CH ENERGY GROUP, INC. CENTRAL HUDSON GAS …€¦ · Change in Accounting Principle As discussed in...

CH ENERGY GROUP, INC.

&

CENTRAL HUDSON GAS & ELECTRIC CORP.

ANNUAL FINANCIAL REPORT

for the period ended

DECEMBER 31, 2014

Report of Independent Auditors

The Board of Directors of Fortis Inc.

We have audited the accompanying consolidated financial statements of CH Energy Group, Inc. and

subsidiaries, which comprise the consolidated balance sheets as of December 31, 2014 and 2013, and

the related consolidated statements of income, comprehensive income (loss), equity and cash flows for

the years then ended, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in

conformity with U.S. generally accepted accounting principles; this includes the design, implementation,

and maintenance of internal control relevant to the preparation and fair presentation of financial

statements that are free of material misstatement, whether due to fraud or error.

Auditors Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We

conducted our audits in accordance with auditing standards generally accepted in the United States.

Those standards require that we plan and perform the audit to obtain reasonable assurance about

whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in

the financial statements. The procedures selected depend on the auditor’s judgment, including the

assessment of the risks of material misstatement of the financial statements, whether due to fraud or

error. In making those risk assessments, the auditor considers internal control relevant to the entity’s

preparation and fair presentation of the financial statements in order to design audit procedures that

are appropriate in the circumstances, but not for the purpose of expressing an opinion on the

effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also

includes evaluating the appropriateness of accounting policies used and the reasonableness of

significant accounting estimates made by management, as well as evaluating the overall presentation of

the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for

our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the

consolidated financial position of CH Energy Group, Inc. and subsidiaries at December 31, 2014 and

2013, and the consolidated results of their operations and their cash flows for the years then ended in

conformity with U.S. generally accepted accounting principles.

Change in Accounting Principle

As discussed in Note 5 to the consolidated financial statements, in 2013 CH Energy Group, Inc. changed

its presentation of the operating results of one of its subsidiaries to report them as discontinued

operations for all periods presented in the consolidated financial statements.

Report of Adjustments to 2012 Financial Statements

We also audited the adjustments described in Note 5 that were applied to restate the 2012 consolidated

financial statements. In our opinion, such adjustments are appropriate and have been properly applied.

We were not engaged to audit, review or apply any procedures to the 2012 consolidated financial

statements of the Company other than with respect to the adjustments and, accordingly, we do not

express an opinion or any other form of assurance on the 2012 consolidated financial statements as a

whole.

Report of Other Auditors on 2012 Financial Statements

Except for the adjustments described in Note 5, the consolidated financial statements of CH Energy

Group, Inc. and subsidiaries for the years ended December 31, 2012 were audited by other auditors who

expressed an unmodified opinion on those statements on February 25, 2013.

Toronto, Canada

February 18, 2015



We have audited the accompanying balance sheets of Central Hudson Gas & Electric Corporation as of

December 31, 2014 and 2013, and the related statements of income (loss), comprehensive income

(loss), equity and cash flows for each of the two years in the period ended December 31, 2014. These

financial statements are the responsibility of the Company's management. Our responsibility is to

express an opinion on these financial statements based on our audits. The financial statements of

Central Hudson Gas & Electric Corporation for the year ended December 31, 2012, were audited by

other auditors who expressed an unmodified opinion on those statements on February 25, 2013.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight

Board (United States). Those standards require that we plan and perform the audit to obtain reasonable

assurance about whether the financial statements are free of material misstatement. An audit includes

examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.

An audit also includes assessing the accounting principles used and significant estimates made by

management, as well as evaluating the overall financial statement presentation. We believe that our

audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the

financial position of Central Hudson Gas & Electric Corporation at December 31, 2014 and 2013, and the

results of its operations and its cash flows for each of the two years in the period ended December 31,

2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight

Board (United States), Central Hudson Gas & Electric Corporation's internal control over financial

reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated

Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013

framework) and our report dated February 18, 2015 expressed an unqualified opinion thereon.

Toronto, Canada

February 18, 2015



We have audited Central Hudson Gas & Electric Corporation’s internal control over financial reporting as

of 31 December 2014, based on criteria established in Internal Control—Integrated Framework issued by

the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the

COSO criteria). Central Hudson Gas & Electric Corporation’s management is responsible 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 an opinion on the

company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight

Board (United States). Those standards require that we plan and perform the audit to obtain reasonable

assurance about whether effective internal control over financial reporting was maintained in all

material respects. Our audit included obtaining an understanding of internal control over financial

reporting, assessing the risk that a material weakness exists, testing and evaluating the design and

operating effectiveness of internal control based on the assessed risk, and performing such other

procedures as we considered necessary in the circumstances. We believe that our audit provides a

reasonable basis for our opinion.

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 (1) pertain to the

maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and

dispositions of the assets of the company; (2) 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 (3) 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.

In our opinion, Central Hudson Gas & Electric Corporation maintained, in all material respects, effective

internal control over financial reporting as of 31 December 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight

Board (United States), the balance sheet of Central Hudson Gas & Electric Corporation as of December

31, 2014, and the related statements of income, comprehensive income, equity and cash flows in the

period ended December 31, 2014 and our report dated February 18, 2015 expressed an unqualified

opinion thereon.

Toronto, Canada

February 18, 2015

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING – CENTRAL HUDSON

The management of Central Hudson Gas & Electric Corporation (“management”) is responsible for establishing and maintaining adequate internal control over financial reporting for Central Hudson Gas & Electric Corporation (the “Corporation”) as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly

reflect the transactions and dispositions of the assets of the Corporation; • provide reasonable assurance that transactions are recorded as necessary to permit

preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of the Corporation are being made only in accordance with authorization of management and directors of the Corporation; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

Internal control over financial reporting includes the controls themselves, monitoring (including internal auditing practices) and actions taken to correct deficiencies as identified.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2014. 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, 2014, the Corporation maintained effective internal control over financial reporting.

The effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2014, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which appears herein.

/s/ James P. Laurito /s/ Christopher M. Capone James P. Laurito Christopher M. Capone Chief Executive Officer Executive Vice President and

Chief Financial Officer February 18, 2015

YEAR ENDED DECEMBER 31, 2014

TABLE OF CONTENTS FINANCIAL STATEMENTS CH Energy Group, Inc. PAGE Consolidated Statement of Income – Year Ended December 31, 2014, 2013 and 2012 9 Consolidated Statement of Comprehensive Income – Year Ended December 31, 2014, 2013 and 2012 10 Consolidated Statement of Cash Flows – Year Ended December 31, 2014, 2013 and 2012 11 Consolidated Balance Sheet – December 31, 2014 and 2013 12 Consolidated Statement of Equity – Year Ended December 31, 2014, 2013 and 2012 14

Central Hudson Gas & Electric Corporation Statement of Income – Year Ended December 31, 2014, 2013 and 2012 15 Statement of Comprehensive Income – Year Ended December 31, 2014, 2013 and 2012 15 Statement of Cash Flows – Year Ended December 31, 2014, 2013 and 2012 16 Balance Sheet – December 31, 2014 and 2013 17 Statement of Equity – Year Ended December 31, 2014, 2013 and 2012 19

NOTES TO FINANCIAL STATEMENTS 20

The Notes to Financial Statements are an integral part hereof.

- 9 -

Financial Statements

CH ENERGY GROUP CONSOLIDATED STATEMENT OF INCOME (In Thousands) Year Ended December 31, 2014 2013 2012 Operating Revenues Electric $ 579,757 $ 532,539 $ 512,081 Natural gas 163,005 135,904 132,434 Total Operating Revenues 742,762 668,443 644,515Operating Expenses Operation: Purchased electricity and fuel used in electric generation 232,990 185,736 175,721 Purchased natural gas 78,765 51,342 49,276 Other expenses of operation - regulated activities 250,046 241,366 232,222 Other expenses of operation - non-regulated 7,129 992 1,985 Merger related costs 86 16,292 10,058 Depreciation and amortization 43,859 40,218 38,139 Regulatory Debits - 40,000 - Taxes, other than income tax 55,497 53,499 50,945 Total Operating Expenses 668,372 629,445 558,346Operating Income 74,390 38,998 86,169Other Income and Deductions Income from unconsolidated affiliates 586 505 174 Interest on regulatory assets and other interest income 4,395 5,884 6,178 Regulatory adjustments for interest costs 1,259 1,280 1,307 Other - net (700) (600) (603) Total Other Income 5,540 7,069 7,056Interest Charges Interest on long-term debt 23,528 25,443 24,949 Interest on regulatory liabilities and other interest 9,575 8,316 6,696 Total Interest Charges 33,103 33,759 31,645Income before income taxes 46,827 12,308 61,580Income Tax Expense 20,196 7,574 24,827Net Income from Continuing Operations 26,631 4,734 36,753Discontinued Operations Income from discontinued operations before tax 6,908 7,540 5,246 Gain from sale of discontinued operations 8,036 - - Income tax expense from discontinued operations 7,255 3,092 2,152Net Income from Discontinued Operations 7,689 4,448 3,094Net Income 34,320 9,182 39,847Net Income attributable to non-controlling interest: Dividends declared on Preferred Stock of subsidiary - 92 624 Preferred Stock Redemption Premium - 764 342Net Income Attributable to CH Energy Group 34,320 8,326 38,881Dividends declared on Common Stock 75,000 18,310 33,169Change in Retained Earnings $ (40,680) $ (9,984) $ 5,712


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CH ENERGY GROUP CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) (In Thousands)

Year Ended

December 31,

2014 2013 2012

Net Income $ 34,320 $ 9,182 $ 39,847

Other Comprehensive Income: Net unrealized gains on investments held by equity method investees net of tax of ($3), ($83) and ($17), respectively 6 124 26

Other comprehensive income 6 124 26

Comprehensive income 34,326 9,306 39,873

Comprehensive income attributable to non-controlling interest - 856 966

Comprehensive income attributable to CH Energy Group $ 34,326 $ 8,450 $ 38,907


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CH ENERGY GROUP CONSOLIDATED STATEMENT OF CASH FLOWS (In Thousands) Year Ended December 31, 2014 2013 2012

Operating Activities: Net income $ 34,320 $ 9,182 $ 39,847Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 40,702 39,938 37,898 Amortization 3,157 5,274 4,883 Deferred income taxes - net 15,741 9,655 25,303 Bad debt expense 6,645 3,829 6,331 Undistributed equity in earnings of unconsolidated affiliates 171 (505) (174) Pension expense 21,152 20,601 22,767 Other post-employment benefits ("OPEB") expense 6,803 6,803 6,832 Positive Benefit Adjustment expense - 40,000 - Regulatory liability - rate moderation - - (1,107) Revenue decoupling mechanism recorded 3,245 2,774 (4,194) Regulatory asset amortization 4,554 4,554 4,610 Gain on sale of assets (8,073) (70) (103)Changes in operating assets and liabilities - net: Accounts receivable, unbilled revenues and other receivables (25,700) (7,677) (7,195) Fuel, materials and supplies 1,209 513 746 Special deposits and prepayments (4,357) (2,739) 531 Income and other taxes (16,208) 106 1,372 Accounts payable 17,201 (7,534) 2,717 Accrued interest (221) (37) (402) Customer advances (3,396) (6,229) 5,782 Pension plan contribution (16,986) (26,641) (28,579) OPEB contribution (2,238) (2,894) (3,269) Revenue decoupling mechanism collected (5,105) 1,956 1,660 Regulatory asset - storm deferral (5,108) 3,450 (6,183) Regulatory asset - manufactured gas plant ("MGP") site remediation 4,202 (1,453) 1,657 Regulatory asset - Temporary State Assessment 1,185 2,220 1,132 Deferred natural gas and electric costs (8,389) (9,726) (592) Other - net 23,065 13,170 19,651Net cash provided by operating activities 87,571 98,520 131,921Investing Activities: Proceeds from sale of assets 95,281 103 173 Additions to utility and other property and plant (113,321) (110,972) (111,161) Acquisitions made by competitive business subsidiaries - - (3,499) Other - net 1,861 (5,312) (84)Net cash provided by (used in) investing activities (13,722) (116,181) (114,571)Financing Activities: Redemption of long-term debt (21,651) (47,777) (37,007) Proceeds from issuance of long-term debt 30,000 46,700 72,000 Borrowings of short-term debt - net - (19,500) 13,000 Proceeds from issuance of stock - 65,000 - Dividends paid on Common Stock (75,000) (26,611) (33,137) Redemption of Preferred Stock - (9,625) (12,180) Dividends paid on Preferred Stock of subsidiary - (92) (866) Shares repurchased - - (2,993) Other - net (207) (372) (940)Net cash provided (used in) by financing activities (66,858) 7,723 (2,123)Cash Included in Net Current Assets Held for Sale - (2,457) Net Change in Cash and Cash Equivalents 4,534 (9,938) 15,227Cash and Cash Equivalents at Beginning of Period 18,113 30,508 15,281Cash and Cash Equivalents at End of Period $ 22,647 $ 18,113 $ 30,508

Supplemental Disclosure of Cash Flow Information:

Interest paid $ 24,147 $ 26,048 $ 26,008 Federal and state income taxes paid $ 17,000 $ 2,158 $ 574 Additions to plant included in liabilities $ 7,495 $ 5,901 $ 10,893


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CH ENERGY GROUP CONSOLIDATED BALANCE SHEET (In Thousands) December 31, December 31,

2014 2013 ASSETS

Utility Plant

Electric $ 1,160,643 $ 1,118,552

Natural gas 380,966 356,627

Common 184,804 174,898

Gross Utility Plant 1,726,413 1,650,077

Less: Accumulated depreciation 458,155 434,410

Net 1,268,258 1,215,667

Construction work in progress 57,543 41,862

Net Utility Plant 1,325,801 1,257,529

Non-utility property & plant 524 524

Net Non-Utility Property & Plant 524 524

Current Assets

Cash and cash equivalents 22,647 18,113

Accounts receivable from customers - net of allowance for doubtful accounts of $4.8 million and $3.9 million, respectively. 69,072 66,123

Accounts receivable - affiliates - 151

Accrued unbilled utility revenues 16,866 17,210

Other receivables 4,704 5,583

Fuel, materials and supplies 17,546 18,632

Regulatory assets 56,272 37,626

Income tax receivable 10,694 808

Fair value of derivative instruments - 8,789

Unamortized debt expense 347 334

Special deposits and prepayments 25,473 20,531

Assets held for sale - 105,151

Accumulated deferred income tax 11,955 12,941

Total Current Assets 235,576 311,992

Deferred Charges and Other Assets

Regulatory assets - pension plan 94,426 50,577

Regulatory assets - other 195,303 125,669

Fair value of derivative instruments 570 1,433

Unamortized debt expense 3,749 3,904

Investments in unconsolidated affiliates 1,726 2,082

Other investments 27,666 26,855

Other 3,001 3,769

Total Deferred Charges and Other Assets 326,441 214,289

Total Assets $ 1,888,342 $ 1,784,334


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CH ENERGY GROUP CONSOLIDATED BALANCE SHEET (CONT'D) (In Thousands, except share amounts)

December 31, December 31, 2014 2013

CAPITALIZATION AND LIABILITIES

Capitalization

CH Energy Group Common Shareholders' Equity

Common Stock (30,000,000 shares authorized: $0.01 par value; 15,961,400 shares issued) 15,961,400 shares outstanding, respectively $ 160 $ 160

Paid-in capital 325,906 325,906

Retained earnings 197,439 238,119

Accumulated other comprehensive income 510 504

Total Equity 524,015 564,689

Long-term debt 524,045 495,275

Total Capitalization 1,048,060 1,059,964

Current Liabilities

Current maturities of long-term debt 1,230 21,650

Accounts payable 44,312 31,420

Accounts payable - affiliates 9 -

Accrued interest 5,673 5,894

Accrued vacation and payroll 9,513 6,773

Customer advances 14,167 15,001

Customer deposits 6,948 6,818

Regulatory liabilities 16,058 22,891

Fair value of derivative instruments 7,727 46

Accrued environmental remediation costs 13,425 1,233

Liabilities held for sale - 29,883

Other 17,966 12,200

Total Current Liabilities 137,028 153,809

Deferred Credits and Other Liabilities

Regulatory liabilities - OPEB 47,339 51,590

Regulatory liabilities - other 156,473 142,931

Operating reserves 4,118 2,426


Accrued OPEB costs 24,836 18,036

Accrued pension costs 68,507 17,497

Tax reserve 2,693 2,539

Other 19,651 19,312

Total Deferred Credits and Other Liabilities 417,317 293,900

Accumulated Deferred Income Tax 285,937 276,661

Commitments and Contingencies Total Capitalization and Liabilities $ 1,888,342 $ 1,784,334


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CH ENERGY GROUP CONSOLIDATED STATEMENT OF EQUITY (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, 2011 16,862,087 $ 1,686 (1,967,123) $ (92,908) $ 351,053 $ (328) $ 242,391 $ 354 $ - $ 502,248

Comprehensive Income:

Net income 39,847 39,847

Preferred Stock Redemption 162 (342) (180)

Dividends declared on Preferred Stock of subsidiary (624) (624)

Change in fair value:

Investments 26 26

Dividends declared on common stock (33,169) (33,169)

Treasury shares activity - net 1 59,920 2,767 (1,625) 1,142

Balance at December 31, 2012 16,862,087 $ 1,686 (1,907,203) $ (90,141) $ 349,428 $ (166) $ 248,103 $ 380 $ - $ 509,290


Net income 9,182 9,182

Preferred Stock Redemption (28) 166 (764) (626)

Dividends declared on Preferred Stock of subsidiary (92) (92)


Investments 124 124


Common Stock Cancelled (16,862,087) (1,686) (349,828) (351,514)

Common Stock Issued 15,961,400 160 325,906 326,066

Treasury shares activity - net 1,907,203 90,141 428 90,569

Balance at December 31, 2013 15,961,400 $ 160 - $ - $ 325,906 $ - $ 238,119 $ 504 $ - $ 564,689


Net income 34,320 34,320


Investments 6 6


Balance at December 31, 2014 15,961,400 $ 160 - $ - $ 325,906 $ - $ 197,439 $ 510 $ - $ 524,015


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CENTRAL HUDSON STATEMENT OF INCOME (In Thousands) Year Ended December 31, 2014 2013 2012 Operating Revenues Electric $ 579,757 $ 532,539 $ 512,081 Natural gas 163,005 135,904 132,434 Total Operating Revenues 742,762 668,443 644,515Operating Expenses Operation: Purchased electricity and fuel used in electric generation 232,990 185,736 175,721 Purchased natural gas 78,765 51,342 49,276 Other expenses of operation 250,046 241,366 232,222 Depreciation and amortization 43,859 40,218 38,139 Regulatory Debits - 40,000 - Taxes, other than income tax 54,726 53,334 50,644 Total Operating Expenses 660,386 611,996 546,002Operating Income 82,376 56,447 98,513Other Income and Deductions Interest on regulatory assets and other interest income 4,355 5,838 6,127 Regulatory adjustments for interest costs 1,259 1,280 1,307 Other - net (214) 105 (330) Total Other Income 5,400 7,223 7,104Interest Charges Interest on long-term debt 22,031 23,570 23,008 Interest on regulatory liabilities and other interest 9,540 8,153 6,648 Total Interest Charges 31,571 31,723 29,656Income Before Income Taxes 56,205 31,947 75,961Income Tax Expense 22,361 11,648 28,791Net Income 33,844 20,299 47,170Preferred Stock Redemption Premium - 764 342Dividends Declared on Cumulative Preferred Stock - 92 624Income Available for Common Stock $ 33,844 $ 19,443 $ 46,204

CENTRAL HUDSON STATEMENT OF COMPREHENSIVE INCOME (LOSS) (In Thousands)

Year Ended

December 31,

2014 2013 2012 Net Income $ 33,844 $ 20,299 $ 47,170Other Comprehensive Income 1 - - -Comprehensive Income $ 33,844 $ 20,299 $ 47,170


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CENTRAL HUDSON STATEMENT OF CASH FLOWS (In Thousands)

