-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, DDhACjVJGmL4/DqV7c/sxx2aqiezHxCYU1yksvyBa4npdHQ5bcrqVTigFeyFnXs3 gxTSsjgCAF87ovq9TFoX9A== 0001169232-06-004231.txt : 20061102 0001169232-06-004231.hdr.sgml : 20061102 20061102170051 ACCESSION NUMBER: 0001169232-06-004231 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20060930 FILED AS OF DATE: 20061102 DATE AS OF CHANGE: 20061102 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CH ENERGY GROUP INC CENTRAL INDEX KEY: 0001061393 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 141804460 STATE OF INCORPORATION: NY FISCAL YEAR END: 0210 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 333-52797 FILM NUMBER: 061183483 BUSINESS ADDRESS: STREET 1: 284 SOUTH AVE CITY: POUGHKEEPSIE STATE: NY ZIP: 12601 BUSINESS PHONE: 9144522000 MAIL ADDRESS: STREET 1: 284 SOUTH AVENUE CITY: POUGHKEEPSIE STATE: NY ZIP: 12601 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTRAL HUDSON GAS & ELECTRIC CORP CENTRAL INDEX KEY: 0000018647 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 140555980 STATE OF INCORPORATION: NY FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03268 FILM NUMBER: 061183484 BUSINESS ADDRESS: STREET 1: 284 SOUTH AVE CITY: POUGHKEEPSIE STATE: NY ZIP: 12601 BUSINESS PHONE: 9144522000 MAIL ADDRESS: STREET 1: 284 SOUTH AVENUE CITY: POUGHKEEPSIE STATE: NY ZIP: 12601 10-Q 1 d69744_10-q.txt QUARTERLY REPORT UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-Q (Mark One) |X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended................................September 30, 2006 OR |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from......................to.................... Commission Registrant, State of Incorporation IRS Employer File Number Address and Telephone Number Identification No. - ----------- ---------------------------- ------------------ 0-30512 CH Energy Group, Inc. 14-1804460 (Incorporated in New York) 284 South Avenue Poughkeepsie, New York 12601-4879 (845) 452-2000 1-3268 Central Hudson Gas & Electric Corporation 14-0555980 (Incorporated in New York) 284 South Avenue Poughkeepsie, New York 12601-4879 (845) 452-2000 Indicate by check mark whether the Registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes |X| No |_| Indicate by check mark whether CH Energy Group, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check One): Large Accelerated Filer |X| Accelerated Filer |_| Non-Accelerated Filer |_| Indicate by check mark whether Central Hudson Gas & Electric Corporation is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act (Check One): Large Accelerated Filer |_| Accelerated Filer |_| Non-Accelerated Filer |X| Indicate by check mark whether CH Energy Group, Inc. is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes |_| No |X| Indicate by check mark whether Central Hudson Gas & Electric Corporation is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes |_| No |X| As of the close of business on November 1, 2006, (i) CH Energy Group, Inc. had outstanding 15,762,000 shares of Common Stock ($0.10 per share par value) and (ii) all of the outstanding 16,862,087 shares of Common Stock ($5 per share par value) of Central Hudson Gas & Electric Corporation were held by CH Energy Group, Inc. CENTRAL HUDSON GAS & ELECTRIC CORPORATION MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (H)(1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT PURSUANT TO GENERAL INSTRUCTIONS (H)(2)(a), (b) AND (c). FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2006 INDEX PART I - FINANCIAL INFORMATION PAGE ---- Item 1 - Consolidated Financial Statements (Unaudited) CH ENERGY GROUP, INC. Consolidated Statement of Income - 1 Three Months Ended September 30, 2006, and 2005 Consolidated Statement of Income - 2 Nine Months Ended September 30, 2006, and 2005 Consolidated Statement of Comprehensive Income - 3 Three Months Ended September 30, 2006, and 2005 Consolidated Statement of Comprehensive Income - 3 Nine Months Ended September 30, 2006, and 2005 Consolidated Balance Sheet - September 30, 2006, 4 December 31, 2005, and September 30, 2005 Consolidated Statement of Cash Flows - 6 Nine Months Ended September 30, 2006, and 2005 CENTRAL HUDSON GAS & ELECTRIC CORPORATION Consolidated Statement of Income - 7 Three Months Ended September 30, 2006, and 2005 Consolidated Statement of Income - 8 Nine Months Ended September 30, 2006, and 2005 Consolidated Statement of Comprehensive Income - 9 Three Months Ended September 30, 2006, and 2005 Consolidated Statement of Comprehensive Income - 9 Nine Months Ended September 30, 2006, and 2005 Consolidated Balance Sheet - September 30, 2006, 10 December 31, 2005, and September 30, 2005 Consolidated Statement of Cash Flows - 12 Nine Months Ended September 30, 2006, and 2005 Notes to Consolidated Financial Statements (Unaudited) 13 INDEX PART I - FINANCIAL INFORMATION PAGE ---- Item 2 - Management's Discussion and Analysis of 48 Financial Condition and Results of Operations Item 3 - Quantitative and Qualitative Disclosures 72 about Market Risk Item 4 - Controls and Procedures 72 PART II - OTHER INFORMATION Item 1 - Legal Proceedings 74 Item 1A - Risk Factors 75 Item 6 - Exhibits 76 Signatures 77 Exhibit Index 78 Certifications 79 ----------------------------------------------- Filing Format This Quarterly Report on Form 10-Q is a combined quarterly report being filed by two different registrants: CH Energy Group, Inc. ("Energy Group") and Central Hudson Gas & Electric Corporation ("Central Hudson"), a wholly owned subsidiary of Energy Group. Except where the content clearly indicates otherwise, any reference in this report to Energy Group includes all subsidiaries of Energy Group, including Central Hudson. Central Hudson makes no representation as to the information contained in this report in relation to Energy Group and its subsidiaries other than Central Hudson. PART I - FINANCIAL INFORMATION Item I - Consolidated Financial Statements CH ENERGY GROUP, INC. CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
For the 3 Months Ended September 30, 2006 2005 ---------- ---------- (Thousands of Dollars) Operating Revenues Electric ........................................................................ $ 154,723 $ 159,589 Natural gas ..................................................................... 18,384 14,115 Competitive business subsidiaries ............................................... 66,713 54,192 ---------- ---------- Total Operating Revenues .................................................... 239,820 227,896 ---------- ---------- Operating Expenses Operation: Purchased electricity and fuel used in electric generation ........................................................ 95,665 111,496 Purchased natural gas ......................................................... 10,663 7,311 Purchased petroleum ........................................................... 52,651 43,287 Other expenses of operation - regulated activities ............................ 31,690 24,613 Other expenses of operation - competitive business subsidiaries ............... 12,668 12,642 Depreciation and amortization ................................................... 8,843 9,116 Taxes, other than income tax .................................................... 8,968 8,578 ---------- ---------- Total Operating Expense ..................................................... 221,148 217,043 ---------- ---------- Operating Income .................................................................. 18,672 10,853 ---------- ---------- Other Income and Deductions Interest on regulatory assets and investment income ............................. 1,922 2,629 Other - net ..................................................................... 279 (743) ---------- ---------- Total Other Income .......................................................... 2,201 1,886 ---------- ---------- Interest Charges Interest on long-term debt ...................................................... 4,115 3,421 Interest on regulatory liabilities and other interest ........................... 1,147 966 ---------- ---------- Total Interest Charges ...................................................... 5,262 4,387 ---------- ---------- Income before income taxes, preferred dividends of subsidiary and minority interest 15,611 8,352 Income taxes ...................................................................... 4,392 2,364 Minority Interest ................................................................. 7 -- ---------- ---------- Income before preferred dividends of subsidiary ................................... 11,212 5,988 Cumulative preferred stock dividends of subsidiary ................................ 242 242 ---------- ---------- Net Income ........................................................................ 10,970 5,746 Dividends Declared on Common Stock ................................................ 8,511 8,511 ---------- ---------- Balance Retained in the Business .................................................. $ 2,459 ($2,765) ========== ========== Common Stock: Average Shares Outstanding - Basic ............................................ 15,762 15,762 - Diluted .......................................... 15,777 15,769 Earnings Per Share - Basic .................................................... $ 0.70 $ 0.36 - Diluted .................................................. $ 0.70 $ 0.36 Dividends Declared Per Share .................................................. $ 0.54 $ 0.54
See Notes to Consolidated Financial Statements -1- CH ENERGY GROUP, INC. CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
For the 9 Months Ended September 30, 2006 2005 --------- --------- (Thousands of Dollars) Operating Revenues Electric ........................................................................ $ 398,700 $ 392,866 Natural gas ..................................................................... 125,651 108,687 Competitive business subsidiaries ............................................... 246,592 202,001 --------- --------- Total Operating Revenues .................................................... 770,943 703,554 --------- --------- Operating Expenses Operation: Purchased electricity and fuel used in electric generation ........................................................ 245,114 254,200 Purchased natural gas ......................................................... 87,718 71,288 Purchased petroleum ........................................................... 193,022 154,550 Other expenses of operation - regulated activities ............................ 90,170 73,472 Other expenses of operation - competitive business subsidiaries ............... 43,222 39,350 Depreciation and amortization ................................................... 26,920 27,304 Taxes, other than income tax .................................................... 25,089 25,344 --------- --------- Total Operating Expense ..................................................... 711,255 645,508 --------- --------- Operating Income .................................................................. 59,688 58,046 --------- --------- Other Income Interest on regulatory assets and investment income ............................. 7,524 7,349 Other - net ..................................................................... 1,251 (1,589) --------- --------- Total Other Income .......................................................... 8,775 5,760 --------- --------- Interest Charges Interest on long-term debt ...................................................... 12,139 10,187 Interest on regulatory liabilities and other interest ........................... 3,130 2,285 --------- --------- Total Interest Charges ...................................................... 15,269 12,472 --------- --------- Income before income taxes, preferred dividends of subsidiary and minority interest 53,194 51,334 Income Taxes ...................................................................... 19,250 17,988 Minority Interest ................................................................. (121) -- --------- --------- Income before preferred dividends of subsidiary ................................... 34,065 33,346 Cumulative preferred stock dividends of subsidiary ................................ 727 727 --------- --------- Net Income ........................................................................ 33,338 32,619 Dividends Declared on Common Stock ................................................ 25,534 25,534 --------- --------- Balance Retained in the Business .................................................. $ 7,804 $ 7,085 ========= ========= Common Stock: Average Shares Outstanding - Basic ............................................ 15,762 15,762 - Diluted .......................................... 15,776 15,768 Earnings Per Share - Basic .................................................... $ 2.12 $ 2.07 - Diluted .................................................. $ 2.11 $ 2.07 Dividends Declared Per Share .................................................. $ 1.62 $ 1.62
See Notes to Consolidated Financial Statements -2- CH ENERGY GROUP, INC. CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED)
For the 3 Months Ended September 30, 2006 2005 ---------- ---------- (Thousands of Dollars) Net Income ....................................................................... $ 10,970 $ 5,746 Other Comprehensive Income: Net unrealized gains (losses) net of tax and net income realization: FAS 133 Designated Cash Flow Hedges - net of tax of $118 and $(80) ......... (177) 120 Investments - net of tax of $(139) and $(40) ............................... 209 59 ---------- ---------- Other comprehensive income (loss) ................................................ 32 179 ---------- ---------- Comprehensive Income ............................................................. $ 11,002 $ 5,925 ========== ========== For the 9 Months Ended September 30, 2006 2005 ---------- ---------- (Thousands of Dollars) Net Income ....................................................................... $ 33,338 $ 32,619 Other Comprehensive Income: Net unrealized gains (losses) net of tax and net income realization: FAS 133 Designated Cash Flow Hedges - net of tax of $107 and $(80) ......... (160) 119 Investments - net of tax of $(223) and $(207) .............................. 335 311 ---------- ---------- Other comprehensive income (loss) ................................................ 175 430 ---------- ---------- Comprehensive Income ............................................................. $ 33,513 $ 33,049 ========== ==========
See Notes to Consolidated Financial Statements -3- CH ENERGY GROUP, INC. CONSOLIDATED BALANCE SHEET (UNAUDITED)
September 30, December 31, September 30, ASSETS 2006 2005 2005 ------------- ------------ ------------- (Thousands of Dollars) Utility Plant Electric ........................................................... $ 754,429 $ 739,775 $ 718,995 Natural gas ........................................................ 234,103 226,859 221,940 Common ............................................................. 112,173 107,581 106,335 ---------- ---------- ---------- 1,100,705 1,074,215 1,047,270 Less: Accumulated depreciation .................................... 346,395 333,164 330,285 ---------- ---------- ---------- 754,310 741,051 716,985 Construction work in progress ...................................... 55,952 38,460 51,898 ---------- ---------- ---------- Net Utility Plant .......................................... 810,262 779,511 768,883 ---------- ---------- ---------- Other Property and Plant - net ............................................ 33,713 23,138 23,245 ---------- ---------- ---------- Current Assets Cash and cash equivalents .......................................... 32,195 49,410 51,047 Short-term investments - available-for-sale securities ............. 40,281 42,100 49,600 Accounts receivable - net of allowance for doubtful accounts of $5.1 million, $4.6 million, and $4.6 million, respectively ................................................. 61,814 97,462 81,326 Accrued unbilled utility revenues .................................. 7,122 9,334 5,998 Other receivables .................................................. 6,017 6,326 5,119 Fuel and materials and supplies - at average cost .................. 30,530 28,350 31,189 Regulatory assets .................................................. 20,759 30,764 16,440 Prepaid income taxes ............................................... -- 1,166 572 Fair value of derivative instruments ............................... 54 -- 8,724 Special deposits and prepayments ................................... 25,666 23,184 22,995 Accumulated deferred income tax .................................... 15,925 8,836 12,056 ---------- ---------- ---------- Total Current Assets ...................................... 240,363 296,932 285,066 ---------- ---------- ---------- Deferred Charges and Other Assets Regulatory assets - pension plan ................................... 46,273 97,073 91,247 Intangible asset - pension plan .................................... 18,148 20,217 20,134 Goodwill ........................................................... 52,742 51,333 50,898 Other intangible assets - net ...................................... 27,560 28,368 28,472 Regulatory assets .................................................. 90,483 52,353 47,709 Unamortized debt expense ........................................... 3,721 3,973 3,780 Investments in unconsolidated affiliates ........................... 12,354 7,350 14,624 Other .............................................................. 18,594 19,258 11,666 ---------- ---------- ---------- Total Deferred Charges and Other Assets ................... 269,875 279,925 268,530 ---------- ---------- ---------- Total Assets .................................... $1,354,213 $1,379,506 $1,345,724 ========== ========== ==========
See Notes to Consolidated Financial Statements -4- CH ENERGY GROUP, INC. CONSOLIDATED BALANCE SHEET (UNAUDITED)
September 30, December 31, September 30, CAPITALIZATION AND LIABILITIES 2006 2005 2005 ------------- ------------ ------------- (Thousands of Dollars) Capitalization Common Stock Equity: Common stock, 30,000,000 shares authorized: 15,762,000 shares outstanding, 16,862,087 shares issued, $0.10 par value ............................................... $ 1,686 $ 1,686 $ 1,686 Paid-in capital .................................................. 351,230 351,230 351,230 Retained earnings ................................................ 205,821 198,017 194,857 Treasury stock (1,100,087 shares) ................................ (46,252) (46,252) (46,252) Accumulated comprehensive income (loss) .......................... (345) (520) (213) Capital stock expense ............................................ (328) (328) (328) ----------- ----------- ----------- Total Common Stock Equity .................................... 511,812 503,833 500,980 ----------- ----------- ----------- Cumulative Preferred Stock Not subject to mandatory redemption ............................ 21,027 21,027 21,027 Long-term debt ................................................... 310,888 343,886 319,885 ----------- ----------- ----------- Total Capitalization ......................................... 843,727 868,746 841,892 ----------- ----------- ----------- Current Liabilities Current maturities of long-term debt ............................. 33,000 -- -- Notes payable .................................................... 30,000 30,000 44,000 Accounts payable ................................................. 30,692 54,926 36,636 Accrued interest ................................................. 3,162 5,156 2,544 Dividends payable ................................................ 8,754 8,754 8,754 Accrued vacation and payroll ..................................... 5,957 5,845 5,727 Customer deposits ................................................ 7,894 7,101 6,869 Regulatory liabilities ........................................... 20,037 373 8,525 Fair value of derivative instruments ............................. 6,717 335 -- Accrued environmental remediation costs .......................... 3,500 -- -- Accrued income taxes ............................................. 759 -- -- Deferred revenues ................................................ 14,791 9,717 10,435 Other ............................................................ 11,776 11,964 14,193 ----------- ----------- ----------- Total Current Liabilities .................................... 177,039 134,171 137,683 ----------- ----------- ----------- Deferred Credits and Other Liabilities Regulatory liabilities ........................................... 109,523 156,808 155,529 Operating reserves ............................................... 5,422 6,216 6,921 Accrued environmental remediation costs .......................... 17,932 22,772 22,821 Accrued other post-employment benefit costs ...................... 29,875 24,945 23,881 Accrued pension costs ............................................ 16,032 18,806 14,734 Other ............................................................ 12,903 13,258 13,386 ----------- ----------- ----------- Total Deferred Credits and Other Liabilities ................. 191,687 242,805 237,272 ----------- ----------- ----------- Minority Interest ................................................... 1,501 -- -- ----------- ----------- ----------- Accumulated Deferred Income Tax ..................................... 140,259 133,784 128,877 ----------- ----------- ----------- Commitments and Contingencies (Note 11) Total Capitalization and Liabilities ....... $ 1,354,213 $ 1,379,506 $ 1,345,724 =========== =========== ===========
See Notes to Consolidated Financial Statements -5- CH ENERGY GROUP, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)
For the 9 Months Ended September 30, 2006 2005 ---------- ---------- Operating Activities: (Thousands of Dollars) Net Income ............................................................................ $ 33,338 $ 32,619 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation and amortization ................................................. 26,920 27,304 Deferred income taxes - net ................................................... 7,106 7,776 Provision for uncollectibles .................................................. 4,506 2,784 Accrued/deferred pension costs ................................................ (5,120) (10,735) Minority interest ............................................................. (121) -- Gain on sale of property and plant ............................................ (2,913) -- Changes in operating assets and liabilities - net of business acquisitions: Accounts receivable, unbilled revenues and other receivables .................. 35,176 (15,507) Fuel, materials and supplies .................................................. (2,085) (9,639) Special deposits and prepayments .............................................. (5,148) 1,450 Accounts payable .............................................................. (24,416) (6,782) Accrued taxes and interest .................................................... (1,235) (2,085) Accrued OPEB costs ............................................................ 4,929 7,850 Regulatory Liability-Rate Moderation .......................................... (7,976) -- Deferred natural gas and electric costs ....................................... 16,493 (781) Customer benefit fund ......................................................... (3,205) (3,592) Other - net ................................................................... (3,474) 4,039 ---------- ---------- Net Cash Provided By Operating Activities ........................................... 72,775 34,701 ---------- ---------- Investing Activities: Purchase of short-term investments .................................................. (29,731) (22,750) Proceeds from sale of short-term investments ........................................ 31,550 21,850 Additions to utility plant and other property and plant ............................. (50,827) (45,556) Proceeds from sale of property and plant ............................................ 3,205 -- Issuance of notes receivable ........................................................ (2,105) (4,629) Proceeds from repayment of notes receivable ......................................... 1,750 -- Acquisitions made by competitive business subsidiaries .............................. (13,910) (7,370) Other - net ......................................................................... (4,356) (2,065) ---------- ---------- Net Cash Used in Investing Activities ............................................... (64,424) (60,520) ---------- ---------- Financing Activities: Redemption of preferred stock ....................................................... -- (3) Net borrowings of short-term debt ................................................... -- 32,000 Dividends paid on common stock ...................................................... (25,534) (25,534) Debt issuance costs ................................................................. (32) (14) ---------- ---------- Net Cash (Used in) Provided by Financing Activities ................................. (25,566) 6,449 ---------- ---------- Net Change in Cash and Cash Equivalents .................................................... (17,215) (19,370) Cash and Cash Equivalents - Beginning of Year .............................................. 49,410 70,417 ---------- ---------- Cash and Cash Equivalents - End of Period .................................................. $ 32,195 $ 51,047 ========== ========== Supplemental Disclosure of Cash Flow Information Interest paid ....................................................................... $ 18,360 $ 14,864 Federal and State income tax paid ................................................... $ 10,784 $ 11,960
See Notes to Consolidated Financial Statements -6- CENTRAL HUDSON GAS & ELECTRIC CORPORATION CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
For the 3 Months Ended September 30, 2006 2005 ---------- ---------- (Thousands of Dollars) Operating Revenues Electric ........................................................... $ 154,723 $ 159,589 Natural gas ........................................................ 18,384 14,115 ---------- ---------- Total Operating Revenues ....................................... 173,107 173,704 ---------- ---------- Operating Expenses Operation: Purchased electricity and fuel used in electric generation ....... 94,392 111,496 Purchased natural gas ............................................ 10,663 7,311 Other expenses of operation ...................................... 31,690 24,613 Depreciation and amortization ...................................... 7,070 7,502 Taxes, other than income tax ....................................... 8,877 8,505 ---------- ---------- Total Operating Expenses ....................................... 152,692 159,427 ---------- ---------- Operating Income ..................................................... 20,415 14,277 ---------- ---------- Other Income and Deductions Interest on regulatory assets and other interest income ............ 1,100 1,793 Other - net ........................................................ 54 (314) ---------- ---------- Total Other Income ............................................. 1,154 1,479 ---------- ---------- Interest Charges Interest on long-term debt ......................................... 4,115 3,421 Interest on regulatory liabilities and other interest .............. 1,147 966 ---------- ---------- Total Interest Charges ......................................... 5,262 4,387 ---------- ---------- Income before income taxes ........................................... 16,307 11,369 Income taxes ......................................................... 5,534 4,484 ---------- ---------- Net Income ........................................................... 10,773 6,885 Dividends Declared on Cumulative Preferred Stock ..................... 242 242 ---------- ---------- Income Available for Common Stock .................................... $ 10,531 $ 6,643 ========== ==========
See Notes to Consolidated Financial Statements -7- CENTRAL HUDSON GAS & ELECTRIC CORPORATION CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
For the 9 Months Ended September 30, 2006 2005 ---------- ---------- (Thousands of Dollars) Operating Revenues Electric ........................................................... $ 398,700 $ 392,866 Natural gas ........................................................ 125,651 108,687 ---------- ---------- Total Operating Revenues ....................................... 524,351 501,553 ---------- ---------- Operating Expenses Operation: Purchased electricity and fuel used in electric generation ....... 243,202 254,200 Purchased natural gas ............................................ 87,718 71,288 Other expenses of operation ...................................... 90,170 73,472 Depreciation and amortization ...................................... 21,986 22,506 Taxes, other than income tax ....................................... 24,835 25,103 ---------- ---------- Total Operating Expenses ....................................... 467,911 446,569 ---------- ---------- Operating Income ..................................................... 56,440 54,984 ---------- ---------- Other Income and Deductions Interest on regulatory assets and other interest income ............ 5,149 5,209 Other - net ........................................................ (279) (982) ---------- ---------- Total Other Income ............................................. 4,870 4,227 ---------- ---------- Interest Charges Interest on long-term debt ......................................... 12,139 10,187 Interest on regulatory liabilities and other interest .............. 3,130 2,285 ---------- ---------- Total Interest Charges ......................................... 15,269 12,472 ---------- ---------- Income Before Income Taxes ........................................... 46,041 46,739 Income Taxes ......................................................... 18,090 18,751 ---------- ---------- Net Income ........................................................... 27,951 27,988 Dividends Declared on Cumulative Preferred Stock ..................... 727 727 ---------- ---------- Income Available for Common Stock .................................... $ 27,224 $ 27,261 ========== ==========
See Notes to Consolidated Financial Statements -8- CENTRAL HUDSON GAS & ELECTRIC CORPORATION CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (UNAUDITED) For the 3 Months Ended September 30, 2006 2005 ------- ------- (Thousands of Dollars) Net Income ........................... $10,773 $ 6,885 Other Comprehensive Income ........... -- -- ------- ------- Comprehensive Income ................. $10,773 $ 6,885 ======= ======= For the 9 Months Ended September 30, 2006 2005 ------- ------- (Thousands of Dollars) Net Income ........................... $27,951 $27,988 Other Comprehensive Income ........... -- -- ------- ------- Comprehensive Income ................. $27,951 $27,988 ======= ======= See Notes to Consolidated Financial Statements -9- CENTRAL HUDSON GAS & ELECTRIC CORPORATION CONSOLIDATED BALANCE SHEET (UNAUDITED)
September 30, December 31, September 30, ASSETS 2006 2005 2005 ------------- ------------ ------------- (Thousands of Dollars) Utility Plant Electric ........................................................... $ 754,429 $ 739,775 $ 718,995 Natural gas ........................................................ 234,103 226,859 221,940 Common ............................................................. 112,173 107,581 106,335 ---------- ---------- ---------- 1,100,705 1,074,215 1,047,270 Less: Accumulated depreciation ..................................... 346,395 333,164 330,285 ---------- ---------- ---------- 754,310 741,051 716,985 Construction work in progress ...................................... 55,952 38,460 51,898 ---------- ---------- ---------- Net Utility Plant .......................................... 810,262 779,511 768,883 ---------- ---------- ---------- Other Property and Plant - net ........................................ 496 723 724 ---------- ---------- ---------- Current Assets Cash and cash equivalents .......................................... 2,776 4,232 2,346 Accounts receivable - net of allowance for doubtful accounts of $3.8 million, $3.4 million, and $3.6 million, respectively .................... 37,958 61,055 57,965 Accrued unbilled utility revenues .................................. 7,122 9,334 5,998 Other receivables .................................................. 2,584 2,868 2,426 Fuel and materials and supplies - at average cost .................. 25,041 23,411 26,104 Regulatory assets .................................................. 20,759 30,764 16,440 Fair value of derivative instruments ............................... -- -- 8,525 Special deposits and prepayments ................................... 22,085 16,168 15,996 Accumulated deferred income tax .................................... 15,165 7,997 11,217 ---------- ---------- ---------- Total Current Assets ...................................... 133,490 155,829 147,017 ---------- ---------- ---------- Deferred Charges and Other Assets Regulatory assets - pension plan ................................... 46,273 97,073 91,247 Intangible asset - pension plan .................................... 18,148 20,217 20,134 Regulatory assets .................................................. 90,483 52,353 47,709 Unamortized debt expense ........................................... 3,721 3,973 3,780 Other .............................................................. 11,153 11,653 10,631 ---------- ---------- ---------- Total Deferred Charges and Other Assets ................... 169,778 185,269 173,501 ---------- ---------- ---------- Total Assets .................................... $1,114,026 $1,121,332 $1,090,125 ========== ========== ==========
See Notes to Consolidated Financial Statements -10- CENTRAL HUDSON GAS & ELECTRIC CORPORATION CONSOLIDATED BALANCE SHEET (UNAUDITED)
September 30, December 31, September 30, CAPITALIZATION AND LIABILITIES 2006 2005 2005 ------------- ------------ ------------- (Thousands of Dollars) Capitalization Common Stock Equity: Common stock, 30,000,000 shares authorized; 16,862,087 shares issued and outstanding ($5 par value) ..... $ 84,311 $ 84,311 $ 84,311 Paid-in capital ................................................ 174,980 174,980 174,980 Retained earnings .............................................. 62,033 43,309 35,905 Capital stock expense .......................................... (4,961) (4,961) (4,961) ----------- ----------- ----------- Total Common Stock Equity ................................. 316,363 297,639 290,235 ----------- ----------- ----------- Cumulative Preferred Stock Not subject to mandatory redemption .......................... 21,027 21,027 21,027 Long-term Debt ................................................. 310,888 343,886 319,885 ----------- ----------- ----------- Total Capitalization ...................................... 648,278 662,552 631,147 ----------- ----------- ----------- Current Liabilities Current maturities of long-term debt .......................... 33,000 -- -- Notes Payable ................................................. 30,000 30,000 44,000 Accounts payable .............................................. 23,401 40,884 28,828 Accrued interest .............................................. 3,161 5,156 2,544 Dividends payable - preferred stock ........................... 242 242 242 Accrued vacation and payroll .................................. 4,767 4,566 4,496 Customer deposits ............................................. 7,766 6,932 6,735 Regulatory liabilities ........................................ 20,037 373 8,525 Fair value of derivative instruments .......................... 6,431 315 -- Accrued income taxes .......................................... 6,312 324 848 Accrued environmental remediation costs ....................... 3,500 -- -- Other ......................................................... 7,410 6,895 9,782 ----------- ----------- ----------- Total Current Liabilities ................................. 146,027 95,687 106,000 ----------- ----------- ----------- Defer Credits and Other Liabilities Regulatory liabilities ........................................ 109,523 156,808 155,529 Operating reserves ............................................ 4,248 5,137 5,701 Accrued environmental remediation costs ....................... 16,000 19,500 19,500 Accrued other post-employment benefit costs ................... 29,875 24,945 23,881 Accrued pension costs ......................................... 16,032 18,806 14,734 Other ......................................................... 12,169 11,094 11,195 ----------- ----------- ----------- Total Deferred Credits and Other Liabilities .............. 187,847 236,290 230,540 ----------- ----------- ----------- Accumulated Deferred Income Tax .................................... 131,874 126,803 122,438 ----------- ----------- ----------- Commitments and Contingencies (Note 11) Total Capitalization and Liabilities ...................... $ 1,114,026 $ 1,121,332 $ 1,090,125 =========== =========== ===========
See Notes to Consolidated Financial Statements -11- CENTRAL HUDSON GAS & ELECTRIC CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)
For the 9 Months Ended September 30, 2006 2005 ---------- ---------- Operating Activities: (Thousands of Dollars) Net Income .......................................................................... $ 27,951 $ 27,988 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation and amortization ...................................... 21,986 22,506 Deferred income taxes - net ........................................ 5,624 6,494 Provision for uncollectibles ....................................... 3,833 2,238 Accrued/deferred pension costs ..................................... (5,120) (10,735) Gain on sale of property and plant ................................. (2,215) -- Changes in operating assets and liabilities - net: Accounts receivable, unbilled revenues and other receivables ....... 21,760 (18,941) Fuel, materials and supplies ....................................... (1,630) (8,897) Special deposits and prepayments ................................... (5,917) 4,358 Accounts payable ................................................... (17,483) (4,123) Accrued taxes and interest ......................................... 3,993 (1,237) Accrued OPEB costs ................................................. 4,929 7,850 Regulatory Liability-Rate Moderation ............................... (7,976) -- Deferred natural gas and electric costs ............................ 16,493 (781) Customer benefit fund .............................................. (3,205) (3,592) Other - net ........................................................ (7,723) 383 ---------- ---------- Net Cash Provided by Operating Activities ..................................... 55,300 23,511 ---------- ---------- Investing Activities: Proceeds from sale of property and plant ...................................... 2,440 -- Additions to plant ............................................................ (48,395) (42,681) Other - net ................................................................... (1,542) (967) ---------- ---------- Net Cash Used in Investing Activities ......................................... (47,497) (43,648) ---------- ---------- Financing Activities: Redemption of preferred stock ................................................. -- (3) Net borrowings of short-term debt ............................................. -- 32,000 Dividends paid on cumulative preferred stock .................................. (727) (727) Dividends paid to parent - Energy Group ....................................... (8,500) (17,000) Debt issuance costs ........................................................... (32) (14) ---------- ---------- Net Cash (Used In) Provided by Financing Activities ........................... (9,259) 14,256 ---------- ---------- Net Change in Cash and Cash Equivalents .................................................. (1,456) (5,881) Cash and Cash Equivalents - Beginning of Year ............................................ 4,232 8,227 ---------- ---------- Cash and Cash Equivalents - End of Period ................................................ $ 2,776 $ 2,346 ========== ========== Supplemental Disclosure of Cash Flow Information Interest paid ................................................................. $ 15,581 $ 12,607 Federal and State income tax paid ............................................. $ 6,626 $ 11,875
