPEB costs
|
53,055 | 45,367 | ||||||
|
Accrued pension costs
|
121,911 | 102,555 | ||||||
|
Tax reserve
|
3,172 | 11,486 | ||||||
|
Other
|
18,802 | 16,967 | ||||||
|
Total Deferred Credits and Other Liabilities
|
327,234 | 300,918 | ||||||
|
Accumulated Deferred Income Tax
|
235,160 | 192,439 | ||||||
|
Commitments and Contingencies
|
||||||||
|
Total Capitalization and Liabilities
|
$ | 1,730,112 | $ | 1,729,275 | ||||
(In Thousands, except share amounts)
|
|
|
|
|
CH Energy Group Common Shareholders
|
|
|
|
|
|
|
||||||||||||||||||||
|
|
|
|
|
Common Stock
|
|
Treasury Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
Shares Issued
|
|
Amount
|
|
Shares Repurchased
|
|
Amount
|
|
Paid-In Capital
|
|
Capital Stock Expense
|
|
Retained Earnings
|
|
Accumulated Other Comprehensive Income / (Loss)
|
|
Non-controlling Interest
|
|
Total Equity
|
||||||||
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,454
|
|
|
|
|
|
(176)
|
|
|
44,278
|
|
|
|
Dividends declared on Preferred Stock of subsidiary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(970)
|
|
|
|
|
|
|
|
|
(970)
|
|
|
|
Capital Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
213
|
|
|
213
|
|
|
|
Capital Distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(100)
|
|
|
(100)
|
|
|
|
Change in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10)
|
|
|
|
|
|
(10)
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95
|
|
|
|
|
|
95
|
|
|
Reclassification adjustments for losses recognized in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44
|
|
|
|
|
|
44
|
|
|
Dividends declared on common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
|
||
|
Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39,474
|
|
|
|
|
|
(272)
|
|
|
39,202
|
|
|
|
Dividends declared on Preferred Stock of subsidiary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(970)
|
|
|
|
|
|
|
|
|
(970)
|
|
|
|
Capital Contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172
|
|
|
172
|
|
|
|
Purchase of equity units from non-controlling interest
|
|
|
|
|
|
|
|
|
|
|
|
|
(89)
|
|
|
|
|
|
|
|
|
|
|
|
(1,113)
|
|
|
(1,202)
|
|
|
|
Change in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
309
|
|
|
|
|
|
309
|
|
|
Reclassification adjustments for gains recognized in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(34)
|
|
|
|
|
|
(34)
|
|
|
Dividends declared on common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(34,161)
|
|
|
|
|
|
|
|
|
(34,161)
|
||
|
Treasury shares activity - net
|
|
|
|
|
|
|
(5,300)
|
|
|
(481)
|
|
|
82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(399)
|
||
|
Balance at December 31, 2010
|
|
16,862,087
|
|
$
|
1,686
|
|
(1,062,825)
|
|
$
|
(44,887)
|
|
$
|
350,360
|
|
$
|
(328)
|
|
$
|
230,342
|
|
$
|
459
|
|
$
|
172
|
|
$
|
537,804
|
||
|
Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,310
|
|
|
|
|
|
|
|
|
46,310
|
|
|
|
Dividends declared on Preferred Stock of subsidiary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(970)
|
|
|
|
|
|
|
|
|
(970)
|
|
|
|
Sale of majority owned subsidiary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(172)
|
|
|
(172)
|
|
|
|
Change in fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(105)
|
|
|
|
|
|
(105)
|
|
Dividends declared on common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33,291)
|
|
|
|
|
|
|
|
|
(33,291)
|
||
|
Treasury shares activity - net
|
|
|
|
|
|
|
(904,298)
|
|
|
(48,021)
|
|
|
693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(47,328)
|
||
|
Balance at December 31, 2011
|
|
16,862,087
|
|
$
|
1,686
|
|
(1,967,123)
|
|
$
|
(92,908)
|
|
$
|
351,053
|
|
$
|
(328)
|
|
$
|
242,391
|
|
$
|
354
|
|
$
|
-
|
|
$
|
502,248
|
||
(In Thousands)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Operating Revenues
|
|
|
|
|||||||||
|
Electric
|
$ | 538,548 | $ | 563,139 | $ | 536,170 | ||||||
|
Natural gas
|
161,974 | 156,795 | 174,137 | |||||||||
|
Total Operating Revenues
|
700,522 | 719,934 | 710,307 | |||||||||
|
|
||||||||||||
|
Operating Expenses
|
||||||||||||
|
Operation:
|
||||||||||||
|
Purchased electricity and fuel used in electric generation
|
206,160 | 246,116 | 261,003 | |||||||||
|
Purchased natural gas
|
76,778 | 75,189 | 107,221 | |||||||||
|
Other expenses of operation
|
238,557 | 224,955 | 194,383 | |||||||||
|
Depreciation and amortization
|
35,475 | 33,815 | 32,094 | |||||||||
|
Taxes, other than income tax
|
48,026 | 45,011 | 39,268 | |||||||||
|
Total Operating Expenses
|
604,996 | 625,086 | 633,969 | |||||||||
|
|
||||||||||||
|
Operating Income
|
95,526 | 94,848 | 76,338 | |||||||||
|
|
||||||||||||
|
Other Income and Deductions
|
||||||||||||
|
Interest on regulatory assets and other interest income
|
5,739 | 5,474 | 5,030 | |||||||||
|
Regulatory adjustments for interest costs
|
1,351 | (1,105 | ) | (1,366 | ) | |||||||
|
Other - net
|
(211 | ) | (1,087 | ) | (1,199 | ) | ||||||
|
Total Other Income
|
6,879 | 3,282 | 2,465 | |||||||||
|
|
||||||||||||
|
Interest Charges
|
||||||||||||
|
Interest on long-term debt
|
23,602 | 19,745 | 18,830 | |||||||||
|
Interest on regulatory liabilities and other interest
|
5,589 | 6,103 | 6,055 | |||||||||
|
Total Interest Charges
|
29,191 | 25,848 | 24,885 | |||||||||
|
|
||||||||||||
|
Income Before Income Taxes
|
73,214 | 72,282 | 53,918 | |||||||||
|
|
||||||||||||
|
Income Taxes
|
28,177 | 26,164 | 21,142 | |||||||||
|
|
||||||||||||
|
Net Income
|
45,037 | 46,118 | 32,776 | |||||||||
|
|
||||||||||||
|
Dividends Declared on Cumulative Preferred Stock
|
970 | 970 | 970 | |||||||||
|
|
||||||||||||
|
Income Available for Common Stock
|
$ | 44,067 | $ | 45,148 | $ | 31,806 | ||||||
(In Thousands)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Net Income
|
$ | 45,037 | $ | 46,118 | $ | 32,776 | ||||||
|
Other Comprehensive Income
|
- | - | - | |||||||||
|
Comprehensive Income
|
$ | 45,037 | $ | 46,118 | $ | 32,776 | ||||||
The Notes to Financial Statements are an integral part hereof.
(In Thousands)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Operating Activities:
|
|
|
|
|||||||||
|
Net income
|
$ | 45,037 | $ | 46,118 | $ | 32,776 | ||||||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||||||
|
Depreciation
|
33,671 | 32,200 | 30,949 | |||||||||
|
Amortization
|
1,804 | 1,615 | 1,145 | |||||||||
|
Deferred income taxes - net
|
27,318 | 34,119 | 20,010 | |||||||||
|
Bad debt expense
|
7,156 | 3,940 | 8,833 | |||||||||
|
Pension expense
|
26,516 | 29,345 | 20,282 | |||||||||
|
OPEB expense
|
6,801 | 6,940 | 8,346 | |||||||||
|
Regulatory liability - rate moderation
|
(8,750 | ) | (16,789 | ) | (9,915 | ) | ||||||
|
Revenue decoupling mechanism recorded
|
1,371 | (3,843 | ) | (5,789 | ) | |||||||
|
Regulatory asset amortization
|
4,571 | 4,497 | 4,541 | |||||||||
|
Regulatory asset energy efficiency incentives
|
(2,719 | ) | - | - | ||||||||
|
(Gain) Loss on sale of property and plant
|
(88 | ) | - | 25 | ||||||||
|
Changes in operating assets and liabilities - net:
|
||||||||||||
|
Accounts receivable, unbilled revenues and other receivables
|
3,271 | (9,052 | ) | 3,785 | ||||||||
|
Fuel, materials and supplies
|
(1,010 | ) | 1,278 | 9,810 | ||||||||
|
Special deposits and prepayments
|
(967 | ) | 1,211 | 364 | ||||||||
|
Income and other taxes
|
(69 | ) | 35,609 | (10,793 | ) | |||||||
|
Accounts payable
|
(13,193 | ) | 8,659 | (7,325 | ) | |||||||
|
Accrued interest
|
215 | 330 | (258 | ) | ||||||||
|
Customer advances
|
851 | (1,249 | ) | 5,428 | ||||||||
|
Pension plan contribution
|
(32,699 | ) | (64,805 | ) | (23,124 | ) | ||||||
|
OPEB contribution
|
(1,184 | ) | (4,800 | ) | (3,485 | ) | ||||||
|
Revenue decoupling mechanism collected
|
1,671 | 5,049 | 759 | |||||||||
|
Regulatory asset - storm deferral
|
(11,753 | ) | (19,667 | ) | - | |||||||
|
Regulatory asset - MGP site remediation
|
4,412 | (12,216 | ) | (2,278 | ) | |||||||
|
Regulatory asset - Temporary State Assessment
|
2,342 | 1,445 | (10,947 | ) | ||||||||
|
Deferred natural gas and electric costs
|
19,545 | (2,709 | ) | 14,321 | ||||||||
|
Other - net
|
9,762 | 21,886 | 20,051 | |||||||||
|
Net cash provided by operating activities
|
123,882 | 99,111 | 107,511 | |||||||||
|
|
||||||||||||
|
Investing Activities:
|
||||||||||||
|
Proceeds from sale of property and plant
|
207 | - | - | |||||||||
|
Additions to utility plant
|
(83,102 | ) | (72,375 | ) | (99,756 | ) | ||||||
|
Other - net
|
(4,990 | ) | (4,130 | ) | (7,489 | ) | ||||||
|
Net cash used in investing activities
|
(87,885 | ) | (76,505 | ) | (107,245 | ) | ||||||
|
|
||||||||||||
|
Financing Activities:
|
||||||||||||
|
Redemption of long-term debt
|
(33,400 | ) | (106,150 | ) | (20,000 | ) | ||||||
|
Proceeds from issuance of long-term debt
|
33,400 | 122,150 | 24,000 | |||||||||
|
Borrowings (repayments) of short-term debt - net
|
1,500 | - | (25,500 | ) | ||||||||
|
Additional paid-in capital
|
- | - | 25,000 | |||||||||
|
Dividends paid to parent - CH Energy Group
|
(43,000 | ) | (31,000 | ) | - | |||||||
|
Dividends paid on cumulative Preferred Stock
|
(970 | ) | (970 | ) | (970 | ) | ||||||
|
Other - net
|
(628 | ) | (1,798 | ) | (467 | ) | ||||||
|
Net cash (used in) provided by financing activities
|
(43,098 | ) | (17,768 | ) | 2,063 | |||||||
|
|
||||||||||||
|
Net Change in Cash and Cash Equivalents
|
(7,101 | ) | 4,838 | 2,329 | ||||||||
|
Cash and Cash Equivalents - Beginning of Period
|
9,622 | 4,784 | 2,455 | |||||||||
|
Cash and Cash Equivalents - End of Period
|
$ | 2,521 | $ | 9,622 | $ | 4,784 | ||||||
|
|
||||||||||||
|
Supplemental Disclosure of Cash Flow Information:
|
||||||||||||
|
Interest paid
|
$ | 23,745 | $ | 20,002 | $ | 19,672 | ||||||
|
Federal and state income taxes paid
|
$ | - | $ | - | $ | 12,078 | ||||||
|
Additions to plant included in liabilities
|
$ | 6,172 | $ | 4,125 | $ | 1,619 | ||||||
|
Regulatory asset - storm deferral costs in liabilities
|
$ | 3,525 | $ | - | $ | - | ||||||
(In Thousands)
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
ASSETS
|
|
|
||||||
|
Utility Plant
|
|
|
||||||
|
Electric
|
$ | 1,008,394 | $ | 963,261 | ||||
|
Natural gas
|
305,664 | 292,358 | ||||||
|
Common
|
147,286 | 142,255 | ||||||
|
Gross Utility Plant
|
1,461,344 | 1,397,874 | ||||||
|
|
||||||||
|
Less: Accumulated depreciation
|
388,784 | 395,776 | ||||||
|
Net
|
1,072,560 | 1,002,098 | ||||||
|
|
||||||||
|
Construction work in progress
|
58,847 | 52,607 | ||||||
|
Net Utility Plant
|
1,131,407 | 1,054,705 | ||||||
|
|
||||||||
|
Non-Utility Property and Plant
|
524 | 681 | ||||||
|
Less: Accumulated depreciation
|
- | 35 | ||||||
|
Net Non-Utility Property and Plant
|
524 | 646 | ||||||
|
|
||||||||
|
Current Assets
|
||||||||
|
Cash and cash equivalents
|
2,521 | 9,622 | ||||||
|
Accounts receivable from customers - net of allowance for doubtful accounts of $5.2 million and $5.3 million, respectively
|
61,610 | 67,185 | ||||||
|
Accrued unbilled utility revenues
|
15,299 | 16,233 | ||||||
|
Other receivables
|
5,301 | 10,328 | ||||||
|
Fuel, materials and supplies - at average cost
|
21,037 | 20,027 | ||||||
|
Regulatory assets
|
49,526 | 89,905 | ||||||
|
Fair value of derivative instruments
|
320 | 34 | ||||||
|
Special deposits and prepayments
|
18,258 | 17,184 | ||||||
|
Total Current Assets
|
173,872 | 230,518 | ||||||
|
|
||||||||
|
Deferred Charges and Other Assets
|
||||||||
|
Regulatory assets - pension plan
|
159,020 | 142,647 | ||||||
|
Regulatory assets - other
|
114,980 | 90,264 | ||||||
|
Fair value of derivative instruments
|
931 | - | ||||||
|
Unamortized debt expense
|
4,535 | 4,774 | ||||||
|
Other investments
|
14,047 | 12,511 | ||||||
|
Other
|
3,065 | 3,009 | ||||||
|
Total Deferred Charges and Other Assets
|
296,578 | 253,205 | ||||||
|
|
||||||||
|
Total Assets
|
$ | 1,602,381 | $ | 1,539,074 | ||||
CENTRAL HUDSON BALANCE SHEET (CONT'D)
(In Thousands)
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
CAPITALIZATION AND LIABILITIES
|
|
|
||||||
|
Capitalization
|
|
|
||||||
|
Common Stock (30,000,000 shares authorized: $5 par value; 16,862,087 shares issued and outstanding)
|
$ | 84,311 | $ | 84,311 | ||||
|
Paid-in capital
|
199,980 | 199,980 | ||||||
|
Retained earnings
|
165,965 | 164,898 | ||||||
|
Capital stock expense
|
(4,961 | ) | (4,961 | ) | ||||
|
Total Equity
|
445,295 | 444,228 | ||||||
|
|
||||||||
|
Cumulative Preferred Stock not subject to mandatory redemption
|
21,027 | 21,027 | ||||||
|
|
||||||||
|
Long-term debt
|
417,950 | 453,900 | ||||||
|
Total Capitalization
|
884,272 | 919,155 | ||||||
|
|
||||||||
|
Current Liabilities
|
||||||||
|
Current maturities of long-term debt
|
36,000 | - | ||||||
|
Notes payable
|
1,500 | - | ||||||
|
Accounts payable
|
35,731 | 43,452 | ||||||
|
Accrued interest
|
6,183 | 5,967 | ||||||
|
Dividends payable - Preferred Stock
|
242 | 242 | ||||||
|
Accrued vacation and payroll
|
5,556 | 5,484 | ||||||
|
Customer advances
|
14,604 | 13,753 | ||||||
|
Customer deposits
|
6,582 | 7,654 | ||||||
|
Regulatory liabilities
|
11,161 | 18,596 | ||||||
|
Fair value of derivative instruments
|
19,791 | 13,183 | ||||||
|
Accrued environmental remediation costs
|
6,117 | 1,396 | ||||||
|
Accrued income taxes
|
1,274 | 113 | ||||||
|
Accumulated deferred income tax
|
156 | 13,021 | ||||||
|
Other
|
14,855 | 13,275 | ||||||
|
Total Current Liabilities
|
159,752 | 136,136 | ||||||
|
|
||||||||
|
Deferred Credits and Other Liabilities
|
||||||||
|
Regulatory liabilities - OPEB
|
6,988 | 6,976 | ||||||
|
Regulatory liabilities - other
|
108,887 | 98,370 | ||||||
|
Operating reserves
|
2,120 | 2,068 | ||||||
|
Fair value of derivative instruments
|
- | 11,698 | ||||||
|
Accrued environmental remediation costs
|
9,726 | 1,849 | ||||||
|
Accrued OPEB costs
|
53,055 | 45,367 | ||||||
|
Accrued pension costs
|
121,911 | 102,555 | ||||||
|
Tax reserve
|
3,172 | 11,486 | ||||||
|
Other
|
17,955 | 16,109 | ||||||
|
Total Deferred Credits and Other Liabilities
|
323,814 | 296,478 | ||||||
|
|
||||||||
|
Accumulated Deferred Income Tax
|
234,543 | 187,305 | ||||||
|
|
||||||||
|
Commitments and Contingencies
|
||||||||
|
|
||||||||
|
Total Capitalization and Liabilities
|
$ | 1,602,381 | $ | 1,539,074 | ||||
(In Thousands, except share amounts)
|
|
|
|
|
Central Hudson Common Shareholders
|
|
|
|
||||||||||||||||||||
|
|
|
|
|
Common Stock
|
|
Treasury Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
|
|
|
|
|
Shares Issued
|
|
Amount
|
|
Shares Repurchased
|
|
Amount
|
|
Paid-In Capital
|
|
Capital Stock Expense
|
|
Retained Earnings
|
|
Accumulated Other Comprehensive Income / (Loss)
|
|
Total Equity
|
|||||||
|
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
|
||
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46,118
|
|
|
|
|
|
46,118
|
||
|
Dividends declared
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
On cumulative Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(970)
|
|
|
|
|
|
(970)
|
|
|
|
On Common Stock to parent - CH Energy Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31,000)
|
|
|
|
|
|
(31,000)
|
|
|
Additional Paid-in Capital
|
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
-
|
||
|
Balance at December 31, 2010
|
|
16,862,087
|
|
$
|
84,311
|
|
-
|
|
$
|
-
|
|
$
|
199,980
|
|
$
|
(4,961)
|
|
$
|
164,898
|
|
$
|
-
|
|
$
|
444,228
|
||
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,037
|
|
|
|
|
|
45,037
|
||
|
Dividends declared
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
|
On cumulative Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(970)
|
|
|
|
|
|
(970)
|
|
|
|
On Common Stock to parent - CH Energy Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(43,000)
|
|
|
|
|
|
(43,000)
|
|
|
Additional Paid-in Capital
|
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
-
|
||
|
Balance at December 31, 2011
|
|
16,862,087
|
|
$
|
84,311
|
|
-
|
|
$
|
-
|
|
$
|
199,980
|
|
$
|
(4,961)
|
|
$
|
165,965
|
|
$
|
-
|
|
$
|
445,295
|
||
NOTES TO FINANCIAL STATEMENTS
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. Griffith Energy Services, Inc. (“Griffith”) is CHEC’s wholly owned subsidiary. Their businesses are primarily comprised of a regulated electric utility, regulated natural gas utility and a fuel distribution business.
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 are consolidated in the Consolidated Financial Statements of CH Energy Group. Discontinued operations on CH Energy Group’s Consolidated Statements of Income include the operating results of CHEC’s subsidiaries which were sold in 2011, including Lyonsdale Biomass, LLC (“Lyonsdale”), Shirley Wind, LLC (“Shirley Wind”), CH-Auburn, LLC (“CH-Auburn”) and CH-Greentree, LLC (“CH-Greentree”). The non-controlling 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 for 2011 and 2010 prior to the sale of this subsidiary and Lyonsdale for 2010 prior to the purchase of the minority owner’s interest on October 1, 2010. Inter-company balances and transactions have been eliminated in consolidation. See Note 5 – “Acquisitions, Divestitures and Investments” for further information.
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. For additional information regarding regulatory accounting, see Note 2 – “Regulatory Matters.”
Reclassification
Certain amounts in the 2010 and 2009 Financial Statements have been reclassified to conform to the 2011 presentation. For more information regarding reclassification of discontinued operations, see Note 5 – “Acquisition, Divestitures and Investments.”
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. As with all estimates, actual results may differ from those estimated. Expense items most affected by the use of estimates are depreciation and amortization (including amortization of intangible assets), reserves for uncollectible accounts receivable, tax reserves, 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 decrease in the allowance for doubtful accounts reflects the impact of lower energy prices along with enhanced collection efforts.
|
|
·
|
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 2011, 2010 and 2009 include an estimate for unbilled revenues of $10.3 million, $10.1 million and $8.9 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, 2011, 2010 and 2009 was $5.0 million, $6.1 million and $5.2 million, respectively.
|
|
·
|
The tax reserve recorded by Central Hudson relates to a change in 2010 related to its tax return methodology for claiming deductions for incidental repair and maintenance expenditures on its utility assets. Although the Company believes that its methodology for claiming the deduction is consistent with the Internal Revenue Code and case law, it is unclear whether the Internal Revenue Service will accept the entirety of the deduction claimed. Accordingly, Central Hudson recorded a reserve based upon the expected outcome on audit. See Note 4 – “Income Tax” for further discussion of the tax reserve established.
|
|
·
|
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. For more information of the significant assumptions and estimates, see Note 10 – “Post-Employment Benefits.”
|
|
·
|
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 these services.
Beginning 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, 2011, and 2010, the portion of estimated electric unbilled revenues that is unrecognized in accordance with current regulatory agreements were $11.8 million and $12.1 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, 2011 and 2010 were $4.8 million and $4.7 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
|
The following is a summary of CH Energy Group’s and Central Hudson’s inventories (In Thousands):
CH Energy Group
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Natural gas
|
$ | 11,711 | $ | 10,803 | ||||
|
Petroleum products and propane
|
3,422 | 3,831 | ||||||
|
Fuel used in electric generation
|
285 | 820 | ||||||
|
Materials and supplies
|
9,696 | 9,993 | ||||||
|
Total
|
$ | 25,114 | $ | 25,447 | ||||
Central Hudson
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Natural gas
|
$ | 11,711 | $ | 10,803 | ||||
|
Petroleum products and propane
|
494 | 519 | ||||||
|
Fuel used in electric generation
|
285 | 271 | ||||||
|
Materials and supplies
|
8,547 | 8,434 | ||||||
|
Total
|
$ | 21,037 | $ | 20,027 | ||||
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
|
2011
|
2010
|
|||||||||
|
Electric
|
|
|
|
|||||||||
|
Production
|
25-75 | $ | 37,826 | $ | 34,222 | |||||||
|
Transmission
|
28-70 | 228,319 | 220,051 | |||||||||
|
Distribution
|
7-80 | 741,068 | 707,981 | |||||||||
|
Other
|
37 | 1,181 | 1,007 | |||||||||
|
Total
|
$ | 1,008,394 | $ | 963,261 | ||||||||
|
|
||||||||||||
|
Natural Gas
|
||||||||||||
|
Production
|
25-60 | $ | 5,695 | $ | 5,677 | |||||||
|
Transmission
|
18-70 | 46,828 | 45,992 | |||||||||
|
Distribution
|
25-70 | 252,699 | 240,247 | |||||||||
|
Other
|
N/A | 442 | 442 | |||||||||
|
Total
|
$ | 305,664 | $ | 292,358 | ||||||||
|
|
||||||||||||
|
Common
|
||||||||||||
|
Land and Structures
|
50 | $ | 58,403 | $ | 56,324 | |||||||
|
Office and Other Equipment, Radios and Tools
|
8-35 | 34,589 | 37,658 | |||||||||
|
Transportation Equipment
|
10-12 | 43,690 | 39,904 | |||||||||
|
Other
|
5 | 10,604 | 8,369 | |||||||||
|
Total
|
$ | 147,286 | $ | 142,255 | ||||||||
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 6.75% in 2011, 3.00% in 2010, and 1.00% in 2009. The amounts recorded for borrowed funds for the years 2011, 2010 and 2009 are $0.3 million, $0.2 million and $0.2 million, respectively. In 2011 and 2010, $0.6 million and $0.3 million were recorded for the equity component of AFUDC. There were no equity components of AFUDC in 2009.