Year Ended December 31,

2014 2013 2012 Operating Activities: Net income $ 33,844 $ 20,299 $ 47,170Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 40,702 37,589 35,765 Amortization 3,157 2,629 2,374 Deferred income taxes - net 10,976 8,812 27,154 Bad debt expense 6,645 3,484 5,616 Pension expense 20,597 20,601 22,767 OPEB expense 6,803 6,803 6,832 Positive Benefit Adjustment expense - 40,000 - Regulatory liability - rate moderation - - (1,107) Revenue decoupling mechanism recorded 3,245 2,774 (4,194) Regulatory asset amortization 4,554 4,554 4,610Changes in operating assets and liabilities - net: Accounts receivable, unbilled revenues and other receivables (9,162) (8,095) (4,942) Fuel, materials and supplies 1,086 632 1,773 Special deposits and prepayments (4,958) (1,988) (117) Income and other taxes (8,289) (7,522) 1,084 Accounts payable 12,396 (9,556) 3,080 Accrued interest (132) (33) (400) Customer advances (834) (3,083) 3,480 Pension plan contribution (16,986) (26,641) (28,579) OPEB contribution (2,238) (2,894) (3,269) Revenue decoupling mechanism collected (refunded) (5,105) 1,956 1,660 Regulatory asset - storm deferral (5,108) 3,450 (6,183) Regulatory asset - MGP site remediation 4,202 (1,453) 1,657 Regulatory asset - Temporary State Assessment 1,185 2,220 1,132 Deferred natural gas and electric costs (8,389) (9,726) (592) Other - net 16,427 12,564 15,346Net cash provided by operating activities 104,618 97,376 132,117Investing Activities: Additions to utility plant (113,190) (108,817) (108,290) Other - net 1,703 (6,370) (469)Net cash used in investing activities (111,487) (115,187) (108,759)Financing Activities: Redemption of long-term debt (14,000) (46,700) (36,000) Proceeds from issuance of long-term debt 30,000 46,700 72,000 Borrowings of short-term debt - net - - (1,500) Equity infusion - 40,000 - Redemption of Preferred Stock - (9,653) (12,180) Dividends paid to parent - CH Energy Group (5,000) (22,000) (22,000) Dividends paid on cumulative Preferred Stock - (92) (866) Other - net (207) (417) (981)Net cash provided by financing activities 10,793 7,838 (1,527)Net Change in Cash and Cash Equivalents 3,924 (9,973) 21,831Cash and Cash Equivalents - Beginning of Period 14,379 24,352 2,521Cash and Cash Equivalents - End of Period $ 18,303 $ 14,379 $ 24,352

Supplemental Disclosure of Cash Flow Information:

Interest paid $ 22,560 $ 24,024 $ 23,901

Federal and state income taxes paid $ 20,003 $ 10,370 $ - Additions to plant included in liabilities $ 7,495 $ 5,901 $ 10,893


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CENTRAL HUDSON BALANCE SHEET (In Thousands)

December 31, December 31,

2014 2013

ASSETS

Utility Plant

Electric $ 1,160,643 $ 1,118,552

Natural gas 380,966 356,627

Common 184,804 174,898

Gross Utility Plant 1,726,413 1,650,077

Less: Accumulated depreciation 458,155 434,410

Net 1,268,258 1,215,667

Construction work in progress 57,543 41,862

Net Utility Plant 1,325,801 1,257,529

Non-Utility Property and Plant 524 524

Net Non-Utility Property and Plant 524 524

Current Assets

Cash and cash equivalents 18,303 14,379

Accounts receivable from customers - net of allowance for doubtful accounts of $4.8 million and $3.9 million, respectively. 69,072 66,123

Accrued unbilled utility revenues 16,866 17,210

Other receivables 3,696 3,827

Fuel, materials and supplies - at average cost 17,546 18,632

Regulatory assets 56,272 37,626

Income tax receivable 12,668 4,379

Fair value of derivative instruments - 8,789

Unamortized debt expense 347 334

Special deposits and prepayments 25,418 20,460

Accumulated deferred income tax 5,603 3,280

Total Current Assets 225,791 195,039

Deferred Charges and Other Assets

Regulatory assets - pension plan 94,426 50,577

Regulatory assets - other 195,303 125,669

Fair value of derivative instruments 570 1,433

Unamortized debt expense 3,749 3,904

Other investments 26,856 26,067

Other 2,387 3,012

Total Deferred Charges and Other Assets 323,291 210,662

Total Assets $ 1,875,407 $ 1,663,754


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CENTRAL HUDSON BALANCE SHEET (CONT'D) (In Thousands, except share amounts)

December 31, December 31, 2014 2013

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 239,952 239,952

Retained earnings 216,456 187,612

Capital stock expense (4,633) (4,633)

Total Equity 536,086 507,242

Long-term debt 505,950 475,950

Total Capitalization 1,042,036 983,192

Current Liabilities

Current maturities of long-term debt - 14,000

Accounts payable 44,446 29,886

Accrued interest 5,618 5,750

Accrued vacation and payroll 6,400 6,773

Customer advances 14,167 15,001

Customer deposits 6,948 6,818

Regulatory liabilities 16,058 22,891

Fair value of derivative instruments 7,727 46


Other 15,992 12,027

Total Current Liabilities 130,701 114,425

Deferred Credits and Other Liabilities

Regulatory liabilities - OPEB 47,339 51,590

Regulatory liabilities - other 156,473 142,931

Operating reserves 4,118 2,426


Accrued OPEB costs 24,836 18,036

Accrued pension costs 67,952 17,497

Tax reserve 2,693 2,539

Other 17,870 18,373

Total Deferred Credits and Other Liabilities 414,879 292,961

Accumulated Deferred Income Tax 287,791 273,176

Commitments and Contingencies

Total Capitalization and Liabilities $ 1,875,407 $ 1,663,754


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CENTRAL HUDSON STATEMENT OF EQUITY (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, 2011 16,862,087 $ 84,311 - $ - $ 199,980 $ (4,961) $ 165,965 $ - $ 445,295

Net income 47,170 47,170

Preferred Stock Redemption 162 (342) (180)

Dividends declared

On cumulative Preferred Stock (624) (624)

On Common Stock to parent - CH Energy Group - (22,000) (22,000)


Net income 20,299 20,299

Preferred Stock Redemption (28) 166 (764) (626)

Dividends declared

On cumulative Preferred Stock (92) (92)

On Common Stock to parent - CH Energy Group (22,000) (22,000)

Additional Paid-in Capital 40,000 - 40,000


Net income 33,844 33,844

Dividends declared

On Common Stock to parent - CH Energy Group (5,000) (5,000)


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NOTES TO FINANCIAL STATEMENTS

NOTE 1 – Summary of Significant Accounting Policies

Corporate Structure CH Energy Group is the holding company parent corporation of three principal, wholly owned subsidiaries, Central Hudson Gas & Electric Corporation (“Central Hudson”), Central Hudson Electric Transmission LLC (“CHET”) and Central Hudson Enterprises Corporation (“CHEC”). Effective as of June 27, 2013, all of CH Energy Group’s common stock is indirectly owned by Fortis Inc. (“Fortis”), which is the largest investor-owned gas and electric distribution utility in Canada. Central Hudson is a regulated electric and natural gas subsidiary. CHET was formed to engage in transmission projects and has 6% ownership in New York Transco LLC (“Transco”). CHEC, the parent company of CH Energy Group’s non-regulated businesses and investments, had one wholly owned operating subsidiary during the first quarter of 2014, Griffith Energy Services, Inc. (“Griffith”). On March 4, 2014, CHEC completed the sale of Griffith to Star Gas Partners, L.P. Therefore, operating results of Griffith are reported as Discontinued Operations for all periods presented in the Consolidated CH Energy Group Statement of Income and as held for sale in the Consolidated CH Energy Group Balance Sheet as of December 31, 2013. See Note 5 – “Acquisitions, Investments and Divestitures” for further information. CHEC also has ownership interests in certain subsidiaries that are less than 100% owned. Basis of Presentation

This Annual Report 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, CHET and CHEC. Inter-company balances and transactions have been eliminated in consolidation. 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. 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 2013 and 2012 Financial Statements have been reclassified to conform to the 2014 presentation. For more information regarding reclassification of discontinued operations, see Note 5 – “Acquisitions, Investments and Divestitures.”

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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 included trademarks, covenants not to compete and customer relationships related to Griffith, prior to the sale in March 2014. These assets were amortized based on an assessment of customer attrition as described in Note 6 - “Goodwill and Other Intangible Assets.” These intangible assets were included in Assets held for sale as of December 31, 2013, in the CH Energy Group Consolidated Balance Sheet and the related amortization is included in Discontinued Operations in the 2013 and 2012 CH Energy Group Consolidated Statement of Income. There was no amortization of intangible assets recorded in 2014 under accounting guidance once the asset was designated as held for sale.

• Estimates for uncollectible accounts are based on customer accounts receivable aging data as well as consideration of various quantitative and qualitative factors, including special collection issues. In the current year, the increase in the allowance for doubtful accounts reflects the impact of higher energy prices experienced in the beginning of 2014.

• The tax reserve recorded by Central Hudson relates to a change in 2010 to its tax return methodology for claiming deductions for incidental repair and maintenance expenditures on its utility assets. Although Management believes that its methodology for claiming the deduction is consistent with the Internal Revenue Code and case law, Management cannot predict whether the Internal Revenue Service will accept the entirety of the deduction claimed. See Note 4 – “Income Tax” for further discussion of the tax reserve established.

• 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 include an estimate for unbilled revenues of $11.0 million for 2014 and $11.2 million for both 2013 and 2012. 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, 2014, 2013 and 2012 were $6.0 million, respectively.

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• 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 NYS 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.

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. Pursuant to regulatory requirements, a portion of unbilled electric revenues is not recorded. As of December 31, 2014, 2013 and 2012, the portion of estimated electric unbilled revenues that is unrecognized in accordance with current regulatory agreements was $13.1 million, $13.0 million and $13.2 million, respectively. The full amounts 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 Central Hudson are accounted for on a net basis (excluded from revenue). CH Energy Group’s deferred revenue balance as of December 31, 2013 was $4.7 million and related to Griffith. The December 31, 2013 balance was included in held for sale. There was no deferred revenue balance as of December 31, 2014 as a result of the sale of Griffith on March 4, 2014.

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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 Central Hudson

December 31, December 31, December 31, December 31, 2014 2013 2014 2013 Natural gas $ 6,323 $ 8,078 $ 6,323 $ 8,078Fuel used in electric generation 403 430 403 430Materials and supplies

(1) 10,820 10,124 10,820 10,124

Total $ 17,546 $ 18,632 $ 17,546 $ 18,632

(1) Petroleum products and propane of $3,857 and materials and supplies of $1,493 related to Griffith have been excluded from the CH Energy Group December 31, 2013 balances and designated as Assets held for sale under current accounting guidance in the CH Energy Group Consolidated Balance Sheet. For further details, see Note 5 - "Acquisitions, Investments and Divestitures."

Utility Plant - Central Hudson 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. 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 administrative costs, 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.

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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 2014 2013 Electric: Production 25-75 $ 37,964 $ 37,865 Transmission 28-70 274,155 260,669 Distribution 7-80 844,438 816,000 Other 37 4,086 4,018 Total $ 1,160,643 $ 1,118,552

Natural Gas: Transmission 18-70 53,800 51,716 Distribution 25-85 326,724 304,469 Other N/A 442 442 Total $ 380,966 $ 356,627

Common: Land and Structures 50 $ 66,750 $ 64,157 Office and Other Equipment, Radios and Tools 8-35 42,760 39,738 Transportation Equipment 10-12 53,936 50,962 Other 5 21,358 20,041 Total $ 184,804 $ 174,898

Utility Plant Intangible Assets Included in the Net Utility Plant balance of $1,326 million and $1,258 million at December 31, 2014 and 2013 is $50.9 million and $44.4 million of intangible utility plant assets and the related amortization of $23.0 million and $19.2 million, respectively. 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 4.6% in 2014, 5.00% in 2013, and 3.25% in 2012. The amounts recorded for borrowed funds for 2014 was $0.4 million, 2013 was $0.4 million and $0.3 million for 2012. The equity component of AFUDC recorded for the years 2014, 2013 and 2012 was $0.6 million, $0.6 million and $0.3 million, respectively.

Depreciation and Amortization

For financial statement purposes, Central Hudson’s depreciation provisions are computed on the straight-line method using rates based on studies of the estimated useful lives and estimated net salvage values of properties. The anticipated costs of removing assets upon retirement are 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.

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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. These depreciation rates include a charge for the cost of future removal and retirement of fixed assets. 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. In accordance with current accounting guidance related to asset retirements, Central Hudson has classified $47.8 million and $46.7 million of cost of removal as a regulatory liability as of December 31, 2014 and 2013, respectively. This liability represents the portion of the cost of removal charge in excess of the amount reported as an Asset Retirement Obligation under GAAP. 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 2.86% in 2014, 2.77% in 2013 and 2.79% in 2012 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, 2014, 2013, and 2012 was 26.6%, 26.4% and 26.8%, respectively.

See Note 6 - “Goodwill and Other Intangible Assets” for further discussion of amortization of intangibles (other than goodwill). Asset Retirement Obligations Asset retirement obligations (“AROs”) are recorded as a liability at fair value, with a corresponding increase to utility capital assets. Central Hudson recognizes AROs in the periods in which they are incurred if a reasonable estimate of fair value can be determined. The fair value of AROs is based on an estimate of the present value of expected future cash outlays, discounted at a credit-adjusted risk-free interest rate. AROs are adjusted at the end of each reporting period to reflect the passage of time and any changes in the estimated future cash flows underlying the obligation. Actual costs incurred upon the settlement of AROs are recorded as a reduction in the liabilities. As of December 31, 2014, and 2013 AROs for Central Hudson were approximately $1.2 million and $0.8 million, respectively. These amounts have been classified as “Other” long-term liabilities, with the offset to Utility Plant assets.

Research and Development Central Hudson is engaged in the conduct and support of research and development (“R&D”) activities, which are focused on the improvement of existing energy technologies and the development of new technologies for the delivery and customer use of energy. Central Hudson’s R&D expenditures were $3.3 million in 2014, $3.6 million in 2013 and $4.0 million in 2012. These expenditures were for internal research programs and for contributions to research administered by New York State Energy Research and Development Authority (“NYSERDA”), the Electric Power Research Institute, and other industry organizations. R&D expenditures are provided for in Central Hudson’s rates charged to customers for electric and

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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 and Griffith file state income tax returns in those states in which they conduct business. For more information, see Note 4 - “Income Tax.”

Equity-Based Compensation Through June 27, 2013, CH Energy Group had an equity-based employee compensation plan that is described in Note 11 - “Equity-Based Compensation.”

Parental Guarantees CH Energy Group issued a parental guarantee to Transco, to assure the payment, when due, of certain obligations incurred by CHET. The maximum potential payment under this agreement is $182 million. As of December 31, 2014, CHET does not have any project commitments to Transco. Management is not aware of any existing condition that would require payment under this guarantee. Common Stock Dividends 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 is currently restricted to a maximum annual payment of $26.6 million in dividends to CH Energy Group. 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. In addition, Central Hudson would not be allowed to pay dividends if its average common equity ratio for the 13 months prior to the proposed dividend were more than 200 basis points below the ratio used in setting rates.

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During the year ended December 31, 2014, the Board of Directors of Central Hudson authorized and Central Hudson paid dividends of $5.0 million to parent CH Energy Group. CH Energy Group’s other subsidiaries do not have express restrictions on their ability to pay dividends. See Note 8 - “Capitalization-Common and Preferred Stock” for information regarding dividends declared.

NOTE 2 – Regulatory Matters

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 other affiliates of CH Energy Group; (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 affiliates; (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.

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Summary of Regulatory Assets and Liabilities The following table sets forth Central Hudson’s regulatory assets and liabilities (In Thousands): December 31, December 31, 2014 2013

Regulatory Assets (Debits): Current: Deferred purchased electric and natural gas costs $ 29,482 $ 21,093 Deferred unrealized losses on derivatives - Electric (Note 14) 5,873 - Deferred unrealized losses on derivatives - Gas (Note 14) 1,854 46 Income taxes recoverable through future rates 381 -

PSC General and Temporary State Assessment and carrying charges 2,665 3,962

RDM and carrying charges - Electric 5,661 2,451 Residual natural gas deferred balances 27 4,554 Deferred debt expense on re-acquired debt 520 625

Deferred and accrued costs - MGP site remediation and carrying charges 4,605

4,605

Deferred storm costs and carrying charges 5,113 - Other 91 290 56,272 37,626 Long-term: Deferred pension costs 94,426 50,577 Carrying charges - pension reserve 16,904 13,264

Deferred and accrued costs - MGP site remediation and carrying charges 101,199

39,233

Deferred debt expense on re-acquired debt 4,458 4,978 Deferred Medicare Subsidy taxes 8,931 8,400 Residual natural gas deferred balances and carrying charges 1,130 1,060 Income taxes recoverable through future rates 34,740 37,223 Energy efficiency incentives 2,792 2,719 Deferred Property Taxes 4,019 2,090 Other 21,130 16,702 289,729 176,246 Total Regulatory Assets $ 346,001 $ 213,872

Regulatory Liabilities (Credits): Current: RDM and carrying charges - Gas 5,297 3,888 Deferred unrealized gains on derivatives - Electric (Note 14) - 8,465 Deferred unrealized gains on derivatives - Gas (Note 14) - 324 Income taxes refundable through future rates 4,799 4,209 Deferred unbilled gas revenues 5,962 6,005 16,058 22,891 Long-term: Customer benefit fund 6,271 6,505 Deferred cost of removal (Note 1) 47,832 46,655 Rate Base impact of tax repair project and carrying charges 13,402 12,336 Excess electric depreciation reserve carrying charges 1,586 1,586 Deferred unrealized gains on derivatives - Electric (Note 14) 570 1,433 Income taxes refundable through future rates 23,808 27,484 Deferred OPEB costs 47,339 51,590 Carrying charges - OPEB reserve 20,991 15,197 PBA - Electric and carrying charges 13,005 12,242 PBA - Gas and carrying charges 3,299 3,105 Other 25,709 16,388 203,812 194,521 Total Regulatory Liabilities $ 219,870 $ 217,412

Net Regulatory Assets/(Liabilities) $ 126,131 $ (3,540)

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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 over five years from July 1, 2009 through June 30, 2014. In 2013, the NYSA was extended through March 31, 2019. 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. Revenue Decoupling Mechanism: Effective July 1, 2009 and continuing in the 2010 Order Establishing Rate Plan issued by the PSC Central Hudson on June 18, 2010 (“2010 Rate Order”) and Order Authorizing Acquisition Subject to Conditions (“2013 Joint Petition”) through June 30, 2015, 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. The difference between actual revenues and forecasted revenues are deferred for further recovery from or refund to customers with the deferred balance subject to carrying charges at the Other Customer Deposit Rate approved annually by the PSC.

Residual Natural Gas Deferred Balances: As a result of the 2009 Order Establishing Rate Plan issued by the PSC to Central Hudson on June 22, 2009 (“2009 Rate Order”) and the 2010 Rate Order, 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 will be fully amortized in early 2015.

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. 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.

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Deferred Property Taxes: In accordance with the 2010 Rate Order, Central Hudson is authorized to defer for the benefit of or recovery from customers, 90% of any difference between actual property tax expense and the amounts provided in rates for each Rate Year. The Company portion is limited to 10% and a maximum of $0.8 million per Rate Year. These deferrals continue per the 2013 Joint Petition. Income Taxes Recoverable: This regulatory asset has been established to offset deferred tax liabilities because Management believes it is probable that they will be recoverable from customers. Energy Efficiency Incentives: In 2008, Central Hudson received approval through the Energy Efficiency Portfolio Standard (“EEPS”) proceedings to implement various programs for electric and natural gas residential and commercial customers. In December 2010, the PSC issued an order combining energy savings targets to create a single 2009-2011 target and continuing the system of utility shareholder financial incentives established in the EEPS proceeding. As of December 31, 2011, Central Hudson earned $2.7 million in incentives under the 2009-2011 defined targets. In 2012, the PSC issued a separate order establishing a single target for 2012-2015. Under this program, Central Hudson has the potential to earn a maximum of $2.6 million ($2.3 million for electric and $0.3 million for gas) during 2015 if all targets are met by December 31, 2015. As of December 31, 2014, Central Hudson had earned approximately $0.1 million in incentives under the 2012-2015 defined targets. 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. As of December 31, 2014, Central Hudson has deferred $5.1 million of incremental costs incurred for the restoration of electric service to customers following the impact of the November 27, 2014 storm (“SnowBird”). This deferred amount represents Management’s best estimate of recoverable incremental restoration costs based on actual bills received, a reasonable estimate for bills outstanding (including sales tax) and the estimated Net Income Available and rate of return on common equity for the rate year ended June 30, 2015. Central Hudson will file a petition with the PSC in 2015 seeking Commission approval to recover the incremental electric storm restoration expense associated with SnowBird, with carrying charges subject to the criteria the PSC has established for consideration and approval of previous deferral authorization requests. Positive Benefit Adjustment (“PBA”): Under the 2013 Joint Petition, a $35 million PBA was established to cover expenses normally required to be recovered from ratepayers. In accordance with the order, storm restoration costs of approximately $20.1 million, for storm costs associated with Tropical Storm Irene, the October 2011 snow storm and Superstorm Sandy were offset by the PBA. Income Taxes Refundable: This regulatory liability was established to offset deferred tax assets because Management believes 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.