See Notes to Consolidated Financial Statements -12- CH ENERGY GROUP, INC. CENTRAL HUDSON GAS & ELECTRIC CORPORATION Notes to Consolidated Financial Statements (Unaudited) NOTE 1 - GENERAL Basis of Presentation This Quarterly Report on Form 10-Q is a combined report of CH Energy Group, Inc. ("Energy Group") and its regulated electric and natural gas subsidiary, Central Hudson Gas & Electric Corporation ("Central Hudson"). The Notes to the Consolidated Financial Statements apply to both Energy Group and Central Hudson. Energy Group's Consolidated Financial Statements include the accounts of Energy Group and its wholly owned subsidiaries, which include Central Hudson and Energy Group's non-utility subsidiary, Central Hudson Enterprises Corporation ("CHEC" and, together with its subsidiaries, the "competitive business subsidiaries"). CHEC subsidiary Griffith Energy Services, Inc. ("Griffith") (and prior to its merger with Griffith as of December 31, 2005, SCASCO, Inc. ("SCASCO")) is sometimes referred to herein as the "fuel distribution business." Unaudited Consolidated Financial Statements The accompanying Consolidated Financial Statements of Energy Group and Central Hudson are unaudited but, in the opinion of Management, reflect adjustments (which include normal recurring adjustments) necessary for a fair statement of the results for the interim periods presented. These condensed, unaudited, quarterly Consolidated Financial Statements do not contain the detail or footnote disclosures concerning accounting policies and other matters which would be included in annual Consolidated Financial Statements and, accordingly, should be read in conjunction with the audited Consolidated Financial Statements (including the Notes thereto) included in the combined Energy Group/Central Hudson Annual Report on Form 10-K for the year ended December 31, 2005 (the "Corporations' 10-K Annual Report"). On April 12, 2006, CHEC purchased a 75% interest in Lyonsdale Biomass, LLC ("Lyonsdale"). Lyonsdale owns and operates a 19-megawatt, wood-fired, biomass electric generating plant. The financial statements of Lyonsdale for the period of April 12, 2006, through September 30, 2006, have been fully consolidated into the financial statements of Energy Group. The minority interest shown on Energy Group's Consolidated Financial Statements represents the other owner's proportionate share of the income and equity of Lyonsdale. Energy Group's and Central Hudson's balance sheets as of September 30, 2005, are not required to be included in this Quarterly Report on Form 10-Q; however, these balance sheets are included for supplemental analysis purposes. Central Hudson's and Griffith's operations are seasonal in nature and weather- sensitive and, as a result, financial results for interim periods are not necessarily indicative of trends for a twelve-month period. Demand for electricity typically peaks 13 during the summer, while demand for natural gas and heating oil typically peaks during the winter. NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash and Cash Equivalents For purposes of the Consolidated Statement of Cash Flows, Energy Group and Central Hudson consider temporary cash investments with a maturity, when purchased, of three months or less to be cash equivalents. Revision in the Classification of Certain Securities In connection with the preparation of the Quarterly Report on Form 10-Q for the period ended March 31, 2006, and the classification of Auction Rate Securities and Variable Rate Demand Notes, Energy Group concluded that it was appropriate to classify these securities on Energy Group's Consolidated Balance Sheet as "short-term investments - available-for-sale securities." Previously, these investments had been classified as "cash and cash equivalents." These securities are described in greater detail in Note 5 - "Short-Term Investments" of this Quarterly Report on Form 10-Q. As a result of this revision in classification, Energy Group has also made corresponding adjustments to its Consolidated Statement of Cash Flows for all periods presented to reflect the gross purchases and liquidation of these available-for-sale securities as investing activities rather than as a component of cash and cash equivalents. This revision in classification has no impact on previously reported total current assets, total assets, working capital position, results of operations, or financial covenants and does not affect previously reported cash flows from operating or financing activities. The Consolidated Financial Statements of Central Hudson were not affected by this revision in classification. The impact on net cash from investing activities for the nine months ended September 30, 2005, was a decrease of $0.9 million for activity relating to these investments. The revision in classification for prior period Consolidated Balance Sheets resulted in a decrease to cash and cash equivalents and the reporting of short-term investments in the amount of $42.1 million and $49.6 million at December 31, 2005, and September 30, 2005, respectively. Accounting for Derivative Instruments and Hedging Activities Regulated Electric and Natural Gas Businesses Reference is made to the caption "Accounting for Derivative Instruments and Hedging Activities" of Note 1 - "Summary of Significant Accounting Policies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. At September 30, 2006, the total fair value of open Central Hudson derivatives, which hedge electric and natural gas commodity purchases, was an unrealized loss of $6.4 million. This compares to a fair value at December 31, 2005, of ($315,000), an unrealized loss, and a fair value of $8.5 million at September 30, 2005, an unrealized 14 gain. The significant decrease in the current fair value reflects the decrease in the wholesale costs of electricity and natural gas during the quarter ended September 30, 2006, due to changing market conditions. At September 30, 2006, Central Hudson had open derivative contracts hedging approximately 10.5% of its projected electricity requirements for the period October 2006 through December 2006 and 31.9% of its projected natural gas requirements for the period November 2006 through March 2007. Central Hudson recorded actual net losses of $1.3 million for the quarter ended September 30, 2006, as compared to a net gain of $5.9 million for the same period in 2005. Comparative amounts for the nine months ended September 30, 2006, and 2005, were a net loss of $7.0 million and a net gain of $5.7 million, respectively. Realized gains and losses, in addition to unrealized gains and losses, serve to either decrease or increase actual energy costs and are deferred for return to or recovery from customers under Central Hudson's electric and natural gas energy cost adjustment clauses as authorized by the New York State Public Service Commission ("PSC") and in accordance with the provisions of Statement of Financial Accounting Standard ("SFAS") No. 71, titled Accounting for the Effects of Certain Types of Regulation ("SFAS 71"). Central Hudson also entered into weather derivative contracts to hedge the effect of weather on sales of electricity and natural gas. The periods covered were the three months of the heating seasons ended March 31, 2006, and 2005, the three months of the cooling season ended August 31, 2005, and the months of July and August 2006. Settlement payments to counter-parties during the nine-month periods ended September 30, 2006, and 2005, were $0.5 million and $1.8 million, respectively. These payments related to the cooling season contracts and resulted from weather that was warmer than the contractual strike points. On April 1, 2006, Central Hudson replaced its interest rate cap agreement with a new two-year agreement through April 1, 2008, with similar terms as the expired agreement. As discussed in Note 1 - "Summary of Significant Accounting Policies" of the Corporations' 10-K Annual Report, this rate cap agreement hedges the variability in interest rates related to Central Hudson's bonds issued by the New York State Energy Research Development Authority. Central Hudson also has in place a mechanism authorized by the PSC which defers for return to or recovery from customers any differences between actual variable interest costs and the corresponding costs embedded in customer rates. The premium costs and any realized benefits from the rate cap agreement also pass through this regulatory mechanism. Fuel Distribution Business The fair value of Griffith's open derivative positions at September 30, 2006, was an unrealized loss of $0.3 million as compared to an unrealized gain at September 30, 2005, of $0.2 million. The fair value of derivative instruments at December 31, 2005, was not material. Derivatives outstanding at September 30, 2006, included call and put options designated as cash flow hedges for fuel oil purchases through June 2007 for customers with fixed price contracts. These options hedge approximately 6.7% of Griffith's total projected fuel oil requirements for September 2006 through June 2007. Actual net losses of $0.6 million, including premium expense, were recorded during the 15 quarter and year-to-date ended September 30, 2006. Actual net gains recorded in 2005 were not material. In the first quarter of 2006, Griffith also entered into derivative contracts to hedge a portion (714,000 gallons) of its fuel oil inventory. These derivative instruments, comprised of calendar average New York Mercantile Exchange ("NYMEX") swaps, were designated as a fair value hedge of inventory. The fair value of these instruments at September 30, 2006, and the quarter and nine months to-date impact to earnings were not material. Griffith had previously entered into weather derivative contracts for the three months of the heating seasons ended March 31, 2006, and 2005. Settlement amounts for the comparative quarters were not material. Parental Guarantees Energy Group and certain of the competitive business subsidiaries have issued guarantees in conjunction with certain commodity and derivative contracts that provide financial or performance assurance to third-parties on behalf of a subsidiary. The guarantees are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the relevant subsidiary's intended commercial purposes. In addition, Energy Group agreed to guarantee the post-closing obligations of former subsidiary Central Hudson Energy Services, Inc. ("CH Services") under the agreement related to the sale of former subsidiary CH Resources, Inc. ("CH Resources"), which guarantee became applicable to CHEC. Reference is made to Note 1 - "Summary of Significant Accounting Policies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report under the captions "Parental Guarantees" and "Product Warranties" and to Note 11 - "Commitments and Contingencies" of this Quarterly Report on Form 10-Q under the caption "CHEC." The guarantees described above have been issued to counter-parties to assure the payment, when due, of certain obligations incurred by Energy Group subsidiaries in physical and financial transactions related to heating oil, propane, other petroleum products, weather and commodity hedges, and certain obligations related to the sale of CH Resources. At September 30, 2006, the aggregate amount of subsidiary obligations (excluding obligations related to CH Resources) covered by these guarantees was $4.9 million. Where liabilities exist under the commodity-related contracts subject to these guarantees, these liabilities are included in Energy Group's Consolidated Balance Sheet. Energy Group's approximate aggregate potential liability for product warranties at September 30, 2006, had not changed from that reported at December 31, 2005, which was $101,000. Energy Group's approximate aggregate potential liability for product warranties at September 30, 2005, which had not changed from that reported at December 31, 2004, which was $504,000. Goodwill and Other Intangible Assets Reference is made to Note 5 - "Goodwill and Other Intangible Assets" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. 16 Intangible assets include separate, identifiable, intangible assets such as customer lists and covenants not to compete. Intangible assets with finite lives are amortized over their useful lives. The estimated useful life for customer lists is 15 years, which is believed to be appropriate in view of average historical customer turnover. However, if customer turnover were to substantially increase, a shorter amortization period would be used, resulting in an increase in amortization expense. For example, if a ten-year amortization period were used, annual amortization expense would increase by approximately $1.4 million. The useful life of a covenant not to compete is based on the expiration date of the covenant, generally between two and ten years. Intangible assets with indefinite useful lives and goodwill are no longer amortized, but instead are periodically reviewed for impairment. Goodwill balances are tested annually for impairment in the fourth quarter and are retested between annual tests if an event should occur or circumstances arise that would more likely than not reduce the fair value below its carrying amount. The components of amortizable intangible assets of Energy Group are summarized as follows (thousands of dollars):
- ------------------------------------------------------------------------------------------------------------------ September 30, 2006 December 31, 2005 September 30, 2005 - ------------------------------------------------------------------------------------------------------------------ Gross Gross Gross Carrying Accumulated Carrying Accumulated Carrying Accumulated Amount Amortization Amount Amortization Amount Amortization - ------------------------------------------------------------------------------------------------------------------ Customer Lists $41,758 $14,808 $40,448 $12,754 $39,944 $12,102 - ------------------------------------------------------------------------------------------------------------------ Covenants Not to Compete 1,734 1,124 1,669 995 1,589 959 - ------------------------------------------------------------------------------------------------------------------ Total Amortizable Intangibles $43,492 $15,932 $42,117 $13,749 $41,533 $13,061 - ------------------------------------------------------------------------------------------------------------------
Amortization expense was $2.2 million and $2.0 million for each of the nine-month periods ended September 30, 2006, and 2005, respectively. The estimated annual amortization expense for each of the next five years, assuming no new acquisitions, is approximately $2.9 million. The carrying amount for goodwill not subject to amortization was $52.7 million as of September 30, 2006, $51.3 million as of December 31, 2005, and $50.9 million as of September 30, 2005. Depreciation and Amortization Reference is made to the caption "Depreciation and Amortization" of Note 1 - - "Summary of Significant Accounting Policies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. 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 value of properties. The anticipated costs of removing assets upon retirement are provided for over the life of those assets as a component of depreciation expense. This depreciation method is consistent with industry practice and the applicable depreciation rates have been approved by the PSC. 17 Financial Accounting Standards Board ("FASB") SFAS No. 143, titled Accounting for Asset Retirement Obligations ("SFAS 143"), precludes the recognition of expected future legal retirement obligations as a component of depreciation expense or accumulated depreciation. Central Hudson, however, is required to use depreciation methods and rates approved by the PSC under regulatory accounting. In accordance with SFAS 71, Central Hudson continues to accrue for the future cost of removal for its rate-regulated natural gas and electric utility assets. In accordance with SFAS 143, Central Hudson has classified $44.1 million, $92.2 million, and $91.9 million of net cost of removal as regulatory liabilities as of September 30, 2006, December 31, 2005, and September 30, 2005, respectively. The amount of this liability as of September 30, 2006, has been reduced by the transfer of $52.5 million of electric depreciation reserve pursuant to the Order Establishing Rate Plan ("2006 Order") issued by the PSC on July 24, 2006. The transfer represents a portion of the electric depreciation reserve that is in excess of the theoretical book reserve based on depreciation rates approved by the PSC. For additional information regarding the 2006 Order, see Note 3 - "Regulatory Matters." FASB Interpretation No. 47, titled Accounting for Conditional Asset Retirement Obligations ("FIN 47"), clarifies the term "conditional asset retirement obligation" as used in SFAS 143 to refer to a legal obligation to perform an asset retirement activity when the timing and/or method of settlement are conditional on a future event that may or may not be in the control of the entity. In accordance with FIN 47, Energy Group recorded depreciation expense on the asset retirement obligations and accretion expense on the liabilities for the nine months ended September 30, 2006. These amounts were not material. For further information regarding FIN 47, see the caption "Depreciation and Amortization" of Note 1 - "Summary of Significant Accounting Policies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. For financial statement purposes, the fuel distribution business's depreciation provisions are computed on the straight-line method using depreciation rates based on the estimated useful lives of depreciable property and equipment. Expenditures for major renewals and betterments, which extend the useful lives of property and equipment, are capitalized. Expenditures for maintenance and repairs are charged to expense when incurred. Retirements, sales, and disposals of assets are recorded by removing the cost and accumulated depreciation from the asset and accumulated depreciation accounts with any resulting gain or loss reflected in earnings. Accumulated depreciation for the fuel distribution business was $16.7 million, $14.9 million, and $14.3 million as of September 30, 2006, December 31, 2005, and September 30, 2005, respectively. Accumulated depreciation for Lyonsdale was $0.4 million as of September 30, 2006. 18 Amortization of intangibles (other than goodwill) is computed on the straight-line method over an asset's expected useful life. See the caption "Goodwill and Other Intangible Assets" of this Note 2 for further discussion. Earnings Per Share Reference is made to Note 1 - "Summary of Significant Accounting Policies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report under the caption "Earnings Per Share." In the calculation of earnings per share (basic and diluted) of Energy Group's common stock ("Common Stock"), earnings for Energy Group are reduced by the preferred stock dividends of Central Hudson. The average dilutive effect of Energy Group's stock options and performance shares was 15,473 shares and 6,783 shares for the quarters ended September 30, 2006, and 2005, and 14,455 shares and 5,729 shares for the nine months ended September 30, 2006, and 2005, respectively. Certain stock options are excluded from the calculation of diluted earnings per share because the exercise prices of those options were greater than the average market price per share of Common Stock for some of the periods presented. Excluded from the above calculation were options for 36,900 shares for the three-month period ended September 30, 2005, and 35,700 shares and 36,900 shares for the nine-month periods ended September 30, 2006, and 2005, respectively. For additional information regarding stock options and performance shares, see Note 8 - "Equity-Based Compensation Incentive Plans." Equity-Based Compensation Energy Group has an equity-based employee compensation plan that is described in Note 8 - "Equity-Based Compensation Incentive Plans." FIN 46R - Consolidation of Variable Interest Entities Reference is made to the subcaption "FIN 46 - Consolidation of Variable Interest Entities" of Note 1 - "Summary of Significant Accounting Policies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. Energy Group and its subsidiaries do not have any interests in special purpose entities and are not affiliated with any variable interest entities that currently require consolidation under the provisions of FIN 46R. Reclassification Certain amounts in the 2005 Consolidated Financial Statements have been reclassified to conform to the 2006 presentation. Primarily, the Consolidated Balance Sheet for Energy Group has been reformatted to distinguish Investments in Unconsolidated Affiliates from Other Assets. 19 NOTE 3 - REGULATORY MATTERS Reference is made to Note 2 - "Regulatory Matters" under caption "Rate Proceedings - Electric and Natural Gas" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. In April 2006, Central Hudson, Department of Public Service Staff ("PSC Staff"), and other parties served on all parties a negotiated Joint Proposal ("2006 Joint Proposal") to be considered by the PSC in Central Hudson's then current electric and natural gas rate proceeding. Under the terms of the 2006 Joint Proposal, an increase to electric delivery revenues of $53.7 million over the three-year term is to be phased-in with annual electric delivery rate increases of approximately $17.9 million as of July 1, 2006, July 1, 2007, and July 1, 2008. A natural gas delivery revenue increase of $14.1 million is to be phased-in over two years with natural gas delivery rate increases of $8 million as of July 1, 2006, and $6.1 million as of July 1, 2007. On June 20, 2006, the PSC extended the normal eleven-month suspension of the case through August 29, 2006, with a make-whole provision for the loss of revenues due to the extension of the suspension period past July 1, 2006. On July 24, 2006, the PSC issued the 2006 Order following action to approve the 2006 Joint Proposal at its July 19, 2006, session. The 2006 Order adopted all of the terms and conditions of the 2006 Joint Proposal with a modification requiring distribution right-of-way ("ROW") maintenance expenses to be subject to the same shortfall true-up mechanism that applies to transmission ROW maintenance expenses. The 2006 Order directed a compliance tariff filing to place new rates into effect as of August 1, 2006, subject to the terms and conditions of the 2006 Order; Central Hudson made this compliance filing on July 31, 2006. The 2006 Order provides for delivery rates based on a return on equity ("ROE") of 9.6% with an earnings sharing threshold of 10.6%, above which Central Hudson is to share earnings with its customers. Rates are based on a capital structure which includes 45% common equity, but the actual proportion of common equity up to a limit of 47% may be used in determining the return on common equity for the purpose of earnings sharing. The 2006 Order also includes the continued full recovery of all purchased natural gas and electricity costs through existing monthly supply cost recovery mechanisms. In addition, three-year capital expenditure targets to fund investments in its electric, natural gas, and common plant, and increased allowances for the recovery of operating costs, including transmission and distribution ROW maintenance expenses, have been established. The capital expenditure targets are subject to true-up provisions, requiring deferral of the revenue equivalent of any shortfalls in spending over the three-year term. Transmission and distribution ROW maintenance expenses are also subject to true-up provisions over the three-year term, requiring the deferral of shortfalls in actual expenditures. The 2006 Order also provides increased rate allowances and continued deferral accounting authorization for the recovery of expenses for pensions, other post-employment benefits ("OPEB"), stray voltage testing, manufactured gas plant ("MGP") site remediation, and certain other 20 expense items. The 2006 Order also provides additional funding to assist low-income customers in paying their energy bills as well as continued funding of programs to encourage customers to explore new opportunities available through the competitive retail supply markets. In addition, the 2006 Order includes penalty-only performance mechanisms with established targets for specified levels of performance for a number of customer service quality, natural gas safety, and electric reliability measures. On August 30, 2006, Central Hudson filed for rehearing on one element of the 2006 Order. The filing asserts that the PSC failed to update Central Hudson's allowed ROE using the PSC's Generic Finance Case Methodology. Central Hudson requested that a rehearing be conducted to revise its allowed ROE to 9.9%. Neither Energy Group nor Central Hudson can predict the timing or the final outcome of this petition. A copy of the 2006 Order is available on Energy Group's website at www.CHEnergyGroup.com. Financing Petition On September 21, 2006, the PSC issued an Order authorizing issuance of securities, in response to a financing petition Central Hudson filed on July 3, 2006. The Order authorizes Central Hudson to issue and sell up to $140 million of medium-term notes through December 31, 2009, and to enter into revolving credit agreements in an amount not to exceed $125 million and for periods not to exceed five years. Non-Utility Land Sales Regulated Electric and Natural Gas Businesses Commencing April 26, 2005, and updated on May 22, 2006, Central Hudson filed Notices of Intent with the PSC to sell 43 parcels of non-utility real property. On July 22, 2005, the PSC issued an Order stating that the filings shall be reviewed further under Public Service Law Section 70 ("Section 70") to determine the disposition of and the accounting for the potential gains. On June 23, 2006, the PSC issued an Order approving the proposed transfers of ownership interests in the non-utility property and the recognition of any gains realized upon the transfers for the benefit of shareholders. During the three months ended September 30, 2006, Central Hudson has sold several parcels of non-utility real property for $1.8 million in excess of book value and transaction costs, which is recorded as a reduction to Other Expenses of Operation. Other Businesses On June 29, 2006, Energy Group (the holding company) sold real property for $0.7 million in excess of book value and transaction cost. 21 NOTE 4 - ACQUISITIONS AND INVESTMENTS Reference is made to Note 4 - "Acquisition, Investments, and Divestitures" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. Acquisitions During the first quarter of 2006, Griffith acquired certain assets of one fuel distribution company for a total of $390,000. The purchase price allocated to intangible assets (including goodwill) was $305,000, of which $145,000 was allocated to goodwill. The principal tangible assets acquired were vehicles. During the second quarter of 2006, Griffith acquired certain assets of four fuel distribution companies for a total of $1.7 million. The purchase price allocated to intangible assets (including goodwill) was $1.4 million, of which $654,000 was allocated to goodwill. The principal tangible assets acquired were vehicles, petroleum products, and spare parts. All four acquisitions have earn-out provisions, which may increase the purchase price if certain sales volumes are attained. During the third quarter of 2006, Griffith acquired certain assets of two fuel distribution companies for a total of $1.0 million. The purchase price allocated to intangible assets (including goodwill) was $942,000, of which $478,000 was allocated to goodwill. The principal tangible assets acquired were vehicles and spare parts. Subsequent to September 30, 2006, Griffith acquired certain assets of a fuel distribution company for $300,000. The entire purchase price was allocated to intangible assets. No amount of the purchase price was allocated to goodwill. On April 12, 2006, CHEC purchased a 75% interest in Lyonsdale from Catalyst Renewables Corporation ("Catalyst") for $10.8 million, including a working capital adjustment of $1.0 million. CHEC allocated the total purchase price based on the fair value of assets acquired and liabilities assumed as follows: Current Assets of $1.3 million, Other Property and Plant of $9.6 million, and Current Liabilities of $0.1 million. Catalyst remains the owner of a minority share of Lyonsdale and will provide asset management services to Lyonsdale under a contract expiring April 12, 2009. Lyonsdale owns and operates a 19-megawatt, wood-fired, biomass electric generating plant, which began operation in 1992. The plant is located in Lyonsdale, New York. The energy and capacity of the plant is being sold at a fixed price to an investment grade rated counter-party through a long-term contract beginning May 1, 2006, and ending December 31, 2014. The financial statements of Lyonsdale for the period of April 12, 2006, through September 30, 2006, have been fully consolidated into the financial statements of Energy Group. Investments Reference is made to the subcaption "Investments" of Note 4 - "Acquisitions, Investments, and Divestitures" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. 22 In January 2006, Cornhusker Energy Lexington Holdings, LLC ("Cornhusker Holdings") began operation of its fuel ethanol production facility, located in Lexington, Nebraska. On March 9, 2006, CHEC acquired an additional $2.0 million of subordinated notes issued by Cornhusker Holdings, bringing the total acquired by CHEC to-date to $5.0 million. On March 10, 2006, CHEC invested $4.9 million in CH-Community Wind Energy, LLC, a joint venture between CHEC and Community Energy, Inc. The joint venture closed on its investment in the Bear Creek and Jersey Atlantic wind farm projects, which are both commercially operational. CH-Community Wind Energy, LLC currently owns an 18% minority interest in these projects. CHEC's investments are accounted for under the equity method. NOTE 5 - SHORT-TERM INVESTMENTS Energy Group's short-term investments consist of Auction Rate Securities ("ARS") and Variable Rate Demand Notes ("VRDN"), which have been classified as current available-for-sale securities pursuant to the provisions of SFAS No. 115, titled Accounting for Certain Investments in Debt and Equity Securities. ARS and VRDN are debt instruments with a long-term nominal maturity and a mechanism that resets the interest rate at regular intervals. Energy Group's investments include tax-exempt ARS and VRDN with interest rates that are reset anywhere from 7 to 35 days. These investments are available to fund current operations or to provide funding in accordance with Energy Group's strategy to redeploy equity into its subsidiaries. Due to the nature of these securities with regard to their interest reset periods, the aggregate carrying value approximates their fair value, thereby not impacting shareholders equity with regard to unrealized gains and losses. The aggregate fair value of these short-term investments was $40.3 million at September 30, 2006, $42.1 million at December 31, 2005, and $49.6 million at September 30, 2005. Cash flows from the purchases and liquidation of these investments are reported separately as investing activities in Energy Group's Consolidated Statements of Cash Flow. NOTE 6 - SEGMENTS AND RELATED INFORMATION Reference is made to Note 12 - "Segments and Related Information" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. 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 CHEC. The investments and business development activities of Energy Group and the energy efficiency and investment activities of CHEC, including its ownership interests in ethanol, wind, and biomass energy projects, are reported under the heading "Unregulated - Other." Certain additional information regarding these segments is set forth in the following tables. General corporate expenses, Central Hudson property common to both electric and natural gas segments, and the depreciation of Central Hudson's 23 common property have been allocated in accordance with practices established for regulatory purposes. Central Hudson's and Griffith's operations are seasonal in nature and weather-sensitive and, as a result, financial results for interim periods are not necessarily indicative of trends for a twelve-month period. Demand for electricity typically peaks during the summer, while demand for natural gas and heating oil typically peaks during the winter. 24 CH Energy Group, Inc. Segment Disclosure
- --------------------------------------------------------------------------------------------------------------------------- Quarter Ended September 30, 2006 ------------------------------------------------------------------------------------------------ (In Thousands, Except Earnings Per Share) Regulated Unregulated Eliminations Total - --------------------------------------------------------------------------------------------------------------------------- Natural Fuel Electric Gas Distribution Other - --------------------------------------------------------------------------------------------------------------------------- Revenues from external customers $154,723 $ 18,384 $ 64,266 $ 2,447 $ -- $ 239,820 - --------------------------------------------------------------------------------------------------------------------------- Intersegment revenues 3 38 -- -- (41) -- - --------------------------------------------------------------------------------------------------------------------------- Total revenues $154,726 $ 18,422 $ 64,266 $ 2,447 $ (41) $ 239,820 - --------------------------------------------------------------------------------------------------------------------------- Earnings(loss) before income taxes $ 17,423 $ (1,358) $ (3,882) $ 3,179 $ -- $ 15,362 - --------------------------------------------------------------------------------------------------------------------------- Net(loss) income $ 11,207 $ (676) $ (2,329) $ 2,768 $ -- $ 10,970 - --------------------------------------------------------------------------------------------------------------------------- Earnings(Loss) Per Share - Diluted $ 0.71 $ (0.04) $ (0.15) $ 0.18(1) $ -- $ 0.70 - --------------------------------------------------------------------------------------------------------------------------- Segment Assets at September 30, 2006 $827,095 $286,931 $141,285 $99,219 $ (317)(2) $1,354,213 - ---------------------------------------------------------------------------------------------------------------------------
(1) The amount of earnings per share ("EPS") attributable to CHEC's other business activities was $0.12 per share, with the balance of $0.06 per share resulting primarily from interest income and business development activities. (2) Includes minority interest of $1,501 related to Lyonsdale.
- ----------------------------------------------------------------------------------------------------------------------- Nine Months Ended September 30, 2006 ------------------------------------------------------------------------------------------- (In Thousands, Except Earnings Per Share) Regulated Unregulated Eliminations Total - ----------------------------------------------------------------------------------------------------------------------- Natural Fuel Electric Gas Distribution Other - ----------------------------------------------------------------------------------------------------------------------- Revenues from external customers $398,700 $125,651 $242,325 $ 4,267 $ -- $ 770,943 - ----------------------------------------------------------------------------------------------------------------------- Intersegment revenues 11 277 -- -- (288) -- - ----------------------------------------------------------------------------------------------------------------------- Total revenues $398,711 $125,928 $242,325 $ 4,267 $ (288) $ 770,943 - ----------------------------------------------------------------------------------------------------------------------- Earnings before income taxes $ 33,615 $ 11,699 $ (92) $ 7,366 $ -- $ 52,588 - ----------------------------------------------------------------------------------------------------------------------- Net income $ 20,515 $ 6,709 $ (55) $ 6,169 $ -- $ 33,338 - ----------------------------------------------------------------------------------------------------------------------- Earnings Per Share - Diluted $ 1.30 $ 0.43 $ (0.01) $ 0.39(1) $ -- $ 2.11 - ----------------------------------------------------------------------------------------------------------------------- Segment Assets at September 30, 2006 $827,095 $286,931 $141,285 $99,219 $ (317)(2) $1,354,213 - -----------------------------------------------------------------------------------------------------------------------
(1) The amount of EPS attributable to CHEC's other business activities was $0.18 per share, with the balance of $0.21 per share resulting primarily from interest income and business development activities. (2) Includes minority interest of $1,501 related to Lyonsdale. 25
- ---------------------------------------------------------------------------------------------------------------------------- (In Thousands, Except Quarter Ended September 30, 2005 Earnings Per Share) ------------------------------------------------------------------------------------------- Regulated Unregulated Eliminations Total - ---------------------------------------------------------------------------------------------------------------------------- Natural Fuel Electric Gas Distribution Other - ---------------------------------------------------------------------------------------------------------------------------- Revenues from external customers $159,589 $ 14,115 $ 54,008 $ 184 $ -- $ 227,896 - ---------------------------------------------------------------------------------------------------------------------------- Intersegment revenues 3 14 -- -- (17) -- - ---------------------------------------------------------------------------------------------------------------------------- Total revenues $159,592 $ 14,129 $ 54,008 $ 184 $ (17) $ 227,896 - ---------------------------------------------------------------------------------------------------------------------------- Earnings (loss) before income taxes $ 13,084 $ (1,957) $ (3,967) $ 950 $ -- $ 8,110 - ---------------------------------------------------------------------------------------------------------------------------- Net (loss) income $ 7,750 $ (1,107) $ (2,381) $ 1,484 $ -- $ 5,746 - ---------------------------------------------------------------------------------------------------------------------------- Earnings (Loss) Per Share - Diluted $ 0.49 $ (0.07) $ (0.15) $ 0.09(1) $ -- $ 0.36 - ---------------------------------------------------------------------------------------------------------------------------- Segment Assets at September 30, 2005 $813,955 $276,170 $138,088 $117,716 $ (205) $1,345,724 - ----------------------------------------------------------------------------------------------------------------------------
(1) Reflects Energy Group earnings of $0.09 per share attributable primarily to the recording of New York State income tax benefits of $0.05 per share related to the completion of the Energy Group tax audit as well as investment and business development activities.