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 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, 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, Central Hudson continues to accrue for the future cost of removal for its rate-regulated natural gas and electric utility assets. Central Hudson has classified $52.6 million and $46.9 million of net cost of removal as a regulatory liability as of December 31, 2011 and 2010, 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 2.74% in both 2011 and 2010, and 2.75% in 2009 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 26.7% in 2011, 28.5% in 2010, and 28.4% in 2009.
For financial statement purposes, depreciation provisions at Griffith 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 maintenances 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.
See Note 6 – “Goodwill and Other Intangible Assets” for further discussion of amortization of intangibles (other than goodwill).
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 $2.1 million in 2011, $3.1 million in 2010 and $3.9 million in 2009. 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. The decrease in total R&D expenditures in 2011 as compared to the prior two periods is a result of a PSC Order to cease the collection from customers and payment to NYSERDA of certain energy efficiency research funds in the current year. There is no impact on earnings related to this change and the collections and payments have resumed in 2012. R&D expenditures are provided for in Central Hudson’s rates charged to customers for electric and natural gas delivery service, with any differences between R&D expense and the rate allowances 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, resulting in deferred income taxes 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, Shirley Delaware 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,
|
|||||||||||||||||||||||
|
|
|
2011
|
|
2010
|
|
2009
|
|||||||||||||||||||
|
|
|
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
|
|
|
|
$
|
42,215
|
|
|
|
|
|
|
$
|
39,632
|
|
|
|
|
|
|
$
|
32,803
|
|
|
|
|
|
Earnings attributable to Common Stock - discontinued operations
|
|
|
|
$
|
3,125
|
|
|
|
|
|
|
$
|
(1,128)
|
|
|
|
|
|
|
$
|
10,681
|
|
|
|
|
|
Average number of common shares outstanding - basic
|
|
15,278
|
|
|
|
|
|
|
|
15,785
|
|
|
|
|
|
|
|
15,775
|
|
|
|
|
|
|
|
| Earnings per share - basic - continuing operations | $ | 2.77 | $ | 2.51 | $ | 2.08 | |||||||||||||||||||
|
Earnings per share - basic - discontinued operations
|
|
|
|
|
|
$
|
0.20
|
|
|
|
|
|
|
$
|
(0.07)
|
|
|
|
|
|
|
$
|
0.68
|
||
|
Average dilutive effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options(1) (2)
|
|
1
|
|
$
|
15
|
|
$
|
-
|
|
-
|
|
$
|
-
|
|
$
|
-
|
|
-
|
|
$
|
1
|
|
$
|
-
|
|
|
Performance shares(2)
|
|
164
|
|
$
|
-
|
|
$
|
0.03
|
|
119
|
|
$
|
-
|
|
$
|
0.02
|
|
65
|
|
$
|
-
|
|
$
|
0.01
|
|
|
Restricted shares(2)
|
|
38
|
|
$
|
-
|
|
$
|
0.01
|
|
48
|
|
$
|
-
|
|
$
|
0.01
|
|
41
|
|
$
|
-
|
|
$
|
0.01
|
|
Average number of common shares outstanding - diluted
|
|
15,481
|
|
$
|
45,355
|
|
$
|
2.93
|
|
15,952
|
|
$
|
38,504
|
|
$
|
2.41
|
|
15,881
|
|
$
|
43,485
|
|
$
|
2.74
|
|
|
(1)
|
For 2010 and 2009, 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 that applicable year. The number of Common Stock shares represented by the options excluded from the above calculation were 16,620 shares for 2010 and 17,420 shares for 2009. There were no shares excluded for 2011.
|
|
(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 on October 1, 2009, 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 $1.8 million in 2011, $2.1 million in 2010, and $3.3 million in 2009.
American Recovery and Reinvestment Act of 2009
Central Hudson, Shirley Wind and CH-Auburn have received grant money under the American Recovery and Reinvestment Act of 2009 and account for these grants as a reduction to the related assets or property. The amount of grant money received by Central Hudson was not material. For further details on grant money received by Shirley Wind and CH-Auburn, see Note 5 – “Acquisitions, Divestitures and Investments.”
Parental Guarantees
CH Energy Group and CHEC have issued guarantees to counterparties to assure the payment, when due, of certain obligations incurred by CH Energy Group subsidiaries, in physical and financial transactions.
(In Thousands)
|
|
December 31, 2011
|
|||||||
|
Transaction Description
|
Maximum Potential
Payments
|
Outstanding
Liabilities(1)
|
||||||
|
Heating oil, propane, other petroleum products, weather and commodity hedges
|
$ | 28,550 | $ | 6,770 | ||||
|
(1)
|
Balance included in CH Energy Group's Consolidated Balance Sheet
|
Management is not aware of any existing condition that would require payment under the guarantees.
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 both December 31, 2011 and 2010 was $0.1 million. CH Energy Group’s liability 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.
Common Stock Dividends
On December 15, 2011, the Board of Directors of CH Energy Group declared a quarterly dividend of 55.5 cents per share payable February 1, 2012, to shareholders of record as of January 10, 2012. On September 23, 2011, the Board of Directors of CH Energy Group increased the quarterly dividend to 55.5 cents per share, an increase from the 54 cents per share declared to shareholders each quarter since 1998.
CH Energy Group’s ability to pay dividends is 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, Central Hudson was restricted to a maximum payment of $44.6 million in dividends to CH Energy Group for the year ended December 31, 2011. 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 any of CH Energy Group’s or Central Hudson’s affiliates. Further restrictions are imposed for any downgrades below this level. As of December 31, 2011, Central Hudson had declared and paid dividends of $43.0 million to parent CH Energy Group in 2011, of which $10.0 million was paid during the three months ended December 31, 2011. CH Energy Group’s other subsidiaries do not have express restrictions on their ability to pay dividends.
Effective June 30, 1998 (and amended March 7, 2000), the PSC approved a settlement agreement (the “Settlement Agreement”) between Central Hudson, PSC staff and certain other parties.
The Settlement Agreement included the following major provisions which survived 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
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,
|
|||||||
|
|
2011
|
|
2010
|
|||||
|
Regulatory Assets (Debits):
|
|
|
|
|
|
|
||
|
Current:
|
|
|
|
|
|
|
||
|
Deferred purchased electric and natural gas costs (Note 1)
|
|
$
|
10,775
|
|
$
|
30,320
|
||
|
Deferred unrealized losses on derivatives (Note 14)
|
|
|
19,791
|
|
|
13,149
|
||
|
PSC General and Temporary State Assessment and carrying charges
|
|
|
8,123
|
|
|
9,891
|
||
|
RDM and carrying charges (Note 1)
|
|
|
791
|
|
|
3,966
|
||
|
Residual natural gas deferred balances
|
|
|
4,554
|
|
|
4,554
|
||
|
Deferred debt expense on re-acquired debt
|
|
|
625
|
|
|
624
|
||
|
Deferred and accrued costs - MGP site remediation and carrying charges (Note 12)
|
|
|
4,577
|
|
|
4,488
|
||
|
Deferred storm costs and carrying charges
|
|
|
-
|
(1)
|
|
|
19,985
|
|
|
Uncollectible deferral and carrying charges
|
|
|
-
|
(1)
|
|
|
2,638
|
|
|
Other
|
|
|
290
|
|
|
290
|
||
|
|
|
49,526
|
|
|
89,905
|
|||
|
Long-term:
|
|
|
|
|
|
|
||
|
Deferred pension costs (Note 10)
|
|
|
159,020
|
|
|
142,647
|
||
|
Deferred unrealized losses on derivatives (Note 14)
|
|
|
-
|
|
|
11,698
|
||
|
Carrying charges - pension reserve
|
|
|
4,986
|
|
|
1,144
|
||
|
Deferred and accrued costs - MGP site remediation and carrying charges (Note 12)
|
|
|
14,260
|
|
|
5,876
|
||
|
Deferred debt expense on re-acquired debt
|
|
|
5,332
|
|
|
5,460
|
||
|
Deferred Medicare Subsidy taxes
|
|
|
7,307
|
|
|
6,740
|
||
|
Residual natural gas deferred balances and carrying charges
|
|
|
9,829
|
|
|
14,121
|
||
|
Income taxes recoverable through future rates
|
|
|
42,997
|
|
|
35,903
|
||
|
Energy efficiency incentives
|
|
|
2,719
|
|
|
-
|
||
|
Deferred storm costs and carrying charges
|
|
|
15,416
|
|
|
-
|
||
|
Other
|
|
|
12,134
|
|
|
9,322
|
||
|
|
|
274,000
|
|
|
232,911
|
|||
|
Total Regulatory Assets
|
|
$
|
323,526
|
|
$
|
322,816
|
||
|
|
|
|
|
|
|
|||
|
Regulatory Liabilities (Credits):
|
|
|
|
|
|
|
||
|
Current:
|
|
|
|
|
|
|
||
|
Excess electric depreciation reserve
|
|
$
|
1,107
|
|
$
|
7,366
|
||
|
Income taxes refundable through future rates
|
|
|
5,062
|
|
|
5,128
|
||
|
Deferred unbilled gas revenues
|
|
|
4,992
|
|
|
6,102
|
||
|
|
|
11,161
|
|
|
18,596
|
|||
|
Long-term:
|
|
|
|
|
|
|
||
|
Customer benefit fund
|
|
|
2,623
|
|
|
3,468
|
||
|
Deferred cost of removal (Note 1)
|
|
|
52,565
|
|
|
46,938
|
||
|
Rate Base Impact of Tax Repair Project and carrying charges
|
|
|
9,413
|
(1)
|
|
|
-
|
|
|
Excess electric depreciation reserve and carrying charges
|
|
|
2,678
|
|
|
4,889
|
||
|
Deferred unrealized losses on derivatives (Note 14)
|
|
|
931
|
|
|
-
|
||
|
Income taxes refundable through future rates
|
|
|
29,648
|
|
|
32,397
|
||
|
Deferred OPEB costs
|
|
|
6,988
|
|
|
6,976
|
||
|
Carrying charges - OPEB reserve
|
|
|
5,405
|
|
|
1,599
|
||
|
Other
|
|
|
5,624
|
|
|
9,079
|
||
|
|
|
115,875
|
|
|
105,346
|
|||
|
Total Regulatory Liabilities
|
|
$
|
127,036
|
|
$
|
123,942
|
||
|
|
|
|
|
|
|
|||
|
Net Regulatory Assets
|
|
$
|
196,490
|
|
$
|
198,874
|
||
|
(1)
|
Central Hudson offset deferred storm costs and incremental bad debt expense and associated carrying charges, in accordance with the PSC prescribed Order issued on April 14, 2011. Additionally, a regulatory liability was established for the future benefit of the customers based on the remaining balance of tax refund after these offsets. See Other Regulatory Matters and PSC Proceedings for further discussion.
|
The significant regulatory assets and liabilities include:
PSC General and Temporary State Assessment: In April 2009, the PSC issued an order instituting a new Temporary State Assessment to be collected through utility bills as mandated by NYS. Central Hudson is required to make bi-annual payments of this assessment, in conjunction with its payments of the PSC, General Assessment, and collect the amount from customers in subsequent months. Deferral accounting for both these assessments was authorized in this order.
Residual Natural Gas Deferred Balances: As a result of the 2006, 2009 and 2010 Rate Orders, certain gas regulatory assets and liabilities were identified for offset and reduced by a depreciation reserve adjustment, resulting in an increase to the net regulatory asset. The remaining balance is being amortized over a four-year period which began July 1, 2010.
Deferred Debt Expense on Reacquired Debt: When long-term debt is reacquired or redeemed, regulatory accounting permits deferral of related unamortized debt expense and reacquisition costs. These costs are being amortized over the remaining life of the original life of the issue retired. The amortization of debt costs for reacquired or redeemed debt is incorporated in the revenue requirement for delivery rates as authorized by the PSC.
Storm Costs: Central Hudson is authorized to request and the PSC has historically approved deferral accounting for incremental storm restoration costs which meet the following criteria: (1) the expense must be incremental to the amount provided in rates, (2) the incremental costs must be material and extraordinary in nature, and (3) the company’s earnings cannot be in excess of the authorized regulatory rate of return. The balance shown for storm costs as of December 31, 2010 relates to a significant snow storm event in late February 2010. The balance shown for storm costs as of December 31, 2011 relates to the impacts of Tropical Storm Irene as well as a significant snow storm event in late October 2011. These amounts are based on estimates and assumptions related to storm expense and results of operations for the calendar year. The actual amounts may differ from these estimates resulting in changes in the amount of costs deferred. Management believes the costs deferred as of December 31, 2011 are probable of future recovery. See Other Regulatory Matters and PSC Proceedings for further details on these storm events.
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.”
Deferred Medicare Subsidy Taxes: The Patient Protection and Affordable Care Act signed into law on March 23, 2010, contains a provision which changes the tax treatment related to the Retiree Drug Subsidy benefit under the Medicare Prescription Drug, Improvement and Modernization Act (under Medicare Part D). This change reduces the employer's deduction for the costs of health care for retirees by the amount of Retiree Drug Subsidy payments received. As a result, the deductible temporary difference and any related deferred tax asset associated with the benefit plan were reduced. Under the PSC policy regarding Medicare Act Effects, cost savings and income tax effects related to the Medicare Prescription Drug, Improvement and Modernization Act are deferred for future recovery from or refund to customers.
Income Taxes Recoverable: Regulatory asset balance established to offset deferred tax liabilities because it is probable that they will be recoverable from customers.
Energy Efficiency Incentives: During 2009 and 2010, Central Hudson received approval through the Energy Efficiency Portfolio Standard (“EEPS”) proceedings to implement various programs to electric and natural gas residential and commercial customers. In December 2010, the PSC issued an order combining energy savings targets to create a single 2008-2011 target and continuing the system of utility shareholder financial incentives established in the EEPS proceeding. As of December 31, 2011, Central Hudson achieved enough projected savings through committed contracts with residential and commercial customers to earn $2.7 million in incentives under the 2008-2011 defined targets.
Excess Electric Depreciation Reserve (“EDR”): Under the 2009 Rate Order, this balance was to be used for authorized rate moderation which totaled $25.5 million from July 1, 2009 through June 30, 2010. Under the terms of the 2010 Rate Order, $6.8 million was used for authorized rate moderation from July 1, 2010 through December 31, 2010 and an additional $8.8 million was authorized from January 1, 2011 through December 31, 2011. The current portion of the EDR as of December 31, 2011 represents the amount estimated to be used for rate moderation in the next twelve months related to the Electric Bill Credit and Incremental Finance Charges.
Income Taxes Refundable: Regulatory liability balances established to offset deferred tax assets because it is probable that the related balances will be refundable to customers.
Customer Benefit Fund: The 2010 Order prescribes the use of the residual balance to fund economic development.
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.”
In terms of the expected timing for recovery, regulatory asset balances at December 31, 2011, reflect the following (In Thousands):
|
Balances with offsetting accrued liability balances recoverable when future costs are actually incurred:
|
|
|||
|
Deferred pension related to underfunded status
|
$ | 152,831 | ||
|
Income taxes recoverable through future rates
|
42,997 | |||
|
Deferred unrealized losses on derivatives
|
19,791 | |||
|
Deferred costs - MGP sites
|
15,843 | |||
|
Deferred Medicare Subsidy taxes
|
7,308 | |||
|
Other
|
4,763 | |||
| 243,533 | ||||
|
Balances earning a return via inclusion in rates and/or the application of carrying charges:
|
||||
|
Residual natural gas deferred balances
|
9,191 | |||
|
Deferred pension costs undercollected(1)
|
6,189 | |||
|
PSC General and Temporary State Assessment
|
7,102 | |||
|
Deferred Storm Costs
|
15,272 | |||
|
Accrued costs - MGP sites
|
2,497 | |||
|
Deferred debt expense on re-acquired debt
|
5,957 | |||
|
Other(1)
|
7,031 | |||
| 53,239 | ||||
|
Subject to current recovery:
|
||||
|
Deferred purchased electric and natural gas costs
|
10,774 | |||
|
Residual natural gas deferred balances
|
4,554 | |||
|
RDM
|
782 | |||
|
Other
|
422 | |||
| 16,532 | ||||
|
Other:
|
||||
|
Energy Efficiency Incentives(1)
|
2,719 | |||
| 2,719 | ||||
|
Accumulated carrying charges:(1)
|
||||
|
Pension reserve
|
4,986 | |||
|
Other
|
2,517 | |||
| 7,503 | ||||
|
Total Regulatory Assets
|
$ | 323,526 | ||
2006, 2009 and 2010 Rate Orders
The Company’s 2006, 2009 and 2010 Rate Orders all provide for deferral accounting for full recovery of purchased electricity and natural gas, pensions, OPEBs, MGP site remediation, asbestos litigation and variable rate debt. Additionally, they include penalty-only performance mechanisms for customer service quality, electric reliability and natural gas safety.
Other significant components of the 2006, 2009 and 2010 Rate Orders include:
|
Description
|
2006 Rate Order
|
2009 Rate Order
|
2010 Rate Order
|
|||
|
Electric delivery revenue increases
|
$17.9 million 7/1/06
$17.9 million 7/1/07
$17.9 million 7/1/08
|
$39.6 million(1) 7/1/09
|
$11.8 million(2) 7/1/10
$9.3 million(2) 7/1/11
$9.1 million 7/1/12
|
|||
|
Natural gas delivery revenue increases
|
$8 million 7/1/06
$6.1 million 7/1/07
$0.0 million 7/1/08
|
$13.8 million 7/1/09
|
$5.7 million 7/1/10
$2.4 million 7/1/11
$1.6 million 7/1/12
|
|||
|
ROE
|
9.6%
|
10.0%
|
10.0%
|
|||
|
Earnings sharing
|
Yes(3)
|
No
|
Yes(4)
|
|||
|
Capital structure – common equity
|
45%
|
47%
|
48%
|
|||
|
Targets with true-up provisions - % of revenue requirement to defer for shortfalls
|
||||||
|
Capital Expenditures
|
150%
|
Not applicable
|
Not applicable
|
|||
|
Net plant balances
|
Not applicable
|
100%
|
100%
|
|||
|
Transmission and distribution ROW maintenance
|
100%
|
No
|
100%
|
|||
|
RDMs – electric and natural gas(5)
|
No
|
Yes
|
Yes
|
|||
|
New deferral accounting for full recovery
|
||||||
|
Fixed debt costs
|
No
|
Yes
|
Yes(6)
|
|||
|
Transmission sag mitigation
|
Not applicable
|
Yes
|
Yes
|
|||
|
New York State Temporary Assessment
|
Not applicable
|
Yes
|
Yes
|
|||
|
Material regulatory actions(7)(8)
|
Yes(7)
|
Not applicable
|
Yes(8)
|
|||
|
Property taxes – Deferral for 90% of excess/deficiency relative to revenue requirement
|
Yes
|
No
|
Yes(9)
|
|
(1)
|
Moderated by $20 million bill credit.
|
|
(2)
|
Moderated by $12 million and $4 million bill credits, respectively.
|
|
(3)
|
ROE > 10.6%, 50% to customers, > 11.6%, 65% to customers, > 14.0%, 100% to customers.
|
|
(4)
|
ROE > 10.5%, 50% to customers, > 11.0%, 80% to customers, > 11.5%, 90% to customers.
|
|
(5)
|
Electric is based on revenue dollars; gas is based on usage per customer.
|
|
(6)
|
Deferral authorization in RY2 and RY3 only.
|
|
(7)
|
Changes in federal or state regulations that have an impact of more than 1% of electric or gas net income.
|
|
(8)
|
Legislative, governmental or regulatory actions with individual impacts greater than or equal to 2% of net income of the applicable department.
|
|
(9)
|
The Company’s pre-tax gain or loss limited to $0.7 million per rate year.
|
Other Regulatory Matters and PSC Proceedings
On April 14, 2011, the Commission issued an Order authorizing deferral of $18.8 million of the incremental electric storm restoration expense related to the significant storm event in February 2010 and the $2.6 million of incremental bad debt expense and denying deferral of the Company’s $2.5 million of incremental electric and gas property tax expense. The PSC also approved the ratemaking treatment to offset these deferrals with tax refunds as proposed by the Company in its petition filed on September 23, 2010. The offsets have been recorded as of March 31, 2011. The remaining balance of the tax refund not subject to offset has been established as a regulatory liability subject to carrying charges for the benefit of customers totaling $9.0 million. On May 13, 2011, Central Hudson filed a Petition for Clarification and Rehearing on the PSC’s April 14, 2011 Order. The petition seeks clarification concerning recovery of the costs to achieve and rehearing for reconsideration and recovery of certain costs denied by the Commission, totaling $0.8 million, for deferral accounting treatment proposed by the Company in its September 23, 2010 petition filing related to the incremental electric storm restoration expense for the February 2010 Twin Peaks storm. On November 22, 2011, the PSC issued an order modifying the April 14, 2011 Order to correct for a miscalculation error in the PSC’s analysis and increase authorized deferred incremental storm restoration costs by $0.3 million and to clarify that the Company is allowed to net the external costs to achieve against the federal income tax benefits.
In late August 2011, Central Hudson’s service territory was affected by Tropical Storm Irene, disrupting service to approximately 180,000 customers. On November 28, 2011, Central Hudson filed a petition with the PSC seeking approval of deferred incremental electric restoration costs for future recovery with carrying charges. Central Hudson will finalize its measure of materiality and utility earnings based upon the calendar year ending December 31, 2011 results. Based on current estimates and assumptions, Management believes these incremental costs deferred meet the PSC’s criteria for deferral accounting and therefore are probable of future recovery.
Central Hudson also incurred incremental costs associated with gas emergencies as a result of the impacts of Tropical Storm Irene; however these costs have not been deferred as of December 31, 2011. As of December 31, 2011, approximately $0.8 million has been incurred related to these gas emergencies and additional costs are expected as a result of on-going repairs to damaged infrastructure.