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Rate Base Impact of Tax Repair Project: In April 2011, the PSC approved the ratemaking treatment to offset certain incremental storm costs and incremental bad debt expense deferrals with tax refunds resulting from a change in tax return methodology for claiming deductions for incidental repair and maintenance expenditures on its utility assets. 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. Excess Electric Depreciation Reserve (“EDR”): Under the 2006 Rate Order, a $40M regulatory liability balance was established and was subject to carrying charges at the pre-tax weighted average cost of capital. Under the 2006, 2009 and 2010 Rate Order, this balance was approved for use in rate moderation. As of December 31, 2014 and 2013, the EDR regulatory liability has been fully utilized, however, the carrying charges accumulated remain as a regulatory liability balance.

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, 2014, reflect the following (In Thousands):

December 31,

2014 Balances with offsetting accrued liability balances recoverable when future costs are actually incurred: Deferred pension related to underfunded status $ 98,911 Income taxes recoverable through future rates 35,121 Deferred unrealized losses on derivatives 7,727 Deferred costs - MGP sites 106,943 Deferred Medicare Subsidy taxes 8,931 Other 5,501 263,134Balances earning a return via inclusion in rates and/or the application of carrying charges: Deferred property taxes 3,603 PSC - General and temporary state assessment 2,565 Deferred storm costs 5,108 Deferred debt expense on re-acquired debt 4,978 Other

(1) 11,527

27,781Subject to current recovery: Deferred purchased electric and natural gas costs 29,483 RDM 5,609 Other 27 35,119Other: Energy efficiency incentives

(1) 2,791

Other 378 3,169Accumulated carrying charges:

(1)

Pension reserve 16,903 Other 3,494 20,397 Total Regulatory Assets $ 349,600

(1) Subject to recovery in Central Hudson's future rate proceedings.

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2010 Rate Order and 2013 Joint Petition

From July 1, 2010 through June 30, 2013, Central Hudson operated under the terms of the 2010 Rate Order. On June 26, 2013 the PSC issued its Order Authorizing Acquisition Subject to Conditions in Case 12-M-0192 (the “2013 Joint Petition”), which was accepted on June 27, 2013. The Order adopted the terms of the Joint Proposal dated January 25, 2013 for the acquisition of CH Energy Group, owner of Central Hudson, by Fortis along with additional commitments by the companies to enhance financial protection for ratepayers and other community and economic development benefits. A summary of the key terms of the 2010 Order and the 2013 Joint Petition are as follows:

Description

2010 Rate Order 2013 Joint Petition

Electric delivery revenue increases $9.1 million 7/1/12 $0 effective 7/1/13(6)

Natural gas delivery revenue increases $1.6 million 7/1/12 $0 effective 7/1/13(6)

ROE 10.00% 10.00%

Earnings sharing Yes(1)

Yes(7)

Capital structure – common equity 48% 48%

Positive benefit adjustments N/A $35.0 million(8)

Community benefit fund N/A $5.0 million(8)

Synergy Savings N/A $1.85 million(9)

Targets with true-up provisions - % of revenue requirement to defer for shortfalls

Net plant balances 100% 100%

Transmission and distribution ROW maintenance 100% 100%

RDMs – electric and natural gas(2)

Yes Yes

New deferral accounting for full recovery

Fixed debt costs Yes(3)

N/A(10)

Transmission sag mitigation Yes N/A(10)

New York State Temporary Assessment Yes N/A(10)

Material regulatory actions Yes(4)

N/A(10)

Property taxes – Deferral for 90% of excess/deficiency relative to revenue

requirement Yes

(5) N/A

(10)

(1) ROE > 10.5%, 50% to customers, > 11.0%, 80% to customers, > 11.5%, 90% to customers. (2) Electric is based on revenue dollars; gas is based on usage per customer. (3) Deferral authorization in RY2 and RY3 only. (4) Legislative, governmental or regulatory actions with individual impacts greater than or equal to 2% of net income of the applicable

department. (5) The Company’s pre-tax gain or loss limited to $0.8 million per rate year. (6) There is a rate freeze on Central Hudson electric and gas delivery rates through July 1, 2015. (7) ROE > 10.0% and up to 10.5%, 50% to customers, > 10.5%, 90% to customers. (8) To cover expenses normally required by rate payers, such as storm restoration costs and for economic development and low-income

customer assistance programs. (9) Guaranteed annual synergy savings of $1.85 million to ratepayers for 5 years. (10) There were no new deferrals granted in the 2013 Joint Petition.

Other PSC Proceedings On October 29, 2012, Central Hudson’s service territory was impacted by Superstorm Sandy, and approximately 103,000 electric customers were affected. On April 2, 2014 the PSC issued an Order authorizing deferral of $9.965 million of the Sandy incremental storm restoration expenses, with carrying charges which had been deferred on Central Hudson’s books. On April 22, 2013, the PSC issued Orders approving deferral of $8.9 million and denying deferral of $3.7 million of the incremental electric storm restoration expense related to Tropical

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Storm Irene and the October 2011 snowstorm, respectively. On May 22, 2013, Central Hudson filed a petition for reconsideration and rehearing on these Orders challenging the exclusion of Central Hudson’s normalization adjustments used to measure earnings and seeking recovery of $3.7 million that was denied. On April 2, 2014 the PSC issued an Order affirming the previous Irene and October snowstorm PSC Orders and denying Central Hudson’s rehearing petitions. In February 2014, the PSC issued an Order requiring risk assessments and remediation of certain NYS gas facilities to identify conditions similar to those found in a natural gas explosion that occurred in Horseheads, New York in 2011. In May 2014, the PSC issued a modifying Order in this proceeding extending the requirement for utilities to complete risk assessments until February 2015 and to include a requirement effective August 2014 for utilities to report to Staff on the progress of their risk assessments every 45 days. On December 5, 2014, the Central Hudson filed a request for an extension of the deadline for submitting its Risk Assessment until September 30, 2015. Deferral of those incremental costs was authorized in the Joint Proposal in Case 09-E-0588, extended for two additional rate years in Case 12-M-0192 and is subject to Central Hudson satisfying the PSC’s normal criteria for deferral accounting treatment.

On June 30, 2014, Central Hudson notified the PSC that it will defer the incremental costs (including internal labor costs) it incurs through June 30, 2015, the period covered by the 2013 Joint Petition, in complying with FERC’s new Bulk Electric System regulations. Central Hudson also notified the PSC that it will defer the carrying charges on the amounts deferred (net of taxes) at the rate authorized by the PSC. Deferral of those incremental costs was authorized in the Joint Proposal in Case 09-E-0588, extended for two additional rate years in Case 12-M-0192 and is subject to Central Hudson satisfying the PSC’s normal criteria for deferral accounting treatment. On October 24, 2014, the Commission issued an Order Allocating Property Tax Refund approving the terms of the Central Hudson and New York State Department of Public Service Staff (“Staff”) Joint Proposal filed with the PSC June 13, 2014 regarding the disposition of property tax refunds received by Central Hudson. The Joint Proposal calls for the sharing of the refund, including interest, after deducting cost-to-achieve, on an 85%/15% customer/Company basis. The Company has deferred 85% of the net refund for future pass back to customers.

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NOTE 3 - New Accounting Guidance Newly adopted and soon to be adopted accounting guidance is summarized below, including explanations for any new guidance issued in 2014 (except that which is not currently applicable) and the expected impact on CH Energy Group and its subsidiaries.

Impact Category Accounting Reference Title

Issued Date

Effective Date

1

Liabilities (Topic 405)

ASU No. 2013-04 Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date

Feb-13 Jan-14

2

Income Taxes (Topic 740)

ASU No. 2013-11 Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

Jul-13 Jan-14

3

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (Topic 360)

ASU No. 2014-08 Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

April-14 Jan-15

3

Going Concern (Subtopic 205-40)

ASU No. 2014-15 Presentation of Financial Statements- Going Concern, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern

Aug-14 Jan-16

4

Revenue from Contracts with Customers (Topic 606)

ASU No. 2014-09 Revenue from Contracts with Customers

May-14 Jan-17

5

Compensation-Stock Compensation (Topic 718)

ASU No. 2014-12 Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period

Jun-14 Jan-16

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. Additional disclosures have been added or presentation of information modified where required.

(2) No material impact on the financial condition and no current impact on the results of operations and cash flows of CH Energy Group and its subsidiaries when adopted on the effective date noted. See Note 4 – “Income Tax” for additional details.

(3) No anticipated impact on the financial condition, results of operations and cash flows of CH Energy Group and its subsidiaries upon future adoption.

(4) CH Energy Group and its subsidiaries are assessing the impact that the adoption of this standard will have on the financial condition, results of operations and cash flows.

(5) CH Energy Group and Central Hudson have adopted this ASU early resulting from the election of two CH Energy Group officers to resign under change in control agreements. The impacts are reflected in the compensation expense related to performance share units in Note 11 - "Equity-Based Compensation."

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NOTE 4 – Income Tax

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 ending December 31, 2009. This change allows Central Hudson to take a current tax deduction for a significant amount of repair costs that were 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 Federal NOL for CH Energy Group was carried forward and the balance fully utilized in 2014. Central Hudson fully utilized its Federal NOL carryforward in 2013. As of December 31, 2014, CH Energy Group has fully utilized its NYS NOL carryforward and Central Hudson has a NYS NOL carryforward of approximately $18.6 remaining, which will expire at the end of 2030. Management believes future taxable income will more likely than not be sufficient to utilize all of the tax carryforward prior to its 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. In September 2012, Central Hudson filed corporate income tax returns for the year ended December 31, 2011. With that filing, Central Hudson included an election to adopt the provisions of Revenue Procedure 2011-43 (“Rev Proc”), which provided IRS guidance related to the repair deduction previously taken on electric transmission and distribution property. As such, tax reserves related to the electric transmission and distribution repair deductions, which were established prior to issuance of the Rev Proc, were reclassified to deferred tax liability accounts.

IRS guidance with respect to repairs taken on Gas Transmission and Distribution repairs is still pending. Therefore, remaining reserves related to the gas repair deduction continue to be shown as “Tax Reserve” under the Deferred Credits and Other Liabilities section of the Central Hudson Balance Sheet.

Other than the uncertain tax position related to Central Hudson’s accounting method change for gas transmission and distribution repairs, there are no other uncertain tax positions. Increases to the tax reserve during 2013 and 2014 reflect the ongoing uncertainty related to Gas Transmission and Distribution repair deductions. The following is a summary of activity related to uncertain tax positions (In Thousands):


2014 2013

Tax reserve balance at the beginning of the period 1$ 2,539 $ 2,000

Adjustments related to tax accounting method change 154 539

Tax reserve balance at the end of the period $ 2,693 $ 2,539

Jurisdiction Tax Years Open for Audit

Federal 2011 – 2013

New York State(1)

2010 – 2013 (1) The NY State Department of Taxation and Finance has commenced an income tax audit for the years 2010-2012.

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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):


2014 2013 2012

Federal income tax $ 3,778 $ - $ -

State income tax 677 521 1,331

Deferred federal income tax 14,951 4,634 23,121

Deferred state income tax 790 2,419 375

Total income tax $ 20,196 $ 7,574 $ 24,827

Reconciliation - CH Energy Group

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,

2014 2013 2012

Net income from Continuing Operations $ 26,631 $ 4,734 $ 36,753

Federal income tax 3,778 - -

State income tax 677 521 1,331


Deferred state income tax 790 2,419 375

Income before taxes $ 46,827 $ 12,308 $ 61,580

Computed federal tax at 35% statutory rate $ 16,389 $ 4,308 $ 21,553

State income tax net of federal tax benefit 2,504 2,105 1,824

State income tax rate change (1,203) - -

Depreciation flow-through 4,009 2,968 3,052

Cost of Removal (2,347) (2,418) (2,297)

Nondeductible compensation expense 1,756 - -

Merger Transaction Costs (221) 1,169 3,545

Production tax credits - - (1,271)

Other (691) (558) (1,579)

Total income tax $ 20,196 $ 7,574 $ 24,827

Effective tax rate - federal 40.0% 37.6% 37.5%

Effective tax rate - state 3.1% 23.9% 2.8%

Effective tax rate - combined 43.1% 61.5% 40.3%

The higher than average effective tax rate for year ended December 31, 2014 is due to the impact of nondeductible compensation expense related to the election by two CH Energy Group officers to resign under Change in Control agreements. Net income before tax for the year ended December 31, 2013 includes the impact of the Positive Benefit Adjustment ("PBA") of $35 million and the Community Benefit Fund of $5 million recorded upon the closing of the Fortis transaction. The lower net income resulting from the impact of the PBA and Community

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Benefit Fund has also resulted in a further distortion of the effective rate for year ended

December 31, 2013.

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,

2014 2013

Accumulated Deferred Income Tax Asset:

Unbilled revenues $ 9,749 $ 8,305

Plant-related 8,967 9,033

Regulatory liability - future income tax 24,180 27,752

OPEB expense 41,551 38,465

NOL carryforwards - 8,666

PBA 6,459 6,080

Contributions in aid of construction 7,925 6,885

Directors and officers deferred compensation 6,317 6,437

Other 33,872 21,252

Accumulated Deferred Income Tax Asset 139,020 132,875

Accumulated Deferred Income Tax Liability:

Depreciation 254,907 238,277

Repair allowance 8,852 9,265

Pension expense 18,387 19,657

Change in tax accounting for repairs 62,430 55,590

Regulatory asset - future income tax 28,642 29,970

Residual deferred gas balance 11 1,815

PSC assessments 902 1,321

Cost of removal 5,469 5,766

Electric fuel costs 7,649 4,771

Pension reserve carrying charges 6,697 5,255

Revenue decoupling mechanism 2,222 950

Gas costs 3,109 4,012

Storm deferrals 2,024 -

Other (1)

11,702 19,946

Accumulated Deferred Income Tax Liability 413,003 396,595

Net Deferred Income Tax Liability 273,982 263,720

Net Current Deferred Income Tax Asset (1)

(11,955) (12,941)

Net Long-term Deferred Income Tax Liability $ 285,937 $ 276,661

(1) At December 31, 2013, a current deferred tax asset of $412 and a deferred tax liability of $2,737 associated with Griffith, are excluded from the chart above and included as "Assets held for sale" in the CH Energy Group Consolidated Balance Sheet. See Note 5 "Acquisitions, Investments and Divestitures" for further details.

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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):


2014 2013 2012

Federal income tax $ 10,718 $ 1,544 $ -

State income tax 667 1,292 1,637


Deferred state income tax 1,055 553 2,042

Total income tax $ 22,361 $ 11,648 $ 28,791

Reconciliation - Central Hudson

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, 2014 2013 2012 Net income $ 33,844 $ 20,299 $ 47,170Federal income tax 10,718 1,544 -State income tax 667 1,292 1,637Deferred federal income tax 9,921 8,259 25,112Deferred state income tax 1,055 553 2,042 Income before taxes $ 56,205 $ 31,947 $ 75,961

Computed federal tax at 35% statutory rate $ 19,672 $ 11,181 $ 26,586State income tax net of federal tax benefit 2,692 1,393 3,106State income tax rate change (1,203) - -Depreciation flow-through 4,009 2,968 3,052 Cost of Removal (2,347) (2,418) (2,297)Other (462) (1,476) (1,656) Total income tax $ 22,361 $ 11,648 $ 28,791

Effective tax rate - federal 36.7% 30.7% 33.1% Effective tax rate - state 3.1% 5.8% 4.8% Effective tax rate - combined 39.8% 36.5% 37.9%

On March 31, 2014, New York State enacted into law a corporate income tax rate reduction from the current 7.1% to 6.5%, effective January 1, 2016. The resulting one-time adjustment to long term NYS tax liabilities to reflect this change has decreased the effective NYS tax rate for the year ended December 31, 2014. Net income before tax for the year ended December 31, 2013, included the impact of the Positive Benefit Adjustment ("PBA") of $35 million and the Community Benefit Fund of $5 million recorded upon the closing of the Fortis transaction. The lower net income resulting from the impact of the PBA and Community Benefit Fund have resulted in a distortion of the effective rate for 2013.

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The following is a summary of the components of deferred taxes as reported in Central Hudson’s Balance Sheet (In Thousands): December 31,

2014 2013

Accumulated Deferred Income Tax Asset:

Unbilled revenues $ 9,749 $ 8,305

Plant-related 8,967 9,033

OPEB expense 41,551 38,465

NOL carryforwards(1)

541 1,817

PBA 6,459 6,080

Contributions in aid of construction 7,925 6,885

Regulatory liability - future income tax 24,180 27,752

Directors and officers deferred compensation 6,317 6,437

Other 25,126 18,440

Accumulated Deferred Income Tax Asset 130,815 123,214 Accumulated Deferred Income Tax Liability:

Depreciation 254,907 238,277

Repair allowance 8,852 9,265

Pension expense 18,387 19,657

Change in tax accounting for repairs 62,430 55,590

Regulatory asset - future income tax 28,642 29,970 Residual deferred gas balance 11 1,815

PSC assessments 902 1,321

Cost of removal 5,469 5,766

Electric fuel costs 7,649 4,771

Pension reserve carrying charges 6,697 5,255

Revenue decoupling mechanism 2,222 950

Gas costs 3,109 4,012

Storm deferrals 2,024 -

Other 11,702 16,461

Accumulated Deferred Income Tax Liability 413,003 393,110

Net Deferred Income Tax Liability 282,188 269,896

Net Current Deferred Income Tax Asset (5,603) (3,280)

Net Long-term Deferred Income Tax Liability $ 287,791 $ 273,176(1)

Under ASU No. 2013-11, the presentation of uncertain tax positions when a NOL carryforward exists should be netted with the NOL carryforward. As of December 31, 2014, approximately $0.3 million of uncertain tax positions have been netted with the NOL carryforward presented above.

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NOTE 5 – Acquisitions, Investments and Divestitures

Acquisitions During the year ended December 31, 2012, Griffith acquired five fuel distribution companies with a total purchase price of $3.5 million, total intangible assets of $3.1 million, including goodwill of $1.5 million and total tangible assets of $0.4 million. There were no additional acquisitions made by CH Energy Group or Central Hudson for the years ended December 31, 2014, 3012 and 2012. Divestitures During the first quarter of 2014, CHEC divested Griffith. The results of operations of Griffith for the 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 those investments with those from continuing operations in the CH Energy Group Consolidated Statement of Cash Flows. The details of the sale transaction are as follows (In Thousands): Griffith Date of Sale 3/4/2014 Assets: Cash $ 4,151 Accounts Receivable, net of allowance 47,170 Fuel, Materials and Supplies 5,228 Other Current Assets 6,656 Total Current Assets 63,205 Net Intangibles 48,660 Other Assets 1,227 Property, Plant and Equipment: Property, plant and equipment 34,711 Less: Accumulated depreciation 24,235 Total property, plant and equipment, net 10,476 Assets sold $ 123,568 Liabilities: Accounts Payable $ 10,933 Deferred Revenue 4,448 Accrued Expenses 2,325 Accrued Vacation and Payroll 2,027 Other Current Liabilities 6,765 Total Current Liabilities 26,498 Other Liabilities 4,898 Liabilities sold $ 31,396 Net Assets Sold $ 92,172Net Proceeds from Sale $ 100,208Pre-tax gain on sales transaction $ 8,036Net Increase to Earnings $ 3,153

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Investments

The value of CHEC's investments as of December 31, 2014 and December 31, 2013 are as follows (In Thousands): Intercompany Debt Equity Investment

CHEC Investment Description 2014 2013 2014 2013 Griffith Energy Services

100% controlling interest in a fuel distribution business $ - $ 30,000 $ - $ 38,971

CH-Community Wind 50% equity interest in a joint venture that owns 18% interest in two operating wind projects 1 - - - -

Other Partnerships and an energy sector venture capital fund

-

- 1,653

2,082

$ - $ 30,000 $ 1,653 $ 41,053

The table below provides additional detail of the financial results of the discontinued operations (In Thousands):

Year Ended

December 31,

2014 2013 2012

Revenues from discontinued operations $ 85,856 $ 298,367 $ 280,205

Income from discontinued operations before tax 6,908 7,540 5,246

Gain from sale of discontinued operations 8,036 - -

Income tax expense from discontinued operations 7,255 3,092 2,152

In 2013, Management commenced with a plan to evaluate and potentially divest Griffith.

Based on the bids received and status of due diligence and negotiations at that time,

Management had concluded that as of December 31, 2013, the sale of Griffith was probable to

close within the next 12 months. As such, the assets and liabilities of Griffith as of December

31, 2013 were recorded at the lower of the carrying value or fair value less costs to sell and

reported as held for sale in the Consolidated CH Energy Group Balance Sheet as of December

31, 2013.