- ---------------------------------------------------------------------------------------------------------------------------- Nine Months Ended September 30, 2005 ------------------------------------------------------------------------------------------- (In Thousands, Except Earnings Per Share) Regulated Unregulated Eliminations Total - ---------------------------------------------------------------------------------------------------------------------------- Natural Fuel Electric Gas Distribution Other - ---------------------------------------------------------------------------------------------------------------------------- Revenues from external customers $392,866 $108,687 $201,362 $ 639 $ -- $ 703,554 - ---------------------------------------------------------------------------------------------------------------------------- Intersegment revenues 9 218 -- -- (227) -- - ---------------------------------------------------------------------------------------------------------------------------- Total revenues $392,875 $108,905 $201,362 $ 639 $ (227) $ 703,554 - ---------------------------------------------------------------------------------------------------------------------------- Earnings before income taxes $ 33,782 $ 12,230 $ 1,317 $ 3,278 $ -- $ 50,607 - ---------------------------------------------------------------------------------------------------------------------------- Net income $ 20,098 $ 7,163 $ 789 $ 4,569 $ -- $ 32,619 - ---------------------------------------------------------------------------------------------------------------------------- Earnings Per Share - Diluted $ 1.28 $ 0.45 $ 0.05 $ 0.29(1) $ -- $ 2.07 - ---------------------------------------------------------------------------------------------------------------------------- Segment Assets at September 30, 2005 $813,955 $276,170 $138,088 $117,716 $ (205) $1,345,724 - ----------------------------------------------------------------------------------------------------------------------------
(1) The amount of EPS attributable to CHEC's other business activities was $0.02 per share; the balance of $0.27 per share resulted primarily from the recording of New York State income tax benefits of $0.14 per share related to the completion of the Energy Group tax audit as well as investment and business development activities. 26 Central Hudson Gas & Electric Corporation Segment Disclosure
- ----------------------------------------------------------------------------------------------------- (In Thousands) Quarter Ended September 30, 2006 - ----------------------------------------------------------------------------------------------------- Natural Electric Gas Eliminations Total - ----------------------------------------------------------------------------------------------------- Revenues from external customers $154,723 $ 18,384 $ -- $ 173,107 - ----------------------------------------------------------------------------------------------------- Intersegment revenues 5 38 (43) -- - ----------------------------------------------------------------------------------------------------- Total Revenues $154,728 $ 18,422 $ (43) $ 173,107 - ----------------------------------------------------------------------------------------------------- Earnings before income taxes $ 17,665 $ (1,358) $ -- $ 16,307 - ----------------------------------------------------------------------------------------------------- Net Income $ 11,390 $ (617) $ -- $ 10,773 - ----------------------------------------------------------------------------------------------------- Income Available for Common Stock $ 11,207 $ (676) $ -- $ 10,531 - ----------------------------------------------------------------------------------------------------- Segment Assets at September 30, 2006 $827,095 $ 286,931 $ -- $1,114,026 - ----------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------- (In Thousands) Nine Months Ended September 30, 2006 - ----------------------------------------------------------------------------------------------------- Natural Electric Gas Eliminations Total - ----------------------------------------------------------------------------------------------------- Revenues from external customers $398,700 $ 125,651 $ -- $ 524,351 - ----------------------------------------------------------------------------------------------------- Intersegment revenues 11 277 (288) -- - ----------------------------------------------------------------------------------------------------- Total Revenues $398,711 $ 125,928 $ (288) $ 524,351 - ----------------------------------------------------------------------------------------------------- Earnings before income taxes $ 34,160 $ 11,881 $ -- $ 46,041 - ----------------------------------------------------------------------------------------------------- Net Income $ 21,065 $ 6,886 $ -- $ 27,951 - ----------------------------------------------------------------------------------------------------- Income Available for Common Stock $ 20,515 $ 6,709 $ -- $ 27,224 - ----------------------------------------------------------------------------------------------------- Segment Assets at September 30, 2006 $827,095 $ 286,931 $ -- $1,114,026 - ----------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------- (In Thousands) Quarter Ended September 30, 2005 - ----------------------------------------------------------------------------------------------------- Natural Electric Gas Eliminations Total - ----------------------------------------------------------------------------------------------------- Revenues from external customers $159,589 $ 14,115 $ -- $ 173,704 - ----------------------------------------------------------------------------------------------------- Intersegment revenues 3 14 (17) -- - ----------------------------------------------------------------------------------------------------- Total Revenues $159,592 $ 14,129 $ (17) $ 173,704 - ----------------------------------------------------------------------------------------------------- Earnings before income taxes $ 13,266 $ (1,897) $ -- $ 11,369 - ----------------------------------------------------------------------------------------------------- Net Income $ 7,932 $ (1,047) $ -- $ 6,885 - ----------------------------------------------------------------------------------------------------- Income Available for Common Stock $ 7,750 $ (1,107) $ -- $ 6,643 - ----------------------------------------------------------------------------------------------------- Segment Assets at September 30, 2005 $813,955 $ 276,170 $ -- $1,090,125 - ----------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------- (In Thousands) Nine Months Ended September 30, 2005 - ----------------------------------------------------------------------------------------------------- Natural Electric Gas Eliminations Total - ----------------------------------------------------------------------------------------------------- Revenues from external customers $392,866 $ 108,687 $ -- $ 501,553 - ----------------------------------------------------------------------------------------------------- Intersegment revenues 9 218 (227) -- - ----------------------------------------------------------------------------------------------------- Total Revenues $392,875 $ 108,905 $ (227) $ 501,553 - ----------------------------------------------------------------------------------------------------- Earnings before income taxes $ 34,327 $ 12,412 $ -- $ 46,739 - ----------------------------------------------------------------------------------------------------- Net Income $ 20,644 $ 7,344 $ -- $ 27,988 - ----------------------------------------------------------------------------------------------------- Income Available for Common Stock $ 20,098 $ 7,163 $ -- $ 27,261 - ----------------------------------------------------------------------------------------------------- Segment Assets at September 30, 2005 $813,955 $ 276,170 $ -- $1,090,125 - -----------------------------------------------------------------------------------------------------
27 NOTE 7 - NEW ACCOUNTING STANDARDS AND OTHER FASB PROJECTS Reference is made to the captions "New Accounting Standards and Other FASB Projects - Standards Implemented" and "New Accounting Standards and Other FASB Projects - Standards to be Implemented" of Note 1 - "Summary of Significant Accounting Policies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. Classification of Options and Similar Instruments Issued as Employee Compensation that Allow for Cash Settlement Upon the Occurrence of a Contingent Event On February 3, 2006, the FASB issued FASB Staff Position ("FSP") No. FAS 123(R)-4, titled Classification of Options and Similar Instruments Issued as Employee Compensation that Allow for Cash Settlement Upon the Occurrence of a Contingent Event ("FSP FAS 123(R)-4"). This FSP addresses the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event, such as a change in control or other liquidity event of the company, death or disability of the holder, or an initial public offering. FSP FAS 123(R)-4 amends FASB Statement No. 123(R), titled Share-Based Payment ("SFAS 123(R)"), to address such situations. The guidance in this FSP is effective with the adoption of SFAS 123(R). For Energy Group, SFAS 123(R) was adopted effective January 1, 2006. The provisions of this FSP do not currently apply to Energy Group or its subsidiaries. Accounting for Certain Hybrid Financial Instruments - an Amendment of FASB Statements Nos. 133 and 140 In March 2006, the FASB issued SFAS No. 155, titled Accounting for Certain Hybrid Financial Instruments, an Amendment of FASB Statements No. 133 and 140 ("SFAS 155"). SFAS 155 modifies requirements for financial reporting for certain hybrid financial instruments by requiring more consistent accounting which eliminates exemptions and provides a means to simplify the accounting for these instruments. SFAS 155 also resolves issues addressed in Statement 133 Implementing Issue No. D1, titled Application of Statement 133 to Beneficial Interests in Securitized Financial Assets. SFAS 155 is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006, with earlier application permitted. If applicable, Energy Group would expect to adopt SFAS 155 as of January 1, 2007. The provisions of SFAS 155 do not currently apply to Energy Group or its subsidiaries, as they do not have hybrid financial instruments as defined by SFAS 155. 28 Presentation of Governmental Taxes in the Income Statement In June 2006, the Emerging Issues Task Force ("EITF") ratified a consensus on EITF Issue No. 06-3, titled How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement. This Issue focused on any taxes assessed by a governmental authority that are imposed concurrently on specific revenue-producing transactions between a seller and a customer and how they should be presented in the income statement. Taxes assessed on an entity's activities over a period of time, such as gross receipts taxes, are not within the scope of the Issue. The presentation of taxes on either a gross (i.e. included in revenues and costs) or net basis (i.e. excluded from revenues) is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22, titled Disclosure of Accounting Policies. Tax amounts deemed significant when reporting on a gross basis should be disclosed for interim and annual financial statements for each period for which an income statement is presented. This Issue does not require an entity to reevaluate its existing classification policies related to taxes assessed by a governmental authority but does require the presentation of additional disclosures. This Issue is applicable to financial reports for interim and annual reporting periods beginning after December 15, 2006, with earlier application permitted. Energy Group does not expect this Issue to have any impact on the financial condition, results of operations, or cash flows of Energy Group or its subsidiaries. Accounting for Uncertain Tax Positions In July 2006, the FASB issued Interpretation No. 48, titled Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 ("FIN 48"). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity's financial statements in accordance with FASB Statement No. 109, titled Accounting for Income Taxes. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting for interim periods, and disclosure and transition issues. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the entity determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, the entity should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit to 29 recognize in the financial statements. The tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, and are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more likely than not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings for that fiscal year. The implementation of FIN 48 is not expected to have a material impact on the financial condition, results of operations, or cash flows of Energy Group or its subsidiaries. Pension Protection Act of 2006 On August 17, 2006, President Bush signed the Pension Protection Act of 2006 ("Pension Act") into law. It introduces new funding requirements for single and multi-employer defined benefit pension plans, provides legal certainty for cash balance and other hybrid plans, and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans, and investment advice provided to plan participants. The new defined benefit funding rules are effective for plan years beginning after December 31, 2007. Certain transition rules will apply for 2008 through 2010. Energy Group is reviewing the potential impacts of the Pension Act. At the present time, neither Energy Group nor Central Hudson can predict the impact that the Pension Act may have on the financial condition, results of operations, or cash flows of Energy Group or its subsidiaries. Fair Value Measurements On September 6, 2006, FASB issued SFAS No. 157, titled Fair Value Measurement ("SFAS 157"). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, SFAS 157 does not require any new fair value measurements. However, for some entities, the application of SFAS 157 will change current practice. The changes to current practice resulting from the application of SFAS 157 relate to the definition of fair value, the methods used to measure fair value, and the expanded disclosure about fair value measurement. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS 157 also stipulates that, as a market-based measurement, 30 fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability and establishes a fair value hierarchy that distinguishes between (a) market participant assumptions developed based on market data obtained from sources independent of the reporting entity and (b) the reporting entity's own assumptions about market participant assumptions developed based on the best information available in the circumstances. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, with early adoption permitted. Energy Group does not expect SFAS 157 to have a significant impact on the financial condition, results of operations, or cash flows of Energy Group or its subsidiaries. Financial Statements - Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements On September 13, 2006, the SEC issued Staff Accounting Bulleting ("SAB") No. 108, titled Financial Statements - Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements ("SAB 108"). SAB 108 is intended to provide guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in the current year financial statements for the purpose of determining whether the current year's financial statements are materially misstated. The SEC indicates that both the "iron curtain" and "rollover" approaches should be used in quantifying a current year misstatement for purposes of determining its materiality. The "iron curtain" approach focuses on how the current year's balance sheet would be affected in correcting a misstatement without considering the year(s) in which the misstatement originated. The "rollover" approach focuses on the amount of the misstatement that originated in the current year's income statement. In SAB 108, the SEC indicates that the registrant must quantify the impact of correcting all misstatements, including both the carry-over and reversing effects of prior year misstatements, on the current year financial statements. The guidance in SAB 108 is effective the first fiscal year ending after November 15, 2006, though early application in an interim period is encouraged. Energy Group does not expect SAB 108 to have any impact on the financial condition, results of operations, or cash flows of Energy Group or its subsidiaries. Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans On September 29, 2006, the FASB issued Statement No. 158, titled Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an Amendment of FASB Statements No. 87, 88, 106, and 132(R) ("SFAS 158"). SFAS 158 requires an employer that sponsors a defined benefit post-retirement plan to report the current economic status (i.e. the overfunded or underfunded status) of the plan in its statement of financial position. Moreover, SFAS 158 requires an employer to measure the plan assets and plan obligations as of the date of its statement of financial position 31 rather than as of a measurement date that is up to three months before the end of its fiscal year. As a result of SFAS 158, reported financial information will measure plan assets and benefit obligations on the same date as the employer's assets and liabilities and reflect all changes in a plan's overfunded or underfunded status as such changes arise. Pursuant to SFAS 87 and SFAS 106, titled Employers' Accounting for Postretirement Benefits Other Than Pensions, the resultant change in status of the liability or prepaid asset will be recognized as a component of other comprehensive income ("OCI"). Pursuant to SFAS 71 and under the policy of the PSC regarding pension and OPEB costs, Central Hudson has historically recovered its net periodic pension and OPEB costs through customer rates, with differences from rate allowances deferred for future recovery from or return to customers as a regulatory asset or regulatory liability. Consistent with this policy, changes in the funded status will be recognized as such, rather than in OCI. SFAS 158 is effective for fiscal years ending after December 15, 2006, which for Energy Group would be fiscal year ended December 31, 2006, with an exception for the provision to change the measurement date, which is effective for fiscal years ending after December 15, 2008. Energy Group is currently assessing the impact that the adoption of SFAS 158 will have on the financial condition, results of operations, or cash flows of Energy Group or its subsidiaries. Amendment of FASB Staff Position FAS 123(R)-1 On October 10, 2006, the FASB FSP No. FAS 123(R)-5, titled Amending Guidance for Accounting for Modifications of Instruments in Connection with Equity Restructuring ("FSP FAS 123(R)-5"). FSP FAS 123(R)-5 addresses whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1. It stipulates that for instruments that were originally issued as employee compensation and then modified solely to reflect an equity restructuring that occurs when the holders are no longer employees, that there is no change in the recognition or measurement of those instruments if (a) there is no increase in fair value of the award and (b) all holders of the same class of instruments are treated in the same manner. The guidance in FSP FAS 123(R)-5 is effective in the first reporting period beginning after October 10, 2006. Early application is permitted in periods for which financial statements have not been issued. The provisions of FSP FAS 123(R)-5 do not currently apply to Energy Group or its subsidiaries. Technical Corrections of FASB Statement No. 123(R) On October 20, 2006, the FASB issued FSP No. FAS 123(R)-6, titled Technical Corrections of FASB Statement No. 123(R) ("FSP FAS 123(R)-6"). FSP FAS 123(R)-6 32 was issued to make several technical corrections to SFAS 123(R), to the following Paragraphs as specified: A240(d)(1) to exempt non-public entities from disclosing the aggregate intrinsic value of outstanding fully vested share options; A102 of Illustration 4(b) to revise the computation of the minimum compensation cost that must be recognized; A170 of Illustration 13(e) to indicate that at the date the illustrative awards were no longer probable of vesting, any previously recognized compensation cost should have been reversed; E1 to change the definition of short-term inducement to exclude an offer to settle an award. The guidance in FSP FAS 123(R)-6 is effective in the first reporting period beginning after October 20, 2006. Early application is permitted in periods for which financial statements have not yet been issued. Energy Group is currently assessing the impact, if any, that the adoption of FSP FAS 123(R)-6 will have on the financial condition, results of operations, or cash flows of Energy Group or its subsidiaries. NOTE 8 - EQUITY-BASED COMPENSATION INCENTIVE PLANS Reference is made to Note 10 - "Equity-Based Compensation Incentive Plans" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report and to the description of Energy Group's Long-Term Performance-Based Incentive Plan (the "2000 Plan") described therein. Energy Group has adopted a Long-Term Equity Incentive Plan (the "2006 Plan") to replace the 2000 Plan. The 2006 Plan was approved by Energy Group's shareholders on April 25, 2006. The 2000 Plan has been terminated, with no new awards to be granted under such plan. Outstanding awards granted under the 2000 Plan will continue in accordance with their terms and the provisions of the 2000 Plan. The 2006 Plan reserves up to a maximum of 300,000 shares of Common Stock for awards to be granted under the 2006 Plan. Awards may consist of stock option rights, stock appreciation rights, performance shares, performance units, restricted shares, restricted stock units, and other awards that Energy Group's Compensation Committee of its Board of Directors ("Compensation Committee") may authorize. The Compensation Committee may also, from time to time and upon such terms and conditions as it may determine, authorize the granting to non-employee Directors of stock option rights, stock appreciation rights, restricted shares, and restricted stock units. In addition to the aggregate limit in the awards described above, the 2006 Plan imposes various sub-limits on the number of shares of Common Stock that may be issued or transferred under the 2006 Plan. The aggregate number of shares of Common Stock actually issued or transferred by Energy Group upon the exercise of incentive stock options shall not exceed 300,000 shares. No participant shall be granted stock option rights and stock appreciation rights, in aggregate, for more than 15,000 shares of Common Stock during any calendar year. No participant in any calendar year shall receive an award of performance shares or restricted shares that specify management objectives, in the aggregate, for more than 20,000 shares of 33 Common Stock, or performance units having an aggregate maximum value as of their respective date of grant in excess of $1 million. The number of shares of Common Stock issued as stock appreciation rights, restricted shares, and restricted stock units (after taking forfeitures into account) shall not exceed, in the aggregate,100,000 shares of Common Stock. Performance shares were granted, in aggregate, to executives covered under the 2000 Plan in the amount of 29,300 shares and 23,000 shares, on January 1, 2004, and January 1, 2005, respectively. Performance shares were granted, in aggregate, to executives covered under the 2006 Plan in the amount of 20,710 shares on April 25, 2006. Due to the retirement of Energy Group's former Chairman in mid-2004, pro-rated shares of the 2004 grants were awarded to him in 2004. As of September 30, 2006, the number of performance shares that remain outstanding are as follows: 19,800 from the 2004 grant, 23,000 from the 2005 grant, and 20,710 from the 2006 grant. The ultimate number of shares earned under the awards is based on metrics established by the Compensation Committee at the beginning of the award cycle. Compensation expense is recorded as performance shares are earned over the relevant three-year life of the performance share grant prior to its award. Compensation expense recorded related to performance shares for the quarters ended September 30, 2006, and 2005, was $397,000 and $121,000, respectively. Compensation expense related to performance shares for the nine months ended September 30, 2006, was $816,000 and was not material for the same period in 2005. A summary of the status of stock options awarded to executives and non-employee Directors of Energy Group and its subsidiaries under the 2000 Plan as of September 30, 2006, is as follows: 34 Weighted Weighted Average Average Stock Option Exercise Remaining Shares Price Life in Years ------------ ---------- ------------- Outstanding at 12/31/05 73,300 $ 46.18 5.99 Granted -- -- -- Exercised (7,800) $ 43.64 Expired/Cancelled -- -- -- ---------- ---------- ---------- Outstanding at 9/30/06 65,500 $ 46.49 5.34 ========== ========== ========== Total Shares Outstanding 15,762,000 Potential Dilution 0.4% A total of 7,800 non-qualified stock options with exercise prices of $31.94, $44.06, and $48.62 were exercised during the nine months ended September 30, 2006. Total intrinsic value of options exercised was not material. Compensation expense related to stock options recorded for the nine months ended September 30, 2006, and 2005, was not material. The balance accrued at September 30, 2006, for outstanding stock options was $213,000. The intrinsic value of options outstanding was not material. The following table summarizes information concerning outstanding and exercisable stock options at September 30, 2006, by exercise price:
Weighted Average Number of Options Remaining Number of Options Number of Options Exercise Price Outstanding Life in Years Exercisable Remaining to Vest - -------------- ----------- ------------- ----------- ----------------- $31.94 320 3.25 320 -- $44.06 29,480 4.25 29,480 -- $48.62 35,700 6.25 30,525 5,175 ------ ---- ------ ----- 65,500 5.34 60,325 5,175
The weighted average exercise price of options remaining to vest is $48.62, with a weighted average remaining life of 6.50 years. Energy Group adopted SFAS 123(R) effective January 1, 2006, using the modified prospective application with no significant impact on its financial condition, results of operations, or cash flows. Under this application, all new awards as of January 1, 2006, and any outstanding awards that may be modified, repurchased, or cancelled will be accounted for under SFAS 123(R). NOTE 9 - INVENTORY Fuel, materials, and supplies for Energy Group includes the inventory of Central Hudson, Griffith, and Lyonsdale. Inventory for Central Hudson is valued at average cost. Inventory for Griffith is valued using the "first-in, first-out" (or "FIFO") inventory 35 method. Inventory for Lyonsdale is valued using the weighted average inventory method. - -------------------------------------------------------------------------------- Energy Group ------------ - -------------------------------------------------------------------------------- September 30, December 31, September 30, 2006 2005 2005 - -------------------------------------------------------------------------------- (In Thousands) - -------------------------------------------------------------------------------- Natural Gas $ 17,794 $ 16,512 $ 19,014 - -------------------------------------------------------------------------------- Petroleum Products and Propane 4,139 4,138 4,276 - -------------------------------------------------------------------------------- Fuel Used In Electric Generation 142 -- -- - -------------------------------------------------------------------------------- Materials and Supplies 8,455 7,700 7,899 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Total $ 30,530 $ 28,350 $ 31,189 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Central Hudson -------------- - -------------------------------------------------------------------------------- September 30, December 31, September 30, 2006 2005 2005 - -------------------------------------------------------------------------------- (In Thousands) - -------------------------------------------------------------------------------- Natural Gas $ 17,794 $ 16,512 $ 19,014 - -------------------------------------------------------------------------------- Petroleum Products and Propane 745 758 764 - -------------------------------------------------------------------------------- Materials and Supplies 6,502 6,141 6,326 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- Total $ 25,041 $ 23,411 $ 26,104 - -------------------------------------------------------------------------------- NOTE 10 - POST-EMPLOYMENT BENEFITS The following are the components of Central Hudson's net periodic benefits costs for its pension and OPEB plans for the quarters and nine months ended September 30, 2006, and 2005. The OPEB amounts for both years reflect the effect of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 under the provisions of FSP 106-2, titled Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. 36
Quarter Ended September 30, Pension Benefits OPEB ----------------------- ----------------------- 2006 2005 2006 2005 (In Thousands) (In Thousands) ----------------------- ----------------------- Service cost $ 1,985 $ 1,837 $ 830 $ 667 Interest cost 5,577 5,489 2,005 1,900 Expected return on plan assets (6,709) (5,808) (1,496) (1,659) Amortization of: Prior service cost 542 535 (314) (868) Transitional (asset) or obligation -- -- 641 641 Recognized actuarial (gain) or loss 3,240 3,331 1,077 1,775 -------- -------- -------- -------- Net periodic benefit cost $ 4,635 $ 5,384 $ 2,743 $ 2,456 ======== ======== ======== ======== Nine Months Ended September 30, Pension Benefits OPEB ----------------------- ----------------------- 2006 2005 2006 2005 (In Thousands) (In Thousands) ----------------------- ----------------------- Service cost $ 5,955 $ 5,511 $ 2,492 $ 2,602 Interest cost 16,730 16,466 6,015 6,691 Expected return on plan assets (20,127) (17,425) (4,489) (4,216) Amortization of: Prior service cost 1,625 1,606 (942) (942) Transitional (asset) or obligation -- -- 1,924 1,924 Recognized actuarial (gain) or loss 9,721 9,994 3,230 5,114 -------- -------- -------- -------- Net periodic benefit cost $ 13,904 $ 16,152 $ 8,230 $ 11,173 ======== ======== ======== ========
Decisions to fund Central Hudson's pension plan (the "Retirement Plan") are based on several factors including the value of plan assets relative to plan liabilities, legislative requirements, and available corporate resources. The liabilities are affected by the discount rate used to determine benefit obligations. Central Hudson is currently reviewing the provisions of the Pension Act to determine funding requirements for the near-term and future periods. Employer contributions for OPEB totaled $3.3 million during the nine months ended September 30, 2006. The total contribution to be made in 2006 is expected to be 37 less than the 2005 amount of $6.1 million due to a reduction in expected future medical claims as a result of recent favorable claims experience. Effective January 1, 2006, a non-qualified Supplemental Executive Retirement Plan replaced the non-qualified Supplementary Retirement Plan and the Retirement Benefit Restoration Plan. For additional information related to pensions and OPEB, please see Note 9 - - "Post-Employment Benefits" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. NOTE 11 - COMMITMENTS AND CONTINGENCIES Energy Group and Central Hudson face a number of contingencies which arise during the normal course of business and which have been discussed in Note 11 - "Commitments and Contingencies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report and to which reference is made. City of Poughkeepsie On January 1, 2001, a fire destroyed a multi-family residence on Taylor Avenue in the City of Poughkeepsie, New York resulting in several deaths and damage to nearby residences. Eight separate lawsuits arising out of this incident have been commenced in New York State Supreme Court, County of Dutchess, by approximately 24 plaintiffs against Central Hudson and other defendants, each lawsuit alleging that Central Hudson supplied the Taylor Avenue residence with natural gas service for cooking purposes at the time of the fire. The basis for the claimed liability of Central Hudson in these actions is that it was allegedly negligent in the supply of such natural gas. The suits seek an aggregate of $528 million in compensatory damages for alleged property damage, personal injuries, wrongful death, and loss of consortium or services. Central Hudson has notified its insurance carrier, has denied liability, and is defending the lawsuits. Based on information known to Central Hudson at this time, including information from ongoing discovery proceedings in the lawsuits, Central Hudson believes that the likelihood it will have a liability in these lawsuits is remote. Environmental Matters Central Hudson: Water In February 2001, Central Hudson received a letter from the New York State Department of Environmental Conservation ("DEC") indicating that it must terminate the discharge from an internal sump at its Neversink Hydroelectric Facility ("Neversink") into a regulated stream or obtain a State Pollutant Discharge Elimination System permit for such discharge. Central Hudson filed for a draft permit in May 2001; the DEC subsequently issued a draft permit on January 15, 2003. Central Hudson has submitted comments on that draft permit to the DEC, and the DEC continues to review those 38 comments. On October 3, 2006, Neversink was transferred to the City of New York ("the City"). Prior to this transfer and pursuant to the agreement between Central Hudson and the City for the conveyance of the Neversink, both Central Hudson and the City certified an application to the DEC for the transfer of the draft permit and its associated application to the City effective October 3, 2006. For additional details concerning this matter, see the caption "Neversink Hydro Station" of this Note 11. Air In October 1999, Central Hudson was informed by the New York State Attorney General ("Attorney General") that the Danskammer Point Steam Electric Generating Station ("Danskammer Plant") was included in an investigation by the Attorney General's Office into the compliance of eight older New York State coal-fired power plants with federal and state air emissions rules. Specifically, the Attorney General alleged that Central Hudson "may have constructed, and continues to operate, major modifications to the Danskammer Plant without obtaining certain requisite preconstruction permits." As part of this investigation, Central Hudson has received several requests for information from the Attorney General, the DEC, and the United States Environmental Protection Agency ("EPA") seeking information about the operation and maintenance of the Danskammer Plant during the period from 1980 to 2000, including specific information regarding approximately 45 projects conducted during that period. In March 2000, the EPA assumed responsibility for the investigation. Central Hudson has completed its production of documents in connection with the information requests, and believes any permits required for these projects were obtained in a timely manner. Notwithstanding Central Hudson's sale of the Danskammer Plant on January 30, 2001, Central Hudson could retain liability depending on the type of remedy, if any, imposed in connection with this matter. Former Manufactured Gas Plant Facilities In 1986, the DEC added to the New York State Registry of Inactive Hazardous Waste Disposal Sites ("Registry") six sites at which MGP owned or operated by Central Hudson or its predecessors were once located. Two additional MGP sites were identified by Central Hudson but not placed on the Registry by the DEC. Three of the eight sites identified are in Poughkeepsie, New York (at Laurel Street, North Water Street, and North Perry Street); the remaining five sites are in Newburgh, Beacon, Saugerties, Kingston, and Catskill, New York. Central Hudson studied all eight sites to determine whether or not they contain any hazardous wastes which could pose a threat to the environment or public health and, if wastes were located at the sites, to determine whether or not remedial actions should be considered. The DEC subsequently removed the six sites it had previously placed on the Registry, subject to future revisions of its testing methods. The DEC subsequently revised its testing methods. As discussed below, the Laurel Street, North Water Street, North Perry Street, Newburgh, Beacon, and Catskill sites have been the subject of further discussions and agreements with the DEC. In addition, as also discussed below, the Saugerties and Kingston sites have been the subject of discussions with the DEC and, regarding the Kingston site, with a private developer. 39 Central Hudson also became aware of information contained in a DEC Internet website indicating that, in addition to the eight sites referenced above, Central Hudson was attributed with responsibility for three additional MGP sites in New York State, located on Broadway in Kingston, at Vassar College in Poughkeepsie, and on Water Street in Newburgh. In response to the website, Central Hudson has shown the DEC that no MGP ever operated at the Broadway, Kingston location. Rather, the location is likely to have been used for an office associated with the MGP site at East Strand Street, Kingston. In addition, Central Hudson has shown the DEC that it never owned or operated an MGP at Vassar College. The DEC has agreed to drop the Broadway, Kingston, and Vassar sites as attributed to Central Hudson. The site identified as the Water Street, Newburgh site is, to Central Hudson's knowledge, an MGP site that ceased operations in the 1880's. The land upon which the plant was located was sold in 1891, before the stock of the MGP site's former operator, Consumers Gas Company of Newburgh, New York was acquired in 1900-01 by Newburgh Light, Heat and Power Company, which was later consolidated with several other companies to form Central Hudson. The DEC is currently considering whether it will agree to drop this site as attributable to Central Hudson. City of Newburgh: In October 1995, Central Hudson and the DEC entered into an Order on Consent regarding the development and implementation of an investigation and remediation program for Central Hudson's MGP site in Newburgh, New York, the City of Newburgh's adjacent and nearby property, and the adjoining areas of the Hudson River ("the site"). The City of Newburgh filed a lawsuit against Central Hudson in the United States District Court for the Southern District of New York alleging violation by Central Hudson of, among others, federal environmental laws and seeking damages of at least $70 million. After a 1998 jury award of $16 million in that lawsuit, reflecting the estimated cost of environmental remediation and damages, Central Hudson and the City of Newburgh entered into a court-approved Settlement Agreement in 1999 under which, among other things, (i) Central Hudson agreed to remediate the City of Newburgh's property at Central Hudson's cost pursuant to the DEC's October 1995 Order on Consent and (ii) if the total cost of the remediation were less than $16 million, Central Hudson would pay the City of Newburgh an additional amount up to $500,000 depending on the extent to which the cost of remediation was less than $16 million. Further studies by Central Hudson of the City of Newburgh's property were provided to the DEC, which determined that the contaminants found may pose a significant threat to human health or the environment. As a result, Central Hudson developed a draft Feasibility Study Report ("Feasibility Report") which was filed with the DEC and provided to the City of Newburgh in 1999. After review of the Feasibility Report by the DEC and the New York State Department of Health ("DOH") and additional sampling by Central Hudson, Central Hudson submitted revised risk assessments in June 2001, which also encompassed additional cleanup of Hudson River sediments and property owned by the City of Newburgh. 40 The DEC and the DOH approved the revised risk assessments. The Feasibility Report was revised based on the revised assessments and filed with the DEC on October 29, 2003. On February 24, 2005, the DEC issued a Proposed Remedial Action Plan ("PRAP") for public review and comment. The PRAP proposed a $22.9 million remediation plan which is similar in scope to one previously submitted by Central Hudson, although it also includes a contingency fund and a projected expense for continued maintenance and monitoring at the site. The PRAP was the subject of a public hearing in the City of Newburgh on March 17, 2005. A public comment period remained open until April 30, 2005. The DEC issued its Record of Decision ("ROD") on December 2, 2005, confirming that the cleanup identified in the PRAP will be required to be conducted by Central Hudson. Central Hudson has entered into a contract with Blasland, Bouck and Lee ("BBL") of Syracuse, New York with a value up to $1.6 million. Under the contract, BBL will conduct additional required pre-design studies and will assist with development of remediation contract specifications and remediation construction oversight assistance, in accordance with the ROD. In September 2006, a contract was awarded to Earthtech for the design and construction of the remedy of a portion of the site. The value of the contract is up to $2.8 million. Earthtech's design for the remedy on a portion of the site was submitted to the DEC on October 20, 2006. As of September 30, 2006, approximately $12.7 million has been spent on the City of Newburgh matter, including the defense of the litigation described above. It is not possible to predict the extent of additional remediation costs that will be incurred in connection with this matter, but Central Hudson believes that such costs could be in excess of $17 million. As of September 30, 2006, a $17 million estimate regarding this matter has been recorded as liability, and the expenses have been deferred, subject to the provisions of a PSC Order issued on June 3, 1997, that granted permission for the deferral of these costs subject to an annual PSC review of the specific costs being deferred. Provisions of the 2006 Order confirm that Central Hudson is permitted to continue to defer these costs. Neither Energy Group nor Central Hudson can make any prediction as to the full financial effect of this matter on either Energy Group or Central Hudson, including the extent, if any, of insurance reimbursement and including implementation of environmental cleanup under the Order on Consent. However, Central Hudson has put its insurers on notice of this matter and intends to seek reimbursement from its insurers for the cost of any liability. Certain of the insurers have denied coverage. Other MGP Sites: Central Hudson conducted site assessments of the Poughkeepsie Laurel Street, North Water Street, and Beacon sites under Voluntary Cleanup Agreements negotiated in 2000 with the DEC to determine if there are any significant quantities of residues from the MGP operations on the sites and whether any such residues would require remediation. In March 2002, the DEC informed Central Hudson that both it and the DOH had approved Central Hudson's Supplemental 41 Preliminary Site Assessment for the North Water Street site, which had concluded that the contamination at the site "does not appear to pose a significant threat to public health and the environment." At that time, the DEC and Central Hudson agreed that further investigation at the site would be given lower priority than work at the other Central Hudson MGP sites. In August 2002, however, an oily sheen on the Hudson River adjacent to this site was reported to the DEC. As a result, the DEC revised its priority determination with respect to the North Water Street site and has now given it a high priority for action. In 2004, Central Hudson received approval from the DEC for and conducted additional investigation work at the North Water Street site, which included field work on the site and in the adjacent Hudson River. A report detailing the work and data gathered was filed with the DEC early in 2005. Subsequently, in 2005, Central Hudson provided the DEC with an additional report of an investigation of subsurface conditions near the Hudson River. In June 2006, Central Hudson filed an additional report with the DEC that provided additional Hudson River field data requested by the DEC, all past data collected to-date, and proposed that Central Hudson next analyze possible remedial alternatives. Central Hudson has not yet received a response from the DEC to this report. Neither Energy Group nor Central Hudson can predict the extent or cost of any possible remediation at this time. In March 2004, Central Hudson requested that the Voluntary Cleanup Agreement covering the North Water Street site be converted into a Brownfield Cleanup Agreement under New York State's new Brownfield Cleanup Program. The Brownfield Cleanup Agreement with the DEC was signed and effective May 12, 2005. Central Hudson believes the Brownfield Cleanup Agreement is unlikely to significantly change the amount or cost of any potential remediation of the North Water Street site, but may permit the recovery by Central Hudson of some of the remediation costs through tax credits. By 2003, Central Hudson had performed a full site investigation and proposed a remediation of the Laurel Street site. The DEC subsequently requested that additional investigation be performed. Central Hudson has performed a limited additional investigation and filed the results with the DEC on September 8, 2006. In October 2000, Central Hudson was notified by the DEC that it had determined that the Poughkeepsie North Perry Street site posed little or no significant threat to the public and that no additional investigation or action was necessary at the present time. In the last year, the DEC has requested that Central Hudson perform very limited and focused additional investigation at the North Perry Street site. Central Hudson has recently completed such additional investigation, which did not indicate the presence of any significant MGP-related material, and has provided the report to the DEC. During the fourth quarter of 2001, Central Hudson was advised that the DEC and the DOH found that no further remedial action was necessary at the Beacon site. In January 2006, Central Hudson was advised that property adjacent to the site of the former Beacon site appeared to have soil present that may be contaminated with MGP-related byproducts. In response to this information, Central Hudson has met with the DEC and is providing the additional information it has received characterizing the nature 42 and extent of the contamination. Central Hudson has also received the results of additional studies of the adjacent property indicating that MGP-related by-products may be located on a portion of the property. Central Hudson has determined that contaminated soil must be removed from the adjacent property and has filed a plan with the DEC for doing so. No estimate of the cost for removing the contaminated soil at Beacon is available pending DEC approval of the cleanup plan and obtaining bids from qualified vendors for performing the cleanup. The DEC has also requested that Central Hudson enter into a Brownfield Cleanup Agreement covering the Kingston, Saugerties, and Catskill sites. Regarding the Kingston site, Central Hudson is considering an offer from a third party to purchase the site. In July 2006, Central Hudson and the third party entered into an agreement allowing the third party to conduct an investigation at the site and approach the DEC with a proposal to remediate the site, if the investigation indicates that remediation is necessary. Central Hudson cannot predict whether this sale, which is subject to Section 70 approval by the PSC, will take place. Regarding the Catskill site, Central Hudson has recently executed a Brownfield Cleanup Agreement to investigate and, if necessary, remediate the site. The application has been deemed complete by the DEC and has undergone a public review and comment period required by the Brownfield Cleanup Program law. The Brownfield Cleanup Agreement has been executed by the DEC. As required under the Agreement, Central Hudson has filed a draft Preliminary Site Assessment ("PSA") plan with the DEC for its review and approval. Subject to such approval, Central Hudson anticipates performing the PSA for the Catskill site in 2007. Regarding the Saugerties site, Central Hudson has submitted to the DEC an analysis indicating that Central Hudson has no legal responsibility for contamination, if any, at the Saugerties site. The DEC has not yet responded to the submitted analysis. A recent policy announced by the DEC could require the reopening of one or more of Central Hudson's closed sites should the DEC determine that testing of indoor air quality within structures located near or on the site(s) is warranted. At this time, the DEC has not indicated that it intends to reopen any Central Hudson site. Central Hudson has developed estimates of the potential costs it could incur in connection with the remediation of four of the MGP sites, namely the City of Newburgh site, the Laurel Street site, the North Water Street site, and the Kingston site. The cost estimates for the Newburgh and Laurel Street sites are based on completed feasibility studies (or their equivalents). The cost estimates for the North Water Street and Kingston sites, however, are considered conceptual and preliminary. Each of the cost estimates involves assumptions relating to investigation expenses, remediation costs, potential future liabilities, and post-remedial monitoring costs, and is based on a variety of factors including projections regarding the amount and extent of contamination, the location, size and use of the sites, proximity to sensitive resources, status of regulatory investigations, and information regarding remediation activities at other MGP sites in New York State. The cost estimates also assume that the proposed remediation techniques are technically feasible and that the remediation plans receive regulatory approval. The cost estimates, when considered in the aggregate, indicate that the total costs in connection with remediation of the four sites could exceed $125 million over the 43 next 30-year period, including the annual cost of operations and maintenance and an annual inflation factor of 2.5%. Central Hudson has already recorded an aggregate of $19.5 million as liabilities, comprised of $3.5 million in current liabilities and $13.5 million in long-term liabilities with respect to the City of Newburgh and $2.5 million in long-term liabilities with respect to the Laurel Street site. Liabilities for MGP site remediation are generally recorded after entering into an Order on Consent and a ROD with the DEC which specifies the nature and estimated cost at such time the liability becomes probable and estimatable. For the Laurel Street site remediation, the $2.5 million estimate was recorded as a liability in June 2002, and the expense was deferred, subject to the provisions of a PSC Order issued on October 25, 2002, that granted permission for the deferral of these and other costs relating to the MGP sites. During the nine months ended September 30, 2006, Central Hudson spent approximately $0.3 million related to investigations of these other MGP sites. Future remediation activities and costs may vary significantly from the assumptions used in Central Hudson's current cost estimates. The remediation actions ultimately required at any of the Central Hudson MGP sites could cause a material adverse effect (the extent of which cannot be reasonably estimated) on the financial condition of Energy Group and Central Hudson if Central Hudson were unable to recover all or a substantial portion of these costs through rates and/or insurance. Central Hudson has put its insurers on notice regarding these matters and intends to seek reimbursement from its insurers for amounts, if any, for which it may become liable. Under the provisions of the 2006 Order, described in Note 3 - "Regulatory Matters" of this Quarterly Report on Form 10-Q, Central Hudson will be permitted to defer for future recovery the differences between actual costs for MGP site investigation and remediation and the rate allowances, with carrying charges to be accrued on the deferred balances at the authorized rate of return. Little Britain Road In December 1977, Central Hudson purchased property at 410 Little Britain Road, New Windsor, New York. In June 1992, the DEC informed Central Hudson that the DEC was preparing to conduct a PSA of the site. In February 1995, the DEC issued an Order on Consent in which Central Hudson agreed to conduct the PSA. In November 2000, following completion of the PSA, Central Hudson and the DEC entered into a Voluntary Cleanup Agreement that called for remediation of soil contamination. Subsequently, Central Hudson removed approximately 3,100 tons of soil and conducted groundwater sampling. Groundwater sampling results from shallow wells showed presence of certain contaminants at levels exceeding DEC criteria. In late 2005, Central Hudson installed a deep groundwater well and it sampled the well in early 2006. Levels of contaminants exceeding DEC criteria were reported. In July and August 2006, Central Hudson, with DEC approval, installed three additional deep groundwater wells. The wells were sampled in September 2006 and showed that DEC criteria are still being exceeded in several wells. A report on the results of the September sampling 44 event has been submitted to the DEC. The wells will be sampled again in December 2006. Central Hudson has put its insurers on notice regarding this matter and intends to seek reimbursement from its insurers for amounts, if any, for which it may become liable. Neither Energy Group nor Central Hudson can predict the outcome of this matter. Orange County Landfill Reference is made to the discussion under the subcaption "Orange County Landfill" in Note 11 - "Commitments and Contingencies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. The Tolling Agreement dated September 7, 2001, whereby Central Hudson agreed to toll the applicable statute of limitations by certain state agencies against Central Hudson for certain alleged causes of action, has through a series of sequential agreements been extended to November 30, 2006. Settlement discussions are ongoing. Neither Energy Group nor Central Hudson can predict the outcome of this matter. Newburgh Consolidated Iron Works By letter from the EPA dated November 28, 2001, Central Hudson, among others, was served with a Request For Information pursuant to the Comprehensive Environmental Response, Compensation and Liability Act regarding any shipments of scrap or waste materials that Central Hudson may have made to Consolidated Iron and Metal Co., Inc. ("Consolidated Iron"), a Superfund site located in Newburgh, New York. Sampling by the EPA indicated that lead and polychlorinated biphenyls (or "PCBs") are present at the site, and the EPA subsequently commenced a remedial investigation and feasibility study at the site. Central Hudson responded to the EPA's information request on January 30, 2002. In its response, Central Hudson stated that it had entered into a contract with Consolidated Iron under which Central Hudson sold scrap metal to Consolidated Iron. The term of the contract was from 1988 to 1989. Records of eight and a possible ninth shipment of scrap metal to Consolidated Iron have been identified. No records were found which indicate that the material sold to Consolidated Iron contained or was a hazardous substance. Central Hudson has put its insurers on notice regarding this matter and intends to seek reimbursement from its insurers for amounts, if any, for which it may become liable. Neither Energy Group nor Central Hudson can predict the outcome of this investigation at the present time. Asbestos Litigation As of September 30, 2006, of the 3,285 cases brought against Central Hudson, 1,161 remain pending. Of the cases no longer pending against Central Hudson, 1,974 have been dismissed or discontinued without payment by Central Hudson, and Central Hudson has settled 150 cases. Central Hudson is presently unable to assess the validity of the remaining asbestos lawsuits; accordingly, it cannot determine the ultimate liability relating to these cases. Based on information known to Central Hudson at this time, including Central Hudson's experience in settling asbestos cases and in obtaining dismissals of asbestos cases, Central Hudson believes that the costs which may be 45 incurred in connection with the remaining lawsuits will not have a material adverse effect on either of Energy Group's or Central Hudson's financial position, results of operations, or cash flows. CHEC: Griffith has received a demand addressed to Griffith Consumers Division ("Consumers"), the entity from which Griffith had purchased certain assets of its business, from the CITGO Petroleum Corporation ("CITGO") for defense and indemnification of CITGO in lawsuit commenced on or about March 13, 2001, by James and Casey Threatte against CITGO and Gordon E. Wenner in the Circuit Court for Loudon County, Virginia. The lawsuit seeks compensatory damages of $1.4 million plus attorney's fees, jointly and severally from CITGO and defendant Wenner, for the alleged contamination of a plaintiff's property in Lovettsville, Virginia, by gasoline containing methyl tertiary butyl ether (or "MTBE") emanating from the neighboring Lovettsville Garage. CITGO maintains that Consumers owes it a defense and indemnification pursuant to a February 1, 1999, Distribution Franchise Agreement pursuant to which CITGO sold gasoline to Consumers, which then resold the gasoline to the Lovettsville Garage. Griffith does not believe it or Consumers is responsible to CITGO in this matter, in part because the supply agreement with the Lovettsville Garage was transferred to another distributor on August 1, 2001, and the transferee agreed to assume any liabilities existing as of that date. Moreover, even if Griffith were determined to be responsible to CITGO, Energy Group believes that CITGO itself is not a proper party to the lawsuit and, therefore, Griffith would be liable only for the reimbursement of defense costs. Griffith has a voluntary environmental program in connection with the West Virginia Division of Environmental Protection regarding Griffith's Kable Oil Bulk Plant, located in West Virginia. During 2006, $31,000 was spent on site remediation efforts. The State of West Virginia has indicated that some additional remediation will be required and Griffith has received an estimate of $300,000 for the environmental remediation. In addition, Griffith spent $305,000 on remediation efforts in Maryland, Virginia, and Connecticut in 2006. Griffith is to be reimbursed $422,000 from the State of Connecticut under an environmental agreement and has recorded this amount as a receivable. Griffith updated the remediation assessments for its environmental sites. Based upon the results of these assessments, Griffith reduced its environmental reserve by $865,000 in September 2006. The reserve is $1.9 million as of September 30, 2006. On May 31, 2002, CH Services sold all of its stock ownership interest in CH Resources to WPS Power Development, Inc. In connection with the sale, CH Services agreed for four years following the date of this sale to retain up to $4 million of potential, on-site environmental liabilities which may have been incurred by CH Resources prior to the closing. No such material liabilities have been identified and this indemnification expired in accordance with its terms on May 31, 2006. 