On October 29, 2011, Central Hudson experienced an unusual winter storm with snow accumulations of up to 20 inches in the service territory, resulting in electric service outages to over 150,000 customers. The Company has deferred $4.1 million of estimated recoverable incremental storm restoration costs as of December 31, 2011 related to this snow event and anticipates filing a petition seeking authority to defer for future recovery all incremental storm restoration costs of approximately $8 million, subject to the criteria the PSC has established for consideration and approval of deferral authorization requests. Based on current estimates and assumptions, Management believes the $4.1 million of incremental costs that have been deferred meet the accounting standard of being probable of future recovery.
Other Regulatory Matters
Non-Utility Land Sales - Central Hudson
Central Hudson had two property sales of non-utility real property resulting in $0.1 million in excess of book value and transaction costs during the year-ended December 31, 2011. Central Hudson did not sell any parcels of non-utility property during 2010 or 2009. This excess is recorded as a reduction to Other Expenses of Operation on the Consolidated Statement of Income.
Newly adopted and soon to be adopted accounting guidance is summarized below, including explanations for any new guidance issued in 2011 (except that which is not currently applicable) which is expected to have a material impact on CH Energy Group and its subsidiaries.
|
Impact
|
|
Category
|
|
Accounting
Reference
|
|
Title
|
|
Issued Date
|
|
Effective Date
|
|
1
|
|
Fair Value Measurements and Disclosures (Topic 820)
|
|
ASU No. 2010-06
|
|
Improving Disclosures About Fair Value Measurements
|
|
Jan-10
|
|
Jan-11
|
|
1
|
|
Intangibles - Goodwill and Other (Topic 365)
|
|
ASU No. 2010-28
|
|
Intangibles - Goodwill and Other: When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Value
|
|
Dec-10
|
|
Jan-11
|
|
1
|
|
Business Combinations (Topic 805)
|
|
ASU No. 2010-29
|
|
Disclosure of Supplementary Pro Forma Information for Business Combinations
|
|
Dec-10
|
|
Jan-11
|
|
1
|
|
Comprehensive Income (Topic 220)
|
|
ASU No. 2011-12
|
|
Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income
|
|
Dec-11
|
|
Jan-12
|
|
2
|
|
Fair Value Measurements (Topic 820)
|
|
ASU No. 2011-04
|
|
Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in US GAAP and IFRS
|
|
May-11
|
|
Jan-12
|
|
2
|
|
Comprehensive Income (Topic 220)
|
|
ASU No. 2011-05
|
|
Presentation of Comprehensive Income
|
|
Jun-11
|
|
Jan-12
|
|
2
|
|
Balance Sheet (Topic 210)
|
|
ASU No. 2011-11
|
|
Disclosures about Offsetting Assets and Liabilities
|
|
Dec-11
|
|
Dec-12
|
|
3
|
|
Intangibles - Goodwill and Other (Topic 350)
|
|
ASU No. 2011-08
|
|
Testing Goodwill for Impairment
|
|
Sep-11
|
|
Jan-12
|
|
Impact Key:
|
|
|
|
|
|
|
|
|
|
|
(1)
|
No current impact on the financial condition, results of operations and cash flows of CH Energy Group and its subsidiaries when adopted on the effective date noted.
|
||||||||
|
(2)
|
No anticipated impact on the financial condition, results of operations and cash flows of CH Energy Group and its subsidiaries upon future adoption.
|
||||||||
|
(3)
|
Effective date of ASU No. 2011-08 is January 2012. CH Energy Group elected to early adopt this guidance as allowed under current accounting guidance. See Note 6 - "Goodwill and Other Intangible Assets" for further discussion of testing goodwill for impairment.
|
||||||||
CH Energy Group and its subsidiaries file a consolidated Federal and New York State income tax return. CHEC and Griffith also file state income tax returns in those states in which they conduct business.
In September of 2010, Central Hudson filed a request with the Internal Revenue Service (“IRS”) to change the company’s tax accounting method related to costs to repair and maintain utility assets. The change was effective for the tax year ended December 31, 2009. This change allows Central Hudson to take a current tax deduction for a significant amount of expenditure that was previously capitalized for tax purposes.
This change resulted in federal and state net operating income tax losses (“NOL”). For Federal tax purposes, CH Energy Group elected to carry back the NOL, which resulted in tax refunds for the tax years 2004 through 2008. The remaining 2010 and 2011 NOL will be carried forward to future periods. For NYS tax purposes, the 2009 and 2010 NOL will be carried forward to future periods. NOL carryforwards will expire in 20 years if not otherwise utilized. CH Energy Group believes future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expiration. Future tax benefits resulting from this change are included within “Accumulated Deferred Income Tax” on the CH Energy Group Consolidated Balance Sheet and the Central Hudson Balance Sheet. CH Energy Group and Central Hudson NOL carryforwards are summarized as follows (In Thousands):
CH Energy Group
|
Year Ended
|
NOL
|
NOL
Carryforward
Amount
|
NOL Expires
|
||||
|
12/31/09
|
NY State
|
$
|
7,716
|
12/31/29
|
|||
|
12/31/10
|
Federal
|
44,713
|
12/31/30
|
||||
|
12/31/10
|
NY State
|
47,846
|
12/31/30
|
||||
|
12/31/11
|
Federal
|
1,651
|
12/31/31
|
||||
Central Hudson
|
Year Ended
|
NOL
|
NOL
Carryforward
Amount
|
NOL Expires
|
||||
|
12/31/09
|
NY State
|
$
|
31,602
|
12/31/29
|
|||
|
12/31/10
|
Federal
|
31,136
|
12/31/30
|
||||
|
12/31/10
|
NY State
|
29,802
|
12/31/30
|
||||
At December 31, 2010, the final regulations clarifying what qualifies as deductible repair and maintenance expenditures for prospective tax years had not been issued. Due to uncertainty, in 2010 Central Hudson established reserves against a portion of the tax benefits claimed. For Federal tax purposes, $8.3 million was reserved against the tax benefit claimed as a result of the 2009 NOL that was carried back to prior years and $1.6 million was reserved against the 2010 NOL Deferred Tax Asset carried forward. For NYS tax purposes, an additional $1.6 million was reserved against the 2009 and 2010 NOL Deferred Tax Asset carry forward. In August 2011, the IRS released Revenue Procedure (“Rev Proc”) 2011-43, which provided preliminary guidance related to repair deductions for electric transmission and distribution property. Based on guidance provided by this Rev Proc, Central Hudson has reclassified $6.4 million of the original reserve related to electric transmission and distribution repairs to deferred tax liability accounts. A Revenue Procedure related to the treatment of gas repairs is expected late in 2012. The remaining reserve related to the gas repair deduction is shown as “Tax Reserve” under the Deferred Credits and Other Liabilities section of the CH Energy Group Consolidated Balance Sheet and the Central Hudson Balance Sheet. Interest on the remaining reserve is being accrued at the applicable IRS rate and is included in “Accrued Interest” under current liabilities on the CH Energy Group Consolidated Balance Sheet and the Central Hudson Balance Sheet and included in “Interest on regulatory liabilities and other interest” under Interest Charges on the CH Energy Group Consolidated Statement of Income and the Central Hudson Statement of Income. No penalties have been recorded related to this uncertain tax position. If CH Energy Group and its subsidiaries incur any penalties on underpayment of taxes, the amounts would be included in “Other” under the Current Liabilities section of the Balance Sheets and “Other-net” under the Other Income and Deductions section of the Statements of Income.
Other than the uncertain tax position related to the Company’s accounting method change, there are no other uncertain tax positions. The following is a summary of activity related to uncertain tax positions (In Thousands):
|
|
Year Ended December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Balance at the beginning of the period
|
$ | 11,486 | $ | - | ||||
|
Adjustment related to reserve related to Revenue Procedure 2011-43
|
(6,398 | ) | - | |||||
|
Adjustment related to tax accounting method change
|
(1,916 | ) | 11,486 | |||||
|
Settlement of uncertain tax positions with tax authorities
|
- | - | ||||||
|
Lapse of statute of limitations related to uncertain tax positions
|
- | - | ||||||
|
Balance at the end of the period
|
$ | 3,172 | $ | 11,486 | ||||
|
Jurisdiction
|
Tax Years Open for Audit
|
|||
|
Federal(1)
|
2007 - 2011 | |||
|
New York State
|
2007 - 2011 | |||
(1) Federal tax filings for the years 2007 - 2010 are currently under audit.
Components of Income Tax - CH Energy Group
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,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Federal income tax
|
$ | 733 | $ | (28,089 | ) | $ | 7,747 | |||||
|
State income tax
|
502 | (3,048 | ) | 4,120 | ||||||||
|
Deferred federal income tax
|
20,077 | 47,198 | 14,951 | |||||||||
|
Deferred state income tax
|
578 | 1,948 | 563 | |||||||||
|
Total income tax
|
$ | 21,890 | $ | 18,009 | $ | 27,381 | ||||||
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,
|
|
|||||||||
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
Net income attributable to CH Energy Group
|
|
$
|
45,340
|
|
|
$
|
38,504
|
|
|
$
|
43,484
|
|
|
Preferred Stock dividends of Central Hudson
|
|
|
970
|
|
|
|
970
|
|
|
|
970
|
|
|
Non-controlling interest in subsidiary
|
|
|
-
|
|
|
|
(272)
|
|
|
|
(176)
|
|
|
Federal income tax
|
|
|
733
|
|
|
|
(28,089)
|
|
|
|
7,747
|
|
|
State income tax
|
|
|
502
|
|
|
|
(3,048)
|
|
|
|
4,120
|
|
|
Deferred federal income tax
|
|
|
20,077
|
|
|
|
47,198
|
|
|
|
14,951
|
|
|
Deferred state income tax
|
|
|
578
|
|
|
|
1,948
|
|
|
|
563
|
|
|
Income before taxes
|
|
$
|
68,200
|
|
|
$
|
57,211
|
|
|
$
|
71,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Computed federal tax at 35% statutory rate
|
|
$
|
23,870
|
|
|
$
|
20,024
|
|
|
$
|
25,081
|
|
|
State income tax net of federal tax benefit
|
|
|
1,818
|
|
|
|
514
|
|
|
|
3,559
|
|
|
Depreciation flow-through
|
|
|
2,695
|
|
|
|
2,204
|
|
|
|
2,906
|
|
|
Cost of Removal
|
|
|
(1,887)
|
|
|
|
(1,582)
|
|
|
|
(1,524)
|
|
|
Reclassification of funded deferred taxes
|
|
|
-
|
|
|
|
(1,332)
|
|
|
|
-
|
|
|
Production tax credits
|
|
|
(56)
|
|
|
|
(447)
|
|
|
|
(1,402)
|
|
|
Federal grant
|
|
|
(2,580)
|
|
|
|
-
|
|
|
|
-
|
|
|
Other
|
|
|
(1,970)
|
|
|
|
(1,372)
|
|
|
|
(1,239)
|
|
|
Total income tax
|
|
$
|
21,890
|
|
|
$
|
18,009
|
|
|
$
|
27,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate - federal
|
|
|
30.5
|
%
|
|
|
33.4
|
%
|
|
|
31.7
|
%
|
|
Effective tax rate - state
|
|
|
1.6
|
%
|
|
|
(1.9)
|
%
|
|
|
6.5
|
%
|
|
Effective tax rate - combined
|
|
|
32.1
|
%
|
|
|
31.5
|
%
|
|
|
38.2
|
%
|
The effective rate for the year ended December 31, 2011 is impacted by the tax benefit related to federal grants received and the reversal of prior period Production Tax Credits as a result of receiving the grant. The net benefit from state income taxes recognized in the year ended December 31, 2010 is due to the true-up of the New York State apportionment rate.
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,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Accumulated Deferred Income Tax Asset:
|
|
|
||||||
|
Excess depreciation reserve
|
$ | 439 | $ | 3,905 | ||||
|
Unbilled revenues
|
7,942 | 11,347 | ||||||
|
Plant-related
|
8,688 | 5,282 | ||||||
|
Regulatory asset - future income tax
|
30,663 | 35,166 | ||||||
|
OPEB expense
|
28,599 | 25,638 | ||||||
|
NOL carryforwards
|
19,959 | 21,676 | ||||||
|
Contributions in aid of construction
|
5,463 | 5,404 | ||||||
|
Directors and officers deferred compensation
|
4,688 | 4,253 | ||||||
|
Other
|
21,409 | 23,802 | ||||||
|
Accumulated Deferred Income Tax Asset
|
127,850 | 136,473 | ||||||
|
|
||||||||
|
Accumulated Deferred Income Tax Liability:
|
||||||||
|
Depreciation
|
194,671 | 169,528 | ||||||
|
Repair allowance
|
10,083 | 10,492 | ||||||
|
Pension expense
|
13,710 | 14,949 | ||||||
|
Change in tax accounting for repairs
|
56,079 | 43,661 | ||||||
|
Regulatory liability - future income tax
|
34,069 | 31,780 | ||||||
|
Residual deferred gas balance
|
5,445 | 7,256 | ||||||
|
PSC assessments
|
2,532 | 3,325 | ||||||
|
Cost of removal
|
4,882 | 4,535 | ||||||
|
Electric fuel costs
|
5,182 | 9,055 | ||||||
|
Gas costs
|
704 | 3,291 | ||||||
|
Storm deferrals
|
6,050 | 7,791 | ||||||
|
Other
|
23,708 | 32,883 | ||||||
|
Accumulated Deferred Income Tax Liability
|
357,115 | 338,546 | ||||||
|
Net Deferred Income Tax Liability
|
229,265 | 202,073 | ||||||
|
Net Current Deferred Income Tax Liability (Asset)
|
(5,895 | ) | 9,634 | |||||
|
Net Long-term Deferred Income Tax Liability
|
$ | 235,160 | $ | 192,439 | ||||
Components of Income Tax - Central Hudson
The following is a summary of the components of state and federal income taxes for Central Hudson as reported in its Statement of Income (In Thousands):
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Federal income tax
|
$ | - | $ | (25,139 | ) | $ | (3 | ) | ||||
|
State income tax
|
- | (634 | ) | 1,135 | ||||||||
|
Deferred federal income tax
|
24,988 | 48,894 | 18,538 | |||||||||
|
Deferred state income tax
|
3,189 | 3,043 | 1,472 | |||||||||
|
Total income tax
|
$ | 28,177 | $ | 26,164 | $ | 21,142 | ||||||
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 Statement of Income (In Thousands):
|
|
|
Year Ended December 31,
|
|
|||||||||
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||
|
Net income
|
|
$
|
45,037
|
|
|
$
|
46,118
|
|
|
$
|
32,776
|
|
|
Federal income tax
|
|
|
-
|
|
|
|
(25,139)
|
|
|
|
(3)
|
|
|
State income tax
|
|
|
-
|
|
|
|
(634)
|
|
|
|
1,135
|
|
|
Deferred federal income tax
|
|
|
24,988
|
|
|
|
48,894
|
|
|
|
18,538
|
|
|
Deferred state income tax
|
|
|
3,189
|
|
|
|
3,043
|
|
|
|
1,472
|
|
|
Income before taxes
|
|
$
|
73,214
|
|
|
$
|
72,282
|
|
|
$
|
53,918
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Computed federal tax at 35% statutory rate
|
|
$
|
25,625
|
|
|
$
|
25,299
|
|
|
$
|
18,871
|
|
|
State income tax net of federal tax benefit
|
|
|
3,189
|
|
|
|
2,631
|
|
|
|
2,210
|
|
|
Depreciation flow-through
|
|
|
2,695
|
|
|
|
2,204
|
|
|
|
2,906
|
|
|
Cost of Removal
|
|
|
(1,887)
|
|
|
|
(1,582)
|
|
|
|
(1,524)
|
|
|
Reclassification of funded deferred taxes
|
|
|
-
|
|
|
|
(1,332)
|
|
|
|
-
|
|
|
Other
|
|
|
(1,445)
|
|
|
|
(1,056)
|
|
|
|
(1,321)
|
|
|
Total income tax
|
|
$
|
28,177
|
|
|
$
|
26,164
|
|
|
$
|
21,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate - federal
|
|
|
34.1
|
%
|
|
|
32.9
|
%
|
|
|
34.4
|
%
|
|
Effective tax rate - state
|
|
|
4.4
|
%
|
|
|
3.3
|
%
|
|
|
4.8
|
%
|
|
Effective tax rate - combined
|
|
|
38.5
|
%
|
|
|
36.2
|
%
|
|
|
39.2
|
%
|
The 2010 tax accounting change, together with other significant book to tax accounting differences, has resulted in reduced current federal and state tax expense for 2011, 2010 and 2009. These accounting differences are primarily temporary and require normalization, resulting in an offsetting deferred tax expense.
The difference in the effective tax rate for 2010 is also impacted by a one-time reclassification of funded deferred taxes to a regulatory liability, resulting in a reduction to the tax provision of $2.3 million.
The following is a summary of the components of deferred taxes as reported in Central Hudson’s Balance Sheet (In Thousands):
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Accumulated Deferred Income Tax Asset:
|
|
|
||||||
|
Unbilled revenues
|
$ | 7,942 | $ | 11,347 | ||||
|
Plant-related
|
8,688 | 5,282 | ||||||
|
OPEB expense
|
28,599 | 25,638 | ||||||
|
NOL carryforwards
|
14,907 | 21,779 | ||||||
|
Excess depreciation reserve
|
439 | 3,905 | ||||||
|
Contributions in aid of construction
|
5,463 | 5,404 | ||||||
|
Regulatory asset - future income tax
|
30,663 | 35,166 | ||||||
|
Directors and officers deferred compensation
|
4,688 | 4,253 | ||||||
|
Other
|
20,411 | 16,651 | ||||||
|
Accumulated Deferred Income Tax Asset
|
121,800 | 129,425 | ||||||
|
|
||||||||
|
Accumulated Deferred Income Tax Liability:
|
||||||||
|
Depreciation
|
194,671 | 169,528 | ||||||
|
Repair allowance
|
10,083 | 10,492 | ||||||
|
Pension expense
|
13,710 | 14,949 | ||||||
|
Change in tax accounting for repairs
|
56,079 | 43,661 | ||||||
|
Regulatory liability - future income tax
|
34,069 | 31,780 | ||||||
|
Residual deferred gas balance
|
5,445 | 7,256 | ||||||
|
PSC assessments
|
2,532 | 3,325 | ||||||
|
Cost of removal
|
4,882 | 4,535 | ||||||
|
Electric fuel costs
|
5,182 | 9,055 | ||||||
|
Gas costs
|
704 | 3,291 | ||||||
|
Storm deferrals
|
6,050 | 7,791 | ||||||
|
Other
|
23,092 | 24,088 | ||||||
|
Accumulated Deferred Income Tax Liability
|
356,499 | 329,751 | ||||||
|
Net Deferred Income Tax Liability
|
234,699 | 200,326 | ||||||
|
Net Current Deferred Income Tax Liability
|
156 | 13,021 | ||||||
|
Net Long-term Deferred Income Tax Liability
|
$ | 234,543 | $ | 187,305 | ||||
Acquisitions
During the years ended December 31, 2011, 2010 and 2009, Griffith acquired fuel distribution companies as follows (Dollars in Thousands):
|
# of
|
|
Total
|
|
Total
|
|||||||||||
|
Acquired
|
Purchase
|
Intangible
|
|
Tangible
|
|||||||||||
|
Year Ended
|
Companies
|
Price
|
Assets(1)
|
Goodwill
|
Assets
|
||||||||||
|
December 31, 2011
|
6 | $ | 4,451 | $ | 4,274 | $ | 1,572 | $ | 177 | ||||||
|
December 31, 2010
|
1 | 743 | 621 | 289 | 122 | ||||||||||
|
December 31, 2009
|
- | - | - | - | - | ||||||||||
|
Total
|
7 | $ | 5,194 | $ | 4,895 | $ | 1,861 | $ | 299 | ||||||
|
(1) Including goodwill.
|
A 2008 acquisition transaction 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. As of December 31, 2011, there are no remaining earn out obligations associated with any acquisitions. There were no earn outs paid in 2011, 2010 and 2009.
Amortizable intangible assets acquired in the current year consist of customer relationships, which will be amortized over a 15-year period, and covenants not to compete, which will be amortized over a 5-year period. The weighted average amortization period of amortizable intangible assets acquired in the current year is 14 years.
Divestitures
In the first quarter of 2011, Griffith reduced its environmental reserve by $0.6 million based on the completion of an environmental study. The reserve adjustment related to the 2009 divestiture of operations in certain geographic locations. During 2011, Griffith recorded expense adjustments of $0.2 million relating to divested operations. As such, income of $0.3 million, net of tax, has been reflected in income from discontinued operations in the CH Energy Group Consolidated Income Statement for the year ended December 31, 2011.
During 2011, CHEC divested four of its renewable energy investments, as follows:
|
-
|
On May 1, 2011, the sale of Lyonsdale, which owns a wood-burning electric generating facility in Lyons Falls, New York, was completed.
|
|
-
|
On August 11, 2011, the sale of Shirley Wind, which owns a wind project in Glenmore, Wisconsin, was completed.
|
|
-
|
On September 16, 2011, the sale of CH-Auburn, which owns an electric generating plant that utilizes methane gas generated by the City of Auburn, New York landfill, was completed.
|
|
-
|
On December 29, 2011, the sale of a molecular gate owned by CH-Greentree, which was used to remove nitrogen from landfill gas and was being leased by Greentree Landfill Gas Company, LLC, was completed.
|
The results of operations of Lyonsdale, CH Shirley Wind, CH-Auburn and CH-Greentree for current and prior periods are presented in discontinued operations in the CH Energy Group Consolidated Statement of Income. Management has elected to include cash flows from discontinued operations of Lyonsdale, CH Shirley Wind, CH-Auburn and CH-Greentree with those from continuing operations in the CH Energy Group Consolidated Statement of Cash Flows. The details of each of the sales transactions by investment are as follows (In Thousands):
|
CH-Auburn
|
Shirley Wind
|
Lyonsdale
|
CH-Greentree
|
|||||||||||||
|
Assets
|
|
|
|
|
||||||||||||
|
Current Assets
|
$ | 174 | $ | 623 | $ | 2,099 | $ | - | ||||||||
|
Other Assets
|
- | 461 | - | - | ||||||||||||
|
Property, Plant and Equipment
|
||||||||||||||||
|
Property, plant and equipment
|
4,667 | 32,564 | 10,670 | 5,500 | ||||||||||||
|
Less: Accumulated depreciation
|
626 | 657 | 4,191 | 1,205 | ||||||||||||
|
Total property, plant and equipment, net
|
4,041 | 31,907 | 6,479 | 4,295 | ||||||||||||
|
Assets sold
|
$ | 4,215 | $ | 32,991 | $ | 8,578 | $ | 4,295 | ||||||||
|
Liabilities
|
||||||||||||||||
|
Current Liabilities
|
$ | 85 | $ | 6 | $ | 322 | $ | - | ||||||||
|
Other Liabilities
|
1,736 | - | - | - | ||||||||||||
|
Liabilities sold
|
$ | 1,821 | $ | 6 | $ | 322 | $ | - | ||||||||
|
Net Assets Sold
|
$ | 2,394 | $ | 32,985 | $ | 8,256 | $ | 4,295 | ||||||||
|
Net Proceeds from Sale
|
$ | 3,673 | $ | 33,100 | $ | 7,700 | $ | 3,000 | ||||||||
|
Pre-tax gain (loss) on sales transaction(1)
|
$ | 1,279 | $ | 115 | $ | (556 | ) | $ | (1,295 | ) | ||||||
|
Tax Benefit of Federal Grant Received(2)
|
$ | 277 | $ | 2,303 | $ | - | $ | - | ||||||||
|
Net Increase (Decrease) to Earnings
|
$ | 1,050 | $ | 2,391 | $ | (328 | ) | $ | (769 | ) | ||||||
|
(1)
|
Included in the Gain from the sale of discontinued operations line of the CH Energy Group Consolidated Income Statement
|
|
(2)
|
Included in the Income tax (benefit) expense from discontinued operations line of the CH Energy Group Consolidated Income Statement
|
Proceeds from these sales were used primarily for the repurchase of outstanding Common Stock of CH Energy Group. Additionally, a portion of the proceeds from the sale of Shirley Wind were used to pay down private placement debt at CH Energy Group, which provided corporate financing for the construction of this project. See Note 9 – “Capitalization – Long-Term Debt” for further details regarding the repayment of debt.