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Below are the major classes of assets and liabilities related to the sale of Griffith designated as held for sale at December 31, 2013 (In Thousands):

December 31,

2013 ASSETS

Current Assets Cash $ 2,457 Accounts receivable from customers-net of $1.9 million allowance for doubtful accounts 30,399 Other receivables 2,609 Fuel, materials and supplies 5,351 Accumulated deferred income tax 412 Fair value of derivative instruments 9 Prepaid income taxes 777 Other current assets 2,792 Total current assets 44,806 Property, Plant and Equipment Property, plant and equipment 34,643 Less: Accumulated depreciation 24,297 Total property, plant and equipment, net 10,346 Other Assets Goodwill 38,981 Other intangible assets - net 9,679 Other 1,339 Total other assets 49,999 Assets held for sale $ 105,151

LIABILITIES Current Liabilities Accounts payable $ 8,296 Accrued vacation and payroll 1,390 Customer advances 7,079 Deferred revenue 4,659 Accrued environmental remediation costs 356 Customer deposits 53 Accumulated deferred income tax 2,737 Other 3,559 Total current liabilities 28,129 Other Liabilities Operating reserves 770 Accrued environmental remediation costs 690 Other 294 Total other liabilities 1,754 Liabilities held for sale $ 29,883

CHEC’s remaining investments are not considered a part of the core business; however, management intends to retain these investments at this time. CH Energy Group formed CHET to engage in transmission projects. The first undertaking of CHET was becoming a member of Transco. CHET’s ownership interest in Transco is 6%. As of December 31, 2014, the value of CHET's investment in Transco is immaterial.

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NOTE 6 – Goodwill and Other Intangible Assets

On March 4, 2014, Griffith was sold, thereby, decreasing customer relationships, trademarks and covenants not to compete to zero.

The components of amortizable intangible assets and amortizable expenses of CH Energy Group are summarized as follows (In Thousands):

December 31, 2014

December 31, 2013

Gross Carrying

Amount Accumulated Amortization

Gross Carrying Amount

Accumulated Amortization

Customer relationships $ -1

$ - $ 37,709 $ 28,531

Trademarks -

- 318 32

Covenants not to compete -1

- 411 196

Total Amortizable Intangibles (1)

$ - $ - $ 38,438 $ 28,759

(1) December 31, 2013 balance reflected as "Assets held for sale" in the CH Energy Group Consolidated Balance Sheet. Amortization

related to customer relationships, trademarks and covenants not to compete under current accounting guidance ceased upon designation as held for sale at December 31, 2013.

Year Ended

December 31,

2014 2013 2012

Intangibles Amortization Expense(1)

$ - $ 2,645 $ 2,509

(1) Included in "Income from discontinued operations" on the CH Energy Group Consolidated Statement of Income.

NOTE 7 – Short-Term Borrowing Arrangements

Description CH Energy Group Central Hudson

Revolving Credit Facilities: (1)

Limit $100 million(2)

$150 million(3),(4)

Expiration October 19, 2015 October 19, 2016


(In Thousands) 2014 2013 2014 2013

Uncommitted Credit: (5)

None

Outstanding 1 1 $ - $ - (1) Providing committed credit.

(2) Participating banks in the credit facility are JPMorgan Chase Bank, N.A., Bank of America, N.A., HSBC Bank USA, N.A. and KeyBank National Association. If these lenders are unable to fulfill their commitments under these facilities, funding may not be available as needed.

(3) Pursuant to PSC authorization, through December 31, 2015, 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.

(4) Participating banks in the credit facility are 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. If these lenders are unable to fulfill their commitments under these facilities, funding may not be available as needed.

(5) To diversify cash sources and provide competitive options to minimize Central Hudson's cost of short-term debt.

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As of December 31, 2014 and December 31, 2013, CH Energy Group and Central Hudson had no borrowings outstanding under their committed and uncommitted short-term borrowing arrangements. The weighted average interest rate for 2014 and 2013 were 1.00% and 1.09%, respectively.

NOTE 8 – Capitalization – Common and Preferred Stock 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. On June 26, 2013, immediately prior to the completion of the Fortis acquisition and pursuant to the Order Authorizing Acquisition Subject to Conditions, Central Hudson issued one share of a new class of Limited Voting Junior Preferred Stock, $100 par value per share (“Junior Preferred Stock”), with no dividend rights. The share has a voting right solely with respect to whether Central Hudson may file a voluntary bankruptcy petition, a petition for receivership or institute any other liquidation or similar proceeding. On June 27, 2013, at the effective time of the closing of the Fortis acquisition, all shares of CH Energy Group Common Stock that immediately prior to the effective time were issued and outstanding or held in treasury, were cancelled and ceased to exist. Subsequently, 14,961,400 shares of new common stock, $0.01 par value per share, were issued to FortisUS, Inc. (“Fortis US”) which became the sole shareholder of CH Energy Group. Following the closing of the transaction, FortisUS purchased an additional one million shares of the new common stock of CH Energy Group for $65.0 million. In 2014, the Board of Directors of CH Energy Group declared and paid dividends of $75 million to FortisUS, the sole shareholder of CH Energy Group, as of June 27, 2013. In 2013 the Board of Directors of CH Energy Group declared dividends of $18.3 million, of which $10.0 million was paid to FortisUS. In January 2015, the Board of Directors of CH Energy Group declared dividends of $5.5 million, payable to FortisUS. The dividends were paid on January 30, 2015. In 2014, the Board of Directors of Central Hudson declared and paid dividends of $5 million to parent CH Energy Group. In 2013, Central Hudson paid $22.0 million of dividends to CH Energy Group. In January 2015, the Board of Directors of Central Hudson declared dividends of $5.5 million, payable to parent CH Energy Group. The dividends were paid on January 30, 2015. Other than the one share of a new class of Junior Preferred Stock mentioned above, Central Hudson has no outstanding preferred stock as of December 31, 2014.

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NOTE 9 - Capitalization - Long-Term Debt Details of CH Energy Group's and Central Hudson’s long-term debt are as follows (In Thousands): December 31,

Series Maturity Date 2014 2013 Central Hudson: Promissory Notes: 2004 Series D (4.73%)

(3) Feb. 27, 2014 - 7,000

2004 Series E (4.80%)(4)

Nov. 05, 2014 - 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 2006 Series E (5.76%)

(4) Nov. 17, 2031 27,000 27,000

1999 Series B(1),(2)

Jul. 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) Nov. 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 23,400

2011 Series G (4.707%)(6)

Apr. 01, 2042 10,000 10,000 2012 Series G (4.776%)

(6) Apr. 01, 2042 48,000 48,000

2012 Series G (4.065%)(6)

Oct. 01, 2042 24,000 24,000 2013 Series C (2.45%)

(7) Nov. 1, 2018 30,000 30,000

2013 Series D (4.09%)(7)

Dec. 2, 2028 16,700 16,700 2014 Series E

(7),(8) Mar. 30, 2024 30,000 -

505,950 489,950 Less: Current Portion - (14,000) Central Hudson Net Long-term debt $ 505,950 $ 475,950

CH Energy Group: Promissory Notes: 2009 Series A (6.58%) Apr. 17, 2014 $ - $ 6,500 2009 Series B (6.80%) Dec. 15, 2025 19,325 20,475 Less: Current Portion (1,230) (7,650)

CH Energy Group Net Long-term debt $ 524,045 $ 495,275

(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) Issued pursuant to a 2012 PSC Order approving the issuance by Central Hudson prior to December 31, 2015, of up to $250 million

of unsecured medium-term notes or other forms of long-term indebtedness. (8) Variable rate notes

In March 2014, Central Hudson issued $30 million of 10-year Series E notes with a floating interest rate of 3 month LIBOR plus 1%. Central Hudson used the proceeds from the sale of the 2014 Series E notes for refunding maturing long term debt, working capital and for general corporate purposes.

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To mitigate the potential cash flow impact from unexpected increases in short-term interest rates, Central Hudson purchased a 3-year interest rate cap that will expire on April 1, 2017. The rate cap has a notional amount equal to the outstanding principal amount of the 2014 Series E notes and is based on the quarterly reset of the LIBOR rate on the quarterly interest payment dates. Central Hudson would receive a payout if the LIBOR rate exceeds 4% at the start of any quarterly interest period during the term of the cap. See Note 14 – “Accounting for Derivative Instruments and Hedging Activities” for fair value disclosures related to this instrument.

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 14, 2012, the PSC authorized Central Hudson to enter into a multi-year committed credit up to $175 million and to issue up to $250 million of long-term debt through December 31, 2015. The Order authorized Central Hudson to issue the long-term debt to finance its construction expenditures, refund maturing long-term debt, redeem existing callable debt and preferred stock, and refinance its 1999 NYSERDA Bonds, Series B.

NYSERDA The principal amount of Central Hudson’s outstanding 1999 Series B NYSERDA Bonds totaled $33.7 million at December 31, 2014. These 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 of 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 NYSERDA Bonds, on March 27, 2014, Central Hudson purchased an interest rate cap. The rate cap is two years in length with a notional amount equal to the outstanding principal amount of the Series B bonds and will expire on April 1, 2016. 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. The rate cap replaced an expiring rate cap with substantially similar terms. See Note 14 – “Accounting for Derivative Instruments and Hedging Activities” for fair value disclosures related to this instrument.

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.

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Debt Covenants CH Energy Group’s $19.9 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.

NOTE 10 – Post-Employment Benefits

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. As of December 31, 2014, 36% of all active employees were not eligible to participate in the Retirement Plan. 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, 2014 and 2013 were $16.4 million and $26.0 million, respectively.

Overall, Central Hudson’s unfunded liability increased by approximately $51.5 million, resulting from an increase in plan liabilities of $106.2 million partially reduced by a $54.7 million increase in plan assets. The decrease in the plan’s discount rate coupled with the incorporation of new mortality table assumptions were the primary factors contributing to the increase to the plan liability. The increase in plan assets was primarily driven by the strength of the financial markets. Contributions for 2015 are expected to be approximately $8.3 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, December 31,

2014(1)

2013 Accrued pension costs $ 69,593 $ 18,083 (1)

Includes approximately $555K of accrued pension liability recorded at the Holding Company only as a result from the election of two CH Energy Group officers to resign under change in control agreements.

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These balances include the difference between the projected benefit obligation (“PBO”) for pensions and the market value of the pension assets, and any liability for the non-qualified Supplemental Executive Retirement Plan ("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):


2014(1)

2013

Prefunded pension costs prior to funding status adjustment $ 29,317 $ 26,311Additional liability required (98,910) (44,394)

Total accrued pension costs $ (69,593) $ (18,083)

Total offset to additional liability - Regulatory assets - Pension Plan $ 98,910 $ 44,394

(1) Includes approximately $555K of accrued pension liability recorded at the Holding Company only as a result from the election of two CH Energy Group officers to resign under change in control agreements.

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 at December 31, 2014 and 2013, using discount rates of 3.9% and 4.6% respectively, as determined from the Mercer Pension Discount Yield Curve reflecting projected pension cash flows. A 1.00% increase in the discount rate would decrease the projection of the pension PBO by approximately $83.5 million. 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.

The 2010 Rate Order includes an increase in the rate allowance for pension and Other Post Employment Benefits (“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.

Retirement Plan Estimates of Long-Term Rates of Return The expected long-term rate of return on the Retirement Plan assets for 2015 is 6.10%, net of investment expense. In determining the expected long-term rate of return on plan assets, Central Hudson considered forward-looking estimated returns evaluated in light of current economic conditions and based on internally consistent economic models. The expected long-term rate of return is a weighted average based on each plan's investment mix and the

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forward-looking estimated returns for each investment class. Central Hudson monitors actual performance against target asset allocations and adjusts actual allocations and targets in accordance with the Retirement Plan strategy. A 100 basis point decrease in the expected long-term rate of return would have increased the 2014 net periodic benefit cost by $5.5 million.

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. The investment policy also reduces the volatility of the plan’s funded status and the level of contributions by more closely aligning the characteristics of plan assets with liabilities. Due to market value fluctuations, Retirement Plan assets will require rebalancing from time to time to maintain the asset allocation within target ranges. Central Hudson cannot assure that the Retirement Plan’s return objectives or funded status objectives will be achieved. Asset allocation targets in effect for the twelve months ended December 31, 2014 as well as actual asset allocations as of December 31, 2014 and December 31, 2013 expressed as a percentage of the market value of the Retirement Plan’s assets, are summarized in the table below:

Asset Class December 31,

2014 Minimum Target

Average Maximum December 31,

2013

Equity Securities 49.5% 41% 50% 59% 52.2%

Debt Securities 48.5% 45% 50% 55% 45.3%

Other(1)

2.0% -% -% 10% 2.5%

(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.

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, 2014 and 2013, 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 12/31/14

% of Total

Market Value at 12/31/13

% of Total

Level 1:

Cash $ 2,798 0.5% $ 59 -% Level 2:

Investment Funds - Equities(1)

298,424 49.5 286,373 52.2 Investment Funds - Fixed Income

(1) 292,235 48.4 248,044 45.3

Cash Equivalents(2)

7,229 1.2 12,581 2.3 Other Investments 2,183 0.4 1,159 0.2

$ 602,869 100.0% $ 548,216 100.0%

(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.

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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 Yield Curve reflecting projected cash flows. The estimates of long-term rates of return and the investment policy and strategy for these plan assets are similar to those used for pension benefits previously discussed in this Note. The estimates of health care cost trend rates are based on a review of actual recent trends and projected future trends.

Central Hudson fully recovers its net periodic post-retirement benefit costs in accordance with the 1993 PSC Policy. Under these guidelines, the difference between the amounts of post-retirement benefits recoverable in rates and the amounts of post-retirement benefits determined by an actuarial consultant in accordance with current accounting guidance related to other post-employment benefits is deferred as either a regulatory asset or a regulatory liability, as appropriate.

Central Hudson’s liability (i.e. the under-funded status) for OPEB at December 31, 2014 and 2013, was $24.8 million and $18.0 million, respectively. The cumulative amount of net periodic benefit cost in excess of employer contributions at December 31, 2014 and December 31, 2013 was $51.5 million and $60.3 million, respectively. The difference between these amounts, $26.7 million at December 31, 2014 and $42.3 million at December 31, 2013, 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 sponsors a 401(k) retirement plan (“401(k) plan”) for its employees. The 401(k) plan provides 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. The costs of Central Hudson’s matching contributions were $2.5 million for 2014, $2.3 million for 2013 and $2.1 million for 2012. Central Hudson also provides an additional contribution of 3% to the 401(k) plan of annualized base salary for eligible employees who do not qualify for Central Hudson’s Retirement Income Plan.

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OPEB Estimates of Long-Term Rates of Return The expected long-term rate of return on OPEB assets for 2015 is 6.94%, net of investment expense. In determining the expected long-term rate of return on plan assets, Central Hudson considered forward-looking estimated returns for each asset class evaluated in light of current economic conditions. The expected long-term rate of return is a weighted average based on each plan's investment mix and the forward-looking estimated returns for each investment class. A 100 basis point decrease in the expected long-term rate of return would have increased the 2014 net periodic benefit cost by $1.1 million. Central Hudson monitors actual performance against target asset allocations and adjusts actual allocations and targets as deemed appropriate in accordance with the OPEB 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:

Due to market value fluctuations, the OPEB Plan assets require periodic rebalancing from time to time to maintain the asset allocation within target ranges.

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.

Asset Class

December 31, 2014

Minimum

Target Average

Maximum

December 31, 2013

Equity Securities 64.9% 55% 65% 75% 65.9% Debt Securities 34.8% 25% 35% 45% 33.8% Other 0.3% - % - % - % 0.3%

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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, 2014 and 2013, 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)


% of Total


% of Total

Level 1: Cash $ 97 0.5% $ 2 -% Level 2: Investment Funds - Equities

(1) 10,372 49.5 9,229 52.2

Investment Funds - Fixed Income(1)

10,156 48.4 7,993 45.3 Cash Equivalents

(2) 251 1.2 405 2.3

Other Investments 76 0.4 37 0.2 $ 20,952 100.0% $ 17,666 100.0% (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.

Union VEBA Plan Assets (Dollars In Thousands)


% of Total


% of Total

Level 1:

Investment Funds - Money Market Mutual Fund $ 265 0.3% $ 244 0.3%

Investment Funds - Fixed Income Mutual Funds 20,056 20.1 18,899 19.6

Investment Funds - Equity Securities Mutual Funds 44,692 44.9 43,688 45.4

Level 2:(1)

1

Fixed Income Commingled Fund 14,597 14.7 13,679 14.2

Investment Funds - Equity Securities Commingled Fund 19,955 20.0 19,726 20.5

$ 99,565 100.0% $ 96,236 100.0%

(1) The Level 2 funds do not have market data available; however, the underlying securities held by those funds do have published market data available.

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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

2014 2013 2014 2013

Change in Benefit Obligation:

Benefit obligation at beginning of year $ 566,299 $ 608,327 $ 131,938 $ 157,362

Service cost 10,720 12,291 2,098 2,670

Interest cost 25,764 22,928 5,671 5,261

Participant contributions - - 778 759

Plan amendments - 5,419 - -

Special Termination Benefits 555 - - -

Benefits paid (31,557) (27,278) (6,026) (6,105)

Actuarial (gain)/loss 100,681 (55,388) 10,894 (28,009)

Benefit Obligation at End of Plan Year $ 672,462 $ 566,299 $ 145,353 $ 131,938

Change in Plan Assets:

Fair Value of plan assets at beginning of year $ 548,216 $ 494,442 $ 113,902 $ 98,950

Adjustment / other - (24) - 24

Actual return on plan assets 70,872 55,936 9,709 17,448

Employer contributions 16,986 26,658 2,238 2,894

Participant contributions - - 778 759

Benefits paid (31,557) (27,278) (6,026) (6,105)

Administrative expenses (1,648) (1,518) (84) (68)

Fair Value of Plan Assets at End of Plan Year $ 602,869 $ 548,216 $ 120,517 $ 113,902

Reconciliation of Funded Status:

Funded Status at end of year $ (69,593) $ (18,083) $ (24,836) $ (18,036)

Amounts Recognized on Balance Sheet:

Current liabilities $ (1,086) $ (586) $ - $ -

Noncurrent liabilities (68,507) (17,497) (24,836) (18,036)

Net amount recognized on Balance Sheet (69,593) (18,083) (24,836) (18,036)

Regulatory asset:

Net (gain)/loss 90,144 34,009 (4,617) (14,365)

Prior service costs (credit) 8,766 10,385 (22,084) (27,920)

Components of Net Periodic Benefit Cost:

Service cost $ 10,720 $ 12,291 $ 2,098 $ 2,670

Interest cost 25,764 22,928 5,671 5,261

Special Termination Benefits 555 - - -

Expected return on plan assets (34,818) (30,792) (7,953) (7,098)

Amortization of prior service cost (credit) 1,618 1,731 (5,836) (5,859)

Amortization of transitional obligation - - - 6

Amortization of actuarial net loss (gain) 10,141 19,362 (463) 3,862

Net Periodic Benefit Cost $ 13,980 $ 25,520 $ (6,483) $ (1,158)

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Pension Benefits Other Benefits

2014 2013 2014 2013 Other Changes in Plan Assets and Benefit Obligation Recognized in Regulatory Assets:

Net (gain)/loss $ 66,276 $ (78,989) $ 9,285 $ (37,965)

Amortization of actuarial net (loss) gain (10,141) (19,362) 463 (3,862)

Prior service credit - 5,419 - -

Amortization of prior service (cost) credit (1,618) (1,731) 5,836 5,859

Amortization of transitional obligation - - - (6)

Total recognized in regulatory asset $ 54,517 $ (94,663) $ 15,584 $ (35,974)Total recognized in net periodic benefit cost and regulatory asset $ 68,497 $ (69,143) $ 9,101 $ (37,132)Weighted-average assumptions used to determine benefit obligations:

Discount rate 3.90% 4.60% 3.90% 4.60%

Rate of compensation increase (average) 4.00% 4.00% 4.00% 4.00%

Measurement date 12/31/14 12/31/13 12/31/14 12/31/13Weighted-average assumptions used to determine net periodic benefit cost for years ended December 31:

Discount rate 4.60% 3.80% 4.60% 3.70%

Expected long-term rate of return on plan assets 6.50% 6.25% 7.09% 7.33%

Rate of compensation increase (average) 4.00% 4.00% 4.00% 4.00%

Assumed health care cost trend rates at December 31:

Health care cost trend rate assumed for next year N/A N/A 7.33% 7.60%

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 2029Pension plans with accumulated benefit obligations in excess of plan assets:

Projected benefit obligation $ 672,463 $ 566,299 N/A N/A

Accumulated benefit obligation $ 618,196 $ 522,067 N/A N/A

Fair Value of plan assets $ 602,869 $ 548,216 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 $16.2 million and $1.6 million, respectively. The estimated net gain and prior service credit 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 $0.1 million and $5.7 million, respectively. The amount of transitional obligation to be amortized from regulatory assets is immaterial.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A 1% change in assumed health care cost trend rates would have the following effects (In Thousands):

One Percentage Point

Increase Decrease

Effect on total of service and interest cost components for 2014 $ 321 $ (280)

Effect on year-end 2014 post-retirement benefit obligation $ 3,746 $ (3,320)

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For 2014, the PBO for Central Hudson’s obligation for OPEB costs was determined using a 3.9% discount rate. This rate was determined using the Mercer Pension Discount Yield Curve reflecting projected cash flows. A 1.0% increase in the discount rate would have decreased the projection of the OPEB obligation by approximately $17.9 million. Central Hudson’s contributions for OPEB totaled $2.2 million and $2.9 million during the years ended December 31, 2014 and 2013. 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. In January 2015, Central Hudson made a $1.5 million contribution for OPEB. No further contributions are expected for 2015.