46 Other Matters Central Hudson: Central Hudson is involved in various other legal and administrative proceedings incidental to its business which are in various stages. While these matters collectively could involve substantial amounts, it is the opinion of Management that their ultimate resolution will not have a material adverse effect on either of Energy Group's or Central Hudson's financial positions, results of operations, or cash flows. Neversink Hydro Station Central Hudson's ownership interest in Neversink was governed by an agreement between Central Hudson and the City, acting through the Board of Water Supply, dated April 21, 1948. That agreement provided for the transfer of Central Hudson's ownership interest in Neversink, which has a book value of zero, to the City on December 31, 2003. Central Hudson and the City engaged in negotiations relating to the transfer of Central Hudson's ownership interest in Neversink and extended the time for the transfer through a series of interim agreements. On February 28, 2006, the parties entered into an "Agreement as to Conveyance of the Neversink Hydroelectric Generating Plant." This agreement specified the terms and conditions related to the transfer including the continued interconnection of the plant to the electric transmission grid and Central Hudson's post-transfer property access rights with respect to certain components of its transmission and distribution equipment. Requisite authorizations for the transfer were issued by the Federal Energy Regulatory Commission and the PSC, and the plant was conveyed to the City on October 3, 2006. Central Hudson retained responsibility for environmental liabilities related to conditions existing as of the time of transfer except to the extent any such liabilities relate to conditions resulting from acts of the City. Central Hudson is not presently aware of any material pre-transfer environmental liabilities with respect to Neversink. 47 ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS EXECUTIVE SUMMARY Business Overview Energy Group is a holding company with the following components: (1) Central Hudson's regulated electric utility business, (2) Central Hudson's regulated natural gas utility business, (3) Griffith's (and, prior to its merger with Griffith as of December 31, 2005, SCASCO's) fuel oil, propane, and motor fuels distribution business, and (4) CHEC's investments in renewable energy supply, energy efficiency, an energy venture capital fund, and other investments of Energy Group, consisting primarily of short-term investments. Central Hudson contributed approximately 68% of Energy Group's revenue and 82% of its net income for the first nine months of 2006, the fuel distribution segment contributed approximately 31% of Energy Group's revenue and 0% of its net income for the first nine months of 2006, and the investment segment contributed less than 1% of Energy Group's revenue and 18% of its net income for the first nine months of 2006. Energy Group intends to deliver shareholder value through a consistent dividend (currently $2.16 per share annually) and growth in earnings per share. Energy Group is targeting 5% annual growth in earnings per share, on average, over the next several years. Central Hudson Since the 2001 New York State electricity restructuring Central Hudson has delivered electricity and natural gas to approximately 367,000 customers in a defined service territory in the mid-Hudson Valley region of New York State. Central Hudson's earnings are derived primarily from delivery charges levied upon end-users of its electricity and natural gas transmission and distribution systems in its service territory. Central Hudson continues to procure supplies of electricity and natural gas for a majority of its customers. In doing so, Central Hudson recovers its actual costs through cost adjustment clauses and without deriving profits from these activities. Central Hudson is facilitating migration of its delivery customers to third-party providers for their energy supplies. Central Hudson's customer accounts have grown steadily in recent years due to home construction and in-migration of residential customers to Central Hudson's service territory, principally from higher cost areas in the New York City metropolitan area. Employment growth and commercial account growth has also been steady. Over time, per customer consumption of electricity and natural gas has gradually increased due to the construction of larger homes and the proliferation of end-uses for electricity, such as computers and other electronic equipment. 48 While these favorable trends are expected to continue in the long run, customer consumption patterns since mid-2005 have been affected by significantly higher prices for electricity and natural gas. This impact has been difficult to quantify precisely due to large variations from normal weather patterns over the same time period. It is also too soon to tell whether any customer conservation in response to higher prices is temporary or permanent, and this will likely be affected by the future trend in energy prices. Consumption patterns could also be affected by an economic recession, dampening of the housing market by rising interest rates, or other economic conditions. Central Hudson's rates are regulated by the PSC, which is responsible for setting rates at a level that will recover the cost of providing safe and reliable service while providing a fair and reasonable return on invested capital. Central Hudson has focused its management attention for many years on managing its costs and maintaining high customer satisfaction so that its costs can be fully recovered and a reasonable rate of return can be earned under applicable regulatory agreements. Central Hudson consistently ranks among the lowest cost electric utilities in New York State, and ranking in the top half in overall customer satisfaction among utilities in the Eastern United States, as reported by J.D. Power and Associates in its 2006 Electric Utility Residential Customer Satisfaction Study. In July 2005, Central Hudson filed for a proposed increase in its electricity and natural gas delivery rates. This proposed increase was requested to cover cumulative inflation, the cost of capital on an increasing investment base, the costs of providing employee benefits (including costs deferred under the then applicable regulatory agreement), environmental and safety compliance costs, and certain other costs. In April 2006, Central Hudson, PSC Staff, and other parties served on all parties the 2006 Joint Proposal to be considered by the PSC in Central Hudson's then current electric and natural gas rate proceeding. Under the terms of the 2006 Joint Proposal, an increase to electric delivery revenues of $53.7 million over the three-year term is to be phased-in with annual electric delivery rate increases of approximately $17.9 million as of July 1, 2006, July 1, 2007, and July 1, 2008. A natural gas delivery revenue increase of $14.1 million is to be phased-in over two years with natural gas delivery rate increases of $8 million as of July 1, 2006, and $6.1 million as of July 1, 2007. On June 20, 2006, the PSC extended the normal eleven-month suspension of the case through August 29, 2006, with a make-whole provision for the loss of revenues due to the extension of the suspension period past July 1, 2006. On July 24, 2006 the PSC issued the 2006 Order following action to approve the 2006 Joint Proposal at its July 19, 2006, session. The 2006 Order adopted all of the terms and conditions of the 2006 Joint Proposal with a modification requiring distribution ROW maintenance expenses to be subject to the same shortfall true-up mechanism that applies to transmission ROW maintenance. The 2006 Order directed a compliance tariff filing to place new rates into effect as of August 1, 2006, subject to the terms and conditions of the 2006 Order; Central Hudson made this compliance filing on 49 July 31, 2006. A copy of the 2006 Order is available on Energy Group's website at www.CHEnergyGroup.com. The 2006 Order provides Central Hudson with improved cash flow and the opportunity to fund significant investments in its electric and natural gas system. If Central Hudson does not expend the funds provided for capital investment, the revenue equivalent of the shortfall must be deferred for the benefit of customers. The 2006 Order also provides for continued recovery of all purchased natural gas and electric supply costs through existing monthly adjustment mechanisms. Central Hudson was provided with increased rate allowances for pension and OPEB expenses, transmission and distribution ROW maintenance expenses, and stray voltage testing expenses. In addition, Central Hudson is allowed to recover the expenses associated with the remediation of its MGP sites. Central Hudson's actual sales growth and its ability to effectively manage its costs of operation will also play significant roles in determining Central Hudson's future earnings and cash flows. On August 30, 2006, Central Hudson filed for rehearing on one element of the 2006 Order. The filing asserts that the PSC failed to update Central Hudson's allowed ROE using the Generic Finance Case Methodology. Central Hudson requested that a rehearing be conducted to revise its allowed ROE from 9.6% to 9.9%. Neither Energy Group nor Central Hudson can predict the final outcome of this petition. Central Hudson's investments in plant and equipment to safely and reliably serve the growing demand for energy in its service territory are expected to provide an opportunity for increased earnings over time and are expected to provide a significant portion of Energy Group's anticipated future earnings per share growth. Fuel Distribution Business Griffith serves more than 85,000 customers in parts of Connecticut, Delaware, the District of Columbia, Maryland, Massachusetts, New York, Pennsylvania, Virginia, and West Virginia. For the purposes of this discussion, references to Griffith should be read as applicable to both Griffith and SCASCO for 2005 and prior periods. Griffith and SCASCO were merged as of December 31, 2005. Griffith's business environment has recently been challenging and remains so due to high wholesale fuel oil, propane, and motor fuel prices. These high wholesale prices have required infusions of working capital into Griffith and have resulted in increased price sensitivity and conservation by Griffith's customers. Customer attrition due to price sensitivity increased through early 2005, but has since been curtailed and modest account growth has resumed. Growth through acquisition of smaller companies, within or adjacent to Griffith's existing delivery areas, resumed in 2005. Griffith's earnings for the first nine months of 2006 were down $0.05 per share, as compared to the same period in 2005. This was due to warmer weather in 2006 and greater operating expenses primarily related to new acquisitions, partially offset by favorable adjustments to environmental reserves and increased service contract revenue. Since 2001, Griffith has acquired and integrated 26 small fuel distribution businesses, including eight from January through October 2006 for an aggregate purchase price of $3.4 million. Energy Group views Griffith's cost management, strong customer service capabilities, and access to capital as competitive advantages that 50 Griffith will endeavor to translate into increased market share and earnings, both through internal marketing and selective acquisitions. CHEC's Investments and Other Items From time to time, CHEC has made investments in the competitive energy markets. In 2006, CHEC made a third renewable energy investment - in a biomass electric generating plant - following investments in 2004 and 2005 in an ethanol production facility and a wind energy venture, respectively. CHEC continues to seek to invest Energy Group's available cash reserves and to utilize Energy Group's potential debt capacity through appropriate investments in the energy markets. CHEC's approach has been cautious, due both to Energy Group's limited risk tolerance and to strong competition from other investors. Passage of the 2005 Energy Policy Act has increased incentives to invest in certain portions of the energy markets, and certain state and federal legislative actions have increased demand for renewable energy. CHEC is evaluating these opportunities but remains cautious about undue reliance on government incentives. CHEC's ability to find investments that provide attractive returns with acceptable risks will be a key factor in determining whether Energy Group is able to achieve its target of 5% average annual growth in earnings per share over the next several years. CHEC's other investments - in energy efficiency projects, a venture capital fund, and other small partnerships - are not expected to play a significant role in Energy Group's strategy going forward. Energy Group's other investments consist primarily of money market and liquid short-term investments, income from which fluctuates with market rates of interest. Over time, Energy Group intends to draw down the balance of its short-term investment portfolio, primarily for investment in its subsidiaries, including investments in the competitive energy markets. Risk Management Energy Group's Common Stock has historically exhibited relatively low volatility, and Energy Group recognizes its shareholder base as having a relatively low risk tolerance. In view of this, Energy Group has an enterprise-wide risk management process in place, which seeks to identify and manage the risks inherent in Energy Group's businesses in a cost-effective manner. In addition to a comprehensive insurance program, Energy Group employs various strategies to moderate volatility in energy prices and interest rates and to reduce potential earnings volatility resulting from the effects of weather on sales volumes. 51 Corporate Governance Energy Group has embraced the corporate governance changes that have been implemented through the Sarbanes-Oxley Act of 2002 and related rulemakings by the SEC and the listing requirements of the New York Stock Exchange. A detailed discussion of Energy Group's corporate governance processes can be found in Energy Group's 2006 proxy statement, available on Energy Group's website, www.CHEnergyGroup.com. Energy Group believes that its current corporate governance processes effectively serve the interests of its shareholders. Credit Quality Energy Group believes that creditworthiness and liquidity are important factors for its long-term success. In light of this, Energy Group has maintained conservative financial policies at its primary subsidiary, Central Hudson, which presently enjoys an A bond rating. In addition, committed lines of credit of $75 million at Energy Group and $77 million at Central Hudson have been established to provide sufficient liquidity in the currently volatile wholesale energy markets. Overview of Third Quarter Results Changes in regulatory provisions under Central Hudson's new rate agreement (i.e. the 2006 Order) and a number of significant one-time and unusual favorable items caused Energy Group's earnings to increase to $0.70 per share in the third quarter of 2006 as compared to $0.36 per share during the same quarter of 2005. The implementation of a rate increase this quarter allows Central Hudson to better cover its expenses. This quarter also benefited by a total of $0.28 per share from a number of significant one-time and unusual favorable items recognized in the third quarter, including tax adjustments, modifications to reserves, and the sale of property - while last year's third quarter earnings were depressed by earnings deferrals under Central Hudson's prior rate agreement. This further amplified the year-to-year change. Year-to-date earnings stand at $2.12 per share as compared to $2.07 per share for the nine months ended September 30, 2005. Regulated Electric and Natural Gas Businesses Central Hudson earned $0.67 per share in the third quarter of 2006 as compared to $0.42 per share during the same period of 2005, an increase of $0.25 per share quarter-over-quarter. Certain items totaling $0.20 per share favorably influenced the results, including adjustments to regulatory mechanisms resulting from the 2006 Order and the sale of real property. Comparatively cooler summer weather decreased earnings by approximately $0.08 per share during the quarter. 52 Fuel Distribution Business Results within the fuel distribution business were stable, at a loss of $0.15 per share during the quarter, which was the same amount posted during the third quarter of 2005 and which is typical during the non-heating season. Gross profit on petroleum products was level as compared to the same quarter of 2005. Increased service profitability and a reduction of environmental reserves offset increased operating expenses that resulted largely from acquisitions, which are expected to increase revenues during the upcoming heating season. The reduction of environmental reserves was due to improvements in environmental clean-up technology and updated estimates of remediation costs. Other Businesses CHEC's investment in Lyonsdale on April 12, 2006, had a net positive impact of $0.02 per share in the third quarter. In total, Other Income for Energy Group (the holding company) and interests held by CHEC increased by nearly $0.07 per share as compared to the third quarter of 2005. The reversal of a reserve for certain operating and income tax contingent liabilities increased income from investments in Cornhusker Holdings, and a reduction in business development expenses contributed to that increase, though results were partially dampened by the recording of unfavorable income tax adjustments by Energy Group (the holding company). REGULATORY MATTERS For further information regarding the 2006 Order, see Note 3 - "Regulatory Matters." NON-UTILITY LAND SALES For further information regarding non-utility land sales, see Note 3 - "Regulatory Matters." 53 CAPITAL RESOURCES AND LIQUIDITY The growth of Energy Group's retained earnings in the nine months ended September 30, 2006, contributed to the increase in the book value per share of its Common Stock from $31.97 at December 31, 2005, to $32.47 at September 30, 2006; the common equity ratio increased from 56.0% at December 31, 2005, to 56.4% at September 30, 2006. Book value per share at September 30, 2005, was $31.78 and the common equity ratio was 56.6%. Both Energy Group's and Central Hudson's liquidity reflect cash flows from operating, investing, and financing activities, as shown on their respective Consolidated Statements of Cash Flows and as discussed below. The principal factors affecting Energy Group's liquidity are the net cash flows generated from the operations of its subsidiaries, subsidiary capital expenditures and investments, the external financing of its subsidiaries, and the dividends Energy Group pays to its shareholders. Central Hudson's cash flows from operating activities reflect principally its energy deliveries and costs of operations. The volume of energy deliveries is dependent primarily on factors external to Central Hudson, such as weather and economic conditions. Prices at which Central Hudson delivers energy to its customers are determined in accordance with rate plans approved by the PSC. In general, changes in the cost of purchased electricity, fuel, and natural gas may affect the timing of cash flows but not net income because these costs are fully recovered through its electric and natural gas cost adjustment mechanisms. Central Hudson's cash flows are also affected by capital expenditures, permanent financing for its growing asset base, fluctuations in working capital caused by weather and energy prices, and other regulatory deferral mechanisms whereby cash may be expended in one period and recovery of the cash from customers may not occur until a subsequent period(s). Energy Group - Cash Flow Summary Changes in Energy Group's cash and cash equivalents resulting from operating, investing, and financing activities for the nine months ended September 30, 2006, and 2005, are summarized in the following chart:
- ------------------------------------------------------------------------------------------------- Nine Months Nine Months Variance Energy Group Ended 2006 Ended 2005 2006 vs. 2005 - ------------------------------------------------------------------------------------------------- Net Cash Provided By (Used In): (Millions of Dollars) - ------------------------------------------------------------------------------------------------- Operating Activities $ 72.8 $ 34.7 $ 38.1 - ------------------------------------------------------------------------------------------------- Investing Activities (64.4) (60.5) (3.9) - ------------------------------------------------------------------------------------------------- Financing Activities (25.6) 6.4 (32.0) - ------------------------------------------------------------------------------------------------- Net change for the period (17.2) (19.4) 2.2 - ------------------------------------------------------------------------------------------------- Balance at beginning of period 49.4 70.4 (21.0) - ------------------------------------------------------------------------------------------------- Balance at end of period $ 32.2 $ 51.0 $ (18.8) - -------------------------------------------------------------------------------------------------
54 Energy Group's net cash flows provided by operating activities of $72.8 million during the nine months ended September 30, 2006, were $38.1 million higher as compared to the nine months ended September 30, 2005. Increased cash flows reflect the collection of cash and a decrease in accounts receivable primarily due to reduced billings to Central Hudson customers as a result of lower wholesale costs for purchased electricity, cooler summer weather as compared to last year, and seasonally lower billings to Griffith customers. The increase in cash flows was slightly offset by decreases in accounts payable primarily as a result of lower wholesale costs for purchased electricity for Central Hudson and lower volumes of petroleum products purchased by Griffith. Net cash flows used in investing activities were $3.9 million higher during the nine months ended September 30, 2006, as compared to the same period in 2005. The purchase of a majority interest in Lyonsdale and minor acquisitions by Griffith increased expenditures in 2006. Partially offsetting the higher expenditures were repayments made to CHEC for notes outstanding, proceeds from sales of real property, and net funds received from the purchase and sale of Energy Group's short-term investments. As discussed in Note 2 - "Summary of Significant Accounting Policies" under caption "Revision in the Classification of Certain Securities," these investments were previously classified as cash and cash equivalents. As a result of this revision in classification, Energy Group concluded that it is appropriate to classify these securities on the Consolidated Balance Sheet for Energy Group as short-term investments - available-for-sale securities. As a result of this revision in classification, Energy Group has also made corresponding adjustments to its Consolidated Statement of Cash Flows for all periods presented to reflect the gross purchases and liquidation of these available-for-sale securities as investing activities rather than as a component of cash and cash equivalents. This revision in classification has no impact on previously reported total current assets, total assets, working capital position, results of operations, or financial covenants and does not affect previously reported cash flows from operating or financing activities. The Consolidated Financial Statements of Central Hudson were not affected by this revision in classification. For more information relating to Energy Group's short-term investments, see Note 5 - "Short-Term Investments." Net cash flows from financing activities were $32.0 million lower for the nine months ended September 30, 2006, as compared to the same period in 2005. The resulting decrease in cash flows used was primarily driven by proceeds of net borrowings of short-term debt by Central Hudson during the first nine months of 2005 as compared to the same period in 2006. Central Hudson - Cash Flow Summary Changes in Central Hudson's cash and cash equivalents resulting from operating, investing, and financing activities for the nine months ended September 30, 2006, and 2005, are summarized in the following chart: 55
- ------------------------------------------------------------------------------------------------- Nine Months Nine Months Variance Central Hudson Ended 2006 Ended 2005 2006 vs. 2005 - ------------------------------------------------------------------------------------------------- Net Cash Provided By (Used In): (Millions of Dollars) - ------------------------------------------------------------------------------------------------- Operating Activities $ 55.3 $ 23.5 $ 31.8 - ------------------------------------------------------------------------------------------------- Investing Activities (47.5) (43.7) (3.8) - ------------------------------------------------------------------------------------------------- Financing Activities (9.2) 14.3 (23.5) - ------------------------------------------------------------------------------------------------- Net change for the period (1.4) (5.9) 4.5 - ------------------------------------------------------------------------------------------------- Balance at beginning of period 4.2 8.2 (4.0) - ------------------------------------------------------------------------------------------------- Balance at end of period $ 2.8 $ 2.3 $ 0.5 - -------------------------------------------------------------------------------------------------
Central Hudson's net cash flows provided by operating activities in the nine months ended September 30, 2006, were $31.8 million higher as compared to the nine months ended September 30, 2005. The increase in operating cash flows reflects a decrease in accounts receivable primarily due to a decrease in wholesale costs for purchased electricity and lower electricity purchases as a result of cooler summer weather as compared to last year. The increase in cash flows was slightly offset by the use of cash related to a new requirement to make prepayments for electricity supply to the New York Independent System Operator ("NYISO"). Central Hudson's net cash flows related to investing activities of $47.5 million in the nine months ended September 30, 2006, reflect a decrease of $3.8 million as compared to the nine months ended September 30, 2005. The net decrease was comprised primarily of increased construction and removal expenditures, offset slightly by proceeds from non-utility real property sales. Net cash flows used for financing activities were $23.5 million higher for the nine months ended September 30, 2006, as compared to the same period in 2005. The net increase in cash used was primarily driven by the lower amount of net borrowings of short-term debt as compared to the same period in 2005, offset slightly by lower dividends paid to Energy Group in 2006. Contractual Obligations A review of capital resources and liquidity should also consider other contractual obligations and commitments, which are further disclosed in Note 11 - - "Commitments and Contingencies" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report. Central Hudson's actuarial consultant is currently reviewing the Pension Act to project the funding requirements for the Retirement Plan. These projections are expected to be available by year-end 2006. Employer contributions for OPEB totaled $3.3 million during the nine months ended September 30, 2006. The total contribution to be made in 2006 is expected to be less than the 2005 amount of $6.1 million due to a reduction in expected future medical claims as a result of recent favorable claims experience. 56 Financing Program At September 30, 2006, Energy Group, on a consolidated basis, had current maturities of $33 million of long-term debt, $30 million of short-term debt outstanding, cash and cash equivalents of $32.2 million, and short-term investments of $40.3 million. Energy Group, the holding company, has a $75 million revolving credit agreement with several commercial banks which, as of September 30, 2006, had no outstanding balance. As of September 30, 2006, Central Hudson had current maturities of $33 million of long-term debt, short-term debt outstanding of $30 million, and cash and cash equivalents of $2.8 million. The short-term debt outstanding is from the use of uncommitted credit lines. Central Hudson has a $75 million revolving credit agreement with a group of commercial banks which, as of September 30, 2006, had no outstanding balance. Central Hudson also has a committed short-term credit agreement for $2.0 million and certain uncommitted lines of credit with various banks. These agreements give Central Hudson competitive options to minimize the cost of its short-term borrowing. In March 2004, the PSC approved Central Hudson's petition to enter into committed multi-year short-term financing agreements up to $77 million and to issue and sell up to $85 million of medium-term notes during the period January 1, 2004, to December 31, 2006. Central Hudson has issued $58 million of medium-term notes under the corresponding registration statements and expects to issue the remaining $27 million before December 31, 2006. On July 3, 2006, Central Hudson filed a new financing petition with the PSC seeking authorization for its expected financing needs for the period January 1, 2007, through December 31, 2009. This petition requested authorization to increase committed multi-year short-term borrowing capacity to $125 million from the current authorization for $75 million. Additionally, this petition requested authorization for the issuance of up to $140 million of medium-term notes over the three-year period to meet its projected cash requirements and finance the redemption of maturing notes. On September 21, 2006, the PSC issued an Order approving Central Hudson's financing petition. Central Hudson is evaluating its options for establishing a financing program under the terms of the Order. Central Hudson's current senior unsecured debt ratings/outlook is A2/stable by Moody's Investors Service and A/stable by both Standard and Poor's Corporation and Fitch Ratings. Energy Group and Central Hudson each believes that it will be able to meet its reasonably likely short-term and long-term cash requirements, assuming that Central Hudson's current and future rate plans reflect the costs of service, including a reasonable return on invested capital. 57 CHEC has a $15.0 million line of credit with a commercial bank which, as of September 30, 2006, had no outstanding balance. On July 25, 2002, the Board of Directors of Energy Group authorized a Common Stock Repurchase Program ("Repurchase Program") to repurchase up to 4.0 million shares, or approximately 25%, of outstanding Common Stock over the five years beginning August 1, 2002. Between August 1, 2002, and December 31, 2003, the number of shares repurchased under the Repurchase Program was 600,087 at a cost of $27.5 million. No shares were repurchased during the nine months ended September 30, 2006, or during the twelve months ended December 31, 2005, and 2004. Energy Group intends to set repurchase targets, if any, each year based on circumstances then prevailing. Repurchases have been suspended while Energy Group assesses opportunities to redeploy its cash reserves in regulated and competitive energy-related businesses. Energy Group reserves the right to modify, suspend, or terminate the Repurchase Program at any time without notice. EARNINGS PER SHARE Energy Group's consolidated earnings per share (basic) for the third quarter of 2006 were $0.70 per share as compared to $0.36 per share for the third quarter of 2005, an increase of $0.34 per share. Details of the change in earnings are as follows: Three Months Ended September 30, 2006 Regulated Electric and Natural Gas Businesses Earnings for Central Hudson's electric and natural gas operations increased $0.25 per share due to the following: o An increase of $0.12 per share from electric and natural gas regulatory mechanisms due to 1) an increase of $0.07 per share related to reduced amounts recorded for PSC assessments for service interruptions and 2) $0.06 per share resulting from a reduction in shared earnings from electric operations - i.e., no shared earnings were recorded in the third quarter this year as compared to $0.06 per share last year. The increase in earnings was partially offset by a $0.01 per share reduction related to annual reconciling adjustments for Central Hudson's natural gas supply charge. o An increase of $0.07 per share from gains realized on the sale of real property. o An increase of $0.06 per share from an increase in electric net operating revenues resulting primarily from the implementation of the 2006 Order for electric rates. This increase was the net result of $0.11 per share from the rate increase and a reduction of $0.05 per share from lower electric deliveries. The reduction in deliveries was due to 23% fewer cooling 58 degree days compared to the third quarter of 2005, which negatively impacted earnings by $0.08 per share. o An increase of $0.04 per share due to an increase in natural gas net operating revenues resulting primarily from the implementation of the 2006 Order for natural gas rates. Despite modest customer growth, billed deliveries to firm natural gas customers decreased 3%, which had a negligible impact on earnings. o A decrease of $0.03 per share due to an increase in interest charges on long and short-term debt. Interest costs on long-term debt increased due to the issuance of medium-term notes in December 2005 and increased interest costs on variable rate debt, which was partially offset by favorable regulatory adjustments for the change in interest costs on these variable rate obligations. Additional short-term debt was required during the early portion of the third quarter of 2006 for working capital needs. o A decrease of $0.01 per share due to the net effect of various other items including an increase in use taxes and a reduction in regulatory carrying charges due from customers related to pension costs, which were partially offset by a decrease in depreciation and amortization on utility plant assets. o Operating expenses were flat. Earnings increased $0.08 per share resulting from the reduction of reserves for injuries and damages and environmental obligations for MGP sites. Expenses related to MGP sites will be recovered pursuant to the provisions of the 2006 Order for electric and natural gas rates. The increase in earnings was offset by increases in tree trimming expenses, storm expenses, and other operation and maintenance expenses. Fuel Distribution Business Earnings from the fuel distribution business remained unchanged reflecting the following: o An increase of $0.03 per share due to an adjustment of environmental reserves resulting from improved remediation technology. o An increase of $0.02 per share due to an increase in service profitability resulting primarily from an increase in service contract revenue. o Gross margin from the sale of petroleum products was flat. Increases in margins per gallon in most product categories and higher volumes were offset by recorded losses on options used for hedging purposes. 59 o A decrease of $0.05 per share due to an increase in operating expenses. The increase in operating expenses is due to an increase in expenses associated with acquisitions made in the fourth quarter of 2005 and in the first nine months of 2006, which negatively impacted earnings by $0.03 per share, and an increase in general and administrative expenses. Other Businesses Earnings for Energy Group, the holding company, and CHEC's interests in partnerships and other investments increased $0.09 per share due to the following: o An increase of $0.07 per share due to the reversal of reserves for certain operating and income tax contingent liabilities related to CH Resources. o An increase of $0.03 per share due to an increase in income from CHEC's investment interest in Cornhusker Holdings. This plant was under construction during the third quarter of 2005. o An increase of $0.02 per share due to income from CHEC's 75% interest in the Lyonsdale plant. The Lyonsdale ownership stake was acquired in April 2006. o A decrease of $0.03 per share due to the net effect of various other items including unfavorable New York State income tax adjustments related primarily to the 2005 tax year and audited tax years 2002 through 2004, partially offset by a reduction in business development costs. Nine Months Ended September 30, 2006 Energy Group's consolidated earnings per share (basic) for the nine months ended September 30, 2006, and 2005, reflect earnings per share (basic) of $2.12 and $2.07, respectively, an increase in earnings of $0.05 per share. Details of the nine-month changes in earnings are as follows: Regulated Electric and Natural Gas Businesses Earnings per share for Central Hudson's electric and natural gas operations remained unchanged due to the following: o An increase of $0.21 per share from electric and natural gas regulatory mechanisms including $0.15 per share from a decrease in electric shared earnings resulting from lower operating income for the rate year ended June 30, 2006, $0.07 per share related to reduced amounts recorded for PSC assessments for service interruptions, and a favorable reconciling adjustment of $0.03 per share related to Central Hudson's natural gas supply charge. These increases were partially offset by the absence in the 60 current period of $0.04 per share related to a billing issue resolved by the NYISO in June 2005. o An increase of $0.07 per share resulting from gains on the sale of real property in the third quarter of 2006. o An increase of $0.02 per share from electric net operating revenues. This increase is the net result of $0.12 per share from the rate increase and a reduction of $0.10 per share from lower electric deliveries due to weather, net of the effect of weather-hedging contacts. The reduction in deliveries was due to 22% fewer cooling degree-days compared to the nine months ended September 30, 2005, which negatively impacted earnings by $0.11 per share, net of the effect of weather-hedging contracts. o A decrease of $0.19 per share due to an increase in various operating expenses. This figure is net of $0.12 per share from the recording of electric revenues to restore earnings to the allowed rate of return in accordance with the provisions of the previous rate agreement. Expenses that increased included line clearance work ($0.09 per share), storm restoration efforts ($0.08 per share), other electric transmission and distribution maintenance expenses ($0.03 per share), electric transmission line inspection ($0.03 per share), uncollectible accounts ($0.02 per share), and other expenses (totaling $0.06 per share). o A decrease of $0.07 per share due to an increase in interest charges on long and short-term debt. Interest costs on long-term debt increased due primarily to the issuance of medium-term notes in December 2005. Additional short-term debt, on average, was required for working capital needs. o A decrease of $0.05 per share from natural gas net operating revenues. Natural gas deliveries lowered earnings by approximately $0.11 per share of which $0.09 per share was due to weather. The reduction in deliveries reflects an 8% decrease in heating degree-days. This decrease was partially offset by a $0.06 per share increase in earnings largely related to the implementation of the 2006 Order for natural gas rates. o An increase of $0.01 per share due to the net effect of various other items including a decrease in depreciation and amortization of utility plant assets, a decrease in income taxes, an increase in payroll and use taxes, and an increase in regulatory carrying charges due to customers. 61 Fuel Distribution Business Earnings from the fuel distribution business decreased $0.05 per share due to the following: o A decrease of $0.10 per share due to greater operating expenses including $0.10 per share related to acquisitions made in the fourth quarter of 2005 and the first nine months of 2006, as well as increases in marketing and other general and administrative expenses. The increase in operating expenses was partially offset by adjustments to environmental reserves, which favorably impacted earnings by $0.04 per share. o An increase of $0.05 per share due to an increase in service contract revenue of $0.07 per share. This was partially offset by a decrease in gross margins from the sale of petroleum products of $0.02 per share resulting from a decrease in volumes sold due to warmer weather. Heating degree days, as adjusted for billing lags, were 15% lower than last year. Other Businesses Earnings for Energy Group (the holding company) and CHEC's interests in partnerships and other investments increased $0.10 per share due to the following: o An increase of $0.07 per share due to the reversal of reserves for certain operating and income tax contingent liabilities related to CH Resources. o An increase of $0.07 per share due to an increase in income from CHEC's investment interest in Cornhusker Holdings. o An increase of $0.02 per share due to income from CHEC's 75% interest in the Lyonsdale plant. The Lyonsdale ownership stake was acquired in April 2006. o A net decrease of $0.06 per share related to Energy Group (the holding company) due primarily to the absence of favorable income tax adjustments recorded in the second quarter of 2005 related to the completion of a tax audit for 2001. This decrease was partially offset by a gain realized from the sale of real property held by Energy Group and a reduction in business development costs and injuries and damages expense. RESULTS OF OPERATIONS The following discussion and analyses include explanations of significant changes in revenues and expenses between the three and nine months ended 62 September 30, 2006, and the three and nine months ended September 30, 2005, for the regulated electric and natural gas businesses, the fuel distribution business, and the other businesses. OPERATING REVENUES Energy Group's consolidated operating revenues increased $11.9 million, or 5.2%, for the three months ended September 30, 2006, as compared to the same period in 2005. Revenues increased $67.4 million, or 9.6%, for the comparative nine-month periods. Details of these revenue changes are presented in the following charts and related discussions concerning the variances. 63
- ------------------------------------------------------------------------------------------------------------------- 2006/2005 INCREASE (DECREASE) (Thousands of Dollars) THREE MONTHS ENDED SEPTEMBER 30, 2006 - ------------------------------------------------------------------------------------------------------------------- Fuel Electric Natural Gas Distribution Other Total - ------------------------------------------------------------------------------------------------------------------- Customer Deliveries $ 8,827(a) $ 1,183(b) $ 10,258(c) $ (76) $ 20,192 - ------------------------------------------------------------------------------------------------------------------- Sales to Other Utilities (218) 4,056 -- -- 3,838 - ------------------------------------------------------------------------------------------------------------------- Energy Cost Adjustment(d) (16,742) (654) -- -- (17,396) - ------------------------------------------------------------------------------------------------------------------- Deferred Revenues(e) 3,242 (299) -- -- 2,943 - ------------------------------------------------------------------------------------------------------------------- Lyonsdale Sales -- -- -- 2,339 2,339 - ------------------------------------------------------------------------------------------------------------------- Miscellaneous 25 (17) -- -- 8 - ------------------------------------------------------------------------------------------------------------------- Total $ (4,866) $ 4,269 $ 10,258 $ 2,263 $ 11,924 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- 2006/2005 INCREASE (DECREASE) (Thousands of Dollars) NINE MONTHS ENDED SEPTEMBER 30, 2006 - ------------------------------------------------------------------------------------------------------------------- Fuel Electric Natural Gas Distribution Other Total - ------------------------------------------------------------------------------------------------------------------- Customer Deliveries $ 6,009(a) $ (1,855)(b) $ 40,963(c) $ 136 $ 45,253 - ------------------------------------------------------------------------------------------------------------------- Sales to Other Utilities (589) 13,059 -- -- 12,470 - ------------------------------------------------------------------------------------------------------------------- Energy Cost Adjustment(d) (10,180) 5,538 -- -- (4,642) - ------------------------------------------------------------------------------------------------------------------- Deferred Revenues(e) 8,821 158 -- -- 8,979 - ------------------------------------------------------------------------------------------------------------------- Lyonsdale Sales -- -- -- 3,492 3,492 - ------------------------------------------------------------------------------------------------------------------- Miscellaneous 1,773 64 -- -- 1,837 - ------------------------------------------------------------------------------------------------------------------- Total $ 5,834 $ 16,964 $ 40,963 $ 3,628 $ 67,389 - -------------------------------------------------------------------------------------------------------------------
(a) Includes an offsetting restoration of amounts from Central Hudson's Customer Benefit Fund (described under the captions "Rate Proceedings - Electric and Natural Gas" in Note 2 - "Regulatory Matters" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report) for customer refunds and back-out credits for retail access customers. Customer refunds ceased in October 2005. (b) Includes both firm and interruptible revenues. (c) Due to increase in average selling price of all petroleum products due to higher wholesale purchase prices. (d) Changes in energy cost adjustment revenues do not affect earnings since they offset related costs. (e) Includes the restoration of other revenues from Central Hudson's Customer Benefit Fund for other authorized programs and the deferral of electric shared earnings in accordance with the provisions of Central Hudson's rate agreements with the PSC (described in Note 2 - "Regulatory Matters" to the Consolidated Financial Statements of the Corporations' 10-K Annual Report). Regulated Electric and Natural Gas Businesses For the three months ended September 30, 2006, utility electric and natural gas operating revenues decreased slightly from $173.7 million in 2005 to $173.1 million in 2006. Electric revenues decreased $4.9 million, or 3.0%, and natural gas revenues increased $4.3 million or 30.2%. The $16.7 million decrease in electric energy cost adjustment revenues is due to cooler weather and a decrease in wholesale costs. This decrease was largely offset by an increase of $8.8 million in revenues largely resulting from the implementation of the 2006 Order for electric rates effective July 1, 2006, and an increase of $3.4 million in revenues related to the resetting of regulatory mechanisms for service interruptions and shared earnings. No shared earnings were recorded in the third quarter of 2006. Natural gas revenues reflect an increase of $4.1 64 million in revenues from sales of natural gas to retail marketers and for electric generation. These sales for resale revenues do not impact earnings since any related profits or losses are returned or charged, respectively, to customers. The balance of the increase is due to an increase in delivery revenues resulting from the implementation of the 2006 Order, partially offset by a decrease in revenues related to the recovery of natural gas supply costs. For the nine months ended September 30, 2006, utility electric and natural gas operating revenues increased $22.8 million, or 4.5%, from $501.6 million in 2005 to $524.4 million in 2006. Electric revenues increased $5.8 million, or 1.5%, from $392.9 million in 2005 to $398.7 million in 2006 and natural gas operating revenues increased $17.0 million, or 15.6%, from $108.7 million in 2005 to $125.7 million in 2006. The change in revenues includes a significant increase in natural gas sales of $4.1 million due to an increase in the sale of natural gas for electric generation and to retail marketers. In addition, as a result of the 2006 Order, delivery revenues increased $8.8 million and $3.4 million in revenues related to the resetting of the regulatory mechanisms for service interruptions and shared earnings. Fuel Distribution Business For the three months ended September 30, 2006, fuel oil distribution revenues increased $10.3 million, or 19.1%, from $54.0 million in 2005 to $64.3 million in 2006 due to a significant increase in the price of petroleum products. Revenues from petroleum products increased $9.3 million, or 19.0%, from $49.0 million in 2005 to $58.3 million in 2006. Motor fuel revenues increased $5.8 million, or 14.9%, from $39.0 million in 2005 to $44.8 million in 2006. Heating oil revenues also increased $3.5 million, or 38.5%, from $9.1 million in 2005 to $12.6 million in 2006. Other revenues related to service and installations and energy services increased $1.0 million. For the nine months ended September 30, 2006, fuel oil distribution revenues increased $40.9 million, or 20.3%, from $201.4 million in 2005 to $242.3 million in 2006. Revenues from petroleum products increased $38.0 million, or 20.3%, from $187.3 million in 2005 to $225.3 million in 2006, due primarily to a significant increase in the wholesale price of petroleum products, which was partially offset by a reduction in volumes. Motor fuel revenues increased $28.3 million, or 29%, while heating oil revenues increased $9.0 million, or 10.4%. Other revenues related to the sale of petroleum products increased $0.7 million, while other revenues related to energy service and service and installations increased $2.9 million. SALES VOLUMES Sales volumes for both Central Hudson and the fuel distribution business vary in response to weather conditions. Electric deliveries peak in the summer and deliveries of natural gas and petroleum products used for heating purposes peak in the winter. Sales also vary in response to the price of the particular energy product and with the economy. 65 Regulated Electric and Natural Gas Businesses The following chart reflects the change in the level of electric and natural gas deliveries (sales) for the quarter and nine months ended September 30, 2006, as compared to the same period for 2005. Deliveries of electricity and natural gas to residential and commercial customers contribute the most to Central Hudson's earnings. Industrial sales and interruptible sales have a negligible impact on earnings.