The table below provides additional detail of the financial results of the discontinued operations (In Thousands):
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Revenues from discontinued operations
|
$ | 6,948 | $ | 12,196 | $ | 132,707 | ||||||
|
Income (loss) from discontinued operations before tax
|
1,660 | (2,333 | ) | 5,026 | ||||||||
|
Gain (loss) from sale of discontinued operations
|
(457 | ) | - | 10,767 | ||||||||
|
Income tax (benefit) expense from discontinued operations
|
(1,923 | ) | (1,205 | ) | 5,112 | |||||||
As of December 31, 2011, CHEC has two remaining investments in renewable energy – Cornhusker Holdings and CH-Community Wind. The value of CHEC’s investments in Cornhusker and CH-Community Wind is zero as of December 31, 2011. See Note 15 – “Other Fair Value Measurements” for further details on the fair value assessments and impairments recorded on these investments. CHEC also has investments in cogeneration partnerships and an energy sector venture capital fund totaling approximately $2.8 million as of December 31, 2011. These investments are not considered a part of the core business. However, Management intends to retain these investments at this time.
Investments
The value of CHEC's investments as of December 31, 2011 are as follows (In Thousands):
|
CHEC Investment
|
Description
|
Intercompany Debt
|
Equity Investment
|
Total
|
||||||||||
|
Griffith Energy Services
|
100% controlling interest in a fuel distribution business
|
$ | 35,100 | $ | 35,651 | $ | 70,751 | |||||||
|
Cornhusker Holdings
|
12% equity interest plus subordinated debt investment in an operating corn-ethanol plant
|
- | - | - | ||||||||||
|
CH-Community Wind
|
50% equity interest in a joint venture that owns 18% interest in two operating wind projects
|
- | - | - | ||||||||||
|
Other
|
Partnerships and an energy sector venture capital fund
|
- | 2,777 | 2,777 | ||||||||||
|
|
|
$ | 35,100 | $ | 38,428 | $ | 73,528 | |||||||
Goodwill, customer relationships 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, 2011 and 2010, for “Goodwill” and “Other intangible assets - net” relate to Griffith. In accordance with current accounting guidance related to goodwill and other intangible assets, goodwill and other intangible assets that have indefinite useful lives are no longer amortized, but instead are periodically reviewed for impairment.
In the fourth quarter, Management performed a qualitative assessment of any potential impairment of Griffith’s goodwill. The last quantitative analysis of impairment was performed as of September 30, 2010, which reflected that the fair value of Griffith exceeded its carrying value by approximately $34.2 million. Additionally, Management believes that no event has occurred which would trigger impairment since the last quantitative test performed. Based on these factors and other factors considered in its qualitative analysis, Management believes that it is more likely than not that the fair market value is more than the carrying value of Griffith and therefore, the first and second steps of the impairment test prescribed in guidance were not necessary.
As a result of the divestiture in December 2009, Griffith reduced its 2009 goodwill by approximately $10 million in addition to the goodwill recorded when the divested assets were purchased. This additional reduction was recorded in accordance with current accounting guidance related to goodwill, which requires an allocation of goodwill based on the fair values of the divested region and the portion of the business retained.
The components of amortizable intangible assets of CH Energy Group are summarized as follows (In Thousands):
|
|
December 31, 2011
|
December 31, 2010
|
|||||||||||
|
|
Gross Carrying Amount
|
Accumulated Amortization
|
Gross Carrying Amount
|
Accumulated Amortization
|
|||||||||
|
Customer relationships
|
$ | 36,517 | $ | 23,571 | $ | 34,063 | $ | 21,214 | |||||
|
Covenants not to compete
|
361 | 134 | 113 | 95 | |||||||||
|
Total Amortizable Intangibles
|
$ | 36,878 | $ | 23,705 | $ | 34,176 | $ | 21,309 | |||||
(In Thousands)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Amortization Expense
|
$ | 2,396 | $ | 2,277 | $ | 4,001 | ||||||
The estimated annual amortization expense for each of the next five years, assuming no new acquisitions or divestitures, is approximately $2.1 million.
|
Description
|
CH Energy Group
|
Central Hudson
|
|||||||||||
|
Revolving Credit Facilities(1)
|
|
|
|
||||||||||
|
Limit
|
$150 million
|
$150 million(2)
|
|||||||||||
|
Expiration
|
February 2013
|
October 2016
|
|||||||||||
|
|
|
|
|||||||||||
| (In Thousands) | |||||||||||||
|
December 31,
|
December 31,
|
||||||||||||
|
2011
|
2010
|
2011
|
2010
|
||||||||||
|
Outstanding
|
$ | 6,500 | $ | - | $ | 1,500 | $ | - | |||||
|
Uncommitted Credit(3)
|
None
|
||||||||||||
|
Outstanding
|
$ | - | $ | - | |||||||||
|
(1)
|
Providing committed credit.
|
|
(2)
|
Pursuant to PSC authorization, through December 31, 2012, Central Hudson is authorized to increase this limit to $175 million. Such an increase could provide greater liquidity to support construction forecasts, seasonality of the business, volatile energy markets, adverse borrowing environments and other unforeseen events.
|
|
(3)
|
To diversify cash sources and provide competitive options to minimize Central Hudson's cost of short-term debt.
|
On October 19, 2011, Central Hudson entered into a new $150 million committed revolving credit facility with JPMorgan Chase Bank, N.A., Bank of America, N.A., HSBC Bank USA, N.A., KeyBank National Association and RBS Citizens Bank, N.A. as the participating banks. The new credit facility has a term of five years. The prior $125 million facility was terminated as of the effective date of the new agreement. CH Energy Group revolving credit facilities reflect commitments from JPMorgan Chase Bank, N.A., Bank of America, N.A., HSBC Bank USA, N.A. and KeyBank, N.A. If any of these lenders are unable to fulfill their commitments under these facilities, funding may not be available as needed.
Griffith’s short-term financing needs are currently provided by CH Energy Group through intercompany notes.
Debt Covenants
CH Energy Group’s and Central Hudson’s credit facilities 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
|
12/31/11
|
2011
|
2010
|
||||||||||
| 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 2011, 2010 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 million 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.
During 2011 and 2010, CH Energy Group had purchased 919,114 and 29,562 shares under the Repurchase Program, respectively. No shares were repurchased under the Repurchase Program during the year ended 2009.
As part of this Repurchase Program, on August 16, 2011, CH Energy Group implemented an accelerated share repurchase program (“ASR”) providing for the repurchase by CH Energy Group of a number of shares with a value as of the date of the agreement of $30 million. CH Energy Group paid $30 million and received 554,017 shares on August 17, 2011, which represented 100% of the total number of shares CH Energy Group would receive if the price per share of the Common Stock remained at the closing price on August 16, 2011 of $54.15 per share throughout the remainder of the calculation period under the program, which is expected to end no later than May 16, 2012 (but may be earlier terminated by the agent under certain circumstances).
The actual number of shares of Common Stock that CH Energy Group will repurchase under the ASR will be determined at the end of the calculation period based on the difference between the $30 million contract amount and an amount determined by multiplying a discounted daily volume-weighted average price of CH Energy Group’s Common Stock over the calculation period by the number of shares initially purchased. The actual number of shares CH Energy Group will repurchase under the ASR is subject to collar provisions that establish a minimum and maximum number of shares to be repurchased and certain other adjustments. If the actual number of shares to be delivered under the program exceeds the number of shares initially delivered by the agent to CH Energy Group, following the end of the calculation period the agent will be required to deliver to CH Energy Group a number of additional shares equal to the excess. If the actual number of shares to be delivered under the program is less than the number of shares initially delivered by the agent to CH Energy Group, then following the end of the calculation period CH Energy Group will be required, at its election, to either deliver to the agent a number of shares of Common Stock approximately equal to the difference or pay to the agent cash in an amount equal to the value of such shares. CH Energy Group controls the form of settlement of any obligation resulting from the ASR and in all cases may elect to deliver its Common Stock at settlement, except in the presence of a liquidating event or default or termination event. CH Energy Group has sufficient authorized and unissued shares available to settle the contract based on the current CH Energy Group stock price and after considering all other commitments that may require the issuance of stock during the maximum calculation period. Additionally, the ASR permits settlement in unregistered shares and further specifies that CH Energy Group cannot be required to deliver more than the shares available at the time but must use its best efforts to authorize, issue and deliver additional shares if necessary to satisfy its obligations under the contract. Accordingly, and in accordance with current accounting guidance, this transaction has been accounted for as an equity transaction.
Subsequent to December 31, 2011, no additional shares have been purchased under the Repurchase Program. CH Energy Group reserves the right to modify, suspend, renew, or terminate the Repurchase Program at any time without notice. CH Energy Group intends to set repurchase targets, if any, from time to time based on then prevailing circumstances. The shares repurchased by CH Energy Group have not been retired or cancelled, and the repurchases accordingly have been presented as an increase to treasury stock in CH Energy Group’s Consolidated Balance Sheet.
Other Common Stock Activity
Effective July 1, 2011, employer matching contributions to the Savings Incentive Plan (“SIP”) are paid either in cash or in CH Energy Group Common Stock. During the third quarter of 2011, CH Energy Group began making employer matching contributions to the SIP by issuing treasury shares. During 2011, employer matching contributions issued from treasury totaled 19,556 shares. Management expects to continue making employer matching contributions to the SIP in stock, which it estimates will be approximately 48,000 shares per year.
Details of CH Energy Group's and Central Hudson’s long-term debt are as follows (In Thousands):
|
|
December 31,
|
|||||||||
|
Series
|
Maturity Date
|
2011
|
2010
|
|||||||
|
Central Hudson:
|
|
|
|
|||||||
|
Promissory Notes:
|
|
|
|
|||||||
|
2002 Series D (6.64%)(3)
|
Mar. 28, 2012
|
$ | 36,000 | $ | 36,000 | |||||
|
2008 Series F (6.854%)(5)
|
Nov. 01, 2013
|
30,000 | 30,000 | |||||||
|
2004 Series D (4.73%)(3)
|
Feb. 27, 2014
|
7,000 | 7,000 | |||||||
|
2004 Series E (4.80%)(4)
|
Nov. 05, 2014
|
7,000 | 7,000 | |||||||
|
2007 Series F (6.028%)(5)
|
Sep. 01, 2017
|
33,000 | 33,000 | |||||||
|
2004 Series E (5.05%)(4)
|
Nov. 04, 2019
|
27,000 | 27,000 | |||||||
|
1999 Series A (5.45%)(7)
|
Aug. 01, 2027
|
- | 33,400 | |||||||
|
1998 Series A (6.50%)(1)
|
Dec. 01, 2028
|
16,700 | 16,700 | |||||||
|
2006 Series E (5.76%)(4)
|
Nov. 17, 2031
|
27,000 | 27,000 | |||||||
|
1999 Series B(1)(2)
|
July 01, 2034
|
33,700 | 33,700 | |||||||
|
2005 Series E (5.84%)(4)
|
Dec. 05, 2035
|
24,000 | 24,000 | |||||||
|
2007 Series F (5.804%)(5)
|
Mar. 23, 2037
|
33,000 | 33,000 | |||||||
|
2009 Series F (5.80%)(5)
|
Oct. 01, 2039
|
24,000 | 24,000 | |||||||
|
2010 Series A (4.30%)(6)
|
Sep. 21, 2020
|
16,000 | 16,000 | |||||||
|
2010 Series B (5.64%)(6)
|
Sep. 21, 2040
|
24,000 | 24,000 | |||||||
|
2010 Series G (2.756%)(6)
|
Apr. 01, 2016
|
8,000 | 8,000 | |||||||
|
2010 Series G (4.15%)(6)
|
Apr. 01, 2021
|
44,150 | 44,150 | |||||||
|
2010 Series G (5.716%)(6)
|
Apr. 01, 2041
|
30,000 | 30,000 | |||||||
|
2011 Series G (3.378%)(6)
|
Apr. 01, 2022
|
23,400 | - | |||||||
|
2011 Series G (4.707%)(6)
|
Apr. 01, 2042
|
10,000 | - | |||||||
|
|
453,950 | 453,950 | ||||||||
|
|
||||||||||
|
Unamortized Discount on Debt
|
|
- | (50 | ) | ||||||
|
Total Long-term debt
|
|
$ | 453,950 | $ | 453,900 | |||||
|
|
||||||||||
|
Less: Current Portion
|
|
(36,000 | ) | - | ||||||
|
|
||||||||||
|
Central Hudson Net Long-term debt
|
|
$ | 417,950 | $ | 453,900 | |||||
|
|
||||||||||
|
CH Energy Group:
|
|
|||||||||
|
Promissory Notes:
|
|
|||||||||
|
2009 Series A (6.58%)
|
Apr. 17, 2014
|
$ | 6,500 | $ | 26,500 | |||||
|
2009 Series B (6.80%)
|
Dec. 15, 2025
|
22,559 | 23,500 | |||||||
|
|
||||||||||
|
Less: Current Portion
|
|
(1,006 | ) | (941 | ) | |||||
|
|
||||||||||
|
CH Energy Group Net Long-term debt
|
|
$ | 446,003 | $ | 502,959 | |||||
|
(1)
|
Promissory Notes issued in connection with the sale by NYSERDA of tax-exempt pollution control revenue bonds.
|
|
(2)
|
Variable (auction) rate notes.
|
|
(3)
|
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.
|
|
(4)
|
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.
|
|
(5)
|
Issued pursuant to a 2006 PSC Order approving the issuance by Central Hudson prior to December 31, 2009, of up to $120 million of unsecured medium-term notes.
|
|
(6)
|
Issued pursuant to a 2009 PSC Order approving the issuance by Central Hudson prior to December 31, 2012, of up to $250 million of unsecured medium-term notes or other forms of long-term indebtedness.
|
|
(7)
|
In November 2011, Central Hudson redeemed its 1999 Series A NYSERDA Bonds with the use of proceeds from its 2011 Series G Notes.
|
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.
On September 22, 2009, the PSC authorized Central Hudson to issue up to $250 million of long-term debt through December 31, 2012 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.
On September 21, 2010, Central Hudson entered into a Note Purchase Agreement to issue and sell, in a private placement exempt from registration under the Securities Act of 1933, $40 million of senior unsecured notes in two series. Series A bears interest at the rate of 4.30% per annum on a principal amount of $16 million and matures on September 21, 2020. Series B bears interest at the rate of 5.64% per annum on a principal amount of $24 million and matures on September 21, 2040. Central Hudson used a portion of the proceeds from the sale of the notes for refunding maturing long term debt and retained the rest for general corporate purposes.
On September 30, 2011, Central Hudson issued $33.4 million of its Series G registered unsecured Medium Term Notes in two maturities. The first maturity bears interest at the rate of 3.378% per annum on a principal amount of $23.4 million and matures on April 1, 2022. The second maturity bears interest at the rate of 4.707% per annum on a principal amount of $10.0 million and matures on April 1, 2042. In November 2011, Central Hudson used the proceeds from the sale of the notes for redeeming its 1999 Series A NYSERDA Bonds in the principal amount of $33.4 million bearing interest at the rate of 5.45%. No bonds of this 1999 Series A remained outstanding following the redemption.
In March 2012, medium term notes issued by Central Hudson totaling $36.0 million will mature. Central Hudson expects to refinance these notes under its Series G note program.
In September 2011, following the sale of Shirley Wind, CH Energy Group repaid $20 million of its 2009 Series A private placement debt with a portion of the proceeds from the sale. As a result, a prepayment penalty was incurred of approximately $3.0 million, which has been included in Penalty for Early Retirement of Debt on the CH Energy Group Consolidated Statement of Income.
Griffith had no third-party long-term debt outstanding as of December 31, 2011 or 2010.
NYSERDA
Central Hudson’s Series B NYSERDA Bonds total $33.7 million at December 31, 2011. These bonds are tax-exempt multi-modal bonds that are currently in a variable rate mode. In its Orders, the PSC has authorized deferral accounting treatment for variations in the interest costs from these bonds. As such, variations between the actual interest rates on these bonds and the interest rate included in the current delivery rate structure for these bonds are deferred for future recovery from or refund to customers and therefore do not impact earnings.
To mitigate the potential cash flow impact from unexpected increases in short-term interest rates on Series B Bonds, Central Hudson purchased an interest rate cap based on an index of short-term tax-exempt debt. The rate cap is two years in length with a notional amount aligned with Series B and will expire on April 1, 2012. The cap is based on the monthly weighted average of an index of tax-exempt variable rate debt, multiplied by 175%. Central Hudson would receive a payout if the adjusted index exceeds 5.0% for a given month. As of December 31, 2011, no payout is expected and as such the fair value of this instrument is not material. Central Hudson expects to replace the expiring rate cap as needed.
Central Hudson is currently evaluating what actions, if any, it may take in the future in connection with its Series B NYSERDA Bonds. Potential actions may include converting the debt 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 and unamortized costs written off on redemptions of Central Hudson’s debt prior to maturity have been deferred and are amortized over the remaining lives of the related extinguished issues, as directed by the PSC.
Debt Covenants
CH Energy Group’s $29.1 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.
Decisions to fund Central Hudson’s Retirement Plan are based on several factors, including, but not limited to, corporate resources, projected investment returns, actual investment returns, inflation, the value of plan assets relative to plan liabilities, regulatory considerations, interest rate assumptions and the Pension Protection Act of 2006 (“PPA”). Based on the funding requirements of the PPA, Central Hudson plans to make contributions that maintain the target funded percentage at 80% or higher. Contributions to the Retirement Plan during the years ended December 31, 2011 and 2010 were $32.0 million and $64.2 million, respectively.
The fair value of the plan assets has increased by approximately $35.2 million in 2011, reflecting significant contributions and asset returns that were partially offset by benefit payments and administrative expenses. Plan liabilities, however, increased by approximately $54.5 million, reflecting a decline in the plan discount rate. The net impact was an increase in the unfunded liability of approximately $19.3 million. Contributions for 2012 are expected to be approximately $28 million. As noted above, actual contributions could vary significantly based upon a range of factors that Central Hudson considers in its funding decisions.
The balance of Central Hudson's accrued pension costs (i.e., the under-funded status) is as follows (In Thousands):
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Accrued pension costs
|
$ | 122,562 | $ | 103,227 | ||||
These balances include the difference between the projected benefit obligation (“PBO”) for pensions and the market value of the pension assets, and the liability for the non-qualified SERP.
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,
|
||||
|
|
|
2011
|
|
2010
|
||
|
Prefunded pension costs prior to funding status adjustment
|
|
$
|
30,270
|
|
$
|
34,307
|
|
Additional liability required
|
|
|
(152,832)
|
|
|
(137,534)
|
|
Total accrued pension costs
|
|
$
|
(122,562)
|
|
$
|
(103,227)
|
|
Total offset to additional liability - Regulatory assets - Pension Plan
|
|
$
|
152,832
|
|
$
|
137,534
|
Gains or losses and prior service costs or credits that arise during the period but that 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 has PSC approval to record regulatory assets rather than adjusting comprehensive income to offset the additional liability.
The valuation of the current and prior year PBO was determined as of the measurement date of December 31, 2011 and 2010, using discount rates of 4.5% for 2011 (as determined using the Mercer Pension Discount Curve reflecting projected pension cash flows) and 5.3% for 2010 (as determined using the Citigroup Pension Discount Curve reflecting projected pension cash flows). Central Hudson accounts for pension activity in accordance with PSC-prescribed provisions, which among other things, requires a ten-year amortization of actuarial gains and losses. Declines in the market value of the Trust Fund’s investment portfolio, which occurred from 2000 through 2002, 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.
The 2010 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 2010 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 2010 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, 2010 is being recovered via a four-year amortization that began July 1, 2010.
In addition to the Retirement Plan, a portion of CH Energy Group’s and Central Hudson’s executives are covered under a non-qualified Supplemental Executive Retirement Plan.
Retirement Plan Estimates of Long-Term Rates of Return
The expected long-term rate of return on the Retirement Plan assets is 7.00%, 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 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
Central Hudson’s Retirement Plan investment policy seeks to achieve long-term growth and income to match the long-term nature of its funding obligations. During the first quarter of 2010, Management began a transition to a liability-driven investment (“LDI”) strategy for its pension plan assets. Management’s objective is to reduce the plan’s funded status volatility and the level of contributions by more closely aligning the characteristics of plan assets with liabilities.
Asset allocation targets in effect as of December 31, 2011 as well as actual asset allocations as of December 31, 2011 and 2010 expressed as a percentage of the market value of the Retirement Plan’s assets, are summarized in the table below:
|
Asset Class
|
December 31,
2010
|
Minimum
|
Target Average
|
Maximum
|
December 31,
2011
|
|||||||||||||||
|
Equity Securities
|
54.8 | % | 45 | % | 50 | % | 55 | % | 35.8 | % | ||||||||||
|
Debt Securities
|
44.0 | % | 45 | % | 50 | % | 55 | % | 54.4 | % | ||||||||||
|
Other(1)
|
1.2 | % | - | % | - | % | - | % | 9.8 | % | ||||||||||
|
(1)
|
Consists of temporary cash investments, as well as receivables for investments sold and interest, and payables for investments purchased, which have not settled as of that date.
|
The above current asset allocations are the result of the transition to an asset allocation of approximately 50% equity and 50% long duration fixed income assets by year-end 2011 compounded by recent market activity. A reduction in interest rates has made the long duration bonds held in debt securities more valuable and the recent decrease in stock price performance in 2011 has reduced the value of the pension plan’s equity investments. As noted in the above chart, the resulting December 31, 2011 asset allocations are outside of the target minimum for equity and within the expected target range for debt. Due to market value fluctuations, Retirement Plan assets will require rebalancing from time-to-time to maintain the target asset allocation. Management is currently monitoring on-going market activity and the impact on the pension plan asset allocations to determine if a rebalancing will be necessary.
Central Hudson cannot assure that the Retirement Plan’s return objectives or funded status objectives will be achieved.
Retirement Plan Investment Valuation
The Retirement Plan assets are valued under the current fair value framework. See Note 14 - “Accounting for Derivative Instruments and Hedging Activities” for further discussion regarding the definition and levels of fair value hierarchy established by accounting guidance.