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)

2015 $ 31,611 $ 6,946 $ 6,265

2016 32,436 7,229 6,510

2017 33,066 7,560 6,804

2018 33,796 7,906 7,115

2019 34,523 8,244 7,414

2020 - 2024 188,234 47,242 42,489

(1) Estimated benefit payments reduced by estimated gross amount of Medicare Act of 2003 subsidy receipts expected.

NOTE 11 – Equity-Based Compensation On June 25, 2013, prior to the completion of the acquisition of CH Energy Group by Fortis, the CH Energy Group, Inc. 2011 Long-Term Equity Incentive Plan (the “2011 Plan”) was terminated, and no new awards may be granted under such plan.

Immediately prior to the completion of the acquisition, all unvested awards (performance shares, restricted shares and restricted stock units) under the 2011 Plan became vested and were converted into the right to receive $65.00 per share. There were no awards outstanding under the 2011 Plan at the time of its termination.

Performance Share Units In January 2014, 78,536 Performance Share Units (“PSUs”) were granted to the officers of CH Energy Group and Central Hudson under the 2014 PSU Plan, representing a component of the officers’ long-term incentives, half of which are subject to performance based criteria with the remaining half vesting after 3 years without any correlation to performance. Each PSU represents a unit with an underlying value equivalent to the value of one common share of Fortis and is subject to a three-year vesting period, at which time a cash payment may be made, as determined by the Governance and Human Resource Committee of the Board of Directors. Each PSU accrues notional common share dividends equivalent to those declared by the Fortis Board of Directors. In the third quarter of 2014, 2,969 PSUs were forfeited following the resignation of an Officer.

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Compensation Expense The following table summarizes expense for equity-based compensation by award type for the years ended December 31, 2014, 2013 and 2012 (In Thousands): CH Energy Group Central Hudson

Year Ended December 31, Year Ended December 31,

2014 2013 2012 2014 2013 2012

Performance shares $ 1,390 $ 7,292 $ 3,589 $ 595 $ 1,222 $ 2,185

Restricted shares and stock units $ - $ 875 $ 455 $ - $ 134 $ 254Recognized tax benefit of restricted shares and stock units $ - $ 349 $ 182 $ - $ 54 $ 101

The liabilities associated with the PSU Plan are recorded at fair value at each reporting date until settlement, recognizing compensation expense over the vesting period on a straight line basis. The fair value of the PSU liabilities is based on the Fortis common share closing price at the end of each reporting period and the expected payout based on management's best estimate including analysis of historical performance in accordance with the defined metrics of the grant.

Under the PSU agreement, the amount of any outstanding awards payable to an employee who resigns for Good Reason, as defined in the employee's employment agreement, and who has 25 years or more of service with the Company is determined as if the employee continued to be an employee through the end of the performance period. In accordance with ASU 2014-12, in this situation, compensation expense for that individual is recognized over the requisite service period, instead of the performance period. As a result, 2014 PSU expense includes additional compensation expense to recognize the payment due to a CH Energy Group officer with outstanding awards who elected to resign for Good Reason under the officer's employment agreement, and who had over 25 years of service.

Prior to the acquisition of CH Energy Group by Fortis, compensation expense for performance shares was 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. The fair value of performance shares was 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 was recorded as performance shares were earned over the relevant three-year life of the performance share grant prior to its award. Compensation expense for restricted shares prior to the acquisition by Fortis was recognized over the defined vesting periods based on the grant date fair value of the awards.

Immediately prior to the completion of the acquisition of CH Energy Group by Fortis, all remaining unvested performance shares, restricted stock shares and restricted stock units vested were cancelled in exchange for cash payments. As a result of the acceleration, additional expense of $5.8 million related to performance shares and $0.7 million related to restricted shares and restricted stock units was recognized by CH Energy Group in the second quarter of 2013 and not allocated to its subsidiaries.

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Deferred Stock Units

Prior to the acquisition of CH Energy Group by Fortis Inc., CH Energy Group provided equity compensation for its non-employee Directors. Each Director was required 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 could be in the form of deferred stock units). Following the merger, non-employee directors no longer receive equity compensation.

Total equity compensation expense to non-employee Directors recognized by CH Energy Group was $0.3 million for the year ended December 31, 2013 and $0.6 million for the year ended December 31, 2012. There was no equity compensation expense to non-employee Directors for the year ended December 31, 2014.

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.”

NOTE 12 – Commitments and Contingencies Electricity Purchase Commitments

In 2010, Central Hudson entered into two 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. These contracts expired on December 31, 2013 and were not renewed. In 2014, Central Hudson entered into two agreements with Entergy Nuclear Power Marketing, LLC to purchase electricity on a unit contingent basis at defined prices from December 1, 2014 through March 31, 2015. For the month of December 2014, energy supplied under these agreements cost approximately $2.9 million.

Currently, Central Hudson meets its capacity and electricity obligations through contracts with capacity and energy providers, purchases from the NYISO energy and capacity markets and its own generating capacity. In November 2013, Central Hudson entered into a contract to purchase 200 megawatts of installed capacity from the Roseton Generating Facility from May 2014 through April 2017 with $33.5 million in purchase commitments remaining as at December 31, 2014. In June 2014, Central Hudson entered into a contract to purchase available installed capacity from the Danskammer Generating Facility from October 2014 through August 2018 with approximately $91.2 million in purchase commitments remaining as at December 31, 2014.

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 and vehicles. The provisions of these leases generally provide for renewal options and some contain escalation clauses. Operating lease rental payment amounts charged to expense by Central Hudson were $1.5 million for 2014 and $1.7 million for 2013 and 2012.

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In addition to Central Hudson’s operating lease rental payments, CH Energy Group had additional operating lease rental payments that were immaterial for 2014, $0.8 million for 2013 and $0.7 million for 2012, which were related to Griffith and therefore are included in Discontinued Operations on the CH Energy Group Consolidated Statement of Income.

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, 2014 (In Thousands): Projected Payments Due By Period

Less than

1 year

Year Ending 2016

Year Ending 2017

Year Ending 2018

Year Ending 2019 Thereafter Total

Operating Leases $ 1,990 $ 1,797 $ 1,621 $ 1,616 $ 1,569 $ 1,548 $ 10,141Purchased Electric Contracts

(1) 53,920 41,688 35,148 22,819 2,413 6,119 162,107

Purchased Natural Gas Contracts

(1) 26,801 14,228 12,579 8,523 7,349 19,984 89,464

Repayments of Long-Term Debt 1,230 9,315 34,406 31,503 28,607 420,214 525,275Interest Obligations on Long-Term Debt 23,142 22,891 22,082 20,536 19,592 272,262 380,505

Total $ 107,083 $ 89,919 $ 105,836 $ 84,997 $ 59,530 $ 720,127 $ 1,167,492

(1) Purchased electric and purchased natural gas costs for Central Hudson are fully recovered via their respective regulatory cost adjustment mechanisms.

The following is a summary of commitments for Central Hudson as of December 31, 2014 (In Thousands):

Projected Payments Due By Period

Less than

1 year

Year Ending 2016

Year Ending 2017

Year Ending 2018

Year Ending 2019 Thereafter Total

Operating Leases $ 1,990 $ 1,797 $ 1,621 $ 1,616 $ 1,569 $ 1,548 $ 10,141Purchased Electric Contracts

(1) 53,920 41,688 35,148 22,819 2,413 6,119 162,107

Purchased Natural Gas Contracts

(1) 26,801 14,228 12,579 8,523 7,349 19,984 89,464

Repayments of Long-Term Debt - 8,000 33,000 30,000 27,000 407,950 505,950Interest Obligations on Long-Term Debt 21,848 21,683 20,964 19,515 18,676 269,386 372,072

Total $ 109,751 $ 93,579 $ 102,292102,292

$ 81,538 $ 57,007 $ 704,987 $ 1,149,154

(1) Purchased electric and purchased natural gas costs for Central Hudson are fully recovered via their respective regulatory cost adjustment mechanisms.

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Other Contractual Obligations CHET was established to be an investor in Transco, which was created to develop, own and operate electric transmission projects in New York State. In December 2014, Transco filed an application with the FERC for the recovery through a formula rate, the cost of and a return on five high voltage transmission projects totaling $1.7 billion. CHET’s maximum commitment for these five projects is $182 million, which is the maximum budgeted amount for these projects at 100% equity. Capital Expenditures: Central Hudson is a regulated utility, and as such is obligated to provide service to customers within its service territory. Central Hudson’s capital expenditures are largely driven by the need to ensure continued and enhanced performance, reliability and safety of the electric and gas systems and to meet customer growth. Central Hudson’s capital expenditure program is forecasted to be approximately $137 million for 2015. 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 2015 are expected to total approximately $8.3 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 • 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 1800s with all sites ceasing operations by the 1950s. This process produced certain by-products that may pose risks to human health and the environment.

The New York State Department of Environmental Conservation (“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 seven 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

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the authorized pre-tax rate of return. In the June 26, 2013 Order (Case 12-M-192), the PSC modified the deferral for MGP Site Investigation and Remediation ("SIR") Costs authorized to apply to all Environmental SIR costs incurred by Central Hudson during the period from July 1, 2013 to June 30, 2015. Site investigation and remediation can be divided into various stages of completion based on the milestones of activities completed and reports reviewed. Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated at a point in time. These stages, the types of costs accrued during various stages and the sites currently in each stage, include:

1. Investigation – Begins with preliminary investigations and is completed upon filing and

approval by DEC of a Remedial Investigation (“RI”) Report. Central Hudson accrues for estimated investigation costs, Remediation Alternative Analysis (“RAA”), and Remedial Design costs.

2. Remedial Alternatives Analysis – Engineering analysis of alternatives for remediation based on the RI is compiled into a RAA Report. 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 (“OM&M”). These amounts represent a significant portion of the total costs to remediate and are subject to change based on further investigations, final remedial design and associated engineering estimates, regulatory comments and requests, remedial design changes/negotiations, and changed or unforeseen conditions during the remediation or additional requirements following the remediation. Prior to the completion of the RAA, management cannot reasonably estimate what cost will be incurred for remediation or post-remediation activities.

� Site #5 – North Water Street – Remedial Alternatives Analysis in progress

− Field activities associated with the former propane tank area investigation have been completed and the DEC has approved the report of findings. Based on the results of this investigation some level of future remediation may be required in this area.

− The DEC is reviewing the RAA Report. Once approved, the DEC will release a draft Decision Document for Central Hudson and public comment. After the draft is finalized, the remedial design will begin.

− Approximately $57.5 million was accrued in May 2014 based on the scope of work and cost estimate developed for remediation and OM&M activities in the RAA Report.

3. Remedial Design - Upon approval of the RAA and final decision of remediation approach

based on alternatives presented, a Remedial Design is developed and filed with the DEC for approval. � Site #6 – Kingston – Remedial Design in Progress

− The DEC approved the RAA Report in July 2014. Additionally, the DEC released a Fact Sheet on November 13, 2014 inviting the public to comment on the proposed site remedy outlined in the RAA. Subsequently, the DEC will consider public comments received and ultimately issue a final Decision Document.

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− Pre-design investigation activities were completed between August and September 2014 and a report of findings was submitted to the DEC for review and approval in December 2014.

− Bids in response to a request for proposal seeking a qualified Environmental/Engineering firm to prepare a 50% Remedial Design document were received in November 2014. It is anticipated that a contract will be executed with the successful bidder by early 2015.

− Approximately $33 million was accrued in December 2013 and an additional $1.5 million in June 2014 based on the scope of work and cost estimate developed for remediation and OM&M activities in the RAA Report.

� Site #2 – Newburgh Area A – Remedial Design/Work Plan in Progress

− In 2012, Central Hudson retired and removed propane air facilities located on Area A.

− In March 2014, approximately $5 million was accrued based on this scope of work and cost estimate developed for remediation of the former propane tank area.

− Central Hudson and the DEC conducted a meeting in November 2014 to discuss the preferred excavation approach in the area of the former propane tanks (Area A). As a result of the discussion, Central Hudson submitted a figure proposing additional delineation soil borings to the DEC for review and the DEC responded with modifications to the proposal and requested a letter work plan be submitted for review and approval. It is anticipated that the letter work plan will be submitted to the DEC for review and approval in the first quarter of 2015.

− Central Hudson is currently developing a Remedial Action Work Plan (“RAWP”) associated with Area A that is anticipated to be submitted to the DEC for review and approval in the first quarter of 2015.

4. Remediation – Completion of the work plan as defined in the approved Remedial Design. 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.

5. Post-Remediation Monitoring – Entails the 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 ongoing monitoring being performed and future potential usage of the property.

� Site #2 – Newburgh Area B and C – Post-Remediation In Progress

− Field activities associated with the sediment documentation sampling of surface sediments in both the non-aqueous phase liquid (“NAPL”) and polycyclic aromatic hydrocarbon (“PAH”) dredge areas in Area C were completed in September 2014. The results were subsequently submitted to the DEC for review in November 2014.

− Amounts accrued represent an estimate of costs for OM&M and execution of the draft SMP related to the previously remediated area of site.

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� Site #3 – Laurel Street – Post-Remediation In Progress − The SMP was submitted to the DEC for review and approval in September 2014. − The Environmental Easement (“EE”) package for the Central Hudson owned portion

of the site was submitted to the DEC for review in October 2014. Following their respective review, the DEC provided comments on the EE package in October 2014. It is anticipated that the revised EE package will be submitted to the DEC for review and execution in early 2015.

− Amounts accrued represent an estimate of costs for OM&M. � Site #4 – Catskill – Post-Remediation In Progress

− During 2013, remediation activities were essentially complete, as well as the installation and development of post remediation wells.

− EE packages for Areas A, B and C were submitted to the DEC and executed in December 2014. The fully executed EEs were submitted and officially recorded by the Greene County Clerk in December 2014.

− The DEC approved the draft FER and revised SMP in July 2014. The final FER was submitted to the DEC in December 2014.

− Amounts accrued represent an estimate of costs to complete the post-remediation and OM&M.

• No Action Required

� Site #1 – Beacon – No Action Required

− The SMP was submitted to the DEC and a release letter for the site was received in 2013.

− No further costs are expected and no amounts are accrued as of September 30, 2014 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 likelihood of the building being removed or the costs that may be incurred related to this.

� Site #7 – Bayeaux Street – 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 amounts accrued and spent are detailed in the chart below (In Thousands):

Liability Liability Current Long-Term

Recorded Amounts Recorded Portion of Portion of

as of Spent in Liability as of Liability at Liability at

Site # 12/31/13 2014 Adjustment 12/31/14 12/31/14 12/31/14

2, 3, 4, 5 and 6 $ 40,802 $ 876 $ 64,780 $ 104,706 $ 11,152 $ 93,554

Based on a cost model analysis completed in 2014 of possible remediation and future OM&M costs for sites #1 through #6 above, the Little Britain Road property, and Eltings Corners, Central Hudson believes there is a 90% confidence level that the total costs to remediate these sites will not exceed $168.7 million over the next 30 years. Consistent with the previous cost model update, the total cost is derived from the summation of the 90% confidence level

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adjusted for inflation for each individual site. The cost model involves assumptions relating to investigation expenses, results of investigations, remediation costs, potential future liabilities, and post-remedial OM&M 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 New York State Department of Health (“NYSDOH”) approval. Future remediation activities, including OM&M 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:

− The 2010 Rate Order included cash recovery from customers of $13.6 million spread equally over the three year settlement period ending June 30, 2013. The 2013 Joint Petition (“JP”) continues cash recovery from customers of $9.2 million from July 1, 2013 through Rate Year ending June 30, 2015.

− As part of the 2010 Rate Order and JP, 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, 2014 was approximately $33.6 million, with $4.6 million recovered in 2014.

− The total spent in 2014 related to site investigation and remediation was approximately $1.0 million.

− The regulatory asset balance as of December 31, 2014 was $103.5 million, which represents the difference between amounts spent or currently accrued as a liability and the amounts recovered through rate allowance, as well as carrying charges accrued.

Central Hudson has put its insurers on notice and intends to seek reimbursement from its insurers for its costs. Certain of these insurers have denied coverage. In addition to the rate allowance amounts noted above, Central Hudson has recovered approximately $2.9 million from insurance, of which $0.6 million was recovered in 2014. However, we do not expect insurance recoveries to offset a meaningful portion of total costs.

• Little Britain Road property owned by Central Hudson There has been no change to this site in 2014, however, the relevant historical disclosure is provided as required. 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

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proposed that additional groundwater work be done to address groundwater sampling results that showed the presence of certain contaminants at levels exceeding the 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 October 2011, the DEC requested a ‘non-committal’ meeting with Central Hudson to discuss the site and possible next steps. At the annual MGP meeting with Central Hudson in October 2012, the DEC discussed the Little Britain Road property requesting an upcoming meeting to discuss the site and possible next steps. Central Hudson responded that it was available for such a meeting. 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. In the course of Central Hudson’s hazardous waste permit renewal process for this facility, sediment contamination was discovered within the wetland area across the street from the main property. In July 2014, Central Hudson submitted a draft Corrective Measures Study (“CMS”) scoping document for review by the DEC. Based on information contained within the CMS scoping document, which included the estimated extent of remediation required as well as a preliminary cost estimate to perform the work, $2.8 million was initially accrued to account for this future expenditure. Subsequently Central Hudson proceeded to prepare and submit a Focused Corrective Measures Study Report (“FCMS”) to the DEC for their review and approval. Following their review, the DEC approved the FCMS in December 2014. This report more specifically identifies the method of remediation as well as provides a more refined estimated cost to implement. As a result, as of December 31, 2014, the estimated cost to perform remediation decreased from the preliminary cost estimate of $2.8 million to $2.2 million. The accrual is expected to be spent in the next twelve months provided the DEC continues to move the schedule and overall remediation process forward.”

CHEC

CHEC’s reserve for environmental remediation is $0.2 million as of December 31, 2014, of which approximately $0.1 million is expected to be spent in the next twelve months.

Certain Litigation Related to the Fortis Transaction Following the announcement of the proposed acquisition of CH Energy Group by Fortis on February 21, 2012, several complaints were filed by purported CH Energy Group shareholders. All actions were joined under the master caption In re CH Energy Group, Inc. Shareholder Litigation and, on April 9, 2012, a master amended complaint was filed. In the master amended complaint, plaintiffs named defendants CH Energy Group, its directors, Fortis, FortisUS, and

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Cascade Acquisition Sub, Inc. and sought among other things, an order preliminarily and permanently enjoining the merger with Fortis, damages, and plaintiffs’ fees and expenses. The plaintiffs generally alleged that the individual defendants breached their fiduciary duties in connection with the proposed transaction and that the entity defendants aided and abetted that breach. The plaintiffs further alleged that the preliminary proxy filed in connection with the proposed transaction with Fortis contained material misstatements and omissions.

In February 2014, the parties executed a settlement agreement that would, among other things, dismiss all causes of action asserted in the master amended complaint and release all claims that shareholders of CH Energy Group from February 19, 2012 through consummation of the merger may have arising out of or relating in any manner to the merger. At a final settlement hearing held on June 19, 2014, the court issued an Order and Final Judgment pursuant to which the court approved the settlement agreement and dismissed the action. The settlement of approximately $0.5 million is recoverable from insurers and has been reflected in the second quarter of 2014 of CH Energy Group’s Consolidated Income Statement, reversing the shareholder settlement expense accrued in 2013 and favorably impacting 2014 results.

Other Matters Asbestos Litigation

As of December 31, 2014, of the 3,348 asbestos cases brought against Central Hudson, 1,170 remained pending. Of the cases no longer pending against Central Hudson, 2,022 have been dismissed or discontinued without payment by Central Hudson, and Central Hudson has settled 156 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. Other Litigation Central Hudson is 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.

NOTE 13 – Segments and Related Information

CH Energy Group's reportable operating segments are the regulated electric utility business and regulated natural gas utility business of Central Hudson and the unregulated fuel distribution business of Griffith, prior to its divestiture on March 4, 2014. Other activities of CH Energy Group, which do not constitute a business segment, include CHEC’s renewable energy investments, CHET’s investment in Transco and the holding company’s activities, which

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consist primarily of financing its subsidiaries, and are reported under the heading “Other Businesses and Investments.”

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.

On March 4, 2014, CHEC completed the sale of Griffith to Star Gas Partners, L.P. Therefore, operating results of Griffith are reported as discontinued operations for all periods presented in the Consolidated CH Group Statement of Income. The segment information presented below for Griffith includes the operating results for this segment. The reclassification of these results to discontinued operations is presented in the Elimination column in order to reconcile the total to the amounts presented in the Consolidated CH Energy Group Statement of Income.