INCREASE (DECREASE) FROM 2005 INCREASE (DECREASE) FROM 2005 ----------------------------- ------------------------------ 3 MONTHS ENDED 9 MONTHS ENDED --------------- -------------- SEPTEMBER 30, 2006 SEPTEMBER 30, 2006 ------------------ ------------------ Electric Natural Gas Electric Natural Gas -------- ----------- -------- ----------- Residential.................. (4)% (11)% (5)% (12)% Commercial................... (2)% 4% (3)% (10)% Industrial................... (3)% (17)% (2)% (25)% Other(a)..................... 1% (78)% 1% (12)% -- --- -- --- Total (3)% (3)% (4)% (12)%
(a) Includes interruptible natural gas deliveries. Third quarter 2006 electric deliveries to residential and commercial customers decreased due mostly to weather, which was partially offset by modest customer growth. Residential cooling degree-days decreased 23% over the prior year but were 19% higher than normal. Natural gas deliveries to residential customers decreased due to lower usage, which was partially offset by modest customer growth. Commercial deliveries increased due to both customer growth and increased usage. Natural gas sales in the third quarter, which is a non-heating season, represent only 8% of annual natural gas sales. For the nine months ended September 30, 2006, deliveries of electricity to residential and commercial customers decreased as a result of less usage due to cooler weather and some conservation in the first five months of the year and cooler weather in June, August, and September. The decrease in deliveries was partially offset by some customer growth. As compared to the same period in 2005, residential heating degree-days decreased 7% and cooling degree-days decreased 22%. Deliveries of natural gas to firm Central Hudson customers for the nine months ended September 30, 2006, decreased due to warm weather and conservation in the first five months of the year, as evidenced by an 8% decrease in residential heating degree-days for this period. Industrial deliveries decreased due to the loss of several customers. 66 Fuel Distribution Business For the three months ended September 30, 2006, sales of petroleum products for the fuel distribution business increased 2.0 million gallons, or 8.5%, to 24.9 million gallons in the third quarter of 2006 from 22.9 million gallons in the third quarter of 2005. Sales of heating oil to residential customers increased 1.2 million gallons, or 29.4%, from 4.2 million gallons in 2005 to 5.4 million in 2006. The increase resulted from a 20% increase in sales from acquisitions made in the fourth quarter of 2005 and the second and third quarters of 2006. Motor fuel sales increased 0.7 million gallons, or 3.9%, from 18.4 million gallons in 2005 to 19.1 million gallons in 2006 while sales of propane remained relatively flat at 0.3 million gallons in 2005 and 2006. Motor fuel sales increased primarily from the gain of one large volume customer and acquisitions in 2005 and in the second quarter of 2006. For the nine months ended September 30, 2006, sales of petroleum products decreased 1.1 million gallons, or 1.0%, from 99.1 million gallons in 2005 to 98 million gallons in 2006. This was due to a decrease of 3.7 million gallons, or 8.2%, in sales of heating oil from 44.7 million gallons in 2005 to 41 million gallons in 2006. The decrease in sales of heating oil reflects a reduction in residential sales due to warmer weather in 2006 than 2005, as evidenced by a 15% decrease in heating degree-days, adjusted for billing lags. Nearly one-half of the decrease in volume was offset by an increase in sales from acquisitions made in the fourth quarter of 2005 and in 2006. Motor fuel sales increased 2.9 million gallons, or 5.5%, from 52.6 million gallons in 2005 to 55.5 million gallons in 2006, 80% of the increase was due to acquisitions made in 2005 and 2006, while sales of propane decreased slightly from 1.8 million gallons in 2005 to 1.5 million gallons in 2006 due to warmer weather in 2006. OPERATING EXPENSES Regulated Electric and Natural Gas Businesses For the three months ended September 30, 2006, total utility operating expenses decreased $6.7 million, or 4.2%, from $159.4 million in 2005 to $152.7 million in 2006. The reduction results from a $17.1 million decrease in purchased electricity expense due to decreases in wholesale costs and volumes purchased, the latter due primarily to cooler weather in 2006. This decrease was partially offset by an increase in purchased natural gas expense of $3.4 million and an increase of $7.1 million in other expenses of operation. Natural gas expense increased due to an increase in volumes purchased, most of which was sold for electric generation. The increase in other operating expenses is largely due to an increase in the level of pension and OPEB costs recorded in accordance with the implementation of the 2006 Order for electric and natural gas rates. The overall increase in other operating expenses is also partially offset by $1.8 million in gains realized on the sale of real property in the third quarter of 2006. 67 For the nine months ended September 30, 2006, operating expenses increased by $21.3 million, or 4.8%, from $446.6 million in 2005 to $467.9 million in 2006. Purchased electricity costs decreased $11 million, or 4.3%, due primarily to decreases in volumes purchased and wholesale costs. Purchased natural gas costs increased $16.4 million, or 23%, primarily due to an increase in wholesale costs, an increase in volumes purchased, mostly sold for electric generation, and a change in amounts recorded related to the recovery of these costs via Central Hudson's energy cost adjustment mechanisms, which were partially offset by a decrease in natural gas delivery volumes. Other operating expenses increased $15.9 million, or 13.1%, from $121.1 million in 2005 to $137.0 million in 2006 due to an increase in storm restoration costs mostly from severe wind storms in January and February 2006 and an increase in the level of pension and OPEB costs, recorded in accordance with the 2006 Order. This increase was partially offset by $1.8 million in gains realized on the sale of real property in the third quarter of 2006. Fuel Distribution Business For the three months ended September 30, 2006, operating expenses for CHEC's fuel distribution business increased $10.2 million, or 18.1%, from $56.5 million in 2005 to $66.7 million in 2006. The cost of petroleum increased $9.4 million, or 21.8%, due to higher wholesale market prices and increased volumes. Other operating expenses increased $0.8 million, or 6.1%, in 2006 largely due to acquisitions made in the fourth quarter of 2005 and in 2006. Partially offsetting the increase in other operating expenses was a favorable adjustment to environmental reserves. For the nine months ended September 30, 2006, operating expenses increased $41.9 million, or 21%, from $200.9 million in 2005 to $242.8 million in 2006. The cost of petroleum products increased $38.5 million, or 25%, due to higher wholesale market prices. Other operating expenses increased $3.4 million in 2006 primarily due to a $2.6 million increase resulting from expenses associated with the acquisitions made in the fourth quarter of 2005 and in 2006. The balance of $0.8 million reflects increases in marketing and other general and administrative expenses. Other Businesses Revenues and Operating Expenses On April 12, 2006, CHEC purchased a 75% majority interest in Lyonsdale from Catalyst Renewables Corporation. Lyonsdale owns and operates a 19-megawatt, wood-fired electric generating plant. The financial statements of Lyonsdale have been fully consolidated into the financial statements of Energy Group since the date of purchase. The third quarter results for Lyonsdale resulted in a net income of $0.3 million which includes operating revenues of $2.3 million, operating expenses of $2.4 million, an income tax credit of $0.4 million, and a minority interest amount of ($7,000). 68 The consolidation of 100% of the revenue and expenses of Lyonsdale resulted in year-to-date net income of $0.2 million. Operating revenues were $3.5 million and operating expenses were $4.1 million. The expenses are comprised of $1.9 million of fuel used in electric generation, $0.7 million in labor expenses, $1.0 million of other expenses of operation, $0.4 million of depreciation expense, and $0.1 million of interest expense. In addition, there was an income tax credit of $0.7 million, mostly due to production tax credits, and a minority interest of $0.1 million. OTHER INCOME Regulated Electric and Natural Gas Businesses Other income for Central Hudson decreased $0.3 million for the quarter ended September 30, 2006, reflecting a decrease in regulatory carrying charges due from customers related to pension costs partially offset by the recording of favorable regulatory adjustments for the change in interest costs on Central Hudson's variable rate long-term debt. The latter adjustment partially offsets the increase in interest costs on the variable rate debt, as discussed under the caption "Interest Charges." The decrease in regulatory carrying charges results from the reduction of interest-bearing pension related balances in accordance with the 2006 Order for electric and natural gas rates. For the nine months ended September 30, 2006, as compared to the nine months ended September 30, 2005, other income increased $0.6 million due to the recording of favorable regulatory adjustments for the change in interest costs on the variable rate long-term debt. This increase was partially offset by a decrease in regulatory carrying charges due from customers related to pension costs. Other Businesses Other income relating primarily to Energy Group (the holding company) and CHEC's investments in partnerships and interests other than fuel distribution operations increased $0.6 million for the quarter ended September 30, 2006. This was due to an increase in income from CHEC's interest in Cornhusker Holdings and a reduction in Energy Group expenses, primarily business development costs. For the nine months ended September 30, 2006, other income increased $2.4 million largely due to a $1.7 million increase in income from Cornhusker Holdings, a $0.7 million pre-tax gain on the sale of real property held by Energy Group, and reductions in Energy Group expenses related to business development and injuries and damages expense. These increases were partially offset by an increase in other taxes for Energy Group and losses on other investments held by CHEC. INTEREST CHARGES Interest charges (which are solely related to Central Hudson) increased $0.9 million and $2.8 million for the quarter and nine months ended September 30, 2006, 69 respectively. The increase is due to the issuance of medium-term notes in December 2005 and increased interest charges on Central Hudson's variable rate debt. Additional short-term debt was required for working capital needs due to higher fuel prices. INCOME TAXES Income taxes for Energy Group increased $2.0 million, or 85.8%, from $2.4 million in the third quarter of 2005 to $4.4 million in the third quarter of 2006. This increase was primarily due to income before income taxes increasing $7.3 million, or 86.9%. For the nine months ended September 30, 2006, income taxes for Energy Group increased $1.3 million, or 7.0%, from $18.0 million in 2005 to $19.3 million in 2006. This increase was primarily due to income before income taxes increasing $1.9 million, or 3.7%, in 2006 and an increase in the effective tax rate in 2006 to 36.2% from 35.0% in 2005. The increase in the effective tax rate was primarily due to the absence of favorable income tax adjustments recorded in 2005, related to the completion of income tax audits, which were partially offset by production tax credits recognized in 2006. Income taxes for Central Hudson increased $1.1 million, or 23.4%, from $4.5 million in the third quarter of 2005 to $5.5 million in the third quarter of 2006. This increase was primarily due to income before income taxes increasing $4.9 million, or 43.4%, which was partially offset by a reduction to income tax expense in the third quarter of 2006 related to the closeout of Internal Revenue Service ("IRS") income tax audits for multiple years. For the nine months ended September 30, 2006, income taxes for Central Hudson decreased $0.7 million, or 3.5%, from $18.8 million in 2005 to $18.1 million in 2006. This decrease was primarily due to income before income taxes decreasing $0.7 million, or 1.5%, in 2006 and a reduction to income tax expense in the third quarter of 2006 related to the closeout of IRS income tax audits for multiple years. COMMON STOCK DIVIDENDS Reference is made to the caption "Common Stock Dividends and Price Ranges" of Part II, Item 7 of the Corporations' 10-K Annual Report for a discussion of Energy Group's dividend payments. On March 24, 2006, the Board of Directors of Energy Group declared a quarterly dividend of $0.54 per share, payable May 1, 2006, to shareholders of record as of April 10, 2006. On May 25, 2006, the Board of Directors of Energy Group declared a quarterly dividend of $0.54 per share, payable August 1, 2006, to shareholders of record as of July 10, 2006. On September 28, 2006, the Board of Directors of Energy Group declared a quarterly dividend of $0.54 per share, payable November 1, 2006, to shareholders of record as of October 10, 2006. 70 OTHER MATTERS Changes in Accounting Standards: See Note 2 - "Summary of Significant Accounting Policies" and Note 7 - "New Accounting Standards and Other FASB Projects" for discussion of relevant changes, which discussion is incorporated by reference herein. Higher Energy Prices: In the first nine months of 2006, Central Hudson's regulated electric and natural gas delivery customers received bills reflecting higher per unit energy prices than those received in the first nine months of 2005. For heating customers, total bill impacts were partially mitigated by a reduction in average usage in response to warmer winter weather. While higher energy prices themselves have little or no impact on Central Hudson's earnings due to adjustment mechanisms that recover energy costs from customers, management believes that continued high energy prices could cause a change in customer behavior toward increased conservation and energy efficiency, resulting in a decrease in delivery volumes and a negative impact on earnings. Additionally, persistently higher prices or further price increases could lead to an economic slowdown and dampen economic growth in Central Hudson's service territory. Slower growth could adversely affect the overall volume of electricity and natural gas deliveries, reducing earnings from utility operations. Customers of the fuel distribution business are also experiencing higher per unit prices. In the first nine months of 2006, Griffith experienced year-over-year volume decreases that were partially driven by price-sensitive conservation, energy efficiency efforts, and fuel switching. If fuel oil prices remain high during the upcoming heating season, energy efficiency efforts and continued conservation could further reduce residential fuel delivery volumes. Both Central Hudson's electricity and natural gas businesses and Griffith's fuel distribution business also face several other challenges that could result from continued higher prices: higher working capital needs driven by lags between disbursements to energy suppliers and receipts from customers, higher bad debt expenses resulting from customers who are unable to pay higher energy bills, and political and regulatory responses to higher energy prices. Management believes that Energy Group has adequate liquidity to meet the working capital demands of the current and near-term energy price environment and is actively monitoring bad debt expense and the political/regulatory environment. CHEC's investment in ethanol production may realize benefits from higher energy prices in the future through higher prices for ethanol produced, but in the short-term benefits would be limited by the extent volumes have been sold at fixed prices. These benefits, however, may be partially offset by higher prices for the fuel used in the ethanol production process. 71 FORWARD-LOOKING STATEMENTS Statements included in this Quarterly Report on Form 10-Q and the documents incorporated by reference which are not historical in nature, are intended to be, and are hereby identified as, "forward-looking statements" for purposes of the safe harbor provided by Section 21E of the Securities Exchange Act of 1934, as amended ("Exchange Act"). Forward-looking statements may be identified by words including "anticipates," "intends," "estimates," "believes," "projects," "expects," "plans," "assumes," "seeks," and similar expressions. Forward-looking statements including, without limitation, those relating to Energy Group's and Central Hudson's ("Registrants") future business prospects, revenues, proceeds, working capital, liquidity, income and margins, are subject to certain risks and uncertainties that could cause actual results to differ materially from those indicated in the forward-looking statements, due to several important factors, including those identified from time to time in the forward-looking statements. Those factors include, but are not limited to: weather; fuel prices; corn and ethanol prices; energy supply and demand; interest rates; potential future acquisitions; developments in the legislative, regulatory, and competitive environment; market risks; electric and natural gas industry restructuring and cost recovery; the ability to obtain adequate and timely rate relief; changes in fuel supply or costs including future market prices for energy, capacity, and ancillary services; the success of strategies to satisfy electricity, natural gas, fuel oil, and propane requirements; the outcome of pending litigation and certain environmental matters, particularly the status of inactive hazardous waste disposal sites and waste site remediation requirements; and certain presently unknown or unforeseen factors, including, but not limited to, acts of terrorism. Registrants undertake no obligation to update publicly any forward-looking statements, whether as a result of new information, future events, or otherwise. Given these uncertainties, undue reliance should not be placed on the forward-looking statements. ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Reference is made to Part II, Item 7A of the Corporations' 10-K Annual Report for a discussion of market risk. There has been no material change in either the market risks or the practices employed by Energy Group and Central Hudson to mitigate these risks discussed in the Corporations' 10-K Annual Report. For related discussion on this activity, see, in the Consolidated Financial Statements of the Corporations' 10-K Annual Report, Note 1 - "Summary of Significant Accounting Policies" under the caption "Accounting for Derivative Instruments and Hedging Activities" and Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" under subcaption "Capital Resources and Liquidity." ITEM 4 - CONTROLS AND PROCEDURES The Chief Executive Officer and Chief Financial Officer of Energy Group and Central Hudson evaluated the effectiveness of the disclosure controls and procedures 72 (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this Quarterly Report on Form 10-Q and based on that evaluation, concluded that, as of the end of the period covered by this Quarterly Report on Form 10-Q, the Registrants' controls and procedures are effective for recording, processing, summarizing, and reporting information required to be disclosed in their reports under the Securities Exchange Act of 1934, as amended, within the time periods specified in the SEC's rules and forms. There was only one change to the Registrants' internal control over financial reporting that occurred during the Registrants' last fiscal quarter. In July 2006, Central Hudson completed the implementation of a new fixed asset software application. The general computer controls and business controls related to this new application are in the process of being tested for design and operational effectiveness. It is not expected that this change has materially affected, or is likely to materially affect, the Registrants' internal control over financial reporting. 73 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS Central Hudson: Former Manufactured Gas Plant Facilities For information about investigations and remediation efforts involving MGP facilities owned or operated by Central Hudson or its predecessors, see Item 3 of the Corporations' 10-K Annual Report and Note 11 - "Commitments and Contingencies" to the financial statements included in that report and Note 11 - "Commitments and Contingencies" to the financial statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q under the subcaption "Former Manufactured Gas Plant Facilities," which is incorporated herein by reference. Little Britain Road For information about the Little Britain Road site, see Note 11 - "Commitments and Contingencies" to the financial statements under the subcaption "Little Britain Road" included in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference. Orange County Landfill For information about the Orange County Landfill matter, see Item 3 of the Corporations' 10-K Annual Report and Note 11 - "Commitments and Contingencies" to the financial statements included in that report and Note 11 - "Commitments and Contingencies" to the financial statements under the subcaption "Orange County Landfill" included in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference. Asbestos Litigation For information about asbestos lawsuits to which Central Hudson is a party, see Item 3 of the Corporations' 10-K Annual Report and Note 11 - "Commitments and Contingencies" to the financial statement included in that report and Note 11 - "Commitments and Contingencies" to the financial statements under the subcaption "Asbestos Litigation" included in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated herein by reference. Neversink For information concerning the transfer of Neversink to the City, see Item 3 of the Corporations' 10-K Annual Report and Note 11 - "Commitments and Contingencies" to the financial statements included in that report and Note 11 - "Commitments and Contingencies" to the financial statements included in Part I, Item 1 of this Quarterly 74 Report on Form 10-Q under the subcaption "Neversink Hydro Station," which is incorporated herein by reference. CHEC: For information concerning Griffith's remediation efforts at the Kable Oil bulk plant in West Virginia, see Item 3 of the Corporations' 10-K Annual Report and Note 11 - "Commitments and Contingencies" to the financial statements included in that report and Note 11 - "Commitments and Contingencies" to the financial statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q under the caption "CHEC," which is incorporated herein by reference. For information concerning Griffith's (formerly SCASCO's) remediation efforts in Connecticut, see Item 3 the Corporations' 10-K Annual Report and Note 11 - "Commitments and Contingencies" to the financial statements included in that report and Note 11 - "Commitments and Contingencies" to the financial statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q under the caption "CHEC," which is incorporated herein by reference. ITEM 1A. RISK FACTORS For discussion identifying additional risk factors that could cause actual results to differ materially from those anticipated, see the discussion under Item 1A - Risk Factors of the Corporations' 10-K Annual Report and Item 1A - Risk Factors of the combined Energy Group/Central Hudson Quarterly Report on Form 10-Q for the quarter ended June 30, 2006. High Wholesale Fuel Oil Prices May Adversely Affect the Ability of Griffith to Attract New Customers, Retain Existing Customers, and Maintain Sales Volumes On September 30, 2006, the average wholesale price of fuel oil, as measured by the closing price on the NYMEX, was $1.88 per gallon. This is a 15.1% increase over the $1.64 per gallon price on September 30, 2005, and a 67.8% increase over the $1.12 per gallon price on September 30, 2004. Griffith's management believes the significant rise in the wholesale price of fuel oil has adversely impacted the ability of Griffith to attract new full service residential customers and, to a lesser extent, retain existing full service residential customers. Griffith's management believes some customer attrition is due to former and prospective full service customers deciding, because of high fuel oil prices, to purchase fuel from discount distributors, which - unlike Griffith - do not offer other services such as equipment installation, repair, and maintenance. In addition, Griffith's management believes that some customers are conserving their use of fuel oil by accepting lower temperatures in their homes and by implementing home improvements (e.g., more insulation, better windows). If higher fuel prices were to continue indefinitely, or such prices were to increase significantly, Griffith could experience further customer attrition and further reductions in sales volume due to customer conservation. If one or both of these were to occur and be material, the 75 consequence could be a material reduction in profitability that could, in turn, lead to an impairment of the goodwill included in the intangible assets on Griffith's and Energy Group's balance sheet. Additionally, if customer attrition were to accelerate significantly the remaining value of the customer list could be impaired or subject to accelerated amortization. ITEM 6. EXHIBITS (a) The following exhibits are furnished in accordance with the provisions of Item 601 of Regulation S-K. Exhibit No. Regulation S-K Item 601 Designation Exhibit Description 12 Statements Showing Computation of the Ratio of Earnings to Fixed Charges and the Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. 31.1 Rule 13a-14(a)/15d-14(a) Certification by Mr. Lant. 31.2 Rule 13a-14(a)/15d-14(a) Certification by Mr. Capone. 32.1 Section 1350 Certification by Mr. Lant. 32.2 Section 1350 Certification by Mr. Capone. 99 New York State Public Service Commission Order Establishing Rate Plan dated July 24, 2006. 76 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized. CH ENERGY GROUP, INC. (Registrant) By: /s/ Donna S. Doyle ------------------------------------------- Donna S. Doyle Vice President - Accounting and Controller CENTRAL HUDSON GAS & ELECTRIC CORPORATION (Co-Registrant) By: /s/ Donna S. Doyle ------------------------------------------- Donna S. Doyle Vice President - Accounting and Controller Dated: November 2, 2006 77 EXHIBIT INDEX Following is the list of Exhibits, as required by Item 601 of Regulation S-K, filed as part of this Quarterly Report on Form 10-Q: Exhibit No. Regulation S-K Item 601 Designation Exhibit Description 12 Statements Showing Computation of the Ratio of Earnings to Fixed Charges and the Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. 31.1 Rule 13a-14(a)/15d-14(a) Certification by Mr. Lant. 31.2 Rule 13a-14(a)/15d-14(a) Certification by Mr. Capone. 32.1 Section 1350 Certification by Mr. Lant. 32.2 Section 1350 Certification by Mr. Capone. 99 New York State Public Service Commission Order Establishing Rate Plan dated July 24, 2006. 78 EX-12 2 d69744_ex12.txt STATEMENT RE: COMPUTATION OF THE RATIO OF EARNINGS CH ENERGY GROUP, INC. Computation of Ratio of Earnings to Fixed Charges EXHIBIT (12) (i)
2006 2005 ----------------------------------- ----------------------- 3 Months 9 Months 12 Months 3 Months 9 Months Ended Ended Ended Ended Ended Sept 30 Sept 30 Sept 30 Sept 30 Sept 30 --------- --------- --------- --------- --------- Earnings: ($000) A. Net Income from Continuing Operations $ 10,970 $ 33,338 $ 45,010 $ 5,746 $ 32,619 B. Preferred Stock Dividends $ 242 $ 727 $ 970 $ 242 $ 727 C. Federal and State Income Tax 4,392 19,250 27,081 2,364 17,988 Less Income from Equity Investments 327 1,273 2,260 5 497 Plus Cash Distribution from Equity Investments 734 774 2,296 157 311 --------- --------- --------- --------- --------- D. Earnings before Income Taxes and Equity Inv $ 16,011 $ 52,816 $ 73,097 $ 8,504 $ 51,148 ========= ========= ========= ========= ========= E Fixed Charges Interest on Mortgage Bonds 0 0 0 0 0 Interest on Other Long-Term Debt 4,115 12,139 15,778 3,421 10,187 Other Interest 1,105 2,848 3,674 795 1,751 Interest Portion of Rents (2) 271 798 1,058 250 796 Amortization of Premium & Expense on Debt 245 735 985 263 793 Preferred Stock Dividends Requirements of Central Hudson 332 1,074 1,467 330 1,064 --------- --------- --------- --------- --------- Total Fixed Charges $ 6,068 $ 17,594 $ 22,962 $ 5,059 $ 14,591 ========= ========= ========= ========= ========= Less Preferred Stock Dividends Requirements of Central Hudson 332 1,074 1,467 330 1,064 F Total Earnings $ 21,747 $ 69,336 $ 94,592 $ 13,233 $ 64,675 ========= ========= ========= ========= ========= Preferred Dividend Requirements: G. Allowance for Preferred Stock Dividends Under IRC Sec 247 $ 242 $ 727 $ 970 $ 242 $ 727 H. Less Allowable Dividend Deduction (32) (96) (127) (32) (96) --------- --------- --------- --------- --------- I. Net Subject to Gross-up 210 631 843 210 631 J. Ratio of Earnings before Income Taxes and Equity Inv. to Net Income (D/(A+B)) 1.428 1.550 1.590 1.420 1.534 --------- --------- --------- --------- --------- K. Preferred Dividend (Pre-tax) (I x J) 300 978 1,340 298 968 L. Plus Allowable Dividend Deduction 32 96 127 32 96 --------- --------- --------- --------- --------- M. Preferred Dividend Factor 332 1,074 1,467 330 1,064 ========= ========= ========= ========= ========= N. Ratio of Earnings to Fixed Charges (F/E) 3.6 3.9 4.1 2.6 4.4 ========= ========= ========= ========= ========= Year Ended December 31, ---------------------------------------------------------------- 2005 2004 2003 2002 2001 --------- --------- --------- --------- --------- Earnings: ($000) A. Net Income from Continuing Operations $ 44,291 $ 42,423 $ 43,985 $ 36,453 $ 50,835 B. Preferred Stock Dividends $ 970 $ 970 $ 1,387 $ 2,161 $ 3,230 C. Federal and State Income Tax 25,819 31,256 30,435 22,294 (3,338) Less Income from Equity Investments 1,484 922 865 749 1,922 Plus Cash Distribution from Equity Investments 1,833 1,776 1,249 959 3,934 --------- --------- --------- --------- --------- D. Earnings before Income Taxes and Equity Inv $ 71,429 $ 75,503 $ 76,191 $ 61,118 $ 52,739 ========= ========= ========= ========= ========= E Fixed Charges Interest on Mortgage Bonds 0 0 570 2,136 5,211 Interest on Other Long-Term Debt 13,826 11,488 10,699 9,819 10,446 Other Interest 2,577 5,517 9,828(1) 11,659 12,837 Interest Portion of Rents (2) 1,077 1,192 1,040 749 801 Amortization of Premium & Expense on Debt 1,043 1,066 1,159 1,249 1,350 Preferred Stock Dividends Requirements of Central Hudson 1,457 1,594 2,243 3,346 3,154 --------- --------- --------- --------- --------- Total Fixed Charges $ 19,980 $ 20,857 $ 25,539 $ 28,958 $ 33,799 ========= ========= ========= ========= ========= Less Preferred Stock Dividends Requirements of Central Hudson 1,457 1,594 2,243 3,346 3,154 F Total Earnings $ 89,952 $ 94,766 $ 99,487 $ 86,730 $ 83,384 ========= ========= ========= ========= ========= Preferred Dividend Requirements: G. Allowance for Preferred Stock Dividends Under IRC Sec 247 $ 970 $ 970 $ 1,387(1) $ 2,161 $ 3,230 H. Less Allowable Dividend Deduction (127) (127) (127) (127) (127) --------- --------- --------- --------- --------- I. Net Subject to Gross-up 843 843 1,260 2,034 3,103 J. Ratio of Earnings before Income Taxes and Equity Inv. to Net Income (D/(A+B)) 1.578 1.740 1.679 1.583 0.975 --------- --------- --------- --------- --------- K. Preferred Dividend (Pre-tax) (I x J) 1,330 1,467 2,116 3,219 3,027 L. Plus Allowable Dividend Deduction 127 127 127 127 127 --------- --------- --------- --------- --------- M. Preferred Dividend Factor 1,457 1,594 2,243 3,346 3,154 ========= ========= ========= ========= ========= N. Ratio of Earnings to Fixed Charges (F/E) 4.5 4.5 3.9 3.0 2.5 ========= ========= ========= ========= =========
(1) Reflects SFAS No. 150, titled Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, reclassification of $208,750 in preferred stock dividends to interest expense for the quarter ended September 30, 2003. (2) The percentage of rent included in the fixed charges calculation is a reasonable approximation of the interest factor. CENTRAL HUDSON GAS & ELECTRIC CORPORATION Computation of Ratio of Earnings to Fixed Charges Exhibit (12) (i) (i) and Ratio of Earnings to Fixed Charges and Preferred Dividends
2006 2005 ----------------------------------- ---------------------- 3 Months 9 Months 12 Months 3 Months 9 Months Ended Ended Ended Ended Ended Sept 30 Sept 30 Sept 30 Sept 30 Sept 30 --------- --------- --------- --------- --------- Earnings: ($000) A. Net Income $ 10,773 $ 27,951 $ 35,598 $ 6,885 $ 27,988 B. Federal & State Income Tax 5,534 18,090 23,275 4,484 18,751 --------- --------- --------- --------- --------- C. Earnings before Income Taxes $ 16,307 $ 46,041 $ 58,873 $ 11,369 $ 46,739 ========= ========= ========= ========= ========= D. Fixed Charges Interest on Mortgage Bonds 0 0 0 0 0 Interest on Other Long-Term Debt 4,115 12,139 15,778 3,421 10,187 Other Interest 1,105 2,848 3,673 794 1,752 Interest Portion of Rents (2) 192 584 798 192 621 Amortization of Premium & Expense on Debt 245 735 986 264 792 --------- --------- --------- --------- --------- Total Fixed Charges $ 5,657 $ 16,306 $ 21,235 $ 4,671 $ 13,352 ========= ========= ========= ========= ========= E. Total Earnings $ 21,964 $ 62,347 $ 80,108 $ 16,040 $ 60,091 ========= ========= ========= ========= ========= Preferred Dividend Requirements: F. Allowance for Preferred Stock Dividends Under IRC Sec 247 $ 242 $ 727 $ 970 $ 242 $ 727 G. Less Allowable Dividend Deduction (32) (96) (127) (32) (96) --------- --------- --------- --------- --------- H. Net Subject to Gross-up 210 631 843 210 631 I. Ratio of Earnings before Income Taxes to Net Income (C/A) 1.514 1.647 1.654 1.651 1.670 --------- --------- --------- --------- --------- J. Pref. Dividend (Pre-tax) (H x I) 318 1,039 1,394 347 1,054 K. Plus Allowable Dividend Deduction 32 96 127 32 96 --------- --------- --------- --------- --------- L. Preferred Dividend Factor 350 1,135 1,521 379 1,150 M. Fixed Charges (D) 5,657 16,306 21,235 4,671 13,352 --------- --------- --------- --------- --------- N. Total Fixed Charges and Preferred Dividends $ 6,007 $ 17,441 $ 22,756 $ 5,050 $ 14,502 ========= ========= ========= ========= ========= O. Ratio of Earnings to Fixed Charges (E/D) 3.9 3.8 3.8 3.4 4.5 ========= ========= ========= ========= ========= P. Ratio of Earnings to Fixed Charges and Preferred Dividends (E/N) 3.7 3.6 3.5 3.2 4.1 ========= ========= ========= ========= ========= Year Ended December 31, ---------------------------------------------------------------- 2005 2004 2003 2002 2001 --------- --------- --------- --------- --------- Earnings: ($000) A. Net Income $ 35,635 $ 38,648 $ 38,875 $ 32,524 $ 44,178 B. Federal & State Income Tax 23,936 28,426 26,981 21,690 (7,637) --------- --------- --------- --------- --------- C. Earnings before Income Taxes $ 59,571 $ 67,074 $ 65,856 $ 54,214 $ 36,541 ========= ========= ========= ========= ========= D. Fixed Charges Interest on Mortgage Bonds 0 0 570 2,136 5,211 Interest on Other Long-Term Debt 13,826 11,488 10,699 9,819 10,446 Other Interest 2,577 5,517 9,828(1) 11,772 11,820 Interest Portion of Rents (2) 835 954 768 749 801 Amortization of Premium & Expense on Debt 1,043 1,066 1,159 1,249 1,350 --------- --------- --------- --------- --------- Total Fixed Charges $ 18,281 $ 19,025 $ 23,024 $ 25,725 $ 29,628 ========= ========= ========= ========= ========= E. Total Earnings $ 77,852 $ 86,099 $ 88,880 $ 79,939 $ 66,169 ========= ========= ========= ========= ========= Preferred Dividend Requirements: F. Allowance for Preferred Stock Dividends Under IRC Sec 247 $ 970 $ 970 $ 1,387(1) $ 2,161 $ 3,230 G. Less Allowable Dividend Deduction (127) (127) (127) (127) (127) --------- --------- --------- --------- --------- H. Net Subject to Gross-up 843 843 1,260 2,034 3,103 I. Ratio of Earnings before Income Taxes to Net Income (C/A) 1.672 1.736 1.694 1.667 0.827 --------- --------- --------- --------- --------- J. Pref. Dividend (Pre-tax) (H x I) 1,409 1,463 2,134 3,391 2,566 K. Plus Allowable Dividend Deduction 127 127 127 127 127 --------- --------- --------- --------- --------- L. Preferred Dividend Factor 1,536 1,590 2,261 3,518 2,693 M. Fixed Charges (D) 18,281 19,025 23,024 25,725 29,628 --------- --------- --------- --------- --------- N. Total Fixed Charges and Preferred Dividends $ 19,817 $ 20,615 $ 25,285 $ 29,243 $ 32,321 ========= ========= ========= ========= ========= O. Ratio of Earnings to Fixed Charges (E/D) 4.3 4.5 3.9 3.1 2.2 ========= ========= ========= ========= ========= P. Ratio of Earnings to Fixed Charges and Preferred Dividends (E/N) 3.9 4.2 3.5 2.7 2.1 ========= ========= ========= ========= =========