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, 2011 and 2010, as well as the associated level within the fair value hierarchy in which the fair value measurements in their entirety fall (Dollars in Thousands):
|
Investment Type
|
Market Value at 12/31/11
|
% of Total
|
Market Value at 12/31/10
|
% of Total
|
||||||||||||
|
Level 1
|
|
|
|
|
||||||||||||
|
Cash Equivalents
|
$ | 20 | - | % | $ | 12 | - | % | ||||||||
|
Level 2
|
||||||||||||||||
|
Investment Funds - Equities(1)
|
154,657 | 35.8 | % | 217,461 | 54.8 | % | ||||||||||
|
Investment Funds - Fixed Income(1)
|
235,168 | 54.4 | % | 174,723 | 44.0 | % | ||||||||||
|
Cash Equivalents(2)
|
3,731 | 0.9 | % | 1,762 | 0.5 | % | ||||||||||
| Receivable for Securities Sold(2) | 40,415 | 9.4 | % | 4,911 | 1.2 | % | ||||||||||
| Payable for Securities Purchased(2) | (3,374 | ) | (0.8 | )% | (2,455 | ) | (0.6 | )% | ||||||||
| Other Investments | 1,511 | 0.3 | % | 519 | 0.1 | % | ||||||||||
| $ | 432,128 | 100.0 | % | $ | 396,933 | 100.0 | % | |||||||||
|
(1)
|
Reported at net asset value, which equals redemption price on that date.
|
|
|
(2)
|
Reported at stated value, which approximates fair value on that date.
|
|
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,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Balance at Beginning of Period
|
$ | - | $ | 14,498 | ||||
|
Unrealized gains
|
- | 267 | ||||||
|
Realized losses
|
- | 139 | ||||||
|
Purchases, issuances, sales and settlements
|
- | (121 | ) | |||||
|
Transfers in and/or out of Level 3
|
- | (14,783 | ) | |||||
|
Balance at End of Period
|
$ | - | $ | - | ||||
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 currently selects the discount rate using the Mercer Pension Discount Curve in 2011 and used the Citigroup Pension Discount Curve in 2010, both 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 is deferred as either a regulatory asset or a regulatory liability, as appropriate.
The effect of the Medicare Act of 2003 was reflected in 2011 and 2010, 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. The Patient Protection and Affordable Care Act signed into law on March 23, 2010, contains a provision which changes the tax treatment related to the Retiree Drug Subsidy benefit under the Medicare Prescription Drug, Improvement and Modernization Act (under Medicare Part D). This change reduces the employer's deduction for the costs of health care for retirees by the amount of Retiree Drug Subsidy payments received. As a result, the deductible temporary difference and any related deferred tax asset associated with the benefit plan were reduced. Under the PSC policy regarding Medicare Act Effects, cost savings and income tax effects related to the Medicare Prescription Drug, Improvement and Modernization Act are deferred for future recovery from or refund to customers. See Note 2 – “Regulatory Matters” for further information.
Central Hudson’s liability (i.e. the under-funded status) for OPEB at December 31, 2011, was $53.1 million and at December 31, 2010, was $45.4 million. The cumulative amount of net periodic benefit cost in excess of employer contributions at December 31, 2011 and December 31, 2010 was $60.3 million and $53.3 million respectively. The difference between these amounts, $7.3 million at December 31, 2011 and $7.9 million at December 31, 2010, will be recognized in Central Hudson’s future expense and have been recorded as 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. The matching benefit varies by employer and employee group. For Central Hudson, the costs of their matching contributions were $2.1 million, $2.0 million and $1.8 million for 2011, 2010, and 2009, respectively. Beginning in 2011, the 401(k) plan also provides an additional company contribution of 3% of annualized base salary for eligible employees who do not qualify for Central Hudson’s Retirement Income Plan. For Griffith, the costs of their matching contributions were $0.5 million for both 2011 and 2010 and $0.9 million for 2009. Profit-sharing contributions made by Griffith were $0.1 million, $0.4 million and $0.6 million for 2011, 2010 and 2009, respectively.
OPEB Estimates of Long-Term Rates of Return
The expected long-term rate of return on OPEB assets is 7.9%, 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, 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
Central Hudson currently funds its union OPEB obligations through a voluntary employee’s beneficiary association (“VEBA”), and funds its management OPEB liabilities through a 401(h) plan. The VEBA and 401(h) plan are both a form of trust fund. Central Hudson’s VEBA investment policy seeks to achieve a rate of return for the VEBA over the long term that contributes to meeting the VEBA’s current and future obligations, including interest and benefit payment obligations. The policy also seeks to earn long-term returns from capital appreciation and current income that at least keep pace with inflation over the long term. Central Hudson’s 401(h) plan is invested with the previously mentioned Retirement Plan’s investments. However, there are no assurances that the OPEB Plan’s return objectives will be achieved.
The asset allocation strategy employed in the VEBA reflects Central Hudson’s return objectives and what Management believes is an acceptable level of short-term volatility in the market value of the VEBA's assets in exchange for potentially higher long-term returns. 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 VEBA’s assets, summarized in the table below:
|
Asset Class
|
December 31, 2010
|
Minimum
|
Target Average
|
Maximum
|
December 31, 2011
|
|||||||||||||||
|
Equity Securities
|
64.4 | % | 55 | % | 65 | % | 75 | % | 60.4 | % | ||||||||||
|
Debt Securities
|
35.5 | % | 25 | % | 35 | % | 35 | % | 38.1 | % | ||||||||||
|
Other
|
0.1 | % | - | % | - | % | - | % | 1.5 | % | ||||||||||
Due to market value fluctuations, the OPEB Plan assets require periodic rebalancing from time-to-time to maintain the target asset allocation.
Management uses outside consultants and outside investment managers to aid in the determination of the OPEB Plan’s asset allocation and to provide the management of actual plan assets, respectively.
OPEB Investment Valuation
The OPEB Plan assets are valued under the current fair value framework. See Note 14 - “Accounting for Derivative and Hedging Activities” for further discussion regarding the definition and levels of fair value hierarchy established by guidance.
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, 2011 and 2010, as well as the associated level within the fair value hierarchy in which the fair value measurements in their entirety fall.
401 (h) Plan Assets
(Dollars in Thousands)
|
Investment Type
|
Market Value at 12/31/11
|
% of Total
|
Market Value at 12/31/10
|
% of Total
|
||||||||||||
|
Level 1
|
|
|
|
|
||||||||||||
|
Cash Equivalents
|
$ | 1 | - | % | $ | - | - | % | ||||||||
|
Level 2
|
||||||||||||||||
|
Investment Funds - Equities(1)
|
4,044 | 35.8 | % | 5,695 | 54.8 | % | ||||||||||
|
Investment Funds - Fixed Income(1)
|
6,149 | 54.4 | % | 4,575 | 44.0 | % | ||||||||||
|
Cash Equivalents(2)
|
97 | 0.9 | % | 46 | 0.5 | % | ||||||||||
| Receivable for Securities Sold(2) | 1,057 | 9.4 | % | 129 | 1.2 | % | ||||||||||
| Payable for Securities Purchased(2) | (88 | ) | (0.8 | )% | (64 | ) | (0.6 | )% | ||||||||
| Other Investments | 39 | 0.3 | % | 13 | 0.1 | % | ||||||||||
| $ | 11,299 | 100.0 | % | $ | 10,394 | 100.0 | % | |||||||||
|
(1)
|
Reported at net asset value, which equals redemption price on that date.
|
|
| (2) | Reported at stated value, which approximates fair value on that date. |
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,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Balance at Beginning of Period
|
$ | - | $ | 305 | ||||
|
Unrealized gains
|
- | 6 | ||||||
|
Realized losses
|
- | 3 | ||||||
|
Purchases, issuances, sales and settlements
|
- | (3 | ) | |||||
|
Transfers in and/or out of Level 3
|
- | (311 | ) | |||||
|
Balance at End of Period
|
$ | - | $ | - | ||||
Management VEBA Plan Assets(1)
(Dollars In Thousands)
|
Investment Type
|
|
Market Value at 12/31/11
|
|
% of Total
|
|
Market Value at 12/31/10
|
|
% of Total
|
||
|
Level 1
|
|
|
|
|
|
|
|
|
|
|
|
Investment Funds - Money Market Mutual Fund
|
|
$
|
-
|
|
- %
|
|
$
|
3
|
|
2.9%
|
|
Investment Funds - Fixed Income Mutual Funds
|
|
|
-
|
|
- %
|
|
|
34
|
|
33.0%
|
|
Investment Funds - Equity Securities Mutual Funds
|
|
|
-
|
|
- %
|
|
|
46
|
|
44.7%
|
|
Level 2(2)
|
|
|
|
|
|
|
|
|
|
|
|
Investment Funds - Equity Securities Commingled Fund
|
|
|
-
|
|
- %
|
|
|
20
|
|
19.4%
|
|
|
$
|
-
|
|
- %
|
|
$
|
103
|
|
100.0%
|
|
|
(1)
|
The Management VEBA account was terminated in 2011. Plan assets are now funded through a Management 401(h) plan.
|
Union VEBA Plan Assets
(Dollars In Thousands)
|
Investment Type
|
|
Market Value at 12/31/11
|
|
% of Total
|
|
Market Value at 12/31/10
|
|
% of Total
|
||
|
Level 1
|
|
|
|
|
|
|
|
|
|
|
|
Investment Funds - Money Market Mutual Fund
|
|
$
|
191
|
|
0.2%
|
|
$
|
210
|
|
0.3%
|
|
Investment Funds - Fixed Income Mutual Funds
|
|
|
16,996
|
|
21.9%
|
|
|
16,241
|
|
20.2%
|
|
Investment Funds - Equity Securities Mutual Funds
|
|
|
34,487
|
|
44.4%
|
|
|
36,362
|
|
45.1%
|
|
Level 2(2)
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Income Commingled Fund
|
|
|
10,757
|
|
13.9%
|
|
|
11,461
|
|
14.2%
|
|
Investment Funds - Equity Securities Commingled Fund
|
|
|
15,214
|
|
19.6%
|
|
|
16,317
|
|
20.2%
|
|
|
$
|
77,645
|
|
100.0%
|
|
$
|
80,591
|
|
100.0%
|
|
|
(2)
|
The Level 2 funds do not have market data available; however, the underlying securities held by those funds do have published market data available.
|
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
|
||||||||||||||
|
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
|
Change in Benefit Obligation:
|
|
|
|
|
||||||||||||
|
Benefit obligation at beginning of year
|
$ | 500,160 | $ | 467,235 | $ | 136,455 | $ | 127,094 | ||||||||
|
Service cost
|
9,794 | 9,086 | 2,576 | 2,483 | ||||||||||||
|
Interest cost
|
26,147 | 26,283 | 6,649 | 6,990 | ||||||||||||
|
Participant contributions
|
- | - | 585 | 550 | ||||||||||||
|
Benefits paid
|
(29,190 | ) | (26,399 | ) | (6,437 | ) | (6,345 | ) | ||||||||
|
Actuarial loss
|
47,779 | 23,955 | 2,171 | 5,683 | ||||||||||||
|
Benefit Obligation at End of Plan Year
|
$ | 554,690 | $ | 500,160 | $ | 141,999 | $ | 136,455 | ||||||||
|
Change in Plan Assets:
|
||||||||||||||||
|
Fair Value of plan assets at beginning of year
|
$ | 396,933 | $ | 314,252 | $ | 91,088 | $ | 80,853 | ||||||||
|
Actual return on plan assets
|
33,807 | 46,110 | 2,633 | 11,341 | ||||||||||||
|
Employer contributions
|
32,699 | 64,800 | 1,184 | 4,800 | ||||||||||||
|
Participant contributions
|
- | - | 585 | 550 | ||||||||||||
|
Benefits paid
|
(29,190 | ) | (26,399 | ) | (6,437 | ) | (6,345 | ) | ||||||||
|
Administrative expenses
|
(2,121 | ) | (1,830 | ) | (109 | ) | (111 | ) | ||||||||
|
Fair Value of Plan Assets at End of Plan Year
|
$ | 432,128 | $ | 396,933 | $ | 88,944 | $ | 91,088 | ||||||||
|
Reconciliation of Funded Status:
|
||||||||||||||||
|
Funded Status at end of year
|
$ | (122,562 | ) | $ | (103,227 | ) | $ | (53,055 | ) | $ | (45,367 | ) | ||||
|
Amounts Recognized on Balance Sheet:
|
||||||||||||||||
|
Current liabilities
|
$ | (651 | ) | $ | (672 | ) | $ | - | $ | - | ||||||
|
Noncurrent liabilities
|
(121,911 | ) | (102,555 | ) | (53,055 | ) | (45,367 | ) | ||||||||
|
Net amount recognized on Balance Sheet
|
(122,562 | ) | (103,227 | ) | (53,055 | ) | (45,367 | ) | ||||||||
|
Regulatory asset:
|
||||||||||||||||
|
Net loss
|
144,588 | 127,146 | 29,819 | 32,504 | ||||||||||||
|
Prior service costs (credit)
|
8,244 | 10,388 | (39,639 | ) | (45,504 | ) | ||||||||||
|
Transition obligation
|
- | - | 2,553 | 5,119 | ||||||||||||
|
Components of Net Periodic Benefit Cost:
|
||||||||||||||||
|
Service cost
|
$ | 9,794 | $ | 9,086 | $ | 2,576 | $ | 2,483 | ||||||||
|
Interest cost
|
26,147 | 26,283 | 6,649 | 6,990 | ||||||||||||
|
Expected return on plan assets
|
(27,441 | ) | (24,901 | ) | (6,938 | ) | (6,368 | ) | ||||||||
|
Amortization of prior service cost (credit)
|
2,144 | 2,177 | (5,866 | ) | (5,868 | ) | ||||||||||
|
Amortization of transitional obligation
|
- | - | 2,566 | 2,566 | ||||||||||||
|
Amortization of actuarial net loss
|
26,093 | 29,509 | 9,306 | 10,278 | ||||||||||||
|
Net Periodic Benefit Cost
|
$ | 36,737 | $ | 42,154 | $ | 8,293 | $ | 10,081 | ||||||||
|
|
Pension Benefits
|
Other Benefits
|
||||||||||||||
|
|
2011
|
2010
|
2011
|
2010
|
||||||||||||
|
Other Changes in Plan Assets and Benefit Obligation Recognized in Regulatory Assets:
|
|
|
|
|
||||||||||||
|
Net loss
|
$ | 43,535 | $ | 4,576 | $ | 6,621 | $ | 296 | ||||||||
|
Amortization of actuarial net loss
|
(26,093 | ) | (29,509 | ) | (9,306 | ) | (10,278 | ) | ||||||||
|
Amortization of prior service (cost) credit
|
(2,144 | ) | (2,177 | ) | 5,866 | 5,868 | ||||||||||
|
Amortization of transitional obligation
|
- | - | (2,566 | ) | (2,566 | ) | ||||||||||
|
Total recognized in regulatory asset
|
$ | 15,298 | $ | (27,110 | ) | $ | 615 | $ | (6,680 | ) | ||||||
|
|
||||||||||||||||
|
Total recognized in net periodic benefit cost and regulatory asset
|
$ | 52,035 | $ | 15,044 | $ | 8,908 | $ | 3,401 | ||||||||
|
|
||||||||||||||||
|
Weighted-average assumptions used to determine benefit obligations:
|
||||||||||||||||
|
Discount rate
|
4.50 | % | 5.30 | % | 4.50 | % | 5.20 | % | ||||||||
|
Rate of compensation increase (average)
|
5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | ||||||||
|
Measurement date
|
12/31/11
|
12/31/10
|
12/31/11
|
12/31/10
|
||||||||||||
|
Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31:
|
||||||||||||||||
|
Discount rate
|
5.30 | % | 5.70 | % | 5.20 | % | 5.70 | % | ||||||||
|
Expected long-term rate of return on plan assets
|
7.00 | % | 7.75 | % | 7.90 | % | 8.00 | % | ||||||||
|
Rate of compensation increase (average)
|
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 | 8.04 | % | 8.31 | % | ||||||||||
|
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)
|
N/A | N/A | 4.50 | % | 4.50 | % | ||||||||||
|
Year that the rate reaches the ultimate trend rate
|
N/A | N/A | 2029 | 2029 | ||||||||||||
|
|
||||||||||||||||
|
Pension plans with accumulated benefit obligations in excess of plan assets:
|
||||||||||||||||
|
Projected benefit obligation
|
$ | 554,690 | $ | 500,160 | N/A | N/A | ||||||||||
|
Accumulated benefit obligation
|
$ | 502,404 | $ | 455,263 | N/A | N/A | ||||||||||
|
Fair Value of plan assets
|
$ | 432,128 | $ | 396,933 | N/A | N/A | ||||||||||
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 $23.2 million and $2.0 million, respectively. The estimated net loss, prior service 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 $8.2 million, $5.9 million and $2.5 million, 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 2011
|
$ | 491 | $ | (422 | ) | |||
|
Effect on year-end 2011 post-retirement benefit obligation
|
$ | 4,471 | $ | (3,931 | ) | |||
Central Hudson’s contributions for OPEB totaled $1.2 million and $4.8 million during the years ended December 31, 2011 and 2010. 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, corporate resources and regulatory considerations.
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)
|
|||
|
2012
|
|
$
|
30,039
|
|
$
|
7,617
|
|
$
|
7,007
|
|
2013
|
|
|
29,857
|
|
|
7,910
|
|
|
7,263
|
|
2014
|
|
|
29,995
|
|
|
8,334
|
|
|
7,657
|
|
2015
|
|
|
30,424
|
|
|
8,690
|
|
|
7,981
|
|
2016
|
|
|
30,914
|
|
|
9,039
|
|
|
8,299
|
|
2017 - 2021
|
|
|
167,302
|
|
|
49,157
|
|
|
44,975
|
|
(1) Estimated benefit payments reduced by estimated gross amount of Medicare Act of 2003 subsidy receipts expected.
|
CH Energy Group’s Long-Term Performance-Based Incentive Plan (“2000 Plan”), adopted in 2000 and amended in 2001 and 2003, reserved 500,000 shares of CH Energy Group’s Common Stock for awards to be granted under the 2000 Plan.
In 2006, CH Energy Group adopted a Long-Term Equity Incentive Plan (“2006 Plan”) to replace the 2000 Plan and the 2000 Plan was terminated, with no new awards to be granted under such plan. Outstanding stock option awards granted under the 2000 Plan continue in accordance with their terms and the provisions of the 2000 Plan. The 2006 Plan reserved up to a maximum of 300,000 shares of CH Energy Group’s Common Stock for awards to be granted under the 2006 Plan.
In 2011, CH Energy Group adopted the 2011 Long-Term Equity Incentive Plan (the “2011 Plan”) to replace the 2006 Plan. The 2011 Plan was approved by shareholders on April 26, 2011. The 2006 Plan has been terminated, with no new awards to be granted under such plan. Outstanding awards granted under the 2006 Plan will continue in accordance with their terms and the provisions of the 2006 Plan.
The 2011 Plan reserves for awards to be granted up to a maximum of 400,000 shares of Common Stock plus any shares remaining available under the 2006 Plan as of April 26, 2011 and any shares that are subject to awards granted under the 2006 Plan that are forfeited, cancelled, surrendered or otherwise terminated without the issuance of shares on or after that date. Awards may consist of incentive stock options, nonqualified stock options, stock appreciation rights, restricted shares, restricted share units, performance shares, dividend equivalents and other awards that CH Energy Group’s Compensation Committee of its Board of Directors (“Compensation Committee”) may authorize. The 2011 Plan contains a provision which continues to allow executives to defer receipt of performance shares and performance units and active Directors to defer fees or shares payable to them in accordance with the terms of CH Energy Group’s Directors and Executives Deferred Compensation Plan. The 2011 Plan will continue in effect until February 9, 2021, unless sooner terminated by the Board of Directors. Termination will not affect grants and awards then outstanding.
As of December 31, 2011, 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
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 following table summarizes information concerning stock options outstanding as of December 31, 2011:
|
|
|
|
|
|
|
|
|
|
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, 2003
|
|
$
|
48.62
|
|
36,900
|
|
12,840
|
|
1.00
|
|
12,840
|
|
|
|
|
|
|
36,900
|
|
12,840
|
|
1.00
|
|
12,840
|
A summary of the current year activity of stock options awarded to executives and non-employee Directors of CH Energy Group and its subsidiaries under the 2000 Plan is as follows:
|
|
|
|
Stock Option Shares
|
|
Weighted Average Exercise Price
|
|
Weighted Average Remaining Life in Years
|
|
|
Outstanding at 12/31/10
|
|
16,620
|
|
$
|
48.62
|
|
2.00
|
|
|
|
Granted
|
|
-
|
|
|
-
|
|
|
|
|
Exercised
|
|
3,780
|
|
|
48.62
|
|
|
|
|
Expired / Forfeited
|
|
-
|
|
|
-
|
|
|
|
Outstanding at 12/31/11
|
|
12,840
|
|
$
|
48.62
|
|
1.00
|
|
|
|
|
|
|
|
|
|
|
|
|
Total CH Energy Group Shares Outstanding
|
|
|
14,894,964
|
|
|
|||
|
Potential Dilution
|
|
|
0.1%
|
|
|
|||
The balance accrued for outstanding options was $0.1 million as of December 31, 2011 and 2010. The intrinsic value of outstanding options was $0.1 million as of December 31, 2011 and not material as of December 31, 2010.
Performance Shares
A summary of the status of outstanding 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, 2011
|
|
|
January 26, 2009
|
|
$
|
49.29
|
|
36,730
|
|
28,060
|
|
February 8, 2010
|
|
$
|
38.62
|
|
48,740
|
|
43,220
|
|
February 7, 2011
|
|
$
|
49.77
|
|
40,320
|
|
40,320
|
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. Participants may elect to defer receipt of shares earned in accordance with terms and subject to conditions of the Directors and Executives Deferred Compensation Plan. Ultimate payouts from the Directors and Executives Deferred Compensation Plan are made in the form of cash. Accordingly, these awards are classified as liabilities and are adjusted to fair value as of the end of each reporting period.
In May 2011, performance shares earned as of December 31, 2010 for the award cycle with a grant date of January 24, 2008 were issued to participants through purchases of CH Energy Group Common Stock on the open market totaling 6,984 shares. Additionally, due to the retirement of one of Central Hudson’s executive officers on January 1, 2011, a pro-rated number of shares under the January 26, 2009 and February 8, 2010 grants were paid to this individual on July 6, 2011. For the pro-rata payout, 2,374 shares were issued from CH Energy Group’s treasury stock on this date in satisfaction of these awards.