CH Energy Group Segment Disclosure (In Thousands) Year Ended December 31, 2014

Segments Other

Central Hudson Businesses

Natural and

Electric Gas Griffith Investments Eliminations Total

Revenues from external customers $ 579,757 $ 163,005 $ 85,856

(3) $ - $ (85,856) $ 742,762

Intersegment revenues 12 345 -

- (357) -

Total revenues 579,769 163,350 85,856 (3)

- (86,213) 742,762

Depreciation and amortization 33,844 10,015 -

- - 43,859

Operating Income (loss) 67,900 14,476 7,342 (3)(4)

(8,328) (7,000) 74,390

Interest and investment income 3,904 451 -

474 (434) 4,395

Interest charges 24,858 6,713 425 (3)

1,541 (434) 33,103

Income (loss) before income taxes 47,731 8,474 5,671

(3) (105)

(5) (14,944) 46,827

Income tax expense 17,494 4,867 2,325 (4)

2,765 (7,255) 20,196

Net Income (loss) Attributable to CH Energy Group 30,236 3,608 3,346

(1) (2,870)

(2) - 34,320

Segment assets at December 31 1,348,284 527,123 - 14,550 (1,615) 1,888,342

Capital expenditures 80,380 32,811 129 - - 113,320 (1) Includes net income of $3,376 related to Griffith's earnings that are allocated to Discontinued Operations.

(2) Includes net income from Discontinued Operations of $5,128 related to Other Businesses & Investments earnings, including the gain on sale that is allocated to Discontinued Operations. A combined filing tax detriment of $1,067 recorded at the Holding Company as the net result of the gain on Griffith sale and impacts of current year Griffith's operations is included in Discontinued Operations. In addition, the amount includes $251 related to interest income at the Holding Company for inter-company funding of Griffith debt.

(3) Amount represents Discontinued Operations and has been classified as such in the CH Energy Group Consolidated Statement of Income. This amount is included in the Eliminations column as a reconciliation to the Income Statement presentation.

(4) This amount includes ($51) of overhead charges and associated tax benefit billed to Griffith that will be re-allocated to Central Hudson in future years following the sale of Griffith. As such, the amount shown in the elimination column due to the reclassification of Discontinued Operations for this line item does not remove the impact of the overhead charges previously discussed.

(5) Amount includes Discontinued Operations and has been classified as such in the CH Energy Group Consolidated Statement of Income. This amount is included in the Eliminations column as a reconciliation to the Income Statement presentation.

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CH Energy Group Segment Disclosure

(In Thousands) Year Ended December 31, 2013

Segments Other


Natural and



(5) $ - $ (298,367) $ 668,443


- (256) - Total revenues 532,550 136,149 298,367

(5) - (298,623) 668,443

Depreciation and amortization 31,436 8,782 4,994

- (4,994) 40,218 Operating income (loss) 41,114 15,333 6,334

(1) (16,485) (7,298) 38,998


2,289 (2,243) 5,884

Interest charges 25,073 6,650 2,248 (5)

2,036 (2,248) 33,759

Income (loss) before income taxes 22,054 9,893 4,333

(1) (18,675) (5,297) 12,308

Income tax expense (benefit) 7,237 4,411 1,777 (1)

(3,679) (2,172) 7,574

Net Income (Loss) Attributable to CH Energy Group 14,141 5,302 2,557

(2) (13,674)

(3) - 8,326

Segment assets at December 31 1,232,979 430,775 110,361

(4) 10,940 (721) 1,784,334

Capital expenditures 75,945 32,872 2,155 - - 110,972

(1) This amount includes ($964) of overhead charges and associated tax benefit billed to Griffith that will be re-allocated to Central Hudson in

future years upon the completion of the Griffith sale. As such, the amount shown in the Elimination column related to the reclassification of discontinued operations for this line item does not remove the impact of the overhead charges previously discussed.

(2) Includes net income from discontinued operations of $3,125 related to Griffith's earnings that are allocated to discontinued operations.

(3) Includes net income from discontinued operations of $1,323 related to interest income at the Holding Company for funding of Griffith debt.

(4) Includes assets held for sale of $105,151 related to Griffith.

(5) Amount represents Discontinued Operations and has been classified as such in the CH Energy Group Consolidated Statement of Income. This amount is included in the Eliminations column as a reconciliation to the Income Statement presentation.

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CH Energy Group Segment Disclosure

(In Thousands) Year Ended December 31, 2012

Segments Other


Natural and



(5) $ - $ (280,204) $ 644,515


- (157) -

Total revenues 512,094 132,578 280,204 (5)

- (280,361) 644,515

Depreciation and amortization 29,996 8,143 4,642

- (4,642) 38,139

Operating income 76,242 22,271 3,499 (2)

(10,516) (5,327) 86,169


2,266 (2,215)

(1) 6,178

Interest charges 23,397 6,259 2,217 (5)

2,083 (2,311) (1)

31,645

Income (Loss) before income taxes 58,766 17,195 1,295

(2) (12,553) (3,123) 61,580

Income tax expense 20,674 8,117 532 (2)

(3,215) (1,281) 24,827

Net Income (Loss) Attributable to CH Energy Group 37,330 8,874 763

(3) (8,086)

(4) - 38,881

Segment assets at December 31 1,292,382 369,334 111,101

14,195 (714) 1,786,298

Goodwill - - 38,981 - - 38,981

Capital expenditures 79,733 29,052 2,871 - - 111,656

(1) This amount includes ($93) for the elimination of inter-company interest income (expense) generated from temporary lending activities

between CH Energy Group (the holding company) and Central Hudson. The intercompany interest expense at Griffith of $2,217 associated taxes are shown in the Elimination column due to the reclassification to discontinued operations.

(2) This amount includes ($1,828) of overhead charges and associated tax benefit billed to Griffith that will be re-allocated to Central Hudson in future years upon the completion of the Griffith sale. As such, the amount shown in the Elimination column due to the reclassification of discontinued operations for this line item does not remove the impact of the overhead charges previously discussed.

(3) Includes net income from discontinued operations of $1,842 related to Griffith's earnings that are allocated to discontinued operations.

(4) Includes net income from discontinued operations of $1,252 related to interest income at the Holding Company for funding of Griffith debt.

(5) Amount represents discontinued operations and has been classified as such in the CH Energy Group Consolidated Statement of Income. This amount is included in the Eliminations column as a reconciliation to the Income Statement presentation.

NOTE 14 - Accounting for Derivative Instruments and Hedging Activities Purpose of Derivatives Central Hudson enters 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, commodity price risk and adverse or unexpected weather conditions. 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. Derivative transactions are not used for speculative purposes. Central Hudson 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

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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 dependent 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, 2014, Central Hudson had open derivative contracts related to natural gas purchases during January 2015 - March 2015, for 1.44 million Dth, which covers approximately 43.5% of Central Hudson's projected total natural gas supply requirements during this period. At December 31, 2013, Central Hudson had open derivative contracts related to natural gas purchases during January 2014 - March 2014, for 1.25 million Dth, which covered approximately 37.9% of Central Hudson's projected total natural gas supply requirements during that period. In 2014, derivative transactions covered approximately 24.3% of Central Hudson’s total natural gas supply requirements as compared to 27.3% in 2013. Additionally, Central Hudson had open derivative contracts related to electricity purchases at December 31, 2014 for 2.1 million MWh, which covers the following approximate percentages of its projected electricity requirements in 2015 – 2018:

Year Percentage 2015 43.0% 2016 23.1% 2017 7.7% 2018 0%

In 2014, OTC derivative contracts covered approximately 58.9% of Central Hudson’s total electricity supply requirements as compared to 41.2% in 2013.

• 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 was to reduce the volatility to earnings from deferred stock units under CH Energy Group’s Directors and Executives Deferred Compensation Plan. On September 28, 2012, the total return swap agreement expired. During 2012, the swap resulted in income of approximately $0.6 million.

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Accounting for Derivatives The 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 Series B NYSERDA Bonds, 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. 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’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 enters into master netting agreements with counterparties whereby contracts in a gain position can be offset against contracts in a loss position. Of the seventeen total agreements held by Central Hudson, nine contain credit-risk related contingent features. As of December 31, 2014, there were seventeen open derivative contracts under these nine master netting agreements containing credit-risk related contingent features, all of which were in a liability position.

CH Energy Group and Central Hudson have elected gross presentation for their derivative contracts under master netting agreements and collateral positions. On December 31, 2014 and December 31, 2013, Central Hudson did not have collateral posted against the fair value amount of derivatives.

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The net presentation for CH Energy Group's and Central Hudson's derivative assets and liabilities as of December 31, 2014 and 2013 are as follows (In Thousands):

Net Amount of Assets Gross Presented Amounts in the Gross Amounts Not Offset in the Gross Offset in Statement Statement of Financial Position Amounts of the of Cash Recognized Financial Financial Financial Collateral Net Description Assets Position Position Instruments Received Amount As of December 31, 2014 Derivative Contracts: Central Hudson - electric $ 570 $ - $ 570 $ 570 $ - $ -

Total Central Hudson and CH Energy Group Assets $ 570 $ - $ 570 $ 570 $ - $ -

As of December 31, 2013 Derivative Contracts: Central Hudson - electric $ 9,898 $ - $ 9,898 $ - $ - $ 9,898 Central Hudson - gas 324 - 324 40 - 284

Total Central Hudson and CH Energy Group Assets

(1) $ 10,222 $ - $ 10,222 $ 40 $ - $ 10,182

Net Amount of Liabilities Gross Presented Amounts in the Gross Amounts Not Offset in the Gross Offset in Statement Statement of Financial Position Amounts of the of Cash Recognized Financial Financial Financial Collateral Net Description Liabilities Position Position Instruments Received Amount As of December 31, 2014 Derivative Contracts: Central Hudson - electric

1 $ 5,873 $ - $ 5,873 $ 570 $ - $ 5,303

Central Hudson - gas 1,854 - 1,854 - - 1,854

Total Central Hudson and CH Energy Group Liabilities $ 7,727 $ - $ 7,727 $ 570 $ - $ 7,157

As of December 31, 2013 Derivative Contracts: Central Hudson - gas $ 46 $ - $ 46 $ 40 $ - $ 6

Total Central Hudson and CH Energy Group Liabilities

(1) $ 46 $ - $ 46 $ 40 $ - $ 6

(1) Griffith heating oil derivatives have been excluded from the December 31, 2013 CH Energy Group balances above and are designated as

held for sale under current accounting guidance. For further details see Note 5 - "Acquisitions, Investment and Divestitures."

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

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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, 2014 and 2013, CH Energy Group's and Central Hudson's derivative assets and liabilities by category and hierarchy level are as follows (In Thousands): Quoted Prices in Significant

Active Markets Other Significant

for Identical Observable Unobservable

Assets Inputs Inputs

Asset or Liability Category Fair Value (Level 1) (Level 2) (Level 3) As of December 31, 2014

(1)

Assets: Derivative Contracts: Central Hudson - electric $ 570 $ - $ - $ 570

Total CH Energy Group and Central Hudson Assets $ 570 $ - $ - $ 570

Liabilities: Derivative Contracts: Central Hudson - electric1 $ (5,873) $ - $ - $ (5,873) Central Hudson - natural gas (1,854) (1,854) - -

Total CH Energy Group and Central Hudson Liabilities $ (7,727) $ (1,854) $ - $ (5,873)

As of December 31, 2013

(1),(2)

Assets: Derivative Contracts: Central Hudson - electric $ 9,898 $ - $ - $ 9,898 Central Hudson - natural gas 324 324 - -

Total CH Energy Group and Central Hudson Assets $ 10,222 $ 324 $ - $ 9,898

Liabilities: Derivative Contracts: Central Hudson - natural gas $ (46) $ (46) $ - $ -

Total CH Energy Group and Central Hudson Liabilities $ (46) $ (46) $ - $ -

(1) Interest rate cap agreements are not shown in the above table because the FMV at each period stated was zero. (2) Derivative balances related to Griffith, which were designated as held for sale are excluded from December 31, 2013 CH Energy Group

balances.

Central Hudson obtains forward pricing for Level 3 derivatives from an independent third party provider of derivative pricing. Significant unobservable inputs utilized in their pricing model are bi-lateral contracts and projected activity of certain major participants.

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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,

2014 2013

Balance at Beginning of Period $ 9,898 $ (674)

Unrealized gains/(losses) (15,201) 10,572

Realized gains 15,761 2,571

Purchases 11 - 1 -

Issuances - 1 -

Sales and settlements 1 (15,761) 1 (2,571)

Transfers in and/or out of Level 3 1 - 1 -

Balance at End of Period $ (5,303) $ 9,898

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 $ - 1$ -

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, 2014, Central Hudson’s derivative contracts were comprised of swap contracts for electricity and natural gas. Electric swap contracts through December 2016 are valued using the New York Independent System Operator (“NYISO”) Swap Futures Closing Price as posted on NYMEX Clearport. The electric swap contracts from January 2017 through December 2017 are valued using NYISO forward prices provided by a broker, OTC Global Holdings, as posted on the SNL Financial website. All of the electric swap contracts have been classified as Level 3 assets in the fair value hierarchy, since Clearport uses unobservable inputs, such as bi-lateral contracts, projected activity and pricing data from major market participants in its determination of the futures closing price and OTC Global Holdings provides pricing from its forward power curve. Management believes these prices approximate fair value for these instruments. Generally, a change in any of the underlying assumptions would result in a positively correlated change in the fair value measurement. 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.

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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 and CH Energy Group’s Statements of Income as the corresponding amounts are either recovered from or returned to customers through electric cost adjustment clauses in revenues.

For the years ended December 31, 2014, 2013 and 2012, 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


2014 2013 2012 Location of Gain (Loss)

Central Hudson:

Electricity swap contracts $ 15,761 $ 2,571 $ (23,853) Regulatory

(asset)/liability(1)

Natural gas swap contracts 889 (325) (2,219) Regulatory

(asset)/liability(1)

Total return swap contracts 1 - - 557 Other-net

Total Central Hudson $ 16,650 $ 2,246 $ (25,515)

Griffith: Heating oil call

option contracts $ - 1 $ (8) 1 $ 5 Discontinued operations

Total Griffith $ - $ (8) $ 5

Total CH Energy Group $ 16,650 $ 2,238 $ (25,510)

(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 used 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 years ended December 31, 2014 and 2013 approximately $1.3 million and $0.6 million of expense was recorded to the income statement related to Griffith’s weather derivatives, respectively. These amounts are included in income from discontinued operations in the CH Energy Group Consolidated Statement of Income. In the year ended December 31, 2012, approximately $1.6 million of income was recorded to the income statement related to Griffith’s weather derivatives. This amount is included in income from discontinued operations in the CH Energy Group Consolidated Statement of Income.

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NOTE 15 – Other Fair Value Measurements

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. The following table summarizes the amount reported at fair value related to these assets as of December 31, 2014 and December 31, 2013 (In Thousands):

Quoted Prices in Active Markets Significant Significant

for Identical Observable Unobservable Assets Inputs Inputs

Fair Value (Level 1) (Level 2) (Level 3) As of December 31, 2014: Other investments $ 4,317 $ 4,317 $ - $ - As of December 31, 2013:

Other investments $ 5,800 $ 5,800 $ - $ -

As of December 31, 2014 and 2013 a portion of the trust assets for the funding of SERP as well as a portion of CH Energy Group’s Directors and Executives Deferred Compensation Plan at December 31, 2013 were invested in mutual funds and money market accounts, 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.

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 and 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 recover any of its investment. This analysis used significant unobservable inputs including a discount rate and projected cash flows for the entity and as such this is a Level 3 investment. As of December 31, 2014, management believes the fair value of this investment remains at zero and is therefore appropriately reserved.

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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 Valuations were obtained for each issue using the observed Treasury market in conjunction with secondary market trading levels and recent new issuances of comparable companies.

Notes Payable: Carrying amount Due to the short-term nature (typically one month or less) of our Notes Payable borrowings, the carrying value is equivalent to the current FMV.

Long-term Debt Maturities and Fair Value - CH Energy Group

(Dollars in Thousands)

Fixed Rate Variable Rate Total Debt Outstanding

Expected Maturity Date Amount

Estimated Effective

Interest Rate Amount

Estimated Effective


Estimated Effective

Interest Rate

As of December 31, 2014:

2015 $ 1,230 6.87% $ - -%

2016 9,315 3.36% - -%

2017 34,406 6.13% - -%

2018 31,503 2.67% - -%

2019 28,607 5.21% - -%

Thereafter 356,514 5.05% 63,700 0.65%

Total $ 461,575 4.97% $ 63,700 0.65% $ 525,275 4.45%

Fair Value $ 531,666 $ 63,700 $ 595,366


2014 $ 21,650 5.52% $ - -%

2015 1,230 6.86% - -%

2016 9,315 3.36% - -%

2017 34,406 6.13% - -%

2018 31,503 2.67% - -%

Thereafter 385,121 5.06% 33,700 0.17%

Total $ 483,225 4.99% $ 33,700 0.17% $ 516,925 4.68%

Fair Value $ 508,673 $ 33,700 $ 542,373

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Long-term Debt Maturities and Fair Value - Central Hudson

(Dollars in Thousands)

Fixed Rate Variable Rate Total Debt Outstanding

Expected Maturity Date Amount

Estimated Effective


Estimated Effective


Estimated Effective

Interest Rate


2015 $ - -% $ - -%

2016 8,000 2.78% - -%

2017 33,000 6.10% - -%

2018 30,000 2.46% - -%

2019 27,000 5.11% - -%

Thereafter 344,250 4.98% 63,700 0.65%

Total $ 442,250 4.89% $ 63,700 0.65% $ 505,950 4.36%

Fair Value $ 508,723 $ 63,700 $ 572,423


2014 $ 14,000 4.81% $ - -%

2015 - -% - -%

2016 8,000 2.78% - -%

2017 33,000 6.10% - -%

2018 30,000 2.46% - -%

Thereafter 371,250 4.99% 33,700 0.17%

Total $ 456,250 4.89% $ 33,700 0.17% $ 489,950 4.56%

Fair Value $ 478,053 $ 33,700 $ 511,753

NOTE 16 – Related Party Transactions

Thompson Hine LLP serves as outside counsel to CH Energy Group and Central Hudson. One partner in that firm served as Assistant Secretary of each corporation during 2013 and effective on November 1, 2013 began serving as each corporation’s General Counsel and Corporate Secretary. CH Energy Group paid legal fees to Thompson Hine LLP of $1.7 million in 2014 and 2013, and $1.5 million in 2012. Central Hudson paid legal fees to Thompson Hine LLP of $1.5 million in 2014, $0.9 million in 2013 and $0.6 million in 2012.

CH Energy Group may provide services to, and receive services from, Fortis, and other subsidiaries of Fortis. The costs of these services are reimbursed by the beneficiary company through accounts receivable and accounts payable, as necessary. The Company also incurs charges from Fortis for the recovery of general corporate expenses incurred by Fortis or other affiliate. Central Hudson also provides services to, and receives services from, its parent company, CH Energy Group or other affiliate and incurs charges from CH Energy Group for the recovery of general corporate expenses incurred. Central Hudson also incurs charges directly with Fortis or other subsidiaries of Fortis. These transactions are in the normal course of business and are recorded at the United States exchange amounts. Related party transactions, primarily management fees and Board of Director fees included in operating expenses for the years ended December 31, 2014, 2013 and 2012, and accounts receivable at periods ended December 31, 2014 and 2013 are as follows (in Thousands):

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Period Ending December 31, 2014 December 31, 2013

CH Energy Group(1)

Fortis Fortis

Operating Expenses $ 575 $ 226

Accounts Receivable $ - $ 151

Accounts Payable $ 9 $ -

Period Ending December 31, 2014 December 31, 2013 December 31, 2012

Other Affiliates

Other Affiliates

Other Affiliates Central Hudson

(1), (2)CHEG Fortis CHEG Fortis CHEG Fortis

Operating Expenses $ 980 $ - $ - $ 866 $ - $ - $ 736 $ - $ -

Accounts Receivable $ 69 $ 3 $ 15 $ 17 $ 151 $ 489

Accounts Payable $ 299 $ - $ - $ 243 $ - $ -

(1)Fortis amounts reported above include Fortis and all Fortis subsidiaries.

(2)Prior to the acquisition of CH Energy Group by Fortis in 2013, there were no related party transactions with Fortis or Fortis subsidiaries in 2012 related to CH Energy Group or Central Hudson.

NOTE 17 – Subsequent Events

In addition to items disclosed in the footnotes, CH Energy Group has performed an evaluation of events subsequent to December 31, 2014 through the date the financial statements were issued and noted two additional items to disclose.

On January 13, 2015 CH Energy Group’s Board of Directors approved a $5.5 million dividend payment to parent FortisUS that was paid on January 30, 2015.

On January 13, 2015 Central Hudson’s Board of Directors approved a $5.5 million dividend payment to parent CH Energy Group that was paid on January 30, 2015.

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MANAGEMENT’S DISCUSSION and ANALYSIS of FINANCIAL CONDITION and RESULTS of OPERATIONS For the Year Ended December 31, 2014

This Management Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the 2014 Financial Statements and the notes thereto.