(1) Reflects SFAS No. 150, titled Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, reclassification of $208,750 in preferred stock dividends to interest expense for the quarter ended September 30, 2003. (2) The percentage of rent included in the fixed charges calculation is a reasonable approximation of the interest factor. EX-31.1 3 d69744_ex31-1.txt SECTION 302 CERTIFICATION BY MR. LANT. CERTIFICATIONS Exhibit 31.1 I, Steven V. Lant, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CH Energy Group, Inc. and Central Hudson Gas & Electric Corporation (collectively the "Registrants"); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrants as of, and for, the periods presented in this report; 4. The Registrants' other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrants and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; c) Evaluated the effectiveness of the Registrants' disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the Registrants' internal control over financial reporting that occurred during the Registrants' most recent fiscal quarter (the Registrants' fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to 79 materially affect, the Registrants' internal control over financial reporting; and 5. The Registrants' other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrants' auditors and the audit committee of the Registrants' boards of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrants' ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrants' internal control over financial reporting. Date: November 2, 2006 /s/ Steven V. Lant -------------------------------------------------- Steven V. Lant Chairman of the Board, President and Chief Executive Officer of CH Energy Group, Inc. /s/ Steven V. Lant -------------------------------------------------- Steven V. Lant Chairman of the Board and Chief Executive Officer of Central Hudson Gas & Electric Corporation 80 EX-31.2 4 d69744_ex31-2.txt SECTION 302 CERTIFICATION BY MR. CAPONE. CERTIFICATIONS Exhibit 31.2 I, Christopher M. Capone, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CH Energy Group, Inc. and Central Hudson Gas & Electric Corporation (collectively the "Registrants"); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrants as of, and for, the periods presented in this report; 4. The Registrants' other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrants and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrants, including their consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; c) Evaluated the effectiveness of the Registrants' disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the Registrants' internal control over financial reporting that occurred during the Registrants' most recent fiscal quarter (the Registrants' fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to 81 materially affect, the Registrants' internal control over financial reporting; and 5. The Registrants' other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrants' auditors and the audit committee of the Registrants' boards of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrants' ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrants' internal control over financial reporting. Date: November 2, 2006 /s/ Christopher M. Capone ---------------------------------------------- Christopher M. Capone Chief Financial Officer and Treasurer of CH Energy Group, Inc. /s/ Christopher M. Capone ---------------------------------------------- Christopher M. Capone Chief Financial Officer and Treasurer of Central Hudson Gas & Electric Corporation 82 EX-32.1 5 d69744_ex32-1.txt SECTION 1350 CERTIFICATION BY MR. LANT. CERTIFICATIONS Exhibit 32.1 I, Steven V. Lant, do hereby certify in accordance with 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: 1. The Quarterly Report on Form 10-Q of CH Energy Group, Inc. and Central Hudson Gas & Electric Corporation (the "Companies") for the period ended September 30, 2006 (the "Quarterly Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and 2. The information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Companies. Date: November 2, 2006 /s/ Steven V. Lant ---------------------------------------------------- Steven V. Lant Chairman of the Board, President and Chief Executive Officer of CH Energy Group, Inc. /s/ Steven V. Lant ---------------------------------------------------- Steven V. Lant Chairman of the Board and Chief Executive Officer of Central Hudson Gas & Electric Corporation 83 EX-32.2 6 d69744_ex32-2.txt SECTION 1350 CERTIFICATION BY MR. CAPONE. CERTIFICATIONS Exhibit 32.2 I, Christopher M. Capone, do hereby certify in accordance with 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: 1. The Quarterly Report on Form 10-Q of CH Energy Group, Inc. and Central Hudson Gas & Electric Corporation (the "Companies") for the period ended September 30, 2006 (the "Quarterly Report") fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and 2. The information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Companies. Date: November 2, 2006 /s/ Christopher M. Capone ----------------------------------------------- Christopher M. Capone Chief Financial Officer and Treasurer of CH Energy Group, Inc. /s/ Christopher M. Capone ----------------------------------------------- Christopher M. Capone Chief Financial Officer and Treasurer of Central Hudson Gas & Electric Corporation 84 EX-99 7 d69744_ex99.txt RATE PLAN DATED JULY 24, 2006 Exhibit 99 STATE OF NEW YORK PUBLIC SERVICE COMMISSION At a session of the Public Service Commission held in the City of Albany on July 19, 2006 COMMISSIONERS PRESENT: William M. Flynn, Chairman Patricia L. Acampora Maureen F. Harris Robert E. Curry, Jr. Cheryl A. Buley CASE 05-E-0934 - Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations of Central Hudson Gas & Electric Corporation for Electric Service. CASE 05-G-0935 - Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations of Central Hudson Gas & Electric Corporation for Gas Service. ORDER ESTABLISHING RATE PLAN (Issued and Effective July 24, 2006) BY THE COMMISSION: INTRODUCTION This order establishes a three-year rate plan for electric and gas service provided by Central Hudson Gas & Electric Corporation (Central Hudson, the Company). The terms and conditions established by this order are generally consistent with terms and conditions that were set forth in a contested Joint Proposal submitted by Central Hudson, New York State Department of Public Service Staff (Staff), Multiple Intervenors and the United States Department of Defense and all other Federal Executive Agencies (DOD). CASE 05-E-0934, et al. PROCEDURAL HISTORY On July 29, 2005, Central Hudson filed tariff amendments to increase its electric and gas rates each of the next three rate years. For the initial rate year, Central Hudson proposed to increase electric and gas total revenues by approximately $52.8 million (13%) and $18.1 million (15%), respectively. The filing was suspended and these cases were established to examine the Company's proposals.(1) On November 21, 2005, testimony opposing the Company's submission was filed by Staff, the New York State Consumer Protection Board (CPB), and Multiple Intervenors. The Company filed supplemental testimony on November 28, 2005. Rebuttal testimony was filed on December 14, 2005 by Central Hudson, Staff and Multiple Intervenors. Direct testimony was filed by DOD on December 19, 2005. In early January, the Company submitted additional supplemental testimony in response to a Commission Order in Case 04-G-0463.(2) Central Hudson provided its notice of intent to enter into settlement negotiations by letter dated January 6, 2006. In accordance with applicable Commission rules, the notice was reported to the Commission on January 10, 2006.(3) On January 12, 2006, four parties contacted the presiding officers and proposed a one-month postponement of the evidentiary hearings scheduled to commence on January 18, 2006. The evidentiary hearings were cancelled and a procedural ruling - ---------- (1) Order Suspending Major Rate Filings (issued August 24, 2005); Further Suspension of Major Rate Filings (issued December 14, 2005). (2) Case 04-G-0463, Central Hudson Gas & Electric Corporation - Tariff Filing, Order Approving Real-Time Metering Plans, Adopting Daily Balancing Charges and Procedures, and Establishing Further Proceedings (issued November 29, 2005) at 11 (directing Central Hudson to propose and support the permanent rate for daily balancing service in this gas rate case). (3) 16 NYCRR 3.9(a)(2). -2- CASE 05-E-0934, et al. was issued that granted the postponement and established target dates for the submission of a joint proposal.(4) Public statement hearings were held on March 13 and 14, 2006 in Poughkeepsie, Fishkill, Newburgh and Kingston before Administrative Law Judge Michelle L. Phillips. In addition, Commissioner Leonard A. Weiss attended the public statement hearing in Poughkeepsie. In total, 33 people made statements on the record. The speakers generally opposed the rate increases sought by Central Hudson. Several speakers expressed concern that low and fixed income customers could not afford any further increase. Many noted that their bills had already shown significant increases due to the flow-through of commodity costs. Still others stated that schools and businesses would have to pass along any increases through higher taxes and increased prices for goods and services. Some suggested that, if any increase was granted to Central Hudson, it should approximate cost-of-living increases received by the average working person in the Company's service territory. A few opined that the company's level of service did not warrant an increase. Finally, some questioned whether the requested increase was justified, especially given the Company's/CH Energy Group's reported profits of approximately $40 million each of the last two years. Numerous public comments also were received by the Commission through the Department of Public Service Web site and the toll-free telephone line, and through the U.S. Mail. The concerns expressed therein were similar to those expressed at the public statement hearings.(5) In addition, resolutions opposing the Central Hudson request were received from the Towns of Newburgh, Plattekill, Poughkeepsie and Wappingers Falls. - ---------- (4) See Procedural Ruling on Revised Process and Schedule (issued January 17, 2006). (5) One of the comments consisted of a petition, with approximately 25 signatures, opposing the requested rate increase. -3- CASE 05-E-0934, et al. At a conference held on March 9, 2006, the parties agreed to meet with a settlement judge,(6) the Company agreed to further extend the suspension period to the end of August 2006, and evidentiary hearings were rescheduled. At a procedural conference held on April 3, 2006, several of the parties reported reaching an agreement in principle and proposed a new procedural schedule that would allow them to finalize a joint proposal.(7) The Joint Proposal, originally filed with the Commission on April 18, 2006, was subsequently restated on April 19, 2006 and re-filed on April 20, 2006. It recommends a three-year rate plan that is supported by the Company, Staff, Multiple Intervenors and DOD. The Joint Proposal is opposed by CPB, Public Utility Law Project (PULP), Small Customer Marketer Coalition/Retail Energy Supply Association (SCMC/RESA) and Select Energy New York, Inc. (Select Energy). At evidentiary hearings held on May 4 and 5, 2006, witness panels representing CPB, the Company and Staff were cross-examined concerning their support of or opposition to the Joint Proposal. In addition, the prefiled testimony and exhibits submitted by the Company, Staff, CPB, Multiple Intervenors and DOD were moved into evidence. Statements in Support and in Opposition were marked for identification but not placed into evidence. In all, the record consists of 1672 transcript pages and 102 exhibits. Post-hearing briefs were filed by Staff, Central Hudson, Multiple Intervenors, DOD, CPB, PULP and SCMC/RESA on - ---------- (6) Administrative Law Judge Jeffrey E. Stockholm was appointed as a settlement judge. (7) In light of the parties' report, the evidentiary hearings scheduled to commence on April 10, 2006 were postponed without date. Notice Postponing Evidentiary Hearings (issued April 4, 2006). -4- CASE 05-E-0934, et al. May 12, 2006. A revised post-hearing brief was submitted by Central Hudson on June 5, 2006.(8) Public statement hearings on the Joint Proposal were held in Poughkeepsie and Kingston on May 22, 2005. Seven people made statements on the record. Most speakers stated that the Joint Proposal rates were too high. The balance of the statements, for the most part, reiterated concerns that had been expressed at the March public statement hearings (e.g., customers on fixed and low incomes could not afford any increases; schools budgets would be affected and local governments would have to pass along any increases through higher taxes; and that, if any increase was granted to Central Hudson, it should approximate cost-of-living increases received by the average working person in the service territory). The written, telephonic and electronic comments that were received on the Joint Proposal generally echoed the concerns expressed at the May 22nd public statement hearings. PROPOSED RATE PLAN AND THE ISSUES BY SECTION(9) The proposed rate plan consists of a three-year term beginning on July 1, 2006 and ending June 30, 2009. Its most salient provisions are summarized below. Electric Revenues, Rates and Bill Impacts Electric delivery revenues would increase by about $41.4, $6.1 and $5.5 million, respectively, each rate year. - ---------- (8) On May 22 and 23, 2006, respectively, CPB moved to strike, in part, and PULP moved to strike in its entirety, the Company's post-hearing brief, claiming that it included statements that violated Commission guidelines and rules. On May 26, 2006, the Company responded, opposing both motions. On June 5, 2006, a ruling was issued granting, in part, the motions to strike. In compliance with the ruling, the Company submitted a revised post-hearing brief. (9) In the following discussion, the terms of the Joint Proposal, along with any issues related thereto, are generally summarized and discussed. The term Joint Proposal refers to the Joint Proposal as restated April 19, 2006. -5- CASE 05-E-0934, et al. However, by using a portion of electric depreciation reserve, the initial rate year's increase would be moderated, producing three equal increases of approximately $17.9 million each rate year. The revenue allocations among all service classifications, except service classification 9, would be constrained to a minimum increase of 0.75 times the system average and a maximum of 1.25 times the system average. The increase for service classification 9 would be constrained to 0.5 times the system average and would include an additional $50,000 allocation of revenue requirement responsibility. The resulting bill changes for each service classification and each rate year are summarized in Appendix B. The delivery bill increases approximate 10.4%, 9.4% and 8.6%, respectively, each rate year. The delivery bill increases for the residential service class would be about 12.9%, 10.5% and 9.5%, respectively, each rate year. The typical residential electric customer (using 500 kWh per month) would experience a bill impact of about 5.4% in the first rate year. Electric rates would be further unbundled to more accurately separate and reflect commodity and delivery costs and components. The existing Energy Cost Adjustment Mechanism, which is used to recover electric commodity costs from Central Hudson customers, would be modified to remove New York Independent System Operator Ancillary Services Charges and New York Power Authority Transmission Access Charges. As of July 1, 2007, such costs will be recovered in the Market Price Charges and Hourly Pricing Programs. Three Market Price Charges would be implemented on July 1, 2006. The first would apply to service classifications 1 (residential), 2 (general), and 9 (traffic signal); the second would apply to service classification 6 (residential time-of-use); and the third would apply to service classifications 5 (area lighting) and 8 (public street and highway lighting). The proposed Market Price Charges would be based on the average load shapes for each class. As of July 1, 2007, the Market Price Charge for service classification 6 would be further -6- CASE 05-E-0934, et al. differentiated into on- and off-peak rates. Also, as of July 1, 2007, Central Hudson would cease reimbursing energy service companies (ESCOs) for ancillary service costs and New York Power Authority Transmission Access Charges. Gas Revenues, Rates and Bill Impacts Gas delivery revenues would increase by $8,003,000 (about 19%) and by $6,057,000 (about 11.8%) in the first and second rate years, respectively. There would be no increase in the third rate year. The proposed gas revenue requirements are moderated by deferring and amortizing portions of the gas revenue increases. They also include an interruptible profit imputation of $1 million.(10) Gas rates, like the electric rates, would be further unbundled to reflect the transfer of additional commodity-related costs to the proposed Merchant Function Charges. For residential gas customers, the minimum charge would increase from $7.20 to $14 a month. As shown in Appendix F, the annual gas rate increase for a typical gas heating customer (1100 Ccf per year) will be $92.45 (6.36%). A new subclass will be established in service class 11, "Distribution Large Mains" ("SC 11DLM"), for customers using over 400,000 Mcf/year. The costs allocated to SC 11DLM are set forth in Appendix E and they exclude, among other things, the cost of mains that are less than 6 inches in diameter. The U.S. Military Academy at West Point (USMA) would receive service in accordance with the provisions of the new SC 11DLM class after - ---------- (10) Because of the imputation, the Company is permitted each rate year to retain the first $1 million in revenues it receives from interruptible service and service to electric generators. However, if the margin does not reach $1 million in any rate year, the Company is authorized to surcharge ratepayers for 100% of the first $250,000 and 90% of the remaining shortfall. If the margin exceeds $1 million in any rate year, the Company must credit ratepayers for 100% of the first $250,000 and 90% of the remaining shortfall. -7- CASE 05-E-0934, et al. the execution of a contract between Central Hudson and the U.S. Department of the Army on behalf of USMA.(11) The existing Gas Supply Charge (GSC), Firm Transportation Rate (FTR), Interruptible Transportation Rate (ITR) and Interruptible Gas Rate (IGR), which are related to the recovery of gas commodity supply costs, would continue, subject to the proposed gas balancing modifications. Gas Balancing Effective April 1, 2007, new gas balancing procedures would apply to interruptible and firm transportation customers and to aggregated transport customers. Applicable procedures described in the Company's July 2005 "Report on Gas Balancing and Cashout Issues" would be followed in implementing the new gas balancing procedures. Incremental software costs for implementing the procedures would receive deferral accounting.(12) For the interruptible and firm transportation customers, the volumetric balancing service charge would be implemented as two separate rates: one for daily balanced customers and one for monthly balanced customers.(13) The charges would be updated at least annually.(14) The updates would be based on each service classification's total consumption and deliveries during the preceding winter period and the Company's then most recently available gas storage and other relevant costs.(15) - ---------- (11) Additional, non-rate provisions regarding Central Hudson and USMA are set forth in Section XVIII. (12) Any such amounts would be subject to carrying charges at the pre-tax authorized rate of return. (13) See Appendix K. (14) SC 11DLM rates would be excepted from the proposed April 1, 2007 update and would remain in effect until March 31, 2008. Effective April 1, 2008, the charges for SC 11 and SC 11DLM would be determined separately, based on the specific peak day history for each class. (15) The Company would file a statement of Gas Balancing Rates at least 30 days prior to the effective date of an update. -8- CASE 05-E-0934, et al. Interruptible and firm transportation customers would be allowed to designate an ESCO to make supply nominations and effectuate imbalance exchanges. Commencing April 1, 2007, balancing service charges would be billed to the customers, while imbalance penalties would be billed to the customer's ESCO.(16) ESCOs will be required to enter into agreements with Central Hudson to pay for such penalties. Prior to April 1, 2007, all charges would continue to be billed to customers. There also are provisions for the treatment of customers under negotiated contracts, the term of the option period, notification regarding a customer's selected balancing option, the elimination of the current daily balancing provisions, monthly and daily "cash-out" procedures, applicable under-delivery index prices, revisions to over- and under-deliveries for monthly balanced customers, purchasing of over-deliveries, and the delivery requirements that would apply after Central Hudson issues an Operational Flow Order. Finally, the Company will pursue withdrawal of its pending rehearing petition concerning gas balancing. Gas balancing provisions for the aggregated transportation customers include reconciliations and periodic true-ups. Starting April 1, 2007, ESCOs can trade offsetting monthly imbalances as part of the semi-annual reconciliation/true-up. Rate Unbundling Existing electric backout credits and related treatment would be maintained through June 30, 2007, except that the cost of the electric backout credits will be charged against the excess electric depreciation reserve. Commencing July 1, 2007, the electric backout credits would be replaced by four Merchant Function Charge groups and by the lost revenue provisions. - ---------- (16) Balancing Service Charge revenues would be credited to the Gas Supply Charge. -9- CASE 05-E-0934, et al. The four electric Merchant Function Charge groups will be designated MFC1, MFC2, MFC3 and MFC4. MFC1 applies to service classifications 1 and 6; MFC2 applies to service classifications 2 and 3; MFC3 applies to service classifications 3 and 13; and MFC4 applies to service classifications 5, 8, and 9. The new MFCs include cost-based components to represent commodity-related purchasing, credit and collection, call center costs, advertising and promotions, and related Administrative and General (A&G) expenses and rate base items allocated to each group. The existing gas backout credits will continue to be recovered through the Gas Supply Charge through June 30, 2007. Gas delivery service MFCs, analogous to those for electric delivery service, would be implemented on July 1, 2007, with MFC 1 applicable to service classification 1 and MFC 2 applicable to service classification 2. Each MFC group will be further sub-divided into an MFC(A) and an MFC(B). MFC(A) includes the allocated portion of credit and collection function costs and 50% of procurement-related call center function costs, plus associated A&G and rate base items. MFC(B) includes commodity purchasing function costs, allocated portions of advertising & promotions function costs and 50% of procurement-related call center function costs, plus associated A&G and rate base items. Full service customers will be billed for both the MFC(A) and MFC(B). Retail access customers will be billed by for MFC(A) only.(17) Should total monthly migration of electric or gas customers exceed 30%, short run avoided costs will be established through a collaborative effort among the parties and - ---------- (17) Customers who purchase their commodity service from an ESCO that is not participating in the Company's POR Program would not be billed a MFC by Central Hudson. The discount rate charged to ESCOs that participate in Central Hudson's POR Program would be the same for all service classifications and would consist of an amount reflecting commodity-related uncollectibles costs and a time value of money factor of 0.25%. -10- CASE 05-E-0934, et al. be submitted for Commission approval. Central Hudson will propose, no later than October 1, 2006, an unbundled bill format for approval by the Commission. Capital Expenditures Electric capital expenditures, excluding the Allowance for Funds Used During Construction (AFUDC), would be set at $158.078 million ($51.944 million for the first rate year, $52.530 million for the second rate year, and $53.604 million for the third rate year). If actual expenditures fall short of $158.078 million by the end of the third rate year, the amount of the shortfall multiplied by 1.5 times the average authorized pre-tax rate of return will be deferred for ratepayer benefit.(18) Gas plant, excluding both the proposed gas infrastructure enhancements (described in Section XIV.E of Joint Proposal(19)) and AFUDC, would be set at $27.495 million ($10.397 million, $9.354 million and $7.744 million for rate years one, two and three, respectively). If actual expenditures fall short of $27.495 million by the end of the third rate year, the amount of the shortfall multiplied by 1.5 times the average authorized pre-tax rate of return will be deferred for ratepayer benefit.(20) If actual expenditures for gas infrastructure enhancements exceed $15.75 million, the amount above $15.75 million may be applied to reduce the gas plant shortfall. The capital expenditures for common plant would be set, reflecting AFUDC, at $21.693 million ($7.732 million, $7.031 million, and $6.930 million for each rate year, respectively). Again, should actual expenditures fall short of $21.693 million by the end of rate year three, the shortfall - ---------- (18) Commencing July 1, 2009, any such amount would be subject to carrying charges calculated at the authorized pre-tax rate of return. (19) The Joint Proposal erroneously refers to Section XIII.G. The correct reference is Section XIV.E. (20) Commencing July 1, 2009, any such amount would be subject to carrying charges calculated at the authorized pre-tax rate of return. -11- CASE 05-E-0934, et al. multiplied by 1.5 times the average authorized pre-tax rate of return will be deferred for ratepayer benefit.(21) Depreciation The average service lives, net salvage factors and life tables used to calculate the theoretical depreciation reserve and to establish the depreciation expense reflected in the revenue requirements are set forth in Appendix J and will continue to be used until such levels are changed by the Commission. No adjustments will be made to the depreciation rates used prior to June 30, 2006. A new depreciation study will be filed by the Company when it files the next major gas, electric or combined rate case. If a combination gas and electric filing is made, the depreciation study would address gas, electric and common plant accounts; if the filing is limited to only gas or only electric issues, the study need only address the gas or the electric plant accounts. Deferrals The Company will continue to use deferral accounting for certain specified items.(22) In addition, the Company will be authorized to defer items specified in and approved by this Order. The deferrals listed in Appendix I will be subject to the Limitation of Deferral provision set forth under the Section X (Earnings Sharing). Earnings Sharing The Company's allowed return on equity would be 9.6%. If the Company achieves a regulatory rate of return on common equity above 10.6% in either the electric or gas department, the earnings would be shared as follows: above 10.6% and up to 11.6%, equal (50/50) sharing between the Company and ratepayers; - ---------- (21) Commencing July 1, 2009, any such amount would be subject to carrying charges calculated at the authorized pre-tax rate of return. (22) See Section IX. -12- CASE 05-E-0934, et al. above 11.6% and up to 14.0%, shared 35%/65% between the Company and ratepayers, respectively; and any earnings above 14.0% would be deferred for customers' benefit.(23) If the Company achieves a return on common equity above 10.6% in either the electric or gas department, and experiences an under-recovery of migration-related net lost revenues, the net lost revenues will be offset by the Company's portion of the earnings above 10.6%.(24) Additional Rate Provisions There would be additional rate-related requirements and conditions, including, but not limited to, the following: accounting procedures for gas mains and services; permitted balance sheet offsets; cessation of the Benefit Fund, but with the preservation and continuation of certain specified uses; deferral conditions and reporting requirements regarding costs for the East Fishkill Substation; a shortfall protection mechanism for electric transmission right-of-way (ROW) maintenance costs; authorization to record gas and electric revenues attributable to the extension of the suspension period to the end of August; establishment of the rate allowances and the deferral and reporting requirements for manufactured gas plant (MGP) site investigation and remediation (SIR) costs; requirements for the deferral and sharing of property tax costs; and the establishment of factors for common costs allocation, electric losses and lost and unaccounted for gas. They are set forth in Section XI. Low-Income Program A new low-income program, instituted in two phases, will replace Central Hudson's current low-income program ("Powerful Opportunities" or "POP"). An interim program will - ---------- (23) Ratepayers' portions would be subject to carrying charges at the pre-tax authorized rate of return. (24) Any remaining net lost revenues would be deferred for future recovery subject to carrying charges calculated at the authorized pre-tax rate of return. -13- CASE 05-E-0934, et al. replace the POP Program and continue until the second phase ("Enhanced Powerful Opportunities" or "EPOP") is operational. In both phases, the low-income program will be directly administered and managed by the Company. Program funding will be $1.148 million, $1.32 million, $1.50 million, for each of the three rate years, respectively. Unless adjusted by Commission order, the funding will continue at $1.5 million per rate year thereafter. Differences between the funding level and actual expenditures during a rate year will be deferred.(25) If such differences are due to over-expenditures, the deferral will be limited to no more than 15% of the rate year funding level. If such differences are due to under-expenditures, the remaining balance will be used in subsequent rate years for low-income program expenditures. Design, implementation and other program issues for the Enhanced Powerful Opportunities Program will be established through a collaborative effort among the Company and other interested parties. This effort will begin not later than 10 days after Commission action on the Joint Proposal. Working with this collaborative, the Company will complete its development of a detailed EPOP program proposal within 45 days of the Commission's action on this Joint Proposal. The resulting proposal will be submitted for Commission approval and, once approved, would be completely implemented no later than September 1, 2007. The interim program will replace the existing low-income program as soon as reasonably feasible, so that there is no lapse in the availability of a low-income program. Customer Service Quality Performance Mechanism The current Customer Service Quality Performance mechanism will remain in effect through December 31, 2006. A new Customer Service Quality Performance mechanism will become effective on January 1, 2007. A maximum, potential adjustment - ---------- (25) The deferred amounts would be subject to carrying charges calculated at the authorized pre-tax rate of return. -14- CASE 05-E-0934, et al. of 25 basis points, to be calculated on a combined electric and gas basis, will be incurred if the specified service quality targets are not met. Gas Safety Gas Safety targets and rate adjustment levels will continue at their present levels. The targets will be changed for and after calendar year 2008 and will remain at those levels until changed by the Commission. All gas safety target metrics will be calculated on a calendar year basis. The targets and rate adjustments apply to leak management, prevention of excavation damages, and emergency response. Additional targets will be established for expenditures that enhance the gas infrastructure, namely, the replacement of gas cast iron and steel pipe. The target for such expenditures will be set at $15.75 million over the three rate years, but not less than $4.5 million in each calendar year. If actual expenditures fall short of the target level by the end of 2009, Central Hudson would defer, for ratepayer benefit, the amount of the shortfall multiplied by 1.5 times the average authorized pre-tax rate of return.(26) This deferral would be the sole remedy against the Company for failure to fully expend the forecast level for replacement of certain cast iron and steel mains and services.(27) There are also reporting and record keeping requirements related to the gas safety mechanisms and targets. Electric Reliability Effective January 1, 2006, the target for the Customer Average Interruption Duration Index (CAIDI) will be 2.50, and the target for the System Average Interruption Frequency Index (SAIFI) will be 1.45 for each calendar year. A rate adjustment of 10 basis points (electric) will be assessed against Central - ---------- (26) Commencing on January 1, 2010 such deferral will be subject to carrying charges calculated at the authorized pre-tax rate of return. (27) See Section XIV.E(1). -15- CASE 05-E-0934, et al. Hudson for each failure to satisfy an annual target threshold. Certain events, such as "major storm" outages or catastrophic events, would be excluded from the indices' calculation. In addition to the SAIFI and CAIDI targets, reliability-oriented targets for significant construction projects would be established. They include rate adjustments for failure to: complete 100 circuit miles of enhanced distribution line clearing during each respective rate year (5 basis points per rate year); complete and energize the proposed East Kingston substation by June 30, 2007 (5 basis points, electric); and complete reliability-related construction projects in calendar years 2007 and 2008, respectively(28) (5 basis points per calendar year). The Company will pursue withdrawal of its rehearing petition concerning electric reliability. The Joint Proposal also recommends a 37.5 basis point penalty for not meeting reliability target thresholds in 2002 and 2004 and would allow the Company to reverse the 2005 reliability penalty. The proposed rates support a workforce of 855 employees and allow Central Hudson to hire additional line mechanics. Staff and the Company will meet quarterly to discuss reliability, and employee levels and utilization, and the Company will file compliance reports concerning the electric reliability targets. The reliability performance mechanism will remain in place until the Commission adopts a subsequent approach. Meter Reading and Billing Studies A study of the costs and benefits of converting from bi-monthly meter reading and billing to monthly meter reading and billing would be developed by the Company and filed for Commission approval. It will identify the costs associated with the conversion to monthly metering and billing and the net - ---------- (28) Such projects will be identified by Staff from among the electric reliability-related projects identified in the Company's updated capital forecasts. -16- CASE 05-E-0934, et al. revenue requirements effects, and include an implementation plan. An Automated Meter Reading (AMR) Pilot would be developed by the Company and filed for Commission approval. It will include 5000 meters and be funded from unused amounts that were set aside for such purposes. Total costs will be capped at $1.5 million. Retail Access The existing Market Match, Market Expo, ESCO Ombudsman, and ESCO Referral programs would continue, as would the Competition Awareness and Understanding Survey. In addition, one or two annual Energy Fairs would be conducted by Central Hudson, in collaboration with Staff and ESCOs, prior to the winter heating season. Finally, a Competition Education Campaign, aimed at promoting customer migration, would be funded at $350,000 per rate year.(29) PARTY COMMENTS ON JOINT PROPOSAL Statements in Support(30) Central Hudson Central Hudson states that the Joint Proposal is a comprehensive three-year rate plan that implements the Commission's policy objectives, provides much needed rate relief, and proposes a rational outcome for these proceedings. Central Hudson argues that the Joint Proposal should be adopted as presented because it satisfies the Commission's criteria for proposed settlements.(31) With respect to the requirement for consistency with law and policy, Central Hudson asserts that the Joint Proposal - ---------- (29) Actual expenditure shortfalls below the $350,000 rate allowance will be deferred for expenditure on the same purposes in future rate years. (30) Statements in Support were marked for identification as Exhibits ("Ex.") 63 (Multiple Intervenors), 65 (Central Hudson), and 66 (Staff) and are summarized below. (31) Ex. 65 at 2. -17- CASE 05-E-0934, et al. provides just and reasonable rates that are based on extensively investigated costs and found to be justified by the proponents. Central Hudson notes that the settlement negotiations commenced after parties had engaged in extensive discovery and filed their evidentiary cases, and that discovery continued through negotiations. The Company contends that, as a result, parties were fully aware of the revenues and costs used to develop the proposed rates.(32) The Company states that its cost elements increased in virtually every area of its operations since the last time rates were increased. The Company notes there have been significant negative rate allowances for pension and other post-retirement benefit (OPEB) costs, which are no longer appropriate, and therefore have been updated, consistent with applicable Commission policy.(33) The Company observes that rate increases were moderated using the book depreciation reserve in excess of the theoretical reserve, while still preserving the previously established rate base. The Company continues that gas rate moderation was achieved by reducing the size of the first year rate increase and deferring the amortization of those assets to the beginning of the second rate year.(34) The Company reports that electric and gas delivery rates are fully unbundled, consistent with Commission policies.(35) Central Hudson argues that the Joint Proposal compares favorably with the probable outcome of litigation and strikes a reasonable balance among the parties' competing evidentiary positions.(36) The Company asserts that the Joint Proposal favors consumers. It states that the allowed 9.6% rate of return on common equity is at the lower end of a zone of reasonableness, - ---------- (32) Ex. 65 at 3-4. (33) Ex. 65 at 4. (34) Ex. 65 at 4-5. (35) Ex. 65 at 5. (36) Ex. 65 at 6-7. -18- CASE 05-E-0934, et al. and is offset to a degree by the earnings sharing provisions. Central Hudson argues that its ability to attain any return above 9.6% requires it to achieve efficiencies in its operations. It adds that the opportunity for a return above 10.6% is restricted by the earnings sharing provisions and by a limitation on future deferrals. According to the Company, these provisions, coupled with the proposed rates and other provisions, favor consumers' interests.(37) The Company adds that the Joint Proposal precludes it from improving earnings by deferring capital expenditures or electric transmission ROW vegetation management programs because under-expenditures are subject to requirements that the Company defer, for ratepayer benefit, 150% of the revenue requirement equivalent of any shortfall over the three-year term.(38) According to Central Hudson, the rate increases should be viewed in the context of recent rate decisions that have created a pent-up need for increased rates and the amount of inflation since Central Hudson's delivery rates were last increased. Central Hudson states that its delivery rates have not increased in more than 12 years for electric service, and 15 years for natural gas, and that its low electric rates, since 1993, have "saved customers hundreds of millions of dollars compared to the state average."(39) In support of the proposed rate increases, Central Hudson states that, over the last ten years, customers' use of electricity and natural gas has risen by 20% and 27%, respectively; the percent of residential customers with air conditioning increased from 52% in 1993 to more than 85% by 2005; average household electricity use increased by 15 percent from 1993 to today; and since 1993, the consumer price index has risen by 39 percent, raising the costs associated with providing service. Meanwhile, Central Hudson contends that its employee levels (net of the former power plants) declined by nearly - ---------- (37) Ex. 65 at 7-8. (38) Ex. 65 at 8. (39) Ex. 65 at 8-9. -19- CASE 05-E-0934, et al. 25 percent since 1993, while the number of electric and gas customers increased by 11% (30,000) and 17% (9,900), respectively. The Company claims that this represents an average productivity trend of 4% per year and a customer to employee ratio of 425 to one, placing Central Hudson in the top quartile among utilities nation-wide.(40) Central Hudson also highlights its customer service, pointing to its tree trimming programs' 33% reduction in the number of customers experiencing storm outages between 2002 and 2004; its infrastructure improvements that avoided outages to more than 28,000 customers per year; and its positive customer surveys in which overall customer satisfaction rose from 90.2 percent to 95.1 percent from 1998 to 2004.(41) The Company also asserts that the Joint Proposal has support from generally adverse parties, including Staff, Multiple Intervenors, and DOD. In addition, it reports that the proposed Low-Income Program reflects CPB and PULP's active participation. Finally, Central Hudson argues these proceedings provided an adequate record basis for the Commission to render a rationally based decision.(42) Staff Staff asserts that the Joint Proposal should be adopted because it satisfies the established criteria for judging the reasonableness of settlements. Staff notes that a diverse group of parties support the Joint Proposal, including Multiple Intervenors and DOD.