Restricted Shares and Restricted Stock Units
The following table summarizes information concerning restricted shares and stock units outstanding as of December 31, 2011:
|
Grant Date
|
|
Type of Award
|
|
Shares or
Stock Units Granted
|
|
Grant Date
Fair Value
|
|
Vesting Terms
|
|
Unvested Shares
Outstanding at December 31, 2011
|
||
|
January 26, 2009
|
|
Shares
|
|
2,930
|
|
$
|
49.29
|
|
End of 3 years
|
|
2,320
|
(1)
|
|
October 1, 2009
|
|
Shares
|
|
14,375
|
|
$
|
43.86
|
|
Ratably over 5 years
|
|
8,625
|
|
|
November 20, 2009
|
|
Stock
Units
|
|
13,900
|
|
$
|
41.43
|
|
1/3 each year in
Years 5, 6 and 7
|
|
13,900
|
|
|
February 8, 2010
|
|
Shares
|
|
3,060
|
|
$
|
38.62
|
|
End of 3 years
|
|
2,655
|
(2)
|
|
February 10, 2010
|
|
Shares
|
|
5,200
|
|
$
|
38.89
|
|
End of 3 years
|
|
5,200
|
|
|
November 15, 2010
|
|
Shares
|
|
3,000
|
|
$
|
46.53
|
|
Ratably over 3 years
|
|
2,000
|
|
|
February 7, 2011
|
|
Shares
|
|
1,500
|
|
$
|
49.77
|
|
1/3 each year in Years 3, 4 and 5
|
|
1,500
|
|
|
February 7, 2011
|
|
Shares
|
|
2,230
|
|
$
|
49.77
|
|
End of 3 years
|
|
2,230
|
|
|
(1)
|
The vesting of 250 shares was accelerated upon a change in control for an individual resulting from the sale of certain assets of Griffith and the vesting of 360 shares was accelerated as approved by the Board of Directors.
|
|
(2)
|
The vesting of 405 shares was accelerated as approved by the Board of Directors.
|
The above shares granted were issued from CH Energy Group’s treasury or purchased on the open market. The fair value of restricted shares represents the closing price of the Company’s stock on the date of grant. Shares will not be issued with respect to restricted stock units until a specified future date defined within the individual agreement.
In accordance with current accounting guidance related to equity based compensation, unvested restricted shares do not impact the number of common shares outstanding used in the basic EPS calculation. The total unvested outstanding restricted shares and stock units noted above have been included in the diluted EPS calculation for the year ended December 31, 2011, 2010 and 2009.
Compensation Expense
The following table summarizes expense for equity-based compensation by award type for the years ended December 31, 2011, 2010 and 2009 (In Thousands):
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Performance shares
|
$ | 3,545 | $ | 2,217 | $ | 1,088 | ||||||
|
Restricted shares and stock units
|
$ | 459 | $ | 543 | $ | 223 | ||||||
|
Recognized tax benefit of restricted shares and stock units
|
$ | 170 | $ | 203 | $ | 89 | ||||||
Compensation expense for performance shares is recognized over the three year performance period based on the fair value of the awards at the end of each reporting period and the time elapsed within each grant's performance period. Commencing in 2009, CH Energy Group ceased using a binomial model. The fair value of performance shares is currently determined based on the shares' current market value at the end of each reporting period, estimated forfeitures for each grant, and expected payout based on Management's best estimate including analysis of historical performance in accordance with the defined metrics of each grant. 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.
Compensation expense for restricted shares and stock options is recognized over the defined vesting periods based on the grant date fair value of the awards. Stock option expense recognized over the years ended December 31, 2011, 2010 and 2009 was not material.
Deferred Stock Units
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 deferred stock units of CH Energy Group Common Stock. These stock units 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 deferred stock units). 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 deferred stock units. 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, 2011, the annual equity compensation for each non-employee Director was the equivalent of $65,000. Effective July 1, 2011, this compensation was increased to $70,000 per year. Total equity compensation expense to non-employee Directors recognized by CH Energy Group was $0.5 million for the years ended December 31, 2011, 2010 and 2009.
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 requirement 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 9% 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 began with Constellation, which provides Central Hudson with a hedge against electricity price increases and could provide additional future revenue for Central Hudson through 2021. This revenue, if any, will accrue to the benefit of Central Hudson’s customers. 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 2011 was sufficient to supply approximately 13% of Central Hudson’s total system requirements and cost approximately $25.9 million. For the years 2010 and 2009, the energy supplied under this agreement cost approximately $25.9 million and $27.9 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. During this period, the electricity purchased through this Entergy contract represented approximately 23% of Central Hudson’s full-service customer requirements on an annual basis. For the twelve months ended December 31, 2010, energy supplied under this agreement cost approximately $56.1 million. On June 30, 2010 and September 9, 2010, Central Hudson entered into additional agreements with Entergy Nuclear Power Marketing, LLC to purchase electricity on a unit-contingent basis at defined prices from January 1, 2011 through December 31, 2013. The electricity purchased under these current contracts with Entergy is generated from the Indian Point nuclear power facility and is estimated to represent approximately 13% of Central Hudson’s full-service customer requirements on an annual basis. For the twelve months ended December 31, 2011, energy supplied under this agreement cost approximately $20.1 million.
In the event the above noted counterparty is unable to fulfill its commitment 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 contracts with capacity providers, purchases from the NYISO capacity market and its own generating capacity.
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 $2.4 million in 2011, $2.7 million in 2010 and $2.8 million in 2009.
Operating lease rental payment amounts charged to expense by Central Hudson were $1.7 million in 2011, $1.7 million in 2010 and $1.5 million 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, 2011 (In Thousands):
|
Projected Payments Due By Period
|
||||||||||||||||||||||||||||
|
Less than
1 year
|
Year
Ending
2013
|
Year
Ending
2014
|
Year
Ending
2015
|
Year
Ending
2016
|
Thereafter
|
Total
|
||||||||||||||||||||||
|
Operating Leases
|
$ | 2,237 | $ | 2,040 | $ | 1,915 | $ | 1,913 | $ | 1,754 | $ | 2,918 | $ | 12,777 | ||||||||||||||
|
Construction/Maintenance & Other Projects(1)
|
34,883 | 32,668 | 17,004 | 12,520 | 4,832 | 4,604 | 106,511 | |||||||||||||||||||||
|
Purchased Electric Contracts(2)
|
28,104 | 27,391 | 5,894 | 3,119 | 3,119 | 12,237 | 79,864 | |||||||||||||||||||||
|
Purchased Natural Gas Contracts(2)
|
29,446 | 18,023 | 15,891 | 10,489 | 10,230 | 28,411 | 112,490 | |||||||||||||||||||||
|
Purchased Fixed Liquid Petroleum Contracts(3)
|
1,259 | - | - | - | - | - | 1,259 | |||||||||||||||||||||
|
Purchased Variable Liquid Petroleum Contracts(3)
|
60,365 | - | - | - | - | - | 60,365 | |||||||||||||||||||||
|
Total
|
$ | 156,294 | $ | 80,122 | $ | 40,704 | $ | 28,041 | $ | 19,935 | $ | 48,170 | $ | 373,266 | ||||||||||||||
|
(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, 2011.
|
The following is a summary of commitments for Central Hudson as of December 31, 2011 (In Thousands):
|
Projected Payments Due By Period
|
||||||||||||||||||||||||||||
|
Less than
1 year
|
Year
Ending
2013
|
Year
Ending
2014
|
Year
Ending
2015
|
Year
Ending
2016
|
Thereafter
|
Total
|
||||||||||||||||||||||
|
Operating Leases
|
$ | 1,500 | $ | 1,487 | $ | 1,474 | $ | 1,461 | $ | 1,459 | $ | 2,918 | $ | 10,299 | ||||||||||||||
|
Construction/Maintenance & Other Projects(1)
|
34,883 | 32,668 | 17,004 | 12,520 | 4,832 | 4,604 | 106,511 | |||||||||||||||||||||
|
Purchased Electric Contracts(2)
|
28,104 | 27,391 | 5,894 | 3,119 | 3,119 | 12,237 | 79,864 | |||||||||||||||||||||
|
Purchased Natural Gas Contracts(2)
|
29,446 | 18,023 | 15,891 | 10,489 | 10,230 | 28,411 | 112,490 | |||||||||||||||||||||
|
Total
|
$ | 93,933 | $ | 79,569 | $ | 40,263 | $ | 27,589 | $ | 19,640 | $ | 48,170 | $ | 309,164 | ||||||||||||||
|
(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, corporate resources 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 funded percentage at 80% or higher. Central Hudson’s contributions for 2012 are expected to total approximately $28 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.
Environmental Matters
Central Hudson
|
·
|
Air
|
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. Central Hudson sold the Danskammer Plant on January 30, 2001. 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. While Central Hudson could have retained liability after the sale, depending on the type of remedy, Central Hudson believes that the statutes of limitation relating to any alleged violation of air emissions rules have lapsed.
|
·
|
Former Manufactured Gas Plant Facilities
|
Central Hudson and its predecessors owned and operated manufactured gas plants (“MGPs”) to serve their customers’ heating and lighting needs. These plants manufactured gas from coal and oil beginning in the mid to late 1800's with all sites ceasing operations by the 1950's. 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 7 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 all seven of these sites on the New York State Environmental Site Remediation Database. As authorized by the PSC, Central Hudson is currently 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.
MGP site investigation and remediation can be divided into various stages of completion based on the milestones of activities completed and reports reviewed. These stages include:
|
·
|
Investigation – Begins with preliminary investigations and is completed upon filing and approval by DEC of a Remedial Investigation (“RI”) Report.
|
|
·
|
Remedial Alternative Analysis – Engineering analysis of alternatives for remediation based on the RI is compiled into a Remedial Alternative Analysis (“RAA”) Report.
|
|
·
|
Remedial Design - Upon approval of the RAA and final decision of remediation approach based on alternatives presented, a Remedial Design (“RD”) is developed and filed with the DEC for approval.
|
|
·
|
Remediation – Completion of the work plan as defined in the approved RD. Upon completion, final reports are filed with the DEC for approval and may include a Construction Completion Report (“CCR”), Final Engineering Report (“FER”), or other reports required by the DEC based on the work performed.
|
|
·
|
Post-Remediation Monitoring – Entails the operation, maintenance, and monitoring (“OM&M”) as directed by the DEC based on the approved final report of remediation. The activities are typically defined in a Site Management Plan (“SMP”), which is approved by the DEC. The extent of activities during this phase may increase or decrease based on the results of on-going monitoring being performed and future potential usage of the property.
|
Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated at a point in time. Central Hudson has only accrued for estimated investigation costs, remediation alternative analysis, and remedial design costs for those sites still in the investigation phase. Upon completion of the RAA and the filing with the DEC, Management accrues for an estimate of remediation costs developed and quantified in the RAA based on DEC approved methods, as well as an estimate of post-remediation operation, maintenance and monitoring costs. These amounts represent a significant portion of the total costs to remediate. These estimates are subject to change based on further 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 status of the seven MGP sites, for which the DEC has put Central Hudson or its predecessors on notice, are as follows:
|
·
|
Site #1 – Beacon (NY) – Post-Remediation Monitoring Complete
|
|
§
|
SMP submitted to DEC and release letter for the site expected.
|
|
§
|
No further costs expected and no amounts accrued as of December 31, 2011 related to this site.
|
|
§
|
If the building at this site were to be removed, further investigation and testing would be required related to the soil under the building, which may require additional remediation. Management cannot currently estimate the costs that may be incurred related to this.
|
|
·
|
Site #2 – Newburgh (NY) – Post-Remediation In Progress
|
|
§
|
DEC to provide comments on CCR.
|
|
§
|
As of December 31, 2011, amounts accrued represent an estimate of costs for OM&M and execution of the draft SMP.
|
|
§
|
Central Hudson is retiring and removing propane air facilities located on Area A. Once removed, additional investigation and testing will be required, which may require additional remediation. Management cannot currently estimate the costs that may be incurred related to this additional investigation and testing.
|
|
·
|
Site #3 – Laurel Street (Poughkeepsie, NY) – Post-Remediation In Progress
|
|
§
|
CCR approved by the DEC in 2010.
|
|
§
|
As of December 31, 2011, amounts accrued represent an estimate of costs for OM&M.
|
|
·
|
Site #4 – Catskill (NY) – Remedial Design in Progress
|
|
§
|
RAA Report approved by the DEC in July 2011 and Remedial Design is in progress.
|
|
§
|
As of December 31, 2011, amounts accrued represent an estimate of costs to complete the RD, remediation, and OM&M.
|
|
·
|
Site #5 – North Water Street (Poughkeepsie, NY) – RAA in progress
|
|
§
|
RI report approved by the DEC.
|
|
§
|
Further investigation and analysis being performed in connection with the development of the RAA.
|
|
§
|
Upon approval of the RAA, the RD will be completed, followed by remediation.
|
|
§
|
As of December 31, 2011, amounts accrued represent an estimate for completion of the RAA and RD. Management cannot estimate the cost for physical remediation or any post-remediation until the RAA is complete.
|
|
·
|
Site #6 – Kingston (NY) – Investigation in Progress
|
|
§
|
Continuing RI at this site.
|
|
§
|
Upon completion of RI, RAA and RD will be developed, followed by remediation.
|
|
§
|
As of December 31, 2011, amounts accrued represent an estimate of costs to complete the RI, RAA and the RD. Management cannot estimate the cost for physical remediation or any post-remediation until the RAA is complete.
|
|
·
|
Site #7 – Bayeaux Street (Poughkeepsie, NY) – No action required
|
|
§
|
No further investigation or remedial action is currently required. However, per the DEC this site still remains on the list for potential future investigation.
|
A summary of information for sites #1 through #6 are detailed in the chart below (In Thousands):
|
Site #
|
Liability Recorded as of 12/31/10
|
Amounts Spent in 2011(1)
|
Liability Adjustment
|
Liability Recorded as of 12/31/11
|
Current Portion of Liability at 12/31/11
|
Long-Term Portion of Liability at 12/31/11
|
||||||||||||||||||||
| 1, 2, 3, 4 | $ | 2,071 | $ | 1,019 | $ | 13,538 | $ | 14,590 | $ | 5,319 | $ | 9,271 | ||||||||||||||
| 5, 6 | 1,174 | 332 | 411 | 1,253 | 798 | 455 | ||||||||||||||||||||
| $ | 3,245 | $ | 1,351 | $ | 13,949 | $ | 15,843 | $ | 6,117 | $ | 9,726 | |||||||||||||||
|
(1)
|
Amounts spent in 2011 as shown above do not include legal fees of approximately $12 thousand.
|
Sites #1 through #4 include estimates for costs through remediation and post-remediation monitoring as these sites are within stages where estimates have been developed for these activities. Sites #5 and #6 include estimates based on the latest forecast of activities at these sites in connection with preliminary investigations, site testing and development of remediation alternative analysis and remedial design only for these sites. No amounts have been recorded in connection with physical remediation or post-remediation monitoring for sites #5 and #6, and these amounts will likely represent the significant portion of the total cost to remediate and monitor post-remediation. Prior to the completion of the RAA, Management cannot reasonably estimate what cost, if any, will be incurred for remediation or post-remediation activities.
Based on a cost model analysis completed in 2008 of possible remediation and future operating, maintenance, and monitoring costs for sites #2 through #6, Central Hudson believes there is a 90% confidence level that the total costs to remediate these sites will not likely exceed $165.7 million over the next 30 years. The cost model involves assumptions relating to investigation expenses, results of investigations, 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. The cost model also assumes that proposed or anticipated remediation techniques are technically feasible and that proposed remediation plans receive DEC and NYSDOH approval.
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.
Central Hudson expects to recover its remediation costs from its customers. The current components of this recovery include:
|
§
|
Current Rate Order includes recovery from customers of $13.6 million over the three year settlement period ending June 30, 2013.
|
|
§
|
As part of the 2010 Rate Order, Central Hudson maintained previously granted deferral authority and subsequent recovery for amounts spent over the rate allowance.
|
|
§
|
Total MGP Site Investigation and Remediation costs recovered through rates and other regulatory mechanisms from July 1, 2007 through December 31, 2011 was approximately $19.8 million, with $4.5 million recovered in the twelve months ended December 31, 2011.
|
|
§
|
The total spent in 2011 related to site investigation and remediation was approximately $1.5 million.
|
|
§
|
The regulatory asset balance as of December 31, 2011 was $18.8 million, which represents the difference between amounts spent or currently accrued as a liability and the amounts recovered through rate allowance.
|
|
§
|
Upon completion of investigation at sites #5 and #6, when remediation and post-remediation costs will be able to be reasonably estimated and therefore will be recorded as a liability, this regulatory asset balance will likely increase significantly. Management projects that the investigation at these sites will likely be completed within the next two years.
|
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. In addition to the rate allowance amounts noted above, Central Hudson recovered approximately $1.6 million from insurance, with $1.4 million recovered in 2011. However, we do not expect insurance recoveries to offset a meaningful portion of total costs.
|
·
|
Little Britain Road property owned by Central Hudson
|
In 2000, 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 the 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; in addition, in 2008, it also installed an indoor air vapor mitigation system (that continues to operate).
In September 2010, NYSDEC personnel orally advised that Central Hudson would likely receive a letter from the NYSDEC proposing closure of the VCA, and inclusion of the site into the Brownfield Cleanup Program (“BCP”). To date that letter has not been received.
At the October 2011 annual MGP meeting, DEC lead a discussion on the Little Britain Road site. DEC requested a ‘non-committal’ meeting with Central Hudson to discuss the site and possible next steps. Central Hudson did report that a sub-slab depressurization system was installed in 2008. It was agreed that Central Hudson would provide the documentation of this depressurization system, along with the most recent ground-water sampling results. The requested information was submitted to DEC under a November 8, 2011 cover letter. A meeting date has yet to be established.
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.
|
·
|
Eltings Corners
|
Central Hudson owns and operates a maintenance and warehouse facility located in Lloyd, NY. In the course of Central Hudson’s recent hazardous waste permit renewal process for this facility, sediment contamination was discovered within the wetland area across the street from the main property. In cooperation with NYSDEC, Central Hudson continues to investigate the nature and extent of the contamination. The extent of the contamination, as well as the timing and costs for continued investigation and future remediation efforts, cannot be reasonably estimated at this time.
|
·
|
Asbestos Litigation
|
Since 1987, Central Hudson, along with many other parties, has been joined as a defendant or third-party defendant in 3,330 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, 2011, of the 3,330 asbestos cases brought against Central Hudson, 1,158 remain pending. Of the cases no longer pending against Central Hudson, 2,017 have been dismissed or discontinued without payment by Central Hudson, and Central Hudson has settled 155 cases. Central Hudson is presently unable to assess the validity of the remaining asbestos lawsuits; however, 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 year ended December 31, 2011, Griffith spent $0.8 million on remediation efforts in Maryland, Virginia and Connecticut.
Griffith’s reserve for environmental remediation is $1.8 million as of December 31, 2011, of which $0.5 million is expected to be spent in the next twelve months.
In connection with the 2009 sale of operations in certain geographic locations, Griffith agreed to indemnify the purchaser for certain claims, losses and expenses arising out of any breach by Griffith of the representations, warranties and covenants Griffith made in the sale agreement, certain environmental matters and all liabilities retained by Griffith. Griffith’s indemnification obligation is subject to a number of limitations, including a five-year limitation within which certain claims must be brought, an aggregate deductible of $0.8 million applicable to certain types of non-environmental claims and other deductibles applicable to certain specific environmental claims, and caps on Griffith’s liability with respect to certain of the indemnification obligations. The sale agreement includes an aggregate cap of $5.7 million on Griffith’s obligation to indemnify the purchaser for breaches of many of Griffith’s representations and warranties and for certain environmental liabilities. In 2009, the Company reserved $2.6 million for environmental remediation costs it may be obligated to pay based on its indemnification obligations under the sale agreement. To date, Griffith has paid approximately $0.9 million under its environmental remediation cost obligation. In the first quarter of 2011, Griffith reduced the reserve by $0.6 million based on the completion of an environmental study. The balance as of December 31, 2011 related to the divestiture is $1.1 million. Management believes this is the most likely amount Griffith would pay with respect to its indemnification obligations under the sale agreement.
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, based on the facts currently known, 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.
CH Energy Group and Central Hudson expense legal costs as incurred.
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 CHEC’s renewable energy investments and the holding company’s activities, which consist primarily of financing its subsidiaries, 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 and Central Hudson’s property common to both electric and natural gas segments have been allocated in accordance with practices established for regulatory purposes.
In the following segment charts for CH Energy Group, information related to Griffith and Other Businesses and Investments represents continuing operations unless otherwise noted.
CH Energy Group Segment Disclosure
(In Thousands)
| Year Ended December 31, 2011 | |||||||||||||||||||||||
| Segments | Other | ||||||||||||||||||||||
| Central Hudson | Businesses | ||||||||||||||||||||||
| Natural | and | ||||||||||||||||||||||
| Electric | Gas | Griffith | Investments | Eliminations | Total | ||||||||||||||||||
|
Revenues from external customers
|
$ | 538,548 | $ | 161,974 | $ | 284,998 | $ | - | $ | - | $ | 985,520 | |||||||||||
|
Intersegment revenues
|
15 | 392 | - | - | (407 | ) | - | ||||||||||||||||
|
Total revenues
|
538,563 | 162,366 | 284,998 | - | (407 | ) | 985,520 | ||||||||||||||||
|
Depreciation and amortization
|
27,832 | 7,643 | 4,580 | - | - | 40,055 | |||||||||||||||||
|
Operating income
|
73,206 | 22,320 | 4,656 | (593 | ) | - | 99,589 | ||||||||||||||||
|
Interest and investment income
|
4,355 | 1,384 | - | 2,663 | (2,625 | )(1) | 5,777 | ||||||||||||||||
|
Interest charges
|
23,077 | 6,114 | 2,648 | 5,944 | (2,625 | )(1) | 35,158 | ||||||||||||||||
|
Income (loss) before income taxes
|
55,412 | 17,802 | 2,078 | (8,295 | ) | - | 66,997 | ||||||||||||||||
|
Income tax expense
|
20,714 | 7,463 | 852 | (5,216 | ) | - | 23,813 | ||||||||||||||||
|
Net income (loss) attributable to CH Energy Group
|
33,936 | 10,131 | 1,503 | (3) | (230 | )(2) | - | 45,340 | |||||||||||||||
|
Segment assets at December 31
|
1,238,312 | 364,069 | 109,697 | 18,827 | (793 | ) | 1,730,112 | ||||||||||||||||
|
Goodwill
|
- | - | 37,512 | - | - | 37,512 | |||||||||||||||||
|
Capital expenditures
|
66,650 | 18,510 | 2,385 | 2,867 | (4) | - | 90,412 | ||||||||||||||||
|
(1)
|
This represents the elimination of inter-company interest income (expense) generated from lending activities between CH Energy Group (the holding company), and its subsidiaries (CHEC and Griffith).
|
||||||||||
|
(2)
|
Includes net income from discontinued operations of $2,849.
|
||||||||||
|
(3)
|
Includes net income from discontinued operations of $277.
|
|
|
|
|
|
|
|
|||
|
(4)
|
Does not include 1603 Grant proceed reimbursements of $1.6 million pertaining to CH-Auburn and $13.2 million pertaining to Shirley Wind.