Company: CH Energy Group is the holding company parent corporation of three principal, wholly owned subsidiaries, Central Hudson Gas & Electric Corporation (“Central Hudson”), Central Hudson Electric Transmission LLC (“CHET”) and Central Hudson Enterprises Corporation (“CHEC”). All of CH Energy Group’s common stock is indirectly owned by Fortis Inc. (“Fortis”), which is the largest investor-owned gas and electric distribution utility in Canada. Central Hudson is a regulated electric and natural gas subsidiary. CHET holds CH Energy Group’s ownership stake in New York Transco, LLC (“Transco”), a partnership formed to address transmission constraints in NY. CHEC, the parent company of CH Energy Group’s non-regulated businesses and investments, had one wholly owned operating subsidiary during the first quarter of 2014, Griffith Energy Services, Inc. (“Griffith”). On March 4, 2014, CHEC completed the sale of Griffith, its previously 100% owned subsidiary, to Star Gas Partners, LP.

Mission and Strategy

Mission CH Energy Group’s mission is to provide electricity and natural gas 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’s strategy is to:

• Invest primarily in electric and gas transmission and distribution; and• Maintain a financial profile that supports a credit rating for Central Hudson in the “A”

category.

Strategy Execution Management continues to focus on investment in Central Hudson’s electric and natural gas infrastructure as part of its strategy. Central Hudson invested approximately $113 million in 2014, and its five year forecast includes significantly increasing annual capital investments. The long-term capital program provides for continued strengthening of existing electric and gas infrastructure, expansion of gas distribution systems, as well as investment in technology that will improve reliability and customer satisfaction. Central Hudson has effectively managed its operational challenges, including significant weather events in the past few years. However, as a result of the rate freeze period following the Fortis acquisition, Central Hudson did not achieve its allowed return in 2014. Central Hudson filed an electric and natural gas rate case in July 2014 to increase delivery rates effective July 2015 in order to obtain full cost recovery and a competitive return for its shareholder.

As part of CH Energy Group’s overall strategy to invest in the electric transmission and distribution, CH Energy Group formed CHET to be an investor in Transco, a partnership with

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affiliates of the other investor owned utilities in New York (Con Edison, Orange & Rockland Utilities, National Grid, New York State Electric & Gas and Rochester Gas & Electric). Transco was created to develop, own and operate electric transmission projects in New York State. In December 2014, Transco filed an application with the Federal Energy Regulatory Commission (“FERC”) for the recovery through a formula rate the cost of and a return on five high voltage transmission projects totaling $1.7 billion. CHET’s maximum commitment for these five projects is $182 million, which is the maximum budgeted amount for these projects at 100% equity.

Central Hudson

Business Description and Strategy Central Hudson is subject to regulation by the New York State Public Service Commission (“PSC”). The Company’s earnings are derived primarily from the revenue it generates from delivering energy to approximately 300,000 electric and 77,000 natural gas customers, with earnings growth coming primarily from increases in net utility plant. Central Hudson’s delivery rates are designed to recover the cost of providing safe and reliable service while providing the opportunity to earn a fair and reasonable return on its capital.

Central Hudson’s strategy is to provide exceptional value to its customers by: • Practicing continuous improvement in everything we do;• Investing in T&D infrastructure to enhance reliability, improve customer satisfaction and

reduce risk;• Moderating cost pressures that increase customer bill levels and commodity exposures

that cause customer bill variability; and• Advocating on behalf of customers and other stakeholders.

Opportunities and Risks Central Hudson invests significant capital on an annual basis. Central Hudson’s investments enhance safety and reliability through cost-beneficial solutions, which are intended to 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.

Central Hudson believes that there are continuing opportunities for further expansion of its current natural gas customer base due to the natural gas advantage as a cheaper, cleaner, and greener fuel despite the recent decline in oil prices. Central Hudson began implementing a natural gas expansion strategy in 2013 and increased its natural gas customer base by more than 1,000 customers in 2014. In addition, 200 non-heating gas customers were converted to gas heating. Management believes the increase in natural gas customers during 2015 will be in line with the increase in 2014. Central Hudson will continue to seek financing alternatives through private lenders and the New York State Energy Research & Development Authority (“NYSERDA”) in order to remove the cost barrier to customers converting to natural gas.

The key risks management sees in achieving its overall strategy are the regulatory environment, successful execution of its capital investment programs, customer bill pressures from significant capital investments and the economy in Central Hudson’s service territory.

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Central Hudson’s ability to meet its financial objectives is largely dependent on supportive ratemaking practices by the PSC. Risks related to these practices include (1) reduced allowed returns on equity, (2) PSC allowed revenues that result in less than full recovery of the legitimate costs of providing service, resulting in earned returns below authorized returns, (3) declining PSC support for strong capital structures and credit ratings, (4) changes in deferral accounting that increase volatility of earnings and/or defer cash recovery of our costs, (5) elimination of RDMs, and (6) changes in the mechanisms currently in place for recovery of Central Hudson’s commodity purchases. 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 Central Hudson’s shareholder. The PSC Order Authorizing the Acquisition of CH Energy Group by Fortis provided an extension of the key provisions from the 2010 Rate Order, with a 2-year rate freeze through June 30, 2015 and setting aside $40 million of funds to benefit customers, primarily through offsets to regulatory assets in order to mitigate future rate increases. As a result of the 2-year rate freeze, Central Hudson will not earn a return on new capital investments in the utility and must absorb inflationary cost increases over this time period. Additionally, falling interest rates since Central Hudson’s last rate case decision could lead to a decrease in the authorized ROE in its current rate proceeding. A PSC Order establishing new rates will not be in effect until July 2015. No prediction can be made as to the final outcome of the rate filing. The key provisions of the current rate plan include an authorized regulatory return on equity of 10.0% and a 48% regulatory equity ratio; the continuation of RDMs; full recovery and deferral provisions for purchased electric and gas, MGP site remediation, pension and OPEB expenses. The rate plan also contains service quality thresholds, performance below which entails financial penalties.

In addition to the recovery of costs of operation, Central Hudson’s 2010 Rate Order included a return on its projected rate base. Rate base represents Central Hudson’s investment in its utility infrastructure, less depreciation, adjusted for certain required regulatory items. Changes in tax legislation or regulatory accounting can reduce the amount of Central Hudson rate base, reducing Central Hudson’s future rates and potential earnings. For additional discussion of these tax items, see Note 4 – “Income Tax.” During the second quarter of 2014, Governor Cuomo and the Public Service Commission announced the commencement of its Reforming the Energy Vision (“REV”) proceeding. REV is an initiative that aims to improve the efficiency of the electric system; reduce emissions; encourage greater development of clean generation, fuel diversity and energy efficiency measures; and provide customers with knowledge and tools for effective management of their total energy use through the adoption of new technologies on both the utility and customer side of the meter. The outcome of this proceeding cannot be predicted at this time, but it could result in an increased or decreased scope of regulated activities, earnings potential, and risk.

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 – a data driven approach to develop processes that are faster, higher quality and less costly – to streamline existing business processes and foster innovation will play critical roles in managing

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the costs of doing business in a sustainable manner. This is particularly important during the rate freeze period noted above.

The economy in Central Hudson’s service territory affects the growth of utility rate base and earnings through a direct relationship to customer additions and peak demand growth as well as affecting Central Hudson’s ability to collect receivables. 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. Central Hudson has an economic development program intended to increase job growth and income in its service territory.

CH Energy Group - Regulated Operations - Central Hudson

Financial Highlights

Period Ended December 31 Year To Date 2014 2013 Change Electricity Sales (GWh) 5,075 5,159 (84)Natural Gas Sales (PJ) 23.0 23.2 (0.2) ($millions)

Revenues $ 742.8 $ 668.4 $ 74.3

Energy Supply Costs 311.8 237.1 74.7

Other Operating Expenses 304.8 294.7 10.1

Regulatory Debits - 40.0 (40.0)

Depreciation and amortization 43.9 40.2 3.7

Other Income, net 5.4 7.2 (1.8)

Finance Charges 31.6 31.7 (0.1)

Income Taxes 22.4 11.6 10.8

Net income $ 33.8 $ 20.3 $ 13.5

Earnings: Earnings for 2014 as compared to 2013 increased by $13.5 million which was primarily driven by the $24.1 million, net of tax, of customer benefits (“PBA”) recorded in 2013 as required as part of the PSC’s approval of Fortis’ acquisition of Central Hudson and the $2.2 million, net of tax, of storm costs from 2011 recorded in the first quarter of 2013 as a result of a PSC Order denying recovery. Absent these impacts in 2013, earnings in 2014 would have been $12.8 million lower than the same period in 2013. The impact of the rate freeze and the impacts of colder weather and high energy prices on operations, including gas leak repairs, overtime in the call center in response to higher customer bills and an increase in uncollectibles were the primary drivers of the earnings decrease compared to prior year. Also impacting the year over year earnings was an increase in the workers compensation reserves in the first quarter of 2014 due to a change in NY State law and an increasing trend in the costs of claims. The 2014 revenue and energy supply costs reflect colder weather and significantly higher commodity prices; however, this did not have a direct impact on earnings due to the full deferral of commodity costs and the revenue decoupling mechanism (“RDM”). Electricity Sales & Natural Gas Sales: The 2014 electricity and natural gas sales were lower than the prior year primarily as a result of a much cooler summer season than in 2013, which for gas sales resulted in lower deliveries to a power generator as a result of lower operating run times. Although the first half of the year volumes were higher as a result of the colder

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temperatures in the 2014 winter heating season, the second half of the year more than offset the higher sales from earlier in 2014. These variations do not materially impact Central Hudson’s revenue as a result of its RDM structure. Depreciation and Amortization: Depreciation and amortization for the year increased compared to 2013 due to the continued investment in Central Hudson’s electric and gas infrastructure in accordance with its capital expenditure program.

Other Income, net: Other income, net decreased in the current year compared to the prior period due to the reversal of interest income in 2014 that was originally recorded in 2013 associated with a property tax refund as a result of the PSC Order requiring interest to be shared with customers. In 2013, the refund was recorded without any sharing. In addition, 2014 other income related to carrying charges on regulatory assets decreased which were primarily related to deferred storm costs due to the offset of this balance with the PBA, as well as carrying charges on pension costs, as a result of a decrease in the underlying under recovered reserve balance. Finance Charges: Finance charges (interest charges) were relatively unchanged compared to the prior year. Higher interest expense for carrying charges regulatory liabilities, primarily related to PBA and Other Post Employment Benefit (“OPEB”) costs, were offset by lower interest expense on long term debt driven by lower interest on variable rate debt issued in March 2014. Corporate Taxes: Corporate taxes increased year to date primarily as a result of a change in taxable income.

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Central Hudson Revenues - Electric

Period Ended December 31

($millions) Year to Date

2014 2013 Change

Revenues with Matching Expense Offsets:(1)

Recovery of commodity purchases $ 228.2 $ 182.1 $ 46.1

Sales to others for resale 4.7 3.6 1.1

Other revenues with matching offsets 89.1 88.4 0.7

Subtotal 322.0 274.1 47.9

Revenues Impacting Earnings:

Customer sales 241.6 244.0 (2.4)

RDM and other regulatory mechanisms 7.8 5.1 2.7

Other revenues 8.4 9.3 (0.9)

Subtotal 257.8 258.4 (0.6)

Total Electric Revenues $ 579.8 $ 532.5 $ 47.3

(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 entities for resale also do not affect earnings since any related profits or losses are returned or charged, respectively, to customers.

Central Hudson Revenues - Natural Gas


($millions) Year to Date

2014 2013 Change

Revenues with Matching Expense Offsets:(1)

Recovery of commodity purchases $ 59.6 $ 34.3 $ 25.3

Sales to others for resale 18.8 17.1 1.7

Other revenues with matching offsets 18.3 19.1 (0.8)

Subtotal 96.7 70.5 26.2

Revenues Impacting Earnings:

Customer sales 66.2 62.4 3.8

RDM and other regulatory mechanisms (0.6) (0.2) (0.4)

Other revenues 0.7 3.2 (2.5)

Subtotal 66.3 65.4 0.9

Total Natural Gas Revenues $ 163.0 $ 135.9 $ 27.1

(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.

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Central Hudson’s revenues consist of two major categories: those that 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 (most notably, purchased electricity and purchased natural gas, pensions and OPEBs, the NYS Temporary State Assessment, and NYS energy efficiency programs). 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, with the exception of related carrying charges which are recorded in other net.

Electric Revenue: The year over year increase in revenues was primarily driven by the higher recovery of commodity purchases as a result of the higher wholesale prices in 2014.

Gas Revenue: The increase in gas revenues for both periods was due to higher recovery of commodity purchases which were primarily driven by the significantly higher wholesale prices experienced in the first quarter of 2014. Additionally, the increase in gas customer sales above the offsetting decrease in the use-per-customer RDM revenue adjustment relates to an increase in gas customers in 2014 as a result of marketing efforts and a power generator signed on as a new firm gas customer in the fourth quarter.

Central Hudson Operating Expenses


($millions) Year To Date

2014 2013 Change

Expenses Currently Matched to Revenues:(1)

Purchased electricity $ 232.9 $ 185.7 $ 47.2

Purchased natural gas 78.4 51.4 27.0

Pension & OPEB 27.3 27.0 0.3

NYS energy programs 40.8 35.2 5.6

Other matched expenses 41.2 45.3 (4.1)

Subtotal 420.6 344.6 76.0

Other Expense Variations:

Tree trimming 15.0 15.2 (0.2)

Property and school taxes(2)

39.8 39.1 0.7

Weather related service restoration (3)

5.6 6.3 (0.7)

Uncollectible accounts and reserve 6.6 3.5 3.1

Depreciation and amortization 43.9 40.2 3.7

Regulatory debits - 40.0 (40.0)

Other expenses 128.9 123.1 5.7

Subtotal 239.7 267.4 (27.6)

Total Operating Expenses $ 660.4 $ 612.0 $ 48.4

(1) Includes expenses that, in accordance with the 2010 Rate Order, are adjusted in the current period to equal the revenues earned for the applicable expenses and the differences are deferred. This continues per the 2013 Joint Petition.

(2) In accordance with the 2010 Rate Order, Central Hudson is authorized to defer for the benefit of or recovery from customers 90% of any difference between actual property tax expense and the amounts provided in rates for each Rate Year. The Company portion is limited to 10% and a maximum of $0.8 million per Rate Year. This continues per the 2013 Joint Petition.

(3) Weather related service restoration for 2013 includes approximately $3.7 million of incremental electric storm restoration expense related to Tropical Storm Irene and the October 2011 snowstorm that was denied deferral by the PSC in April 2013.

Operating Expenses: Operating expenses increased during 2014 as compared to the 2013 primarily due to the impacts of the colder weather and higher commodity prices from the first

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half of 2014, including higher gas leak repairs, call center overtime and an increase in uncollectible expenses in the second half of 2014. Variations in purchased gas and electricity costs do not have a direct impact on earnings due to Central Hudson’s regulatory mechanism for the full deferral of commodity costs. Also impacting year over year expenses is higher depreciation on Central Hudson’s capital infrastructure investment and an increase in the workers compensation reserves in the first quarter of 2014 due to a change in NY State law and an increasing trend in the costs of claims. The operating costs have risen in comparison to the prior year without a corresponding increase in revenues due to the continuing effects of the rate freeze agreed to as part of the merger approval.

CH Energy Group - Non-regulated and Holding Company Operations Financial Highlights Period Ended December 31 Year To Date ($millions) 2014 2013 Change

Loss from Continuing Operations (7.2) (15.6) 8.4

Income from Discontinued Operations 7.7 4.5 3.2

Loss from Continuing Operations: The loss in 2013 was driven by merger related costs as a result of the acquisition of CH Energy Group by Fortis and the associated costs, including: (1) accelerated equity compensation awards, (2) investment banking fees and (3) legal fees. The loss in 2014 is due to financial impact of the election by two CH Energy Group officers to resign under Change in Control agreements. Income (Loss) from Discontinued Operations: The increase in year over year earnings is the result of a $4.7 million, net of tax gain on the sale of Griffith, which closed on March 4, 2014. The increase was partially offset by higher NYS taxes driven by the inclusion of the taxable gain on the sale of Griffith in the CH Energy Group combined NYS income tax return.

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Financial Position The following table outlines the significant changes in the Balance Sheet of Central Hudson as of December 31, 2014 and December 31, 2013: CH Energy Group – Regulated – Central Hudson Significant Changes in the Balance Sheets as of December 31, 2014 and December 31, 2013

($millions)

Balance Sheet Account Increase

(Decrease) Explanation Regulatory assets - Current 18.6 Increases primarily due to deferred unrealized losses on

derivatives coupled with deferred storm and carrying charges.

Income tax receivable 8.3 This increase is driven by the overpayment of estimated taxes as a result of enactment of the bonus depreciation legislation passed in December 2014.

Fair value of derivative instruments, (net)

(17.4) Decrease due to unrealized mark-to-market losses related to open electric and gas derivative contracts.

Regulatory assets - related to pension plan costs

43.8 This increase is driven by an increase in the projected plan liability due to a change in actuarial assumptions including a decrease in the discount rate and the utilization of updated mortality tables.

Regulatory assets - long term 69.6 Increase primarily due to an increase in the environmental remediation accruals for the Newburgh and North Water Street MGP sites and Eltings site and an increase in storm deferrals.

Long term debt, (net) 16.0 Increase due to the issuance of debt.

Accounts payable 14.6 Increase primarily due to a increase in purchased electric costs as a result of commodity hedges, gas construction costs, software and repairs and maintenance expenses.

Regulatory liabilities - current (6.8) Decrease primarily due to unrealized mark-to-market losses on electric and gas derivative contracts.

Accrued environmental remediation costs

66.1 Increase primarily due to accrual of estimated costs associated with remediation at the North Water Street and Newburgh MGP sites and Eltings site.

Regulatory liabilities - long term 13.5 Increase primarily due to the following: - carrying charges related to the deferred OPEB costs due to the underfunded status of the plan - synergies savings - deferred stray voltage over collection

Accrued pension costs 50.5 The increase is primarily due to a decrease in the discount rate utilized in the calculation of the projected benefit obligation and the use of new mortaility tables which have increased the unfunded level of the pension plan, resulting in a higher accrual. Partially reducing that impact was a $16.4M pension contribution during the first quarter of 2014.

Accumulated deferred income tax, (net)

(12.3) The change in the accumulated deferred tax balance is due to the accounting requirement to recognize deferred taxes for the difference between tax basis of assets and liabilities and the book basis. These amounts are fully deferred for future return to or recovery from customers.

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Liquidity And Capital Resources

The following table outlines the summary of cash flow: CH Energy Group - Regulated, Non-regulated and Holding Company Summary of Cash Flow Period Ended December 31, ($millions) Year to Date

2014 2013

Cash, beginning of period $ 18.1 $ 30.5

Operating Activities 85.1 98.5

Investing Activities (13.7) (116.2)

Financing Activities (66.9) 7.7

Cash included in current assets held for sale - (2.4)

Cash, end of period $ 22.6 $ 18.1

Dividends paid on Common Stock - CH Energy Group $ (75.0) $ (26.6)Dividends paid to parent - Central Hudson $ (5.0) $ (22.0)

Operating Activities: Operating activities generated less cash due primarily to an increase in working capital needs related to higher commodity costs. Investing Activities: Cash provided by investing activities was higher predominately due to proceeds from the sale of Griffith. Additionally, investing activities in 2013 included the funding of the Supplemental Executive Retirement Plan in connection with the closing of the Fortis acquisition. Financing Activities: Financing activities were lower in 2014 primarily due to the payment of dividends from proceeds of the sale of Griffith. Additionally, financing activities in 2013 included proceeds from the issuance of stock, partially reduced by the redemption of outstanding Preferred Stock in June 2013 in connection with the acquisition by Fortis.

Anticipated Sources and Uses of Cash CH Energy Group’s cash flow is primarily generated by the operations of its utility subsidiary, Central Hudson. Generally, the subsidiary does not accumulate significant amounts of cash but rather provides cash to CH Energy Group in the form of dividends. 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 no less than 48%, 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 in 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 2015 and the foreseeable future to meet working capital

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needs, pay dividends on its Common Stock, and fund CHET’s investments in Transco and Central Hudson’s public service obligations and growth objectives.

CH Energy Group’s secondary sources of funds are its cash reserves and its credit facilities. 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 2015 or the foreseeable future.