(43) Staff states that the rate increases are necessary to meet escalating pension and OPEB costs and other inevitable cost increases. To mitigate the increases, it notes that various rate design and rate phase-in mechanisms were devised to alleviate the rate shock that would otherwise occur. Staff - ---------- (40) Ex. 65 at 9-10. (41) Ex. 65 at 10. (42) Ex. 65 at 11. (43) Ex. 66 at 8. -20- CASE 05-E-0934, et al. continues that the three-year plan provides certainty on the magnitude and timing of the increases, so consumers can effectively plan their energy usage and so the Company can provide safe and adequate service. According to Staff, the time between rate filings permits Central Hudson to reduce costs and increase efficiencies, which will benefit ratepayers who share in the resulting higher earnings.(44) Staff contends the record adequately justifies adoption of the Joint Proposal's terms. It states that financial terms are derived from Central Hudson's original testimony and from discovery. Staff asserts that parties had ample opportunity to review the Company's support and to conduct extensive discovery. Staff contends that the Joint Proposal's appendices demonstrate a detailed agreement as to the costs and revenues underlying the proposed base rates.(45) Staff observes that the proposed, successive electric rate increases are moderated and phased-in. Staff contends that the income statements demonstrate that the increase in revenue requirement is constrained, in part, by providing for a reasonable, but modest, ROE.(46) Staff states that gas rates will increase but the rate plan provides for moderation and for no increase in the third rate year, both of which benefit customers.(47) Staff states that the rate increases are admittedly sizable, but inevitable - mainly due to pension and OPEB obligations, which cannot be escaped, and to preserving safe and reliable service, which requires expenditures. Staff notes that a downturn in financial markets required the Company to make substantial contributions to pension and OPEB plans, a trend that is expected to continue. Staff states that rates must be adjusted to recognize not only this fact, but the corresponding fact that earnings from pension and OPEB plans are no longer - ---------- (44) Ex. 66 at 8-9. (45) Ex. 66 at 9-10. (46) Ex. 66 at 12. (47) Ex. 66 at 13-14. -21- CASE 05-E-0934, et al. available as a rate offset. Staff points to its appendices to demonstrate that these expenses account for 55% of the electric increase and 47% of the gas increase, plus another 32% of the gas rate increase for recovery of prior pension and OPEB expense deferrals. Staff continues that reliability expenditures and other mandated costs amount to another 20% of the electric increase and 8% of the gas increase. According to Staff, the overall impact of such expenditures, 75% of the electric increase and 87% of the gas increase, constitute the bulk of the rate increase.(48) Staff asserts that the bill impacts were constrained so that a typical residential electric customer using 500 kWh per month will see a 5.4% bill impact in rate year one, 5.0% in rate year two, and 4.6% in rate year three, while a typical residential annual heating gas customer will see bill impacts of 6.36% in the first rate year and 5.17% in the second rate year. Staff argues that the proposed bill impacts are acceptable because the underlying rates have been structured to satisfy obligations for pension/OPEBs and safety and reliability, and to avoid hidden costs that would force rate increases at the end of the three-year plan.(49) Staff contends that the proposed electric rate design accords with Commission policy on hedging electric commodity costs by precluding new hedges for Central Hudson's larger commercial and industrial customers who experience real-time commodity prices and by recovering residential customers' hedging through the commodity rate.(50) Staff notes that the Joint Proposal does not provide for a fixed price option for gas or electric service, but asserts that requiring a utility-provided fixed price option runs counter to Commission Policy and, thus, is no reason to - ---------- (48) Ex. 66 at 14-16. (49) Ex. 66 at 16-17. (50) Ex. 66 at 17-18. -22- CASE 05-E-0934, et al. withhold approval. Citing to a July 2005 Order,(51) Staff observes its statement that a then-existing Central Hudson fixed price option for gas service distorts the market, acts as a barrier against ESCO entry and is an obstacle to innovation.(52) Staff notes that the new gas balancing program rectifies the current situation under which Central Hudson was the only large local gas delivery company in New York without daily balancing procedures for its largest customer.(53) Staff asserts that providing daily and monthly gas balancing for larger customers and resolving other outstanding gas balancing issues is consistent with Commission orders.(54) Specifically, Staff argues that with the implementation of the proposed balancing and cashout provisions, obsolete provisions in Central Hudson's tariff will be eliminated and imbalances will be properly priced, thus sending the correct price signals and encouraging accurate arrangements for commodity delivery. Staff also asserts that the proposed changes will enhance reliability and minimize deviations between proposed use and actual deliveries. Staff claims that daily and monthly balancing rates have been revised to avoid cross-subsidizations that might exist under the present system. Finally, Staff contends that added opportunity to trade imbalances will allow customers to avoid potential imbalance penalties during times when Central Hudson's overall system is largely balanced.(55) Staff asserts that the Joint Proposal's resolution of the complex and contentious dispute between Central Hudson and USMA over rates for gas delivery service to West Point is one of its major benefits. Staff notes that in addition to arriving at - ---------- (51) Case 05-G-0311, Small Customer Marketer Coalition, Order Directing the Future Termination, Subject to Conditions, of a Fixed-Price Offer (issued July 22, 2005) (July 2005 Order). (52) Ex. 66 at 19. (53) Ex. 66 at 20. (54) Ex. 66 at 20-21. (55) Ex. 66 at 21-22. -23- CASE 05-E-0934, et al. cost-based rates for service to USMA, expensive and time-consuming litigation in front of the Armed Services Contract Board of Appeals, and over possible appeals from its initial decision, is averted.(56) Staff observes that the Joint Proposal provides for further rate unbundling that conforms with Commission policies. Specifically, Staff notes that existing backout credits are replaced with MFCs that are cost-based and are set at tiered levels to recognize the cost differentials for supplying commodity to ESCO customers within and without Central Hudson's Purchase of Receivables (POR) program. Staff asserts that establishing and coordinating MFCs and POR program expenses and charges this way complies with the recent policy developments and would have been difficult to achieve in a litigated proceeding.(57) Staff states the Joint Proposal resolves a highly contentious dispute regarding the proper calculation of electric and gas depreciation, and the size of excess electric depreciation reserve. In addition, Staff notes that the contents and analyses required of a depreciation study to be filed in subsequent proceedings are established, thus eliminating potential, future dispute.(58) Staff argues that the provision to offset certain deferrals against Central Hudson's share of any over-earnings is "of particular importance" because it protects ratepayers by establishing a sharing mechanism that kicks in if Central Hudson accumulates significant deferrals in its favor and also over-earns. Staff argues that the recommended earnings sharing also conforms with numerous other similar rate plan provisions the Commission has adopted and that its allocation of benefits and risks is appropriate.(59) - ---------- (56) Ex. 66 at 22-23. (57) Ex. 66 at 23-24. (58) Ex. 66 at 25-26. (59) Ex. 66 at 27. -24- CASE 05-E-0934, et al. Staff asserts that the allowed 9.6% return is reasonable, noting that it reflects several relevant updates, and is below that adopted in other recent rate plans.(60) Staff notes that the rates provide funds to build a substation, expand electric transmission ROW maintenance efforts, and replace gas cast iron and bare steel pipe. Staff observes that such costs can no longer be offset, as in the past, by the Benefit Fund, which has been depleted, and are required, in part, by new Commission guidelines on ROW maintenance. Staff observes that any shortfalls in these expenditure levels are deferred for ratepayer benefit, thus encouraging Central Hudson to make the expenditures necessary to preserve electric system reliability and gas system safety.(61) With respect to low-income programs, Staff notes that the Joint Proposal provides for rapid implementation of an interim program that will rectify the most serious deficiencies in Central Hudson's existing program and for an enhanced program that is based on elements which represent the Commission's most recent thinking on appropriate low-income program policies. According to Staff, the enhanced program will carefully target assistance to the customers most able to benefit from that assistance, and tailor the amount of the assistance to meet the particular needs of a participating household. Staff notes that program funding will be increased from $1.148 million in Rate Year 1, to $1.32 million in Rate Year 2, and $1.50 million in Rate Year 3, and that any unspent amounts will be deferred for low-income program use in subsequent years.(62) Staff notes that the electric reliability mechanism has been the source of considerable controversy. Staff states that the previous rate order, in recognition of plans to install a new Outage Management System (OMS), allowed Central Hudson to request appropriate adjustment of electric reliability indices if it could show the introduction of OMS affected the - ---------- (60) Ex. 66 at 28. (61) Ex. 66 at 29-33. (62) Ex. 66 at 34-35. -25- CASE 05-E-0934, et al. calculation of the reliability indices. Staff also notes that, following implementation of OMS, Central Hudson had difficulty in meeting the SAIFI and CAIDI reliability indices, which ultimately resulted in contested reliability adjustments. Staff states that the Joint Proposal reasonably resolves these issues by providing that the 2001 Commission rate decision will remain in effect and by requiring the preservation of the 2002 and 2004 adjustments but excusing the 2005 adjustment.(63) Staff observes that the Joint Proposal provides for several studies on improving billing and metering that might benefit Central Hudson's customers, including an AMR Pilot Program. Staff says the pilot will allow Central Hudson to gain experience with AMR technology and learn more about the cost and benefits of installing this type of metering, but will not impact bills as the program would be funded from unused competitive metering funds and excess electric depreciation reserve.(64) Staff asserts that the Joint Proposal's Retail Access provisions advance the Commission's policies for creating competitive opportunities in retail energy markets, while giving Central Hudson clear direction on the best practices for furthering such policies.(65) Multiple Intervenors Multiple Intervenors state that the proposed rate increases apparently cannot be avoided in this proceeding. First, they note that Central Hudson's annual expense related to pensions and OPEBs has increased substantially over the amounts contained in the current electric and gas rate plan. Second, Multiple Intervenors note the need for Central Hudson to undertake certain investments in its electric and gas systems in order to maintain and improve reliability. Finally, they - ---------- (63) Ex. 66 at 37-40. (64) Ex. 66 at 40-41. (65) Ex. 66 at 41. -26- CASE 05-E-0934, et al. observe that a material portion of the rate increases relate to programs mandated by the Commission.(66) One of the primary reasons cited by Multiple Intervenors for their support of the Joint Proposal is the considerable effort that was made to moderate the rate increases to the maximum extent practicable. They argue that the negotiated electric and gas rate moderation is beneficial to customers and in the public interest.(67) Another factor highlighted by Multiple Intervenors is that the Joint Proposal has been drafted in a manner that should allow it to continue after the proposed three-year term without requiring immediate, material rate increases. Multiple Intervenors also cite to the resolution of electric revenue and service classifications 3 and 13 rate design issues as a critical component, stating that the allocations are consistent with the best available cost of service evidence. They conclude that the provisions should be adopted, along with the constraints proposed by the settling parties. Multiple Intervenors argue that the constraints on the revenue allocation are appropriate in this instance because the rate increases are substantial and, if unconstrained, would result in unacceptable customer impacts. They add that the cost of service evidence does not indicate the need for major shifts in revenue responsibility.(68) Multiple Intervenors support the proposed rate design for service classifications 3 and 13, stating that it reflects: (i) cost-based monthly customer charges; (ii) recovery of the residual revenue requirement through per kW demand charges; and (iii) the elimination of per kWh energy charges. They argue that, in this circumstance, energy charges are inappropriate because almost all of Central Hudson's delivery-related costs - ---------- (66) Ex. 63 at 2-3. (67) Ex. 63 at 3. (68) Ex. 63 at 4. -27- CASE 05-E-0934, et al. are fixed in nature and should not vary based on energy consumption.(69) Multiple Intervenors also note their express support for the resolution of gas transportation balancing issues. They argue that the Commission should accord substantial weight to the fact that numerous parties with diverse interests were able to resolve a number of very complicated gas balancing issues, including, but not limited to: (i) the appropriate monthly balancing thresholds and rates for large transportation customers; (ii) the appropriate daily balancing thresholds and rates for large transportation customers; (iii) the transition period for the implementation of daily balancing service; (iv) the rules governing the cash-outs of imbalances; and (v) the rules regarding how imbalances, and imbalance penalties, are calculated. They assert that the proposed revenue allocation is reasonable and consistent with the cost of service evidence. Multiple Intervenors urge consideration of the fact that the Joint Proposal is an integrated agreement and the moderation of the electric and gas rate increases, electric revenue allocation, service classification 3 and 13 electric rate design, gas balancing provisions affecting large transportation customers, and gas revenue allocation are critically important and inextricably linked to their decision to execute and support the proposal.(70) - ---------- (69) Ex. 63 at 5. (70) Ex. 63 at 5-6 -28- CASE 05-E-0934, et al. Statements in Opposition(71) CPB CPB opposes the Joint Proposal, claiming it does not satisfy the Commission's settlement guidelines and requires improvement to properly benefit customers. First, CPB recommends that the residential and small commercial customers be allowed to purchase electric and gas commodity service from the Company at a fixed price.(72) Though recognizing that the July 2005 Order directed Central Hudson to terminate its gas fixed price option, CPB argues that the order is not binding because the basis upon which the Commission acted, namely that retail competition would be inhibited if utilities offered fixed price options, is not supported by the current retail market in Central Hudson's service territory. CPB claims that ESCOs generally have not met consumers' interest in fixed price offerings, despite the absence of utility-provided fixed price options.(73) CPB also claims that Commission policy offers the flexibility to pursue utility-provided fixed price options where, as here, the retail market has not met customers' needs. CPB contends there is a compelling need to provide utility fixed price options to consumers so that they have an additional tool to manage their energy bills.(74) CPB expresses concern that the Joint Proposal devotes inadequate resources to outreach and education on high energy prices. CPB notes that $350,000 will be spent annually on a Competition Education Campaign, but the Joint Proposal is silent on the outreach and education to be conducted for purposes other - ---------- (71) Statements in Opposition were marked as Exhibits 61 (SCMC/RESA), 62 (Select Energy), and 64 (PULP) and are summarized below. CPB submitted its opposition as direct testimony (Tr. 698-775), however, in response to Central Hudson's motion to strike (Tr. 792-795), CPB agreed to redact and submit portions of its opposition as Exhibit 102 (Tr. 1614-1617). (72) Tr. 713. (73) Tr. 718-720. (74) Tr. 720-721. -29- CASE 05-E-0934, et al. than retail competition. CPB recommends that customers be provided information on the cause of high energy prices, actions they can take to manage their energy bills, and how to obtain bill payment assistance, and that $175,000 of the amount earmarked for the Competition Education Campaign be redirected therefor.(75) CPB recognizes that the electricity and gas delivery rate increases are necessary and appropriate, but it asserts that the Joint Proposal overstates revenue requirements and does not balance the Company's and customers' interests. CPB recommends modifications to the construction expenditures, ROW maintenance expenditures, the discount rate used in pension and OPEB expense projections, the automated meter reading program, outreach and education expenses, the structure of the Company's pension plan, retail access expenditures, the treatment of certain customer money set aside for metering purposes, and the excess depreciation reserve surplus. CPB contends that its modifications would not affect the Company's earnings but would benefit customers. CPB also recommends modifications that would affect the Company's earnings, including reductions to storm expense, MGP remediation expense and the allowed return on equity.(76) With respect to capital expenditures, CPB claims they would increase by 27.6% in the 18-month period between 2005 and the 2006 rate year and far exceed any party's recommendations. CPB recommends that capital expenditures be projected at the average of the expenditures made in the last four years adjusted for twice the overall inflation level since 2005.(77) Concerning ROW maintenance expenses, CPB claims there is substantial uncertainty regarding the level of such expenditures and ratepayers are not protected if actual spending is less than projected. CPB also claims that cost savings or other benefits expected to result from such expenditures are not - ---------- (75) Tr. 721-723. (76) Tr. 723-724. (77) Tr. 725-730. -30- CASE 05-E-0934, et al. reflected and it doubts that a 107% increase in annual spending is needed at this time. CPB also notes that, unlike transmission ROW expenditures, there is no shortfall protection for distribution ROW maintenance expenditures. CPB asserts that shortfall protection is needed for expenses that account for 78.4% of total ROW maintenance expenditures. CPB recommends that the ROW maintenance expenditures be revised downward by $3 million each rate year, to reflect recent historical spending levels, and that the Company provide ratepayer protection if actual distribution ROW maintenance expenditures fall short of the rate allowances. If the Company makes ROW maintenance expenditures beyond the amount that CPB advocates, it recommends deferral accounting for such amounts, with any requests to recover such deferrals accompanied by a comprehensive report explaining the need for the expenditures.(78) CPB also takes issue with the projected storm expense. While recognizing that the projections were derived from a four-year average of historical expenditures (adjusted for inflation), CPB claims that, given the substantial increases in ROW maintenance expenditures, all else being equal, storm expense should continue to decline. It therefore recommends that projected storm expense be reduced $2 million, to reflect the average of such expenditures beginning in 2004.(79) With respect to MGP remediation costs, CPB asserts that the Company should be responsible for a portion of the associated program expenses. CPB states that where, as here, the utility is embarking on a program involving many projects and significant cost, there is a compelling need to constrain rates and to encourage cost minimization. CPB therefore recommends that the Company absorb 10% of such costs, and cites to previous PSC orders as support for both cost sharing and deferral limitations.(80) - ---------- (78) Tr. 730-737. (79) Tr. 737-738. (80) Tr. 738-742 -31- CASE 05-E-0934, et al. CPB notes that the proposed rates use a 5.5% discount rate for pension and OPEB obligations. It asserts that a 5.5% discount rate likely overstates pension/OPEB expense and therefore should be increased to 5.75% for this Company. CPB asserts this recommendation is fair to the Company and reduces the revenue requirement by more than $1 million per year.(81) CPB also takes issue with the allowed cost of equity. Specifically, it disagrees with the removal of the CH Energy Group from the proxy group and with changing the weighting between the traditional and zero-beta CAPM methods from 75/25 to 50/50. Finally, CPB disagrees with a 38 basis point stay-out premium. CPB states that the methods developed in the Generic Finance Proceeding indicate that the return should be reduced.(82) CPB acknowledges that pension and OPEB expense is one of the main drivers of the rate increases. It notes that Central Hudson continues to offer a defined benefit pension plan to its management and executive employees, subject to certain eligibility requirements. CPB asserts that defined benefit pension plans are more expensive and that many employers have replaced them or have begun to transition away from them. CPB is concerned that if the Company follows other large employers and transitions away from a defined benefit pension plan, it will retain all associated savings. CPB therefore recommends that the Joint Proposal be modified to provide ratepayers two-thirds of any savings from transitioning away from the current defined pension plan. CPB asserts that this approach is fair to the Company because it provides a financial incentive to pursue cost reductions and also is fair to the ratepayers who would share in the cost savings.(83) CPB notes that funds reserved for metering initiatives will be kept and preserved for that purpose. CPB instead recommends the amount (approximately $466,000) be used to mitigate bills. CPB notes that it has been two and one-half - ---------- (81) Tr. 742-744. (82) Tr. 744-747. (83) Tr. 748-750. -32- CASE 05-E-0934, et al. years since the Commission originally established the funds, and no reasonable metering proposal has been advanced in that time. It therefore asserts that the funds are better used to mitigate increases.(84) CPB also opposes the AMR Pilot Program, stating that no party proposed such a program in their initial testimony. CPB contends that the magnitude of the proposed delivery rate increases and the high energy costs that currently exist argue against its implementation at this time. CPB claims that the program is not needed to provide safe and reliable service. It also claims that ratepayers would be required to pay its costs but the Company retains any resulting cost savings. CPB also asserts that this program may be inconsistent with the Commission's competitive metering agenda. Accordingly, CPB recommends that the pilot program be eliminated and any associated funds be used to mitigate the rate increases.(85) CPB also takes issue with a provision that would allow the Company to reverse a ratepayer credit established when the Company failed to meet 2005 electric reliability targets. CPB claims that this result would not occur in a litigated proceeding and could reduce future incentives for utilities' compliance with regulatory standards and targets.(86) CPB also opposes several retail access provisions, including the Market Match Program, Market Expo, Energy Fairs, ESCO satisfaction mechanism, ESCO ombudsman, competition awareness and understanding survey, the Competition Education Campaign, and the ESCO referral program. It claims that, with the exception of the Competition Education Campaign, the program costs are not quantified. With respect to the ESCO Referral Program, CPB asserts that there is an apparent lack of participation in the program and a failure to meet the requirement that at least two ESCOs participate. CPB asserts the revenue requirement impact of these provisions should be - ---------- (84) Tr. 750-755. (85) Tr. 756-757. (86) Tr. 757-758. -33- CASE 05-E-0934, et al. stated and the retail access provisions should be reduced by $100,000 each year.(87) With respect to the $350,000 earmarked for the Competition Education Program, CPB asserts that there is no demonstration that previous retail access related outreach and education efforts have been cost effective. As a result of this omission and coupled with the alleged lack of ESCO interest in the ESCO Referral program, CPB recommends that the ratepayers fund no more than $175,000 annually for retail competition outreach and education programs.(88) CPB also recommends that the any funds remaining in the electric depreciation reserve account be used to further moderate the proposed rate increases and the amortization of large and unusual losses that Central Hudson incurred in 2001 and 2002 on its retirement plan assets be extended. CPB asserts that both these proposals are fair to the company, in that they do not affect the company's earnings, and to ratepayers, in that they represent a better use of ratepayer money.(89) PULP PULP opposes the Joint Proposal for failing to include utility-sponsored fixed price options and for an alleged improper use of ratepayer funds to promote private energy service company interests. Observing that the July 2005 Order precludes Central Hudson from continuing to offer a fixed price option, PULP advocates an end to this prohibition. PULP contends that the fixed price option from the Company is preferred by residential customers and is highly valuable to low-income customers. Further, PULP asserts the discontinuance of this option was not necessary to support Commission policy, and reinstitution will not frustrate Commission policy. Consequently, PULP urges that - ---------- (87) Tr. 758-762. (88) Tr. 762-765. (89) Tr. 766-767. -34- CASE 05-E-0934, et al. the fixed price option be reinstated in time for the 2006-2007 heating season. PULP also argues that ratepayer funds should not be used to promote retail access. According to PULP, it is unnecessary, and, in the context of the increases proposed here, unjustifiable. PULP states that, if such expenditures are allowed, they should be funded by energy service companies.(90) Select Energy Select Energy opposes the balancing, cash-out and delivery proposals for service classifications 6, 12, and 13. It asserts that the method for monthly cashouts involves significant estimation and does not guarantee improvement over the current method. It claims that, because ESCOs are relying on the accuracy of such calculations, a monthly cashout program based on actual meter reads is preferable. Select Energy further contends that there are inequities between the proposed cashout index points for under-and over-deliveries in winter months. Specifically, it argues that the proposed under-delivery cashout "defaults to the worst case scenario instead of actual costs" and imposes costs on ESCOs that the Company may not have incurred. Select Energy states that Central Hudson only includes actual costs in its monthly supply costs and it should be required to do the same when assessing charges to ESCOs. Select Energy asserts that the cashout proposal incorrectly assumes that customers have a 100% thermal response every month. It claims that the accuracy of the cashout proposal can be improved by implementing "Monthly Thermal Response Adjustment Factors" to account for a typical heating customer's response to heating degree days. It states that the implementation of such an approach should be delayed until appropriate studies can be performed. Select Energy also opposes the incremental delivery requirement. Select Energy contends it is inequitable and - ---------- (90) Ex. 64 at 2-3. -35- CASE 05-E-0934, et al. discriminatory because the same requirements do not apply to sales customers and the incremental deliveries are used to balance Central Hudson's system without regard to actual usage. It also states that the requirement is unpredictable and nearly impossible for marketers to recover from customers. At a minimum, Select Energy argues that Central Hudson should be required to provide a quantitative analysis of when incremental deliveries required and a justification why individual marketers are required to makeup system shortfalls (typically during periods of maximum prices) without any regard for their actual consumption. Select Energy states that since ESCOs already pay for Storage Space, Storage Service, and Peaking Service that are used to balance the system on peak days, ESCOs should not be required to deliver incremental supply.(91) SCMC/RESA SCMC/RESA take issue with the proposed hedging provision, alleging that it is at odds with Commission policy, acts to hinder competition and is inherently illogical.(92) SCMC/RESA assert that the impact of existing or legacy hedges is reflected in the PPA, a rate design component that is charged on an equivalent basis to full service and retail access customers. SCMC/RESA state that this practice will be maintained for the legacy hedges, but all new hedges for small customers entered into after June 30, 2006 would be reflected in the Market Price Charge mechanism, a commodity charge that will be applied only to utility commodity sales customers. SCMC/RESA assert that this proposed rate design change is inequitable, anticompetitive and unreasonable, and should not be implemented. SCMC/RESA urge the Commission to ensure that the reflection of utility hedging activity in rates is consistent with the utility's regulated monopoly advantages and is equitable to ESCOs and retail access customers. SCMC/RESA claim that the proposal to flow hedging costs through the Market Price - ---------- (91) Ex. 62. (92) Ex. 61 at 4. -36- CASE 05-E-0934, et al. Charge ignores the utility's overwhelming competitive advantage, as well as the fact that retail access customers, through their delivery rates, help sustain and fund utility hedging procurement activity. SCMC/RESA claim that the utilities competitive advantage with respect to hedging was recognized and discussed by the Commission in connection with Central Hudson's fixed price option for gas.(93) SCMC/RESA assert that, if the Commission allows the Company to reflect the cost of hedging practices in the commodity portion of the rate, it will reinforce the utility's market dominance and undermine the development of workable competitive playing field.(94) SCMC/RESA further claim that retail customers, through their delivery rates, support and enable the utility to engage in hedging. SCMC/RESA conclude that, given this reality, it is unjust and unreasonable to direct that the impact associated with hedging procurement activities solely to full service customers by the commodity charge rate mechanism. Finally, SCMC/RESA assert that if the Commission adopts the hedging provision and directs Central Hudson to reflect the impact of hedging activities only through the commodity charge, it will be difficult to achieve the eventual withdrawal of utilities from the business of hedging.(95) Post-Hearing Briefs Central Hudson Central Hudson asserts that applicable requirements for a proposed settlement are fully satisfied here and that the opposition warrants no alteration. Central Hudson compares this proposal with recent rate plans for Consolidated Edison Company of New York, Inc. (Con Ed) and National Fuel Gas Corporation (NFG), and finds that the proposed revenue requirements, return on equity, equity ratio and earnings sharing provisions provide - ---------- (93) Ex. 61 at 5-9. (94) Ex. 61 at 10-11. (95) Ex. 61 at 11-15. -37- CASE 05-E-0934, et al. its customers with comparable, if not superior, benefits and protections.(96) With respect to the specific modifications suggested by the opponents, the Company first counters CPB and PULP's proposed fixed price offering. The Company asserts that CPB and PULP should not be allowed to collaterally attack the July 2005 Order directing the termination of its fixed price offering. Given the Commission requirement that proposed settlements conform to law and policy, the August 25, 2004 directive that "utilities should not propose fixed rate commodity tariffs" in future rate proceedings, and the specific directive of the July 2005 order, Central Hudson insists that the Joint Proposal correctly excluded a fixed price offer.(97) The Company further insists that CPB and PULP's assertions about customer preferences for utility fixed price offers are unsubstantiated and lack empirical evidence demonstrating market failure. According to the Company, the Joint Proposal allows the market to function; altering it to require fixed price offerings by the Company would severely wound the competitive market.(98) The Company contests CPB's recommendation to reduce capital expenditures, stating that CPB has not proposed specific quantitative levels. The Company also argues that the CPB formula for setting a revised level of capital expenditures is arbitrary because it is divorced from any assessment of need. The Company asserts that the proposed expenditure levels were carefully and thoroughly reviewed by Staff and Company engineers and revised upward to include additional funds for necessary gas infrastructure enhancements.(99) Central Hudson argues against CPB's proposal to true-up distribution ROW maintenance expenditures. The Company - ---------- (96) Central Hudson Post-Hearing Brief, Revised June 5, 2006 at 2-7. (97) Central Hudson Post-Hearing Brief at 7-8. (98) Central Hudson Post-Hearing Brief at 7, 10. (99) Central Hudson Post-Hearing Brief at 10-12. -38- CASE 05-E-0934, et al. asserts that the scope of the program has not changed and history shows it expended more than was allowed in rates. The Company further argues that CPB's analysis erroneously excluded the enhanced tree trimming costs which undercuts its premise for a true-up mechanism. Finally, the Company contends that the reliability penalties already address the possibility that ratepayers could be short-changed by any underspending.(100) The Company considers CPB's adjustment to storm expenditures an attempt to cast aside the time proven methodology. It says that CPB's testimony on this issue is varied and internally inconsistent. The Company urges rejection of CPB's proposal for MGP and SIR costs, stating that it is inconsistent with applicable policy. It also urges the rejection of CPB's discount rate for pension and OPEB expenses, noting that the support provided is CPB's initial brief in a currently ongoing NYSEG case in which the Company (NYSEG) and Staff agreed to the same 5.5% discount rate proposed here.(101) Central Hudson asserts that CPB's proposal to decrease an already low ROE is unreasonable. It claims that CPB failed to update its own recommendations, and that, given CPB's concession that Con Ed and Central Hudson face the same risks, it is promoting discrimination by advocating a lower ROE for Central Hudson (8.84%) than it previously supported for Con Ed (10.3%). The Company continues that CPB misapplies the Generic Finance Case principles related to stay-out premiums.(102) Central Hudson claims that in the event of future pension plan revisions, certain cost differentials would be captured and available for future disposition by the Commission. It therefore concludes that CPB's proposal regarding supposed cost savings from a change in the current pension plan is inconsistent with the Commission Policy Statement and is premature. - ---------- (100) Central Hudson Post-Hearing Brief at 14-17. (101) Central Hudson Post-Hearing Brief at 18-21. (102) Central Hudson Post-Hearing Brief at 22-25. -39- CASE 05-E-0934, et al. Central Hudson claims that CPB's objections to the proposed metering pilot lack foundation because no funds have been actually committed to it and it would proceed only if ultimately approved by the Commission. The Company discounts CPB's opposition to the reversal of the 2005 electric reliability penalty, stating CPB failed to recognize the provision in context with other interrelated provisions.(103) Central Hudson claims that CPB and PULP's challenges and proposed modifications to the retail access provisions lack justification and evidentiary support, and are inconsistent with Commission policy. The Company continues that the levels of these expenditures are addressed by the proposed deferral mechanisms.(104) Central Hudson asserts that CPB's proposals for additional rate mitigation ignore the nature of excess reserve and the increased risk of future, possibly major rate increases that could flow from a decision to deplete the excess reserve. The Company also claims that CPB's proposal to extend the amortization of pension losses contradicts applicable policies.(105) Central Hudson asserts that SCMC/RESA's understanding of the current treatment of legacy hedges is inaccurate, noting that while Constellation hedges are flowed through the PPA, Entergy hedges are flowed through the Market Price Charge to electric commodity sales customers only. Thus, Central Hudson denies that the proposal to flow post-June 30, 2006 hedges through the Market Price Charge to electric commodity sales customers is a rate design change or is inequitable, anticompetitive or unreasonable. Instead, the Company asserts that the proposed treatment accords with Commission policy articulated in the Retail Energy Markets Policy Statement and warrants no alteration.(106) - ---------- (103) Central Hudson Post-Hearing Brief at 25-27. (104) Central Hudson Post-Hearing Brief at 27-30. (105) Central Hudson Post-Hearing Brief at 30-32. (106) Central Hudson Post-Hearing Brief at 32-33. -40- CASE 05-E-0934, et al. Finally, with respect to the proposed gas balancing provisions, Central Hudson again argues that no alteration is warranted because the proposed formula prevents gaming and is similar to provisions included in the NFG rate plan.(107) Staff Staff urges rejection of the opponents' positions and adoption of the proposal without modification. Staff claims that CPB's modifications should be rejected because they would fundamentally alter the proposal's balancing of ratepayers and shareholders interests, and are premised on misunderstandings and misstatements. Staff insists that the available choice is between the proposed rate plan and a litigated one-year rate determination. Staff contends that CPB's approach would lead to the latter result and asserts that CPB has not demonstrated that its one-year rate determination is superior to the Joint Proposal. Staff asserts that, if CPB's approach prevails, many of the proposed plan's benefits, including promotion of retail access policies, rate unbundling, inauguration of gas balancing and cash-out procedures, a new low-income program that reflects best available practices, spending necessary to ensure safe and reliable service, and resolution of a complex dispute between Central Hudson and USMA, would be lost, replaced by a series of litigated one-year rate proceedings where substantial rate increases would still be needed. Staff argues that since the proposed plan funds all reasonably expected costs and leaves no hidden costs, it could continue beyond its term, extending the time ratepayers and the Company would realize the benefits of stable rates.