|
||||||||||
CH Energy Group Segment Disclosure
(In Thousands)
|
|
Year Ended December 31, 2010
|
||||||||||||||||||||||
|
|
Segments
|
Other
|
|
|
|||||||||||||||||||
|
|
Central Hudson
|
|
Businesses
|
|
|
||||||||||||||||||
|
|
|
Natural
|
|
and
|
|
|
|||||||||||||||||
|
Electric
|
Gas
|
Griffith
|
Investments
|
Eliminations
|
Total
|
||||||||||||||||||
|
Revenues from external customers
|
$ | 563,139 | $ | 156,795 | $ | 240,174 | $ | - | $ | - | $ | 960,108 | |||||||||||
|
Intersegment revenues
|
8 | 253 | - | - | (261 | ) | - | ||||||||||||||||
|
Total revenues
|
563,147 | 157,048 | 240,174 | - | (261 | ) | 960,108 | ||||||||||||||||
|
Depreciation and amortization
|
26,480 | 7,335 | 4,460 | - | - | 38,275 | |||||||||||||||||
|
Operating income
|
70,346 | 24,502 | 5,427 | (972 | ) | - | 99,303 | ||||||||||||||||
|
Interest and investment income
|
4,161 | 1,313 | 1 | 2,147 | (2,147 | )(1) | 5,475 | ||||||||||||||||
|
Interest charges
|
20,589 | 5,259 | 2,041 | 3,343 | (2,147 | )(1) | 29,085 | ||||||||||||||||
|
Income (loss) before income taxes
|
52,113 | 20,169 | 2,935 | (15,673 | ) | - | 59,544 | ||||||||||||||||
|
Income tax expense
|
18,244 | 7,920 | 1,161 | (8,111 | ) | - | 19,214 | ||||||||||||||||
|
Net income (loss) attributable to CH Energy Group
|
33,125 | 12,023 | 1,774 | (8,418 | )(2) | - | 38,504 | ||||||||||||||||
|
Segment assets at December 31
|
1,183,455 | 355,619 | 109,347 | 90,209 | (9,355 | )(3) | 1,729,275 | ||||||||||||||||
|
Goodwill
|
- | - | 35,940 | - | - | 35,940 | |||||||||||||||||
|
Capital expenditures
|
57,700 | 17,159 | 1,930 | 30,355 | - | 107,144 | |||||||||||||||||
|
(1)
|
This represents the elimination of inter-company interest income (expense) generated from lending activities between CH Energy Group (the holding company), and its subsidiaries (CHEC and Griffith).
|
|
(2)
|
Includes loss from discontinued operations of $1,128.
|
|
(3)
|
Includes $5,864 related to Federal income tax due to parent company due to an accounting change for tax purposes.
|
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 | $ | 21 | $ | - | $ | 921,557 | ||||||||||||
|
Intersegment revenues
|
12 | 308 | - | - | (320 | ) | - | |||||||||||||||||
|
Total revenues
|
536,182 | 174,445 | 211,229 | 21 | (320 | ) | 921,557 | |||||||||||||||||
|
Depreciation and amortization
|
25,269 | 6,825 | 4,488 | - | - | 36,582 | ||||||||||||||||||
|
Operating income
|
60,289 | 16,049 | 5,587 | (340 | ) | - | 81,585 | |||||||||||||||||
|
Interest and investment income
|
3,303 | 1,727 | 15 | 4,440 | (3,696 | )(1) | 5,789 | |||||||||||||||||
|
Interest charges
|
19,806 | 5,079 | 2,405 | 2,202 | (3,696 | )(1) | 25,796 | |||||||||||||||||
|
Income (loss) before income taxes
|
41,703 | 12,215 | 3,456 | (1,508 | ) | - | 55,866 | |||||||||||||||||
|
Income tax expense
|
15,743 | 5,399 | 1,332 | (205 | ) | - | 22,269 | |||||||||||||||||
|
Net income (loss) attributable to CH Energy Group
|
25,217 | 6,589 | 11,975 | (4) | (297 | )(3) | - | 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 | 22,072 | - | 120,832 | ||||||||||||||||||
|
(1)
|
This represents the elimination of inter-company interest income (expense) generated from 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 $830.
|
|
(4)
|
Includes income from discontinued operations of $9,851.
|
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 reduce the impact of 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 reduce the impact of volatility in the price of heating oil purchased for delivery to its customers. All derivative transactions are associated with commodity purchases and are not used for speculative purposes. CH Energy Group and its subsidiaries derivative activities consist of the following:
|
·
|
Interest rate caps are used to minimize 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 reduce exposure to 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 minimize commodity price volatility for 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 reduce the risk of price fluctuations for natural gas and the impact of volatility in the commodity markets on its customers.
|
|
·
|
Natural gas swaps and contracts for differences (electricity swaps) are used to minimize commodity price volatility for natural gas and electricity purchases for Central Hudson’s full service customers. A swap contract or a contract for differences is the exchange of two payment streams between two counterparties where the cash flows are dependant on the price of the underlying commodity. In an effort to moderate commodity price volatility, Central Hudson enters into contracts to pay a fixed price and receive market price for a defined commodity and volume. These contracts are aligned with Central Hudson’s actual commodity purchases at market price, resulting in a net fixed price payment.
At December 31, 2011, Central Hudson had open derivative contracts related to natural gas purchases during January 2012 - March 2012, for 1.3 million Dth, which covers approximately 36.4% of Central Hudson's projected total natural gas supply requirements during this period. In 2011, derivative transactions covered approximately 35.0% of Central Hudson’s total natural gas supply requirements as compared to 33.8% in 2010.
Additionally, Central Hudson had open derivative contracts related to electricity purchases at December 31, 2011 for 1.5 million MWh, which covers approximately 31.7% of its projected electricity requirements in 2012, 6.9% of its electricity requirements in 2013 and 6.9% of its electricity requirements in 2014. In 2011, OTC derivative contracts covered approximately 26.5% of Central Hudson’s total electricity supply requirements as compared to 28% in 2010.
|
|
·
|
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 covered 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, 2011, Griffith had open OTC call option positions covering approximately 1.8% of its anticipated fuel oil supply requirements for the period January 2012 through May 2012. In 2011, derivative instruments covered 1.5% of total fuel oil requirements as compared to 1.1% in 2010.
|
|
·
|
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.
|
Accounting for Derivatives
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. Additionally, Central Hudson has been authorized to fully recover the interest costs associated with its variable rate debt, which includes costs and gains and losses associated with its interest rate cap contracts. As a result, derivative activity at Central Hudson does not impact earnings.
On March 18, 2011, Central Hudson entered into a total return master swap agreement with Bank of America with the intent to enter into future swap contracts to exchange total returns on CH Energy Group, Inc. common stock for fixed payments to Bank of America. The purpose is to reduce the volatility to earnings from deferred stock units under CH Energy Group’s Directors and Executives Deferred Compensation Plan. The fair value of the swap is computed using Level 2 inputs within the fair value hierarchy. Quarterly valuations are made on the last day of the quarter or following day if it falls on a weekend, at which time a net cash settlement will be recorded. The fair value of this outstanding contract at December 31, 2011 is $0.3 million which is valued as the spread of CH Energy Group Common Stock from the third quarter 2011 valuation date plus expected dividends reduced by the cost of the swap with the counterparty. The valuation date for the fourth quarter settlement was performed on January 3, 2012. The component of fair value related to the forward portion of the contract was not material. During 2011, the swap has resulted in income of approximately $0.4 million. The proceeds will be used to offset future obligations under CH Energy Group’s Directors and Executives Deferred Compensation Plan.
Derivative contracts related to Griffith’s heating oil contracts are not material. In December 2009, Management made a decision that it was no longer cost effective to perform on-going effectiveness testing and documentation to qualify for hedge accounting treatment under current accounting guidance based on the immateriality of the remaining level of derivative contracts. All open derivative positions on this date were de-designated effective October 1, 2009, and hedge accounting treatment was discontinued. Additionally, on December 11, 2009, Griffith entered into a new derivative financial instrument with the purchaser of Griffith’s operations whereas Griffith agreed to pay the counterparty an amount equal to the economic benefit realized upon the settlement of the certain call option contracts held by Griffith and associated with the projected deliveries to the customers purchased. All new contracts purchased on or after October 1, 2009, have been treated as derivatives not accounted for as hedges.
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.
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 19 total agreements held by both companies, 12 contain credit-risk related contingent features. As of December 31, 2011, there were 37 open derivative contracts under these 12 master netting agreements containing credit-risk related contingent features, of which 27 contracts were in a liability position. 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, 2011 if the contingent features were triggered, are described below.
Contingent Contracts
(Dollars In Thousands)
|
As of December 31, 2011
|
||||||||||||
|
Triggering Event
|
# of Contracts in a Liability Position 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%)
|
4 | $ | (349 | ) | $ | (349 | ) | |||||
|
Credit Rating Downgrade (to below BBB-)
|
23 | (1,252 | ) | (1,252 | ) | |||||||
|
Adequate Assurance(1)
|
- | - | - | |||||||||
|
Total Central Hudson
|
27 | $ | (1,601 | ) | $ | (1,601 | ) | |||||
|
Griffith:
|
||||||||||||
|
Change in Ownership (CHEG ownership of CHEC falls below 51%)
|
- | - | - | |||||||||
|
Adequate Assurance(1)
|
- | - | - | |||||||||
|
Total Griffith
|
- | - | - | |||||||||
|
Total CH Energy Group
|
27 | $ | (1,601 | ) | $ | (1,601 | ) | |||||
|
(1)
|
If the counterparty has reasonable grounds to believe Central Hudson'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 and Central Hudson have elected gross presentation for their derivative contracts under master netting agreements and collateral positions. On December 31, 2011, neither Central Hudson nor Griffith had collateral posted against the fair value amount of derivatives.
The fair value of CH Energy Group’s and Central Hudson’s derivative instruments and their location in the respective Balance Sheets are summarized in the table below, followed by a summarization 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.”
Gross Fair Value of Derivative Instruments
Current accounting guidance related to fair value measurements 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.
Derivative contracts are measured at fair value on a recurring basis. As of December 31, 2011 and 2010, CH Energy Group's and Central Hudson's derivative assets and liabilities by category and hierarchy level are as 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, 2011
|
|
|
|
|
||||||||||||
|
Assets:
|
|
|
|
|
||||||||||||
|
Derivative Contracts:
|
|
|
|
|
||||||||||||
|
Central Hudson - electric
|
$ | 931 | $ | - | $ | - | $ | 931 | ||||||||
|
Central Hudson - total return swap
|
320 | - | 320 | - | ||||||||||||
|
Total Central Hudson Assets
|
$ | 1,251 | $ | - | $ | 320 | $ | 931 | ||||||||
|
Griffith - heating oil
|
$ | 29 | $ | 29 | $ | - | $ | - | ||||||||
|
Total CH Energy Group Assets
|
$ | 1,280 | $ | 29 | $ | 320 | $ | 931 | ||||||||
|
Liabilities:
|
||||||||||||||||
|
Derivative Contracts:
|
||||||||||||||||
|
Central Hudson - electric
|
$ | (17,761 | ) | $ | - | $ | - | $ | (17,761 | ) | ||||||
|
Central Hudson - natural gas
|
(2,030 | ) | (2,030 | ) | - | - | ||||||||||
|
Total CH Energy Group and Central Hudson Liabilities
|
$ | (19,791 | ) | $ | (2,030 | ) | $ | - | $ | (17,761 | ) | |||||
|
As of December 31, 2010
|
||||||||||||||||
|
Assets:
|
||||||||||||||||
|
Derivative Contracts:
|
||||||||||||||||
|
Central Hudson - natural gas
|
$ | 34 | $ | - | $ | 34 | $ | - | ||||||||
|
Total Central Hudson Assets
|
$ | 34 | $ | - | $ | 34 | $ | - | ||||||||
|
Griffith - heating oil
|
$ | 112 | $ | 112 | $ | - | $ | - | ||||||||
|
Total CH Energy Group Assets
|
$ | 146 | $ | 112 | $ | 34 | $ | - | ||||||||
|
Liabilities:
|
||||||||||||||||
|
Derivative Contracts:
|
||||||||||||||||
|
Central Hudson - electric
|
$ | (23,872 | ) | $ | - | $ | - | $ | (23,872 | ) | ||||||
|
Central Hudson - natural gas
|
(1,009 | ) | - | (1,009 | ) | - | ||||||||||
|
Total CH Energy Group and Central Hudson Liabilities
|
$ | (24,881 | ) | $ | - | $ | (1,009 | ) | $ | (23,872 | ) | |||||
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,
|
|||||||
|
|
2011
|
2010
|
||||||
|
Balance at Beginning of Period
|
$ | (23,872 | ) | $ | (11,983 | ) | ||
|
Unrealized gains (losses)
|
7,042 | (11,889 | ) | |||||
|
Realized losses
|
(13,195 | ) | (8,850 | ) | ||||
|
Purchases
|
- | - | ||||||
|
Issuances
|
- | - | ||||||
|
Sales and settlements
|
13,195 | 8,850 | ||||||
|
Transfers in and/or out of Level 3
|
- | - | ||||||
|
Balance at End of Period
|
$ | (16,830 | ) | $ | (23,872 | ) | ||
|
|
||||||||
|
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
|
$ | - | $ | - | ||||
The company did not have any transfers into or out of Levels 1 or 2.
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, 2011, 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, such as pricing data from major market participants in its determination of the futures closing price. Management believes these prices approximate fair value for these instruments. Natural gas swap contracts outstanding as of December 31, 2010 and 2009, were valued using the NYMEX Natural Gas Futures Closing Price plus the NYMEX Clearport Natural Gas Basis Swap Futures Closing Price for Tennessee, Columbia, Dominion-Appalachia and Dawn pipeline locations, and have been classified within Level 2 of the fair value hierarchy. For these natural gas swap contracts that were 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, 2011, all outstanding natural gas swap contracts are valued using the NYMEX Natural Gas Futures Closing Price and have been classified within Level 1 of the fair value hierarchy. 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. Based on the credit ratings by Moody’s, S&P and Fitch of the counterparty, Management has concluded that the credit risk associated with the counterparty’s non-performance on call options in an asset position is not significant. Therefore, no adjustment related to credit risk has been made to the fair value of contracts in an asset position.
The Effect of Derivative Instruments on the Statements of Income
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 energy derivative instruments 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.
Effective October 1, 2009, Griffith de-designated all open derivative positions. The loss reclassified from accumulated other comprehensive income in 2010, as these de-designated derivatives have settled, was not material. The fair values of open derivative instruments held by Griffith 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.
For the year ended December 31, 2011, neither CH Energy Group nor Central Hudson had derivatives designated as hedging instruments. The following table summarizes the effects of CH Energy Group and Central Hudson derivatives on the statements of income (In Thousands):
|
|
Amount of Gain/(Loss) Recognized as Increase/(Decrease) in the Income Statement
|
||||||||||||
|
|
Year Ended December 31,
|
||||||||||||
|
|
2011
|
2010
|
2009
|
Location of Gain/(Loss)
|
|||||||||
|
Central Hudson:
|
|
|
|||||||||||
|
Electricity swap contracts
|
$ | (13,195 | ) | $ | (8,850 | ) | $ | (26,018 | ) |
Regulatory asset(1)
|
|||
|
Natural gas swap contracts
|
(2,311 | ) | (2,616 | ) | (13,758 | ) |
Regulatory asset(1)
|
||||||
|
Total return swap contracts
|
448 | - | - |
Other-net
|
|||||||||
|
Total Central Hudson
|
$ | (15,058 | ) | $ | (11,466 | ) | $ | (39,776 | ) | ||||
|
|
|||||||||||||
|
Griffith:
|
|||||||||||||
|
Heating oil call option contracts
|
(3 | ) | (100 | ) | 54 |
Purchased petroleum
|
|||||||
|
Griffith other derivative financial instrument
|
- | 129 | (73 | ) |
Purchased petroleum
|
||||||||
|
Total Griffith
|
$ | (3 | ) | $ | 29 | $ | (19 | ) | |||||
|
|
|||||||||||||
|
Total CH Energy Group
|
$ | (15,061 | ) | $ | (11,437 | ) | $ | (39,795 | ) | ||||
|
(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.
|
||||||||||||||||||||
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. In the year ended December 31, 2011, approximately $0.7 million of income was recorded. In the years ended December 31, 2010 and December 31, 2009, approximately $0.6 million and $0.2 million of expense was recorded to the income statement related to Griffith’s weather derivatives, respectively.
Other Assets Recorded at Fair Value
In addition to the derivatives reported at fair value discussed in Note 14 – “Accounting for Derivative Instruments and Hedging Activities”, CH Energy Group reports certain other assets at fair value in the Consolidated Balance Sheets, including the investments of CH Energy Group’s Directors and Executives Deferred Compensation Plan. The following table summarizes the amount reported at fair value related to these assets as of December 31, 2011 and December 31, 2010 (In Thousands):
|
Asset 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, 2011
|
||||||||||||||||
|
Other investments
|
$ | 2,605 | $ | 2,605 | $ | - | $ | - | ||||||||
|
As of December 31, 2010
|
||||||||||||||||
|
Other investments
|
$ | 3,912 | $ | 3,912 | $ | - | $ | - | ||||||||
|
Lyonsdale property and plant
|
$ | 6,685 | $ | - | $ | 6,685 | $ | - | ||||||||
As of December 31, 2011 and December 31, 2010, a portion of the trust assets for the funding of CH Energy Group’s Directors and Executives Deferred Compensation Plan are invested in mutual funds, which are measured at fair value on a recurring basis. These investments are valued at quoted market prices in active markets and as such are Level 1 investments as defined in the fair value hierarchy. These amounts are included in the line titled “Other investments” within the Deferred Charges and Other Assets section of the CH Energy Group Consolidated and Central Hudson Balance Sheets.
As a result of an impairment charge recognized in 2010, as of December 31, 2010, Lyonsdale property and plant of $6.7 million was recorded at fair value. The fair value of the assets was calculated based on market participant bids for the purchase of Lyonsdale, which were received in early 2011. Effective May 1, 2011, Lyonsdale was sold. See Note 5 – “Acquisitions, Divestitures and Investments” for further details.
CHEC recorded a reserve against the full balance of its $10 million note receivable from Cornhusker Holdings in the third quarter of 2010. An impairment analysis was performed based on a confluence of various negative trends, including (1) a lower-than-expected level of increased output from the expansion that was completed at the end of 2009 under which Cornhusker Energy Lexington, LLC (the operating company) took on additional debt that is senior to CHEC’s debt; (2) continued lower-than-expected margins; and (3) a change in the historical relationship between corn and distillers grains prices at the site that began in the first quarter. The fair value of the note receivable from Cornhusker Holdings was determined using an income approach, which calculates the fair value as the sum of the net after-tax cash flows to be received over the life of the underlying assets of the company on a discounted basis. The discount rate used in this analysis accounts for both the time value of money and investment risk. Based on this analysis, the present value of the after-tax projected cash flows indicate that there are insufficient funds to repay the subordinated debt to CHEC after payments to the senior creditors are satisfied. As of December 31, 2011, Management believes the fair value of this note receivable remains at zero and therefore appropriately reserved.
In the third quarter of 2011, CHEC recorded an impairment loss for the full value of its investment in CH-Community Wind. An impairment analysis was performed based on preliminary market data obtained during the implementation of CH Energy Group’s change in strategy related to its renewable energy investments, as well as recently updated operating forecasts of the investment. The fair value of CHEC’s investment in CH-Community Wind was also determined using an income approach. Based on this analysis, the present value of the after-tax projected cash flows using a market participant’s expected return, is insufficient for CHEC to recovery any of its investment. As of December 31, 2011, the fair value of this investment remains at zero.
Other Fair Value Disclosure
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.
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: Carrying amount
Long-term Debt: Quoted market prices for the same or similar issues
Notes Payable: Carrying amount
Long-term Debt Maturities and Fair Value - CH Energy Group
(Dollars in Thousands)
December 31, 2011
|
|
|
Expected Maturity Date
|
|||||||||||||||||||||||||||||
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
2016
|
|
|
Thereafter
|
|
|
Total
|
|
Fair Value
|
|||||||||
|
Fixed Rate:
|
|
$
|
37,006
|
|
|
$
|
31,076
|
|
|
$
|
21,650
|
|
|
$
|
1,230
|
|
|
$
|
9,315
|
|
|
$
|
349,032
|
|
|
$
|
449,309
|
|
$
|
504,135
|
|
|
Estimated Effective Interest Rate
|
|
|
6.71
|
%
|
|
|
6.92
|
%
|
|
|
5.45
|
%
|
|
|
6.86
|
%
|
|
|
3.39
|
%
|
|
|
5.23
|
%
|
|
|
5.55
|
%
|
|
|
|
|
Variable Rate:
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
33,700
|
|
|
$
|
33,700
|
|
$
|
33,700
|
|
|
Estimated Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.37
|
%
|
|
|
0.37
|
%
|
|
|
|
|
Total Debt Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
483,009
|
|
$
|
537,835
|
|
|
Estimated Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.22
|
%
|
|
|
|
December 31, 2010
|
|
|
Expected Maturity Date
|
|||||||||||||||||||||||||||||
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
Thereafter
|
|
|
Total
|
|
Fair Value
|
|||||||||
|
Fixed Rate:
|
|
$
|
941
|
|
|
$
|
37,007
|
|
|
$
|
31,076
|
|
|
$
|
41,650
|
|
|
$
|
1,230
|
|
|
$
|
358,296
|
|
|
$
|
470,200
|
|
$
|
489,660
|
|
|
Estimated Effective Interest Rate
|
|
|
6.86
|
%
|
|
|
6.71
|
%
|
|
|
6.92
|
%
|
|
|
6.02
|
%
|
|
|
6.86
|
%
|
|
|
5.54
|
%
|
|
|
5.78
|
%
|
|
|
|
|
Variable Rate:
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
33,700
|
|
|
$
|
33,700
|
|
$
|
33,700
|
|
|
Estimated Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.46
|
%
|
|
|
0.46
|
%
|
|
|
|
|
Total Debt Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
503,900
|
|
$
|
523,360
|
|
|
Estimated Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.42
|
%
|
|
|
|
Long-term Debt Maturities and Fair Value - Central Hudson
(Dollars in Thousands)
December 31, 2011
|
|
|
Expected Maturity Date
|
|||||||||||||||||||||||||||||
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
2016
|
|
|
Thereafter
|
|
|
Total
|
|
Fair Value
|
|||||||||
|
Fixed Rate:
|
|
$
|
36,000
|
|
|
$
|
30,000
|
|
|
$
|
14,000
|
|
|
$
|
-
|
|
|
$
|
8,000
|
|
|
$
|
332,250
|
|
|
$
|
420,250
|
|
$
|
468,042
|
|
|
Estimated Effective Interest Rate
|
|
|
6.71
|
%
|
|
|
6.93
|
%
|
|
|
4.81
|
%
|
|
|
-
|
%
|
|
|
2.83
|
%
|
|
|
5.14
|
%
|
|
|
5.46
|
%
|
|
|
|
|
Variable Rate:
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
33,700
|
|
|
$
|
33,700
|
|
$
|
33,700
|
|
|
Estimated Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.37
|
%
|
|
|
0.37
|
%
|
|
|
|
|
Total Debt Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
453,950
|
|
$
|
501,742
|
|
|
Estimated Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.12
|
%
|
|
|
|
December 31, 2010
|
|
|
Expected Maturity Date
|
|||||||||||||||||||||||||||||
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
Thereafter
|
|
|
Total
|
|
Fair Value
|
|||||||||
|
Fixed Rate:
|
|
$
|
-
|
|
|
$
|
36,000
|
|
|
$
|
30,000
|
|
|
$
|
14,000
|
|
|
$
|
-
|
|
|
$
|
340,200
|
|
|
$
|
420,200
|
|
$
|
432,800
|
|
|
Estimated Effective Interest Rate
|
|
|
-
|
%
|
|
|
6.71
|
%
|
|
|
6.93
|
%
|
|
|
4.81
|
%
|
|
|
-
|
%
|
|
|
5.47
|
%
|
|
|
5.66
|
%
|
|
|
|
|
Variable Rate:
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
33,700
|
|
|
$
|
33,700
|
|
$
|
33,700
|
|
|
Estimated Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0.46
|
%
|
|
|
0.46
|
%
|
|
|
|
|
Total Debt Outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
453,900
|
|
$
|
466,500
|
|
|
Estimated Effective Interest Rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5.28
|
%
|
|
|
|
In addition to items disclosed in the footnotes, CH Energy Group has performed an evaluation of events subsequent to December 31, 2011 through the date the financial statements were issued and noted two additional items to disclose.