Committed Credit Facilities CH Energy Group is well positioned with a strong balance sheet and strong liquidity. ($millions)

December 31, 2014

Credit Limit Outstanding Available Maturity

CH Energy Group (unregulated) $ 100 $ - $ 100 October 19, 2015

Central Hudson (regulated) 150 - 150 October 19, 2016

Total $ 250 $ - $ 250

Central Hudson’s Bond Ratings December 31, 2014 December 31, 2013

Rating Outlook Rating Outlook

S&P A Stable A Stable

Moody’s A2 Stable A3 Stable

Fitch A Negative A Stable

Following Fortis' acquisition of CH Energy Group, Standard & Poor’s resolved the CreditWatch listing on July 2, 2013 after completion of the acquisition. S&P reaffirmed the A rating of Central Hudson and removed it from CreditWatch. Moody’s and Fitch also reaffirmed their existing ratings and outlook subsequent to the merger closing. On November 8, 2013, Moody’s placed the ratings of most regulated utilities and utility holding companies in the United States, including that of Central Hudson, on review for upgrade due to a generally more favorable view of the relative credit supportiveness of the US regulatory environment. On January 30, 2014, Moody’s concluded their review of the company’s ratings initiated on November 8, 2013 and upgraded Central Hudson to a rating of A2 and reaffirmed its stable outlook.1 On July 1, 2014, Fitch Ratings affirmed the rating on Central Hudson’s senior unsecured debt and revised the rating outlook to negative from stable. The negative outlook reflects Fitch’s expected weakening of credit metrics due to Central Hudson’s two-year rate freeze, the expiration of bonus depreciation and the impact of rising capital expenditures.1 Central Hudson’s strong investment-grade credit rating 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.

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.

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CH Energy Group’s capital structure follows:

CH Energy Group's Capital Structure

December 31, 2014 December 31, 2013

$millions % $millions %

Long-term Debt $ 525.3 50.1 $ 516.9 47.8

Short-term Debt 1 - - - -

Common Equity 524.0 49.9 564.7 52.2

Total $ 1,049.3 100.0 $ 1,081.6 100.0

Central Hudson's Capital Structure

December 31, 2014 December 31, 2013

$millions % $millions %

Long-term Debt $ 506.0 48.6 $ 490.0 49.1

Short-term Debt 1 - - - -

Common Equity 536.1 51.4 507.2 50.9

Total $ 1,042.1 100.0 $ 997.2 100.0

Central Hudson's customer rates reflect a capital structure - excluding short-term debt - with 48% common equity. Central Hudson is currently managing its financing to maintain its common equity at no less than 48%. Central Hudson may change its long term capitalization targets to match the capital structure reflected in future customer rates. In March 2014, Central Hudson issued $30 million of 10-year debt with a floating interest rate of 3 month LIBOR plus 1%. Central Hudson used the proceeds from the sale of the notes for refunding maturing long term debt, working capital, and for general corporate purposes. To mitigate the potential cash flow impact from unexpected increases in short-term interest rates, Central Hudson purchased a 3-year interest rate cap based on 3 month LIBOR with a notional amount equal to the outstanding principal amount of this issuance. Central Hudson would receive a payout if the LIBOR rate exceeds 4.0% at the start of each quarterly interest period during the term of the interest rate cap. See Note 14 – “Accounting for Derivative Instruments and Hedging Activities” for fair value disclosures related to this instrument. Central Hudson meets its need for long-term debt financing through 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.

CH Energy Group and Central Hudson believe they will be able to meet their short-term and long-term cash requirements, assuming that Central Hudson’s future rate plans reflect the costs of service, including a reasonable return on invested capital. Capital Stock and Dividends: Other than the issuance by Central Hudson of $30 million in long-term debt and the maturity of $14 million in debt, there have been no changes in Central Hudson’s capital structure in 2014. See the Summary of Cash Flow table for details on dividends.

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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.”

Regulatory Proceedings New Electric and Natural Gas Rate Filing Request On July 25, 2014, Central Hudson filed an electric and natural gas rate case with the PSC. Central Hudson is seeking to increase electricity and natural gas delivery rates which were last set by the PSC on June 18, 2010 in Cases 09-E-0588 and 09-G-0589, implementing a three year rate plan with graduated increases to delivery rates effective July 1, 2010, 2011, and 2012. A delivery rate freeze was implemented for electricity and natural gas delivery rates through June 30, 2015 as part of the regulatory approval of the acquisition of Central Hudson by Fortis. Central Hudson committed to invest $215 million in capital expenditures over the two-year period ending June 30, 2015.

The filing is being made in order to align electric and natural gas delivery rates with the projected costs of providing electric and gas service to our customers. Factors contributing to the need for an increase in rates are the ongoing need for continued electric and gas infrastructure investments, higher operating costs, regulatory mandates, increased prices for materials and supplies and rising property taxes. The filing also seeks to recover projected expenditures associated with MGP site remediation, as well as distribution line tree trimming and enhanced electric transmission right of way management practices.

A Joint Proposal for new electric and natural gas delivery rates, system investments and customer services and programs under a three year plan were submitted February 6, 2015.

The JP proposes the following delivery rate increases:12

Rate Year 1 (In Millions)



Electric2 $20.203 $20.821 $13.986 Gas3 $2.548 $5.330 $4.344

1 The delivery revenue increases shown include the impact of moving 50% of Central Hudson’s share of

Energy Efficiency Portfolio Standard (“EEPS”) costs into base rates in Rate Year 1 and 100% of such costs in Rate Year 2 and Rate Year 3.

2 Electric bill credits of $13 million in Rate Year 1, $12 million in Rate Year 2 and $2.0 million in Rate Year 3 will

be utilized to mitigate the bill impacts of the requested delivery increases. 3

Should Central Hudson receive gas delivery revenues from the Danskammer Generating Station in Rate Year 1 and/or Rate Year 2, 50% of those revenues will be returned to the Company’s gas customers via a bill credit in the subsequent Rate Year.

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The Company’s electric and gas revenue requirements reflect a common equity ratio of 48.0% and a return on equity (“ROE”) of 9.0%. In addition, the JP proposes an earnings sharing mechanism, which provides for a distribution of any potential electric and gas earnings above specified ROE thresholds as follows:

Customers/Shareholders Earned ROE 50%/50% > 9.5% to 10.0% 80%/20% > 10.0% to 10.5% 90%/10% > 10.5%

Other significant terms of the JP include: • The JP provides for partial or full reconciliation of certain expenses including, but not

limited to: property taxes; pensions/OPEBs; environmental site investigation and remediation costs; variable and fixed rate debt; and stray voltage. In addition, the JP includes downward-only reconciliations for net plant; distribution and transmission right-of-way maintenance costs; security costs; energy efficiency, and rate case expense.

• The establishment of and new funding for a Major Storm reserve for electric operations, with related deferral provisions;

• Continuation of Central Hudson’s revenue decoupling mechanisms (“RDMs”) for its electric and gas businesses;

• Continuation of the Customer Service Quality Performance Mechanism with potential negative revenue adjustments if Central Hudson fails to meet any metric;

• More stringent standards for electric reliability and gas safety performance metrics; • Requirements to replace or eliminate 13 miles of leak prone pipe in 2016; 14 miles in

2017; and 15 miles in 2018, with potential for both negative and positive revenue adjustments based on actual miles replaced or eliminated;

• Transition to monthly billing for all customers from Central Hudson’s current bi-monthly billing of certain customer classes by July 2016;

• Additional incentives and support for customer conversion to gas; • The Reforming the Energy Vision (“REV”) Working Group formed will develop REV

demonstration projects and present them to the Commission for consideration.

The next step requires the Administrative Law Judge to issue a notice establishing a schedule for the remainder of the case, including dates for:

• Statement in Support / Opposition • Reply Statements • Evidentiary Hearings.

This notice is expected to be published shortly. Reforming the Energy Vision Order In April 2014, the PSC issued an Order instituting a proceeding Reforming the Energy Vision (“REV”) to reform New York State’s energy industry and regulatory practices. The initiative will seek to further the following policy objectives:

1) Enhanced customer knowledge and tools that will support effective management of their total energy bill

2) Market animation and leverage of ratepayer contributions 3) System wide efficiency 4) Fuel and resource diversity

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5) System reliability and resiliency 6) Reduction of carbon emissions

In addition, the initiative will seek to determine the appropriate role of distribution utilities in furthering these objectives as well as considering regulatory changes to better align utility interests with energy policy objectives. Risk Assessment and Remediation of NYS Gas facilities Order In February 2014, the PSC issued an Order requiring risk assessments and remediation of certain NYS gas facilities to identify conditions similar to those found in a natural gas explosion that occurred in Horseheads, New York in 2011. Management currently believes these costs will qualify for deferral treatment. In May 2014, the PSC issued a modifying Order in this proceeding extending the requirement for utilities to complete risk assessments until February 2015 and to include a requirement effective August 2014 for utilities to report to Staff on the progress of their risk assessments every 45 days. On December 5, 2014 the Company filed a request for an extension of the deadline for submitting its Risk Assessment until September 30, 2015.

No prediction can be made regarding the outcome of this matter or the potential impacts on Central Hudson at this time. Property Tax Refund Proceeding On June 13, 2014, Central Hudson and New York State Department of Public Service Staff (“Staff”) filed a Joint Proposal to the PSC regarding the disposition of property tax refunds received by Central Hudson. The Joint Proposal calls for the sharing of the refund, including interest, after deducting cost-to-achieve, on an 85%/15% customer/Company basis. The Company has deferred 85% of the net refund for future pass back to customers. The deferral amount includes interest from the date refunds were received at the pretax rate of return until they are disbursed in accordance with the terms of a future order of the PSC. On October 24, 2014, the PSC issued an Order Allocating Property Tax Refund approving the terms of the Joint Proposal. AC Transmission Proceeding On August 13, 2014, the PSC issued advisory Staff recommendations in the AC Proceeding and a Notice Seeking Comment on Advisory Staff Recommendations. On September 2, 2014, Central Hudson, as a member of the New York Transmission Owners (“NYTOs”), filed joint comments stating that Staff’s recommendations appropriately recognize that the transmission project cost should be recovered through the FERC-approved NYISO tariff structure and the PSC should provide flexibility for developer proposed cost allocation methods within the FERC Order 1000 Public Policy Planning Guidelines. Further, on September 12, 2014, the NYTOs filed reply comments with respect to various party comments submitted in the proceeding that support NYISO recovery of its study costs and that FERC has jurisdiction over transmission rates and, as such, any risk sharing mechanism must be consistent with FERC policy and subject to FERC approval. No prediction can be made regarding the outcome of this matter or the potential impacts to Central Hudson at this time.

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Natural Gas Plastic Fusion Practices Proceeding In late June 2014, the PSC instituted this proceeding to ensure that local distribution gas companies (“LDCs”) are complying with the tracking, testing, qualifying and requalifying procedures of persons who have performed plastic fusions on natural gas facilities, as required by NYCRR Part 255. The proceeding is intended to gather information that will assist the PSC in deciding what steps, if any, must be taken to address a lapse by LDCs in their qualification and requalification procedures. No prediction can be made regarding the outcome of this matter or the potential impacts to Central Hudson at this time. Net Metering Proceeding On December 15, 2014, the PSC issued an Order raising the net metering purchase cap from 3% to 6% of 2005 load effective January 2, 2015. The Order also directed changes to the basis for crediting small commercial customers for their excess generation. The utilities have requested an extension until February 20, 2015 to comply with the Order. Dynamic Load Management Program Proceeding On December 15, 2014, the PSC issued an Order instituting a proceeding to begin the development and implementation of distribution-level demand response programs and dynamic load management programs with the goal of improving system reliability and resiliency, capturing the benefits of system efficiency and providing customers with additional options to help manage their utility bills. Utilities are required to file distribution-level demand response tariffs with the PSC on March 16, 2015. During January and February, the PSC Staff will convene meetings with stakeholders to consult on the development of these tariffs. No prediction can be made regarding the outcome of this matter or the potential impacts on Central Hudson at this time. Other PSC Proceedings On April 2, 2014, the PSC issued an Order authorizing deferral of $9.965 million of the Sandy incremental storm restoration expenses, with carrying charges which had been deferred on Central Hudson’s books. On April 22, 2013, the PSC issued Orders approving deferral of $8.9 million and denying deferral of $3.7 million of the incremental electric storm restoration expense related to Tropical Storm Irene and the October 2011 snowstorm, respectively. On May 22, 2013, Central Hudson filed a petition for reconsideration and rehearing on these Orders challenging the exclusion of Central Hudson’s normalization adjustments used to measure earnings and seeking recovery of $3.7 million that was denied. On April 2, 2014, the PSC issued an Order affirming the previous Irene and October snowstorm PSC Orders and denying Central Hudson’s rehearing petitions. On June 30, 2014, Central Hudson notified the PSC that it will defer the incremental costs (including internal labor costs) it incurs through June 30, 2015, the period covered by the 2013 Joint Petition, in complying with FERC’s new Bulk Electric System regulations. Central Hudson also notified the PSC that it will defer the carrying charges on the amounts deferred (net of taxes) at the rate authorized by the PSC. Deferral of those incremental costs was

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authorized in the Joint Proposal in Case 09-E-0588, extended for two additional rate years in Case 12-M-0192 and is subject to Central Hudson satisfying the PSC’s normal criteria for deferral accounting treatment.

Risk Factors Storms and other events beyond the Companies’ control: In order to conduct its business, Central Hudson must have access to natural gas and electric supplies and be able to utilize its electric and natural gas infrastructure. Any one or more of the following could impact the company’s ability to access supplies and/or utilize critical facilities: (1) storms, natural disasters, wars, terrorist acts, cyber incidents, failure of critical equipment and other catastrophic events occurring both within and outside the service territory (2) third-party facility owner or supplier financial distress, (3) unfavorable governmental actions or judicial orders, and (4) bulk power system and gas transmission pipeline system capacity constraints. Potential Impacts: The Company 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 and regulated rate recovery.

Recovery of costs through rates: Central Hudson’s retail rates generally may not be changed during their respective terms, absent an increase that meets the PSC’s requirements for deferral accounting. Examples of costs that may not be fully recovered include: (1) higher expenses than reflected in current rates, (2) penalties for failing to achieve performance metrics or violation of PSC Orders, (3) higher capital project costs, and (4) a determination by the PSC that the cost to place a project in service is above a level which is deemed prudent. 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 higher costs. Asbestos litigation and Manufactured Gas Plant facilities (MGP): 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. Central Hudson is also 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 could reduce earnings and cash flows.

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FORWARD-LOOKING STATEMENTS Statements included in this annual report, which are not historical in nature, are intended to be “forward-looking statements.” Forward-looking statements may be identified by words such as “anticipates,” “intends,” “estimates,” “believes,” “projects,” “expects,” “plans,” “assumes,” “seeks,” and other similar words and expressions. CH Energy Group is subject to risks and uncertainties that could cause actual results to differ materially from those indicated in the forward-looking statements. The risks and uncertainties include, but are not limited to: deviations from normal seasonal temperatures and storm activity, changes in energy and commodity prices, availability of energy supplies, changes in interest rates, poor operating performance, legislative and regulatory developments, the outcome of litigations, and the resolution of current and future environmental issues. Additional information concerning risks and uncertainties may be found in the Management Discussion & Analysis section of CH Energy Group’s quarterly and annual financial reports. These reports are available in the Financial Information section of website of CH Energy Group, at www.CHEnergyGroup.com. CH Energy Group undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events, or otherwise.

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ANNUAL FINANCIAL REPORT SUPPLEMENT

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.

Central Hudson

Central Hudson is a New York State natural gas and electric corporation formed in 1926. Central Hudson purchases, sells at wholesale and retail, 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. 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, 2014, was 926.

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. Regulation Central Hudson is subject to regulation as follows:

• PSC – 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” of the Company’s 2014 Annual Report.

• FERC (under the Federal Power Act) – accounting and the acquisition and disposition of property.

• North American Electric Reliability Corporation – ownership, operation and use of a bulk

power system.

• DEC – ownership, operation and use of hydroelectric facilities Central Hudson is not subject to the Natural Gas Act and its hydroelectric facilities are not required to be licensed under the Federal Power Act.

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Rates PSC – Costs of service, both for electric and gas delivery service and supply costs, are recovered from customers through PSC approved tariffs, subject to a standard of prudency. For further information, see Note 1 - “Summary of Significant Accounting Policies” under the caption “Rates, Revenues and Cost Adjustment Clauses” and Note 2 - “Regulatory Matters” under the caption “2010 Rate Order and 2013 Joint Petition” of the Company’s 2014 Annual Report.

• Customer classes – Residential and non-residential. • Retail electricity services – Various service classifications covering delivery service and

full service (which includes electricity supply). • Retail natural gas services – Various service classifications covering transport, retail

access service, and full service (which includes natural gas supply). • RDMs – 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.

• Commodity costs – Costs of electric and natural gas commodity purchases are recovered from customers, without earning a profit on these costs. Rates are reset monthly based on Central Hudson’s actual costs to purchase the electricity and natural gas needed to serve its full service customers.

FERC – Transmission rates and rates for electricity sold for resale which involve interstate commerce. During 2014, the average price of electricity for full service customers was 17.58 cents per kWh as compared to an average of 15.48 cents per kWh in 2013. The average delivery price in 2014 was 6.21 cents per kWh and 6.25 cents per kWh in 2013. The decrease in delivery price was primarily due to the return of base delivery revenue in excess of regulatory target and pass back of revenue realized from the revenue sharing agreement with one of the Company’s former generating plants.

During 2014, the average price of natural gas for full-service customers was $14.90 per Mcf as compared to an average of $13.04 per Mcf in 2013. The average delivery price for natural gas for retail and full service in 2014 was $6.13 per Mcf and $6.94 per Mcf in 2013. The decrease in delivery price was primarily due to the refund of base delivery revenue in excess of the regulatory target (both through the RDM and the weather normalization adjustment), the dilution effect resulting from allocating customer charge revenue over increased sales and the impact of the Company’s declining block rate structure.

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.”

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Electric Central Hudson owns hydroelectric and gas turbine generating facilities as described below.

Type of Electric Generating Plant Year Placed in Service/Refurbished MW(1)

Net Capability

Hydroelectric (3 stations) 1920-1986 22.4

Gas turbine (2 stations) 1969-1970 42.5

Total 64.9 (1) Reflects the name plate rating of Central Hudson’s electric generating plants and therefore does not include firm purchases or sales.

Central Hudson owns substations having an aggregate transformer capacity of 5.4 million kilovolt amperes. Central Hudson’s electric transmission system consists of 629 pole miles of line. The electric distribution system consists of approximately 7,200 pole miles of overhead lines and 1,500 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, 2014, occurred on July 23, 2014, and amounted to 1,060 MW. Central Hudson’s highest peak electric demand reached 1,295 MW on August 2, 2006. Central Hudson’s maximum one-hour demand for electricity within its own territory for part of the 2014-2015 winter capability occurred on January 7, 2015, and amounted to 873 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 165 miles of transmission pipelines and 1,229 miles of distribution pipelines, as well as customer service lines and meters. For the year ended December 31, 2014, the total amount of natural gas purchased by Central Hudson from all sources was 11,213,103 Mcf. The peak daily demand for natural gas of Central Hudson’s customers for the year ended December 31, 2014, occurred on January 22, 2014 and amounted to 126,810 Mcf. Central Hudson’s highest winter period daily peak demand reached 127,143 Mcf which occurred on February 15, 2015. Central Hudson’s firm peak day natural gas capability in 2014-2015 heating season was 130,088 Mcf.

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Purchased Power and Generation Costs

For the year ended December 31, 2014, the sources and related costs of purchased electricity and electric generation for Central Hudson were as follows (In Thousands):

Sources of Energy Aggregate Percentage of Energy

Requirements Costs in 2014 Purchased Electricity 98.5 % $ 240,014Hydroelectric and Other 1.5 73Deferred Electricity Cost (7,097)Total 100.0 % $ 232,990

Other Central Hudson Matters

Labor Relations: Central Hudson has an agreement with Local 320 of the International Brotherhood of Electrical Workers for its 546 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 remains effective through April 30, 2017. Property Additions: During the three-year period ended December 31, 2014, Central Hudson made gross property additions of $322.5 million and property retirements and adjustments of $58.8 million, resulting in a net increase (including construction work in progress) in gross utility plant of $263.7 million, or 17%.

Environmental Quality Regulation

Central Hudson is subject to regulation by federal, state, and local authorities with respect to the environmental effects of their operations. Environmental matters may expose Central Hudson 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 monitors its 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 Central Hudson (air, water and industrial and hazardous wastes) are described below. Unless otherwise noted, all required permits and certifications have been obtained by the applicable company. Management believes that the company was in material compliance with these permits and certifications during 2014. For further discussions related to environmental matters see Note 12 – “Commitments and Contingencies”.

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.

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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 has permits regulating pollutant discharges for relevant locations.

Industrial & Hazardous Substances and Wastes

Central Hudson is 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. 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

2014 actual and 2015 estimated expenditures attributable in whole or in substantial part to environmental considerations are detailed in the table below (In Millions):

2014 2015

Central Hudson $ 1.4 $ 13.9

The increase in 2015 estimated expenditures relates primarily to MGP remediation activities at the Newburgh Area A and Kingston sites. For further discussion of these activities, see Note 12 – “Commitments and Contingencies” under caption “Former Manufactured Gas Plant Facilities”.

Central Hudson is 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 is 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 nor Central Hudson 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.

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