Subsequent to the year-end, Griffith acquired a fuel distribution company for a total of approximately $0.3 million. The purchase price of the company included an immaterial amount for tangible assets and $0.3 million for intangible assets of which approximately $0.2 million is goodwill.
On January 30, 2012, Central Hudson contributed $28 million to its Retirement Plan.
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
CH ENERGY GROUP(1)
Selected financial data for each quarterly period within 2011 and 2010 are presented below (In Thousands, except per share data):
|
|
Operating Revenues
|
Operating Income
|
Net Income from Continuing Operations
|
Net Income/(Loss) from Discontinued Operations, Net of Tax
|
Earnings Per Average Share of Common
Stock (Diluted) Outstanding
|
|||||||||||||||
|
Quarter Ended:
|
|
|
|
|
|
|||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
2011
|
|
|
|
|
|
|||||||||||||||
|
March 31
|
$ | 326,972 | $ | 34,003 | $ | 17,075 | $ | 115 | $ | 1.07 | ||||||||||
|
June 30
|
207,067 | 15,944 | 6,106 | 90 | 0.38 | |||||||||||||||
|
September 30
|
220,755 | 21,830 | 4,807 | 3,763 | 0.54 | |||||||||||||||
|
December 31
|
230,726 | 27,812 | 15,196 | (842 | )(2) | 0.94 | (2) | |||||||||||||
|
|
||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
March 31
|
$ | 299,517 | $ | 41,011 | $ | 20,491 | $ | 224 | $ | 1.28 | ||||||||||
|
June 30
|
199,668 | 18,797 | 7,632 | (1,044 | ) | 0.42 | ||||||||||||||
|
September 30
|
223,357 | 18,537 | 1,705 | 428 | 0.11 | |||||||||||||||
|
December 31
|
237,566 | 20,958 | 10,502 | (736 | )(3) | 0.60 | (3) | |||||||||||||
|
(1)
|
Amounts differ from those previously reported as a result of the presentation of discontinued operations due to CHEC divesting four of its renewable energy investments in 2011.
|
|
|
(2)
|
Includes the impact of the fourth quarter 2011 loss on sale of a molecular gate owned by CH-Greentree at a $1.3 million pre-tax, $0.8 million net of tax and $(0.05) per share, respectively.
|
|
|
(3)
|
Includes the impact of the fourth quarter 2010 impairment on Lyonsdale assets of $2.1 million pre-tax, $1.3 million net of tax and $(0.08) per share, respectively.
|
CENTRAL HUDSON
Selected financial data for each quarterly period within 2011 and 2010 are presented below (In Thousands):
|
|
Operating Revenues
|
Operating Income
|
Income Available for Common Stock
|
|||||||||
|
Quarter Ended:
|
|
|
|
|||||||||
|
|
|
|
|
|||||||||
|
2011
|
|
|
|
|||||||||
|
March 31
|
$ | 230,052 | $ | 26,576 | $ | 12,397 | ||||||
|
June 30
|
148,232 | 18,037 | 7,129 | |||||||||
|
September 30
|
168,168 | 25,064 | 11,423 | |||||||||
|
December 31
|
154,070 | 25,849 | 13,118 | |||||||||
|
|
||||||||||||
|
2010
|
||||||||||||
|
March 31
|
$ | 215,049 | $ | 33,759 | $ | 16,403 | ||||||
|
June 30
|
157,557 | 21,079 | 9,747 | |||||||||
|
September 30
|
184,127 | 21,857 | 9,498 | |||||||||
|
December 31
|
163,201 | 18,153 | 9,500 | |||||||||
CH ENERGY GROUP - (PARENT COMPANY ONLY)
Statement of Income
(In Thousands, except per share amounts)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Equity in earnings of subsidiaries
|
$ | 42,695 | $ | 39,332 | $ | 33,617 | ||||||
|
Business development costs
|
(1,222 | ) | (1,809 | ) | (2,012 | ) | ||||||
|
Interest income
|
3,895 | 2,566 | 4,131 | |||||||||
|
Interest expense
|
(2,962 | ) | (3,342 | ) | (2,170 | ) | ||||||
|
Penalty on early retirement of debt
|
(2,982 | ) | - | - | ||||||||
|
Other income (deductions), net of taxes
|
2,790 | 2,885 | (763 | ) | ||||||||
|
Income from continuing operations
|
42,214 | 39,632 | 32,803 | |||||||||
|
Income from discontinued operations, net of tax
|
3,126 | (1,128 | ) | 10,681 | ||||||||
|
|
||||||||||||
|
Net Income
|
$ | 45,340 | $ | 38,504 | $ | 43,484 | ||||||
|
|
||||||||||||
|
Common Stock:
|
||||||||||||
|
Average shares outstanding
|
||||||||||||
|
Basic
|
15,278 | 15,785 | 15,775 | |||||||||
|
Diluted
|
15,481 | 15,952 | 15,881 | |||||||||
|
|
||||||||||||
|
Earnings per share - Basic
|
||||||||||||
|
Continuing operations
|
$ | 2.77 | $ | 2.51 | $ | 2.08 | ||||||
|
Discontinued operations
|
$ | 0.20 | $ | (0.07 | ) | $ | 0.68 | |||||
|
|
||||||||||||
|
Earnings per share - Diluted
|
||||||||||||
|
Continuing operations
|
$ | 2.73 | $ | 2.48 | $ | 2.07 | ||||||
|
Discontinued operations
|
$ | 0.20 | $ | (0.07 | ) | $ | 0.67 | |||||
|
|
||||||||||||
|
Dividends declared per share
|
$ | 2.19 | $ | 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,
|
|||||||||||
|
|
2011
|
2010
|
2009
|
|||||||||
|
Operating Activities:
|
|
|
|
|||||||||
|
Net income
|
$ | 45,340 | $ | 38,504 | $ | 43,484 | ||||||
|
Equity in earnings of subsidiary companies
|
(45,387 | ) | (38,204 | ) | (44,298 | ) | ||||||
|
Changes in current assets and liabilities:
|
||||||||||||
|
Cash dividends received from subsidiaries
|
70,064 | 31,000 | 5,000 | |||||||||
|
Accrued taxes
|
- | - | (493 | ) | ||||||||
|
Other - net
|
(8,805 | ) | 3,794 | (574 | ) | |||||||
|
Net cash flows provided by operating activities
|
61,212 | 35,094 | 3,119 | |||||||||
|
|
||||||||||||
|
Investing Activities:
|
||||||||||||
|
Investment in subsidiaries
|
29,592 | (46,250 | ) | 30,950 | ||||||||
|
Proceeds from issuance of long-term debt
|
- | - | 50,000 | |||||||||
|
Net cash flows (used in) provided by investing activities
|
29,592 | (46,250 | ) | 80,950 | ||||||||
|
|
||||||||||||
|
Financing Activities:
|
||||||||||||
|
Redemption of long-term debt
|
(20,941 | ) | - | - | ||||||||
|
Net borrowings of short-term debt
|
5,000 | - | - | |||||||||
|
Cash dividends on common shares
|
(33,554 | ) | (34,164 | ) | (34,107 | ) | ||||||
|
Shares repurchased
|
(48,687 | ) | (1,465 | ) | - | |||||||
|
Net cash flows used in financing activities
|
(98,182 | ) | (35,629 | ) | (34,107 | ) | ||||||
|
|
||||||||||||
|
Net change in cash and cash equivalents
|
(7,378 | ) | (46,785 | ) | 49,962 | |||||||
|
|
||||||||||||
|
Cash and cash equivalents - beginning of the year
|
14,506 | 61,291 | 11,329 | |||||||||
|
Cash and cash equivalents - end of the year
|
$ | 7,128 | $ | 14,506 | $ | 61,291 | ||||||
SCHEDULE I - CONDENSED FINANCIAL INFORMATION
CH ENERGY GROUP - (PARENT COMPANY ONLY)
Balance Sheet
(In Thousands)
|
|
December 31,
|
|||||||
|
|
2011
|
2010
|
||||||
|
ASSETS
|
|
|
||||||
|
Current Assets
|
|
|
||||||
|
Cash and cash equivalents
|
$ | 7,128 | $ | 14,506 | ||||
|
Prepaid income tax
|
746 | 2,802 | ||||||
|
Prepayments
|
333 | 604 | ||||||
|
Accounts receivable from subsidiaries
|
1,802 | - | ||||||
|
Other
|
6,935 | 5,140 | ||||||
|
Total Current Assets
|
16,944 | 23,052 | ||||||
|
|
||||||||
|
Other Assets
|
||||||||
|
Investments in subsidiaries
|
527,926 | 582,197 | ||||||
|
Total Other Assets
|
527,926 | 582,197 | ||||||
|
|
||||||||
|
Total Assets
|
$ | 544,870 | $ | 605,249 | ||||
|
|
||||||||
|
CAPITALIZATION AND LIABILITIES
|
||||||||
|
Capitalization
|
||||||||
|
Common stock
|
$ | 1,686 | $ | 1,686 | ||||
|
Paid-in capital
|
350,997 | 350,288 | ||||||
|
Retained earnings
|
242,391 | 230,342 | ||||||
|
Treasury stock
|
(92,908 | ) | (44,887 | ) | ||||
|
Accumulated other comprehensive income
|
354 | 459 | ||||||
|
Capital stock expense
|
(328 | ) | (328 | ) | ||||
|
Total Capitalization
|
502,192 | 537,560 | ||||||
|
|
||||||||
|
Current Liabilities
|
||||||||
|
Current maturities of long-term debt
|
1,006 | 941 | ||||||
|
Notes payable
|
5,000 | - | ||||||
|
Dividends payable
|
8,269 | 8,532 | ||||||
|
Accounts payable
|
199 | 1,100 | ||||||
|
Accounts payable to subsidiaries
|
- | 7,627 | ||||||
|
Accrued interest
|
151 | 430 | ||||||
|
Total Current Liabilities
|
14,625 | 18,630 | ||||||
|
|
||||||||
|
Long Term Liabilities
|
||||||||
|
Private Placement Debt
|
28,053 | 49,059 | ||||||
|
Total Long Term Liabilities
|
28,053 | 49,059 | ||||||
|
|
||||||||
|
Total Capitalization and Liabilities
|
$ | 544,870 | $ | 605,249 | ||||
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.
(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, 2011
|
|
|
|
|
|
|||||||||||||||
|
Operating Reserves
|
$ | 3,187 | $ | 1,185 | $ | 117 | $ | 1,106 | $ | 3,383 | ||||||||||
|
Reserve for Uncollectible Accounts
|
$ | 6,706 | $ | 8,516 | $ | - | $ | 8,234 | $ | 6,988 | ||||||||||
|
|
||||||||||||||||||||
|
Year Ended December 31, 2010
|
||||||||||||||||||||
|
Operating Reserves
|
$ | 4,756 | $ | 912 | $ | 138 | $ | 2,619 | $ | 3,187 | ||||||||||
|
Reserve for Uncollectible Accounts
|
$ | 7,736 | $ | 4,688 | $ | 3,702 | $ | 9,420 | $ | 6,706 | ||||||||||
|
|
||||||||||||||||||||
|
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 | ||||||||||
(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, 2011
|
|
|
|
|
|
|||||||||||||||
|
Operating Reserves
|
$ | 2,068 | $ | 596 | $ | 117 | $ | 661 | $ | 2,120 | ||||||||||
|
Reserve for Uncollectible Accounts
|
$ | 5,300 | $ | 7,156 | $ | - | $ | 7,256 | $ | 5,200 | ||||||||||
|
|
||||||||||||||||||||
|
Year Ended December 31, 2010
|
||||||||||||||||||||
|
Operating Reserves
|
$ | 3,503 | $ | 482 | $ | 138 | $ | 2,055 | $ | 2,068 | ||||||||||
|
Reserve for Uncollectible Accounts
|
$ | 5,800 | $ | 3,942 | $ | 3,702 | $ | 8,144 | $ | 5,300 | ||||||||||
|
|
||||||||||||||||||||
|
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 | ||||||||||
None.
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.
There were no changes to the Registrants’ internal control over financial reporting during the Registrants’ last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
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
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 for its 2012 Annual Meeting (“Proxy Statement”), which will be filed with the SEC.
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 of CH Energy Group.”
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 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 Proxy Statement.
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, 2011, 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
|
12,840
|
(1)
|
$
|
48.62
|
|
432,805
|
(2)
|
||
|
Equity compensation plans not approved by security holders
|
-
|
|
|
-
|
|
-
|
|||
|
Total
|
12,840
|
|
$
|
48.62
|
|
432,805
|
|||
|
(1)
|
This includes only stock options granted under the 2000 Plan.
|
|
|
(2)
|
Pertains to the 2011 Plan only. Effective February 10, 2011, securities can no longer be issued under the 2006 Plan. Granted under the 2006 plan and excluded are 201,270 performance shares, 62,575 restricted shares and share units (including re-invested dividends) and 3,350 other stock awards.
|
The information required hereunder regarding equity ownership in CH Energy Group by its Directors and executive officers is incorporated by reference to the Proxy Statement.
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.
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 will be included in the Proxy Statement.
The following information is provided for Central Hudson:
PRINCIPAL ACCOUNTANT FEES AND SERVICES
|
PricewaterhouseCoopers LLP
|
2011
|
2010
|
||||||
|
Audit Fees
|
$ | 893,411 | $ | 863,432 | ||||
|
Tax Fees
|
||||||||
|
Includes review of federal and state income tax returns and tax research
|
23,400 | 22,200 | ||||||
|
All Other Fees
|
||||||||
|
Consulting services
|
60,600 | 304,474 | ||||||
|
Total
|
$ | 977,411 | $ | 1,190,106 | ||||
PART IV
|
(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 16, 2012
|
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
|
|
|
By:
|
/s/ Steven V. Lant
|
|
Steven V. Lant
Chairman of the Board and Chief Executive Officer
|
Dated: February 16, 2012
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 16, 2012
|
||
|
(b) Principal Accounting Officer:
|
||||
|
/s/ Kimberly J. Wright
|
||||
|
(Kimberly J. Wright)
|
Vice President - Accounting and Controller of
CH Energy Group, Inc.;
and Controller of
Central Hudson Gas & Electric Corporation
|
February 16, 2012
|
||
|
(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 16, 2012
|
||
(d) At least 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 16, 2012
|
(e) At least a majority of Directors of Central Hudson Gas & Electric Corporation:
Steven V. Lant*, Christopher M. Capone*, James P. Laurito* and Charles A. Freni, Jr.*, Directors
|
By:
|
/s/ Steven V. Lant
|
||
|
(Steven V. Lant)
|
February 16, 2012
|
_______________________
*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
|
|
|
|
|
|
|
Designation)
|
|
Exhibits
|
|||
|
|
|
|
|
|
|
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
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. 4, dated February 24, 2004, as filed pursuant to Rule 424(b).
|
|
|
|
|
|
|
|
|
|
|
|
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).
|
|
|
|
|
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).
|
|
|
|
|
|
|
|
|
|
|
|
5--
|
Prospectus Supplement dated March 22, 2010 (to Prospectus dated March 16, 2010) relating to $250,000,000 principal amount of Medium-Term Notes, Series G, and the Prospectus dated March 16, 2010 relating to $250,000,000 principal amount of Central Hudson’s debt securities attached thereto, as filed on March 22, 2010, pursuant to Rule 424(b) in connection with Registration Statement No. 333-163248, and, as applicable to a tranche of such Medium-Term Notes, each of the following:
|
||
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Pricing Supplement No. 1, dated December 2, 2010 filed on December 3, 2010, pursuant to Rule 424(b).
|
|
|
|
|
|
|
|
|
|
|
|
|
(b)
|
Pricing Supplement No. 2, dated September 27, 2011 filed on September 28, 2011, pursuant to Rule 424(b).
|
|
|
|
|
6--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
7--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
8--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
9--
|
Note Purchase Agreement, dated as of August 6, 2010, between Central Hudson Gas & Electric Corporation and the purchasers of its 4.30% Senior Notes, Series A, due September 21, 2020 and its 5.64% Senior Notes, Series B, due September 21, 2040 (Incorporated herein by reference to CH Energy Group’s Current Report on Form 8-K, filed August 9, 2010; Exhibit 10.1)
|
||
|
|
|
|
|
|
|
|
|
|
10--
|
Central Hudson and another subsidiary of CH 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 CH Energy Group and its other subsidiaries or Central Hudson, as the case may be, each on a consolidated basis. CH Energy Group and Central Hudson agree to provide the Commission, upon request, copies of any instruments defining the rights of holders of long-term debt of Central Hudson and such other subsidiary.
|
||
|
10
|
|
Material contracts:
|
|||
|
|
|
|
|
|
|
|
|
|
(i)
|
1--
|
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)
|
|
|
|
|
|
|
|
|
|
|
|
2--
|
Amended and Restated Credit Agreement effective as of October 19, 2011 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 October 24, 2011; Exhibit 10.1)
|
||
|
|
|
|
|
|
|
|
|
|
3--
|
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, National Association, Bank of America, National Association, and HSBC Bank USA, National Association) 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)
|
||
|
|
|
|
|
|
|
|
|
|
4--
|
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, National Association, Bank of America, National Association, and HSBC Bank USA, National Association) 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)
|
||
|
|
|
5--
|
ASR Agreement dated August 16, 2011 among CH Energy Group, Inc, and J.P. Morgan Securities LLC, as arranger and administrative agent. (Incorporated herein by reference to Central Hudson's Current Report on Form 8-K filed on August 18, 2011; Exhibit 10.1)
|
||
|
|
|
|
|
|
|
|
|
|
(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)
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
Amendment to CH Energy Group, Inc. Directors and Executives Deferred Compensation Plan Trust Agreement.
|
|||
|
|
|
|
|
|
|
|
|
|
4--
|
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)
|
||
|
|
|
||||
|
(1) Exhibits in Part (iii) of this Section 10 are management contracts and compensatory plans and arrangements.
|
|||||
|
|
|
5--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
6--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
Amended and Restated CH Energy Group, Inc. Directors and Executives Deferred Compensation Plan, effective as of January 1, 2012 (dated January 6, 2012).
|
|||
|
|
|
|
|
|
|
|
|
|
8--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
9--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
10--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
11--
|
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)
|
||
|
|
|
12--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
13--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
14--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
15--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
16--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
17--
|
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)
|
||
|
|
|
|
|
|
|
|
|
|
18--
|
Amendment to CH Energy Group, Inc. Long-Term Equity Incentive Plan effective as of April 26, 2011. (Incorporated herein by reference to CH Energy Group’s Current Report on Form 8-K filed on April 28, 2011; Exhibit 10.1)
|
||
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19--
|
Amendment to CH Energy Group, Inc. Long-Term Equity Incentive Plan effective as of December 31, 2007. (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)36)
|
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20--
|
CH Energy Group, Inc. Long-Term Equity Incentive Plan, effective as of January 01, 2011. (Incorporated herein by reference from Appendix A to the Proxy Statement of CH Energy Group, Inc., filed with the SEC on March 17, 2011)
|
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21--
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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)
|
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22--
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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 February 8, 2010; Exhibit 10.1)
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23--
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Form of CH Energy Group, Inc. Performance Shares Agreement. (Incorporated herein by reference to CH Energy Group’s Annual Report on Form 10-K for the year ended December 31, 2010; Exhibit (10)(iii)22)
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24--
|
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 February 10, 2012; Exhibit 10.1)
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25--
|
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)
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26--
|
Form of CH Energy Group, Inc. Restricted Shares Agreement. (Incorporated herein by reference to CH Energy Group’s Current Report on Form 8-K filed on February 8, 2010; Exhibit 10.2)
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27--
|
Form of CH Energy Group, Inc. Restricted Shares Agreement. (Incorporated herein by reference to CH Energy Group’s Current Report on Form 8-K filed on February 10, 2012; Exhibit 10.2)
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28--
|
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)
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29--
|
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 CH Energy Group’s Annual Report on Form 10-K for the year ended December 31, 2007; Exhibit (10)(iii)32)
|
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30--
|
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 CH Energy Group’s Annual Report on Form 10-K for the year ended December 31, 2007; Exhibit (10)(iii)33)
|
||
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31--
|
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 CH Energy Group’s Annual Report on Form 10-K for the year ended December 31, 2007; Exhibit (10)(iii)34)
|
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32--
|
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)
|
||
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33--
|
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)
|
||
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34--
|
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)
|
||
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35--
|
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)
|
||
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36--
|
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)
|
||
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37--
|
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)
|
||
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38--
|
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)
|
||
| 39-- |
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)
|
||||
| 40-- |
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)
|
||||
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CH Energy Group Statement showing the computation of the ratio of earnings to fixed charges.
|
||||
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Central Hudson Statement showing the computation of the ratio of earnings to fixed charges and ratio of earnings to fixed charges and preferred dividends.
|
||||
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Subsidiaries of CH Energy Group, Inc. as of December 31, 2011.
|
||||
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Consents of Independent Registered Public Accounting Firm for incorporation by reference of CH Energy Group Inc.’s Registration Statements on Form S-3 and S-8.
|
||||
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|
Consents of Independent Registered Public Accounting Firm for incorporation by reference of Central Hudson Gas & Electric Corporation’s Registration Statement on Form S-3.
|
||||
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Powers of Attorney:
|
||||
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(i)
|
1--
|
Powers of Attorney for each of the directors comprising a majority of the Board of Directors of CH Energy Group, Inc. authorizing execution and filing of this Annual Report on Form 10-K by Steven V. Lant.
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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.
|
||
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Rule 13a-14(a)/15d-14(a) Certification by Mr. Lant.
|
||||
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Rule 13a-14(a)/15d-14(a) Certification by Mr. Capone.
|
||||
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Rule 13a-14(a)/15d-14(a) Certification by Mr. Lant.
|
||||
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Rule 13a-14(a)/15d-14(a) Certification by Mr. Capone.
|
||||
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Section 1350 Certification by Mr. Lant.
|
||||
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|
Section 1350 Certification by Mr. Capone.
|
||||
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|
Section 1350 Certification by Mr. Lant.
|
||||
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|
Section 1350 Certification by Mr. Capone.
|
||||
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|
99
|
|
Additional Exhibits:
|
|||
|
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|
|
(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)
|
|
|
|
|
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)
|
||
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|
|
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)
|
||
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|
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)
|
||
|
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|
|
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|
|
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 CH Energy Group's Annual Report on Form 10-K, for the fiscal year ended December 31, 2002; Exhibit (99)(i)10)
|
||
|
|
|
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 CH Energy Group's Annual Report on Form 10-K, for the fiscal year ended December 31, 2002; Exhibit (99)(i)11)
|
||
|
|
|
|
|
|
|
|
101.INS
|
|
XBRL Instance Document.
|
|||
|
|
|
|
|
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema.
|
|||
|
|
|
|
|
|
|
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase.
|
|||
|
|
|
|
|
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase.
|
|||
|
|
|
|
|
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Label Linkbase.
|
|||
|
|
|
|
|
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase.
|
|||
- 212 -