(108) With respect to specific items, Staff asserts that CPB's and PULP's arguments on a tariffed fixed-price option raise issues that were recently decided and are beyond the scope of these proceedings. Staff adds that reinstituting a fixed - ---------- (107) Central Hudson Post-Hearing Brief at 32. (108) Staff Post-hearing Brief, dated May 12, 2006 at 2-6. -41- CASE 05-E-0934, et al. price offer is short-sighted and would engender long-term harm to consumers, especially low-income customers.(109) Staff further contends that CPB and PULP have not undermined the reasons for terminating Central Hudson's fixed price option. Staff notes that Central Hudson's fixed price option was subsidized by other customers, rendering its design unjust and unreasonable. Staff also notes that the fixed price option distorted and retarded the development of the retail market to customers' disadvantage. Staff claims that CPB and PULP have not refuted the July 2005 Order's analysis of these points. Staff asserts that there is no demonstrated need or established design parameters for a utility fixed price option. Staff notes that fewer than 2,000 customers (less than 3% of the customer base) subscribed to Central Hudson's 2002-03 fixed price option, and, even at its peak, it attracted fewer than 10,000 of Central Hudson's gas customers (less than 15% of its total eligible customer base). Staff notes CPB's acknowledgment that the fixed price option price could exceed standard tariff rates. Staff further states that, if prices have stabilized, reinstituting a fixed price option is an unnecessary response to a problem that no longer exists. Staff further suggests that, as has happened in the past, interest in the fixed price option would quickly evaporate when prices cease rising.(110) Staff argues that CPB and PULP's proposed fixed price option is insufficiently detailed and cannot be successfully implemented. Staff asserts that CPB's position that the fixed price option cannot be subsidized and cannot allow for any utility profit ensures that it will be unworkable or unduly expensive. Staff asserts it is unworkable, in part, because, its proponents acknowledge that the hedging required to offer the option creates volume and price risk, but fail to explain how such risk would be treated.(111) - ---------- (109) Staff Post-hearing Brief at 2, 7. (110) Staff Post-hearing Brief at 8-10. (111) Staff Post-hearing Brief at 10-12. -42- CASE 05-E-0934, et al. Staff also contends that the detrimental impacts that could result in the likely event of a fixed price option price substantially exceeding the standard tariff price are ignored. Staff also argues that CPB and PULP have not meaningfully challenged the impact of a utility-provided fixed price option on competitive markets, even though they were identified and discussed in the July 2005 Order. Staff claims that instead of addressing such impacts, CPB and PULP make unfounded criticisms that the competitive market has failed to respond adequately. Staff says their criticisms are belied by the fact that ESCOs offered fixed price options and nearly 25% of customers availed themselves of such opportunities. Staff asserts that the competitive marketplace can tailor offerings that better meet consumers' needs at reasonable prices, but only if CPB and PULP's proposal is rejected.(112) With respect to CPB's opposition to the proposed levels of safety, reliability and environmental spending, Staff states that CPB erroneously claims that the proposed capital expenditures exceed the levels proposed by any party. Staff responds that the capital expenditures are taken directly from the Company's evidentiary presentation, and are increased by $1.2 million for additional gas reliability expenditures and adjusted to reflect the increasing amounts Central Hudson has actually spent in recent years.(113) Staff also argues that CPB misses important connections between the capital budget spending and forecasts of utility activity (e.g., between one-third and one-half of gas capital expenditures for Rate Years 1 through 3 are dedicated to the facilities needed to extend service to new customers). Staff, like the Company, asserts that CPB has not connected its proposed expenditures to levels needed to preserve safe and reliable service. Staff asserts that as a result of these and other errors, CPB's proposal is unreasonable. - ---------- (112) Staff Post-hearing Brief at 12-15. (113) Staff Post-hearing Brief at 16-17. -43- CASE 05-E-0934, et al. Staff asserts that similar errors afflict CPB's ROW and storm cost analyses. Staff claims that CPB excludes distribution ROW expense expenditures that were funded through the Benefit Fund and disregards the most recent data on storm costs. Staff claims that CPB's arguments regarding the treatment of MGP remediation expense are incorrect, noting that, contrary to CPB's assertions, the existing approach to MGP expense and the related requirements of prior orders would continue. Staff also argues that CPB, in its effort to shift some MGP expense to Central Hudson, overlooks binding orders and instead points to outmoded precedents that do not favor a clean environment. Staff argues that CPB's deferral proposals are factually inaccurate and reflect a misunderstanding of the Joint Proposal's capital budget and ROW expense deferral-based incentive mechanisms. Staff explains that under the proposed rate plan, if Central Hudson fails to achieve a targeted level of capital expenditure or transmission ROW expense, the difference is deferred for ratepayer benefit. Staff contends that, since these expenditures are needed to preserve safe and adequate service and since electric reliability at Central Hudson has fallen below acceptable levels in recent years, every effort should be made to encourage the utility to actually expend those funds. Staff claims that CPB's proposed substitute, which would allow Central Hudson to defer capital and ROW expenditures that exceed CPB's targets, might actually discourage improved reliability because the expenditure levels CPB proposes are insufficient and Central Hudson might not see an incentive sufficient to warrant the expenditure of funds that exceed the inadequate allowances.(114) Staff asserts that it has fully justified moving from its initial 8.65% ROE position to the proposed 9.6% ROE. Staff explains that Central Hudson's parent, CH Energy Group, Inc., was removed from the proxy group of companies considered - ---------- (114) Staff Post-hearing Brief at 17-20. -44- CASE 05-E-0934, et al. comparable to Central Hudson because it yielded uncharacteristically low returns in comparison to the other utility companies in the proxy group. Staff states that the 8 basis point adjustment revised the weighting of the zero beta CAPM calculation in the overall ROE determination from 25%/75% to 50%/50%, which it notes is within the range of previously-accepted weightings. Staff argues that its stay-out premium is reasonable and that CPB's arguments to the contrary rely upon a misunderstanding of the Generic Finance Case methodology, which is not binding in any event. Staff asserts that the difference in the yield between one-year and three-year U.S. Treasury Securities is sufficient to support its risk adjustment for a three-year plan. Moreover, Staff argues that this three-year plan is eligible for a stay-out premium because its prices are set and not updated, and the Generic Finance Case methodology provides an approach to calculating the stay-out premium that yields 38 basis points.(115) Staff urges rejection of CPB's arguments concerning pension and OPEBs. Staff asserts that updating the discount rate now would be superfluous since the rate will be updated when a new actuarial report is filed in January 2007. Staff adds that an earlier update would be immaterial in the context of the overall expense.(116) As to the length of the deferral period, Staff claims that extending it conflicts with the Pension and OPEB Statement and Order,(117) and might also result in inter-generational inequities. In response to CPB and PULP's claims that retail access expenditures are excessive, Staff insists such spending has been constrained to the levels that are necessary to - ---------- (115) Staff Post-hearing Brief at 22-24. (116) Staff Post-hearing Brief at 25. (117) Case 91-M-0890, Accounting and Ratemaking Treatment for Pensions and Post-Retirement Benefits Other Than Pensions (OPEB), Order and Statement of Policy Concerning Pension and Other Post-Employment Benefits (issued September 7, 1993). -45- CASE 05-E-0934, et al. implement Commission policies. Responding to CPB's claim that the expenditures related to the ESCO Referral Program are questionable because the program has not yet commenced operations, Staff asserts that the program has been successfully launched, and that initial indications are that it will achieve its intended objectives. In addition, Staff notes that the Commission has repeatedly expressed its support for ESCO referral programs and rejected all objections to their implementation only six months ago.(118) Staff asserts that CPB's arguments against the proposed metering were rejected in the 2004 Rate Plan Order. Staff contends that the proposed metering initiative is a reasonable use of funds reserved therefor and is in conformance with the prior rate orders.(119) As to CPB's opposition to excusing Central Hudson from making the 2005 reliability adjustment, Staff reiterates that both the 2001 and 2004 Rate Plan Orders authorize Central Hudson to excuse a failure to satisfy reliability targets if it could show that its OMS introduction was at the root of its compliance failures. Staff notes that Central Hudson repeatedly maintained that installation of the OMS system adversely affected its ability to meet reliability targets in 2005, 2004 and 2002 and has complied with the prior orders. Staff contends that the Joint Proposal also complies with the prior orders because it provides for payment of the 2004 and 2002 rate adjustments, and excuses only the 2005 adjustment.(120) Staff notes that, in order to further mitigate the proposed electric rate increases, CPB would entirely deplete the remaining $20 million of excess depreciation reserve. Staff argues that CPB incorrectly presumes $20 million would reduce the electric rate increases by approximately $6 million each - ---------- (118) Case 05-M-0858, State-Wide Energy Services Company Referral Programs, Order Adopting ESCO Referral Program Guidelines and Approving an ESCO Referral Program Subject to Modifications (issued December 22, 2005). (119) Staff Post-hearing Brief at 26-28. (120) Staff Post-hearing Brief at 28-30. -46- CASE 05-E-0934, et al. rate year. Staff asserts that in order for CPB to achieve the reductions it apparently intends, about $36 million in rate moderators would be required. Staff also claims that the associated rate decreases would be of minimal benefit. Staff concludes that the excess electric depreciation reserve balance is best retained to offset future deferrals that are difficult to forecast.(121) Staff asserts that SCMC/RESA's position that Central Hudson should recover the hedging costs for its smaller customers' supply through delivery rates, rather than commodity rates contravenes applicable policy and would dilute the hedge's value. Staff notes that SCMC/RESA misunderstand the current treatment of existing hedges. It states that only the Constellation hedge, a legacy of the divestiture of Central Hudson's generation plant, is recovered from all ratepayers, while the existing Entergy hedge, entered into after divestiture and unrelated to it, is recovered only from commodity customers, in conformance with the 2004 Rate Plan Order.(122) With respect to Select Energy's position that use of Central Hudson's actual gas costs for pricing purposes would be preferable to the use of an index for pricing under-deliveries during the winter, Staff notes that winter under-deliveries can threaten system reliability. Staff asserts that use of an index to determine the pricing for under-deliveries results in setting that price at the marginal cost of additional gas supply. Staff continues that marginal cost pricing is the appropriate reference point because if additional supplies were suddenly needed, the price charged would be at marginal cost rather than at the utility's average cost. Staff states that Select Energy's proposed gas balancing mechanism response adjustment factors disregard of the difficulties that may attend the calculation, billing and implementation of such factors. Staff asserts that the development and consideration of appropriate factors for Central - ---------- (121) Staff Post-hearing Brief at 31. (122) Staff Post-hearing Brief at 31-32. -47- CASE 05-E-0934, et al. Hudson should wait for a time following successful implementation of the proposed gas balancing procedures. In response to Select Energy's opposition to the incremental delivery requirement, Staff says that the requirement is essential to preserving system reliability and the suggested alternative won't work given current metering.(123) Multiple Intervenors Asserting that the Joint Proposal represents an integrated whole, reflecting numerous compromises by parties with diverse and often adverse interests, Multiple Intervenors reiterates it should be adopted without modification. With respect to the proposed electric revenue allocation and rate design, Multiple Intervenors asserts that the testimony and exhibits of Dr. Rosenberg support those provisions. They argue that, based on their witness' testimony, as well as that proffered on revenue allocation and rate design issues by Central Hudson and Staff, the provisions addressing those issues are reasonable and well within the range of likely litigated outcomes. Multiple Intervenor observe that none of the opponents challenged the electric revenue allocation and service classification 3 and 13 rate design and concludes that those provisions should be evaluated as negotiated, uncontested provisions with ample record support. DOD DOD reiterates its request for adoption of the Joint Proposal, asserting that it provides a reasonable resolution of these proceedings. DOD argues that, in addition to resolving numerous and complex issues in these rate cases, the Joint Proposal addresses many details regarding the provision of gas transportation for USMA at West Point and use of the USMA gas distribution system for service to Central Hudson's customers in Highland Falls, New York. DOD asserts that the provisions relating to USMA are just and reasonable and should provide a - ---------- (123) Staff Post-hearing Brief at 32-35. -48- CASE 05-E-0934, et al. constructive and stable basis for the provision of gas to USMA and other affected customers. DOD notes that there is no opposition concerning these provisions.(124) CPB CPB asserts that these proceedings provide an opportunity to address the impact of near-record high commodity prices and the largest delivery percentage rate increases to be proposed for any major energy utility in more than a decade. CPB argues that the Joint Proposal as presented does not satisfactorily address the impact of higher commodity prices, does not provide for measures that would properly respond to today's circumstances, and does not adequately reflect consumer interests. It continues that it does not satisfy the Commission's Settlement Guidelines, nor question whether policies and practices that may have been common before are appropriate now. CPB states the proposal contains some positive elements, like the phase-in of rate increases, the low-income program and the exclusion of the retail access incentive, but overall, is not in consumers' interest.(125) CPB alleges that the Joint Proposal has not earned the support of normally adverse parties, particularly CPB and PULP. It discounts the support of Multiple Intervenors, claiming it is due exclusively to the resolution of electric revenue allocation, electric rate design, and gas balancing and revenue allocation issues. It also discounts DOD's support, contending it is due only to the resolution of disputes regarding service to one customer.(126) CPB argues that the context for this proposal must be carefully considered. It urges consideration of policies it says deny customers the opportunity to purchase commodity from the utility at fixed prices, enable the utility to retain ratepayer funds for unspecified purposes and unspecified periods - ---------- (124) DOD's letter in lieu of brief, dated May 12, 2006. (125) CPB Post-hearing Brief, dated May 12, 2006 at 1, 5-6. (126) CPB Post-hearing Brief at 2-4. -49- CASE 05-E-0934, et al. of time, require ratepayers to fund projects that are not necessary for safe and reliable service and permit unreasonably large increases in certain expense categories that are inappropriate at this time. CPB argues for focusing on the overall increases in delivery rates, not the impact on total bills.(127) CPB denies implications that its position in these proceedings is contrary to the position it took in a case involving Con Ed, stating that it did not support that proposal either and, as here, submitted a statement to help identify and explain the pro-consumer provisions. CPB asserts that its panel testimony acknowledges that consideration should be given to the fact that Central Hudson's base delivery rates have not increased in many years, but it also clearly explains that the benefit of past rate freezes cannot properly be considered as a benefit of this proposal and that the presence of some pro-consumer provisions does not mean that overall, the public interest is satisfied. CPB asserts that it has demonstrated consumers need new tools to help them manage high and volatile energy prices, including a fixed price option from the utility and reliable information from the utility on the reasons for high prices, conservation, and the availability of assistance programs, neither of which, absent any record basis, is provided.(128) In response to Company and Staff assertions that (1) the Commission directed Central Hudson to terminate its fixed price option and (2) this issue cannot be relitigated in this proceeding, CPB asserts that New York State Public Service Law and relevant New York State case law indicate that there is no legal prohibition against considering fixed price proposals in this proceeding. As a threshold matter, CPB states that Company and Staff failed to recognize that the July 2005 Order applies only to gas and that no such order applies to an electricity fixed - ---------- (127) CPB Post-hearing Brief at 4. (128) CPB Post-hearing Brief at 6. -50- CASE 05-E-0934, et al. price option offered by Central Hudson. CPB adds that the issue of whether adequate electric service by Central Hudson requires offering a fixed price option for electricity has not been litigated before the Commission.(129) CPB also points out that applicable rules expressly provide that "[t]he rates, rules and regulations relating thereto that are in effect when the proceeding is initiated will not be presumed to be just and reasonable." It therefore contends that when Central Hudson filed its rate case, all of its rates, rules and regulations became open to reconsideration. CPB asserts that, by the Company's logic, the SCMC/RESA Petition should never have been considered because the issue had already been determined in a previous order. CPB states that the Commission, as a policy making entity, always has the discretion to examine and modify rate policies as it sees fit, a fact that its regulations for rate cases make explicitly clear.(130) CPB also argues that attempts to bar its fixed price option testimony through collateral estoppel must fail because (1) the collateral estoppel doctrine can only be utilized by a party after establishing that the issue in the present proceeding is identical to that necessarily decided in a prior proceeding, and that in the prior proceeding the party against whom preclusion is sought was accorded a full and fair opportunity to contest the issue and (2) it usually is not applied unless the administrative decision was quasi-judicial in character and thus is not applied when an agency acts in a ratemaking capacity. CPB argues that the July 2005 Order constituted ratemaking and therefore can not be granted preclusive effect. CPB further asserts that in administrative proceedings, the proponent, in this case Central Hudson, bears the burden of identifying the issues as identical, and that burden was not met here.(131) - ---------- (129) CPB Post-hearing Brief at 7. (130) CPB Post-hearing Brief at 8. (131) CPB Post-hearing Brief at 7-11. -51- CASE 05-E-0934, et al. CPB counters Company and Staff assertions that the record does not support the adoption of its proposal by citing a recent study's finding that consumers without substantial financial assets decrease spending on items such as food by 40 cents for each unanticipated dollar increase in their home energy bill. CPB cites to its panel testimony for evidence that the availability of a reasonably priced fixed price option would provide a valuable tool to help avoid this scenario. CPB acknowledges that a utility fixed price option will not necessarily decrease bills but maintains it is a tool that should be available to help consumers manage volatile energy bills. CPB asserts that it demonstrated that ESCO fixed price options are not reasonably priced and that ESCO products that are so-identified may in fact permit the ESCO to increase the price without recourse by the customer. CPB continues that of the 8,504 customers who subscribed to Central Hudson's gas fixed price option when it was terminated on October 1, 2005, only 21% had chosen ESCO service six months later. According to CPB, this record evidence demonstrates that the vast majority of fixed price customers in Central Hudson's territory would rather pay the utility's variable price than take service from an ESCO.(132) CPB also claims to have demonstrated that its proposal is consistent with the Commission's orders on retail competition. It asserts that, since the competitive market has not responded adequately and Central Hudson can be distinguished from other utilities, the Commission has new facts and circumstances to consider in evaluating utility fixed price options. CPB adds that, contrary to Staff assertions, there is no Commission directive against utilities offering fixed price products.(133) - ---------- (132) CPB Post-hearing Brief at 12-13. (133) CPB Post-hearing Brief at 13. CPB cites to the NYSEG and RG&E FPO offerings and to Case 00-M-0504 (Statement on Policy on Further Steps Toward Competition in Retail Energy Markets (issued August 25, 2004), page 3) to support its assertions. -52- CASE 05-E-0934, et al. CPB reiterates that consumers should be provided accurate and timely information on the cause of high energy prices, actions they can take to manage their energy bills, and how to obtain assistance in paying their bills. CPB argues that the fact that CPB and Staff played key roles in delivering such information to consumers this past winter, demonstrates that such information can be delivered to consumers without interfering with the Commission's competitive agenda.(134) In response to proponents' claims that using electric reserve depreciation to further mitigate the proposed rate increases would set the stage for rate increases after the funds expire, CPB insists there is no better use for such funds. CPB further claims that the two potential uses for this surplus that are set forth in the Joint Proposal either should not be conducted at this time (i.e., the AMR pilot) or are minimal (i.e., covering cost of electric backout credits).(135) CPB states that, in the current environment of high energy prices and a proposed series of large delivery rate increases, the Commission should carefully consider the appropriateness of funding any projects - like the AMR pilot, retail access programs, and the Competition Education Campaign. CPB claims that its testimony in this regard was not challenged on cross examination.(136) CPB claims the Company's recent capital spending trends belie Staff and Company claims that spending increases are necessary for safe and reliable service, particularly since the Company's electric system earnings exceeded the sharing thresholds in the years 2001-2005. CPB states that even though it now understands that the Joint Proposal reflects a projected increase of $5.571 million (126%) in annual ROW maintenance spending beyond 2005 levels (about 2% less than the Company's request in initial testimony), it remains concerned that an increase of this - ---------- (134) CPB Post-hearing Brief at 13-14. (135) CPB Post-hearing Brief at 15-16. (136) CPB Post-hearing Brief at 16-20. -53- CASE 05-E-0934, et al. magnitude may not be necessary, may not be spent in a cost effective manner, or may not be spent at all. It therefore adheres to its ROW recommendations. CPB contends that its proposed measures are necessitated by the magnitude of the projected spending (even under its proposal), and by the high degree of uncertainty concerning the appropriate level of such spending. CPB notes, that in 2005, the Company chose to spend less on ROW maintenance than it had in any year since before 2000, even though it had excess earnings and failed to meet minimum reliability standards in 3 of the last 4 years. It also highlights Staff testimony that there is no disadvantage to proposed shortfall mechanism. With respect to storm expense, CPB adds to its previous arguments its assertion that the proponents failed to meet their burden to demonstrate that the reasonableness of the proposed costs.(137) In response to the proponents' challenge to its position regarding the reversal of the 2005 reliability penalty, CPB responds that that it is unlikely that the Commission would have reversed its order regarding the 2002 and 2004 penalty, but the Joint Proposal guarantees that the Company could avoid any consequences for its failure to meet applicable 2005 standards. CPB reiterates that shareholders should bear some portion of the MGP costs. It reasons that ratepayers were not responsible for the Company incurring those costs; the expenses at issue are extremely large; it is important to constrain rates; and the Company should be provided an incentive to seek recovery of these expenditures from other responsible parties. CPB also claims that no party challenged its proposal on cross examination.(138) With respect to changing the pension and OPEBs discount rate to 5.75%, CPB claims that, unlike the Company, it used the most recent data available to calculate its recommended rate. CPB also counters the proponents' assertion that large - ---------- (137) CPB Post-hearing Brief at 24-25. (138) CPB Post-hearing Brief at 26-27. -54- CASE 05-E-0934, et al. pension and OPEB expenses are inevitable with its claim that the Joint Proposal does nothing to prevent such a situation from recurring. CPB claims despite the trend away from defined benefit plans, if the Company transitions away from defined benefit pension plans in the next three years as expected, the Joint Proposal would allow it to retain all associated savings. CPB asserts that its proposal to capture any such savings is consistent with the outcome in competitive markets, is fair to the Company and would help reduce the likelihood that Central Hudson will request another large rate increase based primarily on the need to fund employee pensions. With respect to ROE, CPB clarifies that, with the exclusion of the adjustments to account for interest rate changes or to reflect 2005 as the starting point for calculating the stock valuation adjustment, the proposed adjustments should not be adopted. It maintains that use of Generic Finance Methodologies results in a cost of equity of approximately 8.95% for Central Hudson. Specifically, CPB claims that removal of CH Energy Group from the proxy group is atypical, was not made in the Generic Finance case, and both Central Hudson and Staff included CH Energy Group in their proxy groups in this proceeding. CPB adds that changing the weighting of the Traditional and Zero-Beta Capital Asset Pricing Model ("CAPM") from 75/25 to 50/50 is contrary to the approach taken in the Generic Finance case, which has been used in most cases approved by the Commission. Finally, CPB asserts that a stayout premium is inappropriate here because the revenue requirement calculations under the Joint Proposal are essentially equivalent to three one-year rate cases, which would not get a premium under the Generic Finance Case methodology. CPB asserts that the record establishes that removing the results of Consolidated Edison and two other companies from Central Hudson's DCF estimate in these circumstances, as the Company did, was completely arbitrary and served no other purpose but to inflate the Company's estimates. Finally, with respect to possible further rate increase mitigation, CPB reiterates its claims that extending -55- CASE 05-E-0934, et al. the amortization of large and unusual losses incurred by Central Hudson in 2001 and 2002 on its retirement plan assets for an additional 10 years is within the Commission's authority and should be considered if additional rate mitigation is appropriate.(139) PULP In its post-hearing brief, PULP reaffirms its opposition to the Joint Proposal, citing the absence of a fixed price option and the proposed retail access expenditures. At the outset, PULP argues that the motion, made by the Company and supported by Staff, to remove the fixed price option proposal was unjustified and untimely. PULP asserts that, even if the motion could be justified, it should have been made when the proposal was first advanced in CPB's November 2005 testimony. PULP adds that even if the "surprise" motion had been timely, it would have failed because (1) the CPB and PULP proposal is to establish fixed price options for gas and electric service, while the July 2005 Order and the underlying petition addressed gas only and (2) the information provided here in support of the fixed price offer proposal is information which was unavailable to the Commission at the time of its July 2005 decision.(140) PULP argues that this record establishes several reasons why the decision in to terminate the fixed price option should be evaluated anew. PULP cites a discovery response provided by Central Hudson which reports that over 8,500 customers were purchasing gas under its fixed price option in October 2005.(141) PULP notes that under the then-applicable Central Hudson tariff, customers could only receive such service if they affirmatively sought it prior to the heating season. PULP thus concludes that thousands of customers demonstrated in - ---------- (139) CPB Post-hearing Brief at 27-33. (140) PULP Post-hearing Brief, dated May 12, 2006 at 3, n. 3. (141) PULP Post-hearing Brief at 4, citing Ex. 67, Sch. 2. -56- CASE 05-E-0934, et al. the clearest possible way that they wished to receive gas service from Central Hudson under a fixed price option.(142) PULP argues that unrefuted data shows that after the discontinuance of the fixed price option, over 6700 of the 8500 customers who had been taking the Central Hudson fixed price offer continued as Central Hudson customers. PULP thus concludes that even when their preference is eliminated, these customers choose not to move to an ESCO supplier. PULP contends that renewal of the offer of a fixed price option from Central Hudson will provide these customers with "what they want - a fixed price option from their chosen supplier - Central Hudson." PULP claims that refusal to provide a fixed price option from Central Hudson is a market failure. PULP further asserts that the continued unavailability of a fixed price option from Central Hudson is not necessary to implement a Commission policy. PULP claims that since customer migration after the elimination of the fixed price option from Central Hudson did not materially increase the number of customers taking commodity service from ESCOs, its reinstitution will not materially reduce the number of customers who may switch to ESCOs. PULP also argues that, at the time of the July 2005 Order, the Commission believed that seven or more ESCOs would be making fixed price offers to residential customers in the Central Hudson service territory, and that, as of May 2, 2006, actual numbers were far less than the Commission anticipated in July. PULP asserts that this reason alone should warrant reconsideration of these issues.(143) PULP adds that the record now shows that the fixed price offers that are available to residential consumers do not actually provide a fixed price. It asserts that the purpose of a fixed price offer is to shift the risk of commodity price fluctuation from the customer to the commodity supplier. PULP claims that the contracts used by the four ESCOs identified as - ---------- (142) PULP Post-hearing Brief at 4. (143) PULP Post-hearing Brief at 5-6. -57- CASE 05-E-0934, et al. providing a fixed price offer to residential gas customers provide the ESCO with one or more escapes.(144) PULP claims that there is no indication that the Commission was aware in July 2005 of these types commitments and, had it known of them, it could not have concluded that the ESCO's fixed price offers were comparable to the Central Hudson's. PULP concludes that, with the information now in this record, reestablishing the Central Hudson fixed price offer as soon as possible is fully justified.(145) PULP, like CPB, refers to an April 2005 research paper concerning the harmful effects that volatile energy prices can have for low-income households to argue that record in this case now shows that the absence of a fixed price offer for residential customers is particularly harmful to Central Hudson's low income customers.(146) PULP states that the April 2005 paper analyzes data over a 12 year period from more than 50,000 households and shows that, for most customers, a sharp rise in energy costs will be met from savings or by lengthening their credit card or other credit accounts. PULP states that low income customers, however, cannot respond to sharp rises in energy costs in this way, so they will meet the energy cost crisis by reducing consumption of other necessities. PULP argues that for these customers, a fixed price offers some assurance that volatile energy bills will not become a source of life threatening instability. PULP contends that since this research had not been made available last July, it also represents new information that warrants reconsideration of the availability of utility fixed price options.(147) - ---------- (144) PULP Post-hearing Brief at 7. PULP states that the four ESCOs making a fixed price gas offer to the Central Hudson residential customers were and are Intelligent Energy, Interstate Gas Supply, MXenergy, and Energetix, while the one ESCO providing a fixed price electricity offer was and is Accent Energy. (145) PULP Post-hearing Brief at 8-10. (146) PULP Post-hearing Brief at 11. (147) PULP Post-hearing Brief at 11-12. -58- CASE 05-E-0934, et al. With respect to the Joint Proposal's proposed funding for retail access programs, PULP observes that support for retail access will increase from $250,000 per year to $350,000 per year. PULP notes that previous such expenditures were funded from a Benefit Fund and, as such, did not directly impact rates. Now that the Benefit Fund has been exhausted, PULP concludes that these expenditures now will have a direct impact in raising customer rates and bills. PULP contends that when revenue requirements are rising at double digit rates and both gas and electric customers will see dramatic price increases, the continued and increased expenditure of ratepayer funds cannot be justified.(148) PULP argues that the Market Match and Market Expo programs, Energy Fairs, ESCO/Marketer Satisfaction Survey, ESCO ombudsman and Competition Outreach and Education Program, individually, and as a group, are intended solely to give ESCOs better access to customers or to ease or facilitate their participation in the service territory. PULP adds that there is no indication that any of these programs have a material effect on residential customers' migration to ESCO service. PULP contends that these programs have been operating at least since July 2004, but as of November 2005, less than 800 residential customers had migrated to ESCO service. PULP further contends that, while the number of migrating customers increased to just over 5200 in March 2006, this corresponds to the dramatic increase in energy prices over this past winter, and not to these programs. PULP states that, in the absence of easily obtainable data showing actual bill impacts of ESCO service as compared to utility service, it must be assumed that residential customers have not benefited significantly, or at all, from their decision to take ESCO service. PULP thus concludes that use of ratepayer funds to promote retail access cannot be justified.(149) - ---------- (148) PULP Post-hearing Brief at 12-13. (149) PULP Post-hearing Brief at 13-15. -59- CASE 05-E-0934, et al. PULP claims that, as a new program, the overall effectiveness of the Energy Switch program cannot be adequately judged. PULP adds, however, that what can be determined is that its costs are excessive. PULP calculates that, under this program, a minimum of $1750 is spent per day, to recruit, on average, 5 customers per day for ESCO service (or $350 per switched customer). PULP states that the savings for these customers is limited in this program to 7% of the Central Hudson bill for two months, which it calculates would be $18.55 and $11.06 per month for typical gas and electric non-heating customers, respectively. PULP concludes that any money spent by Central Hudson in support of the residential retail access program should be recovered from the ESCOs participating in that program and that any ratepayer funds supporting the retail access programs should be removed and corresponding reductions made to revenue requirement and rates.(150) SCMC/RESA SCMC/RESA respond to the CPB and PULP's assertions that a utility-sponsored fixed price option should be reintroduced by claiming it is unnecessary, unreasonable and inconsistent with established Commission policy. SCMC/RESA cite to the Commission's Statement of Policy governing the implementation of competition in retail markets, specifically its requirement that " ... in future rate proceedings, utilities should not propose fixed rate commodity tariffs or tariffs creating a profit center for commodity sales."(151) SCMC/RESA argue that the Commission has repeatedly underscored the position that ESCOs rather than regulated utilities should be providing fixed price service. SCMC/RESA declare that the assertion that a fixed price option is needed as a "bulwark" against rising energy cost - ---------- (150) PULP Post-hearing Brief at 15-16. (151) SCMC/RESA Post-hearing Memorandum at 4, citing Policy Statement at 40. -60- CASE 05-E-0934, et al. is simplistic and unrealistic.(152) SCMC/RESA assert that historic data does not support the view that a fixed price option will better shield customers from the impact of rising energy prices than variable rates. SCMC/RESA cite as an example, the existing NYSEG's rate plan, claiming that NYSEG's variable rate has generally been lower than its fixed price option. SCMC/RESA expressly counter the CPB and PULP claim that the levels of migration show a preference for a utility-sponsored fixed price option, stating that the numbers could just as easy represent a conscious choice by customers to accept pricing variation instead of the higher costs associated with a fixed price option. SCMC/RESA contend that the Joint Proposal contains recommendations (e.g., a portfolio purchasing strategy, including hedging) that have the potential to moderate swings in supply costs. SCMC/RESA also note the availability of budget billing, as authorized by law, which affords customers the opportunity to pay an equivalent amount each month for energy charges. SCMC/RESA argue that criticism of the ESCOs' fixed price offerings is misguided. SCMC/RESA further assert that ESCOs will respond to market conditions and customers preferences, and will provide products in accordance with the demand therefor.(153) With respect to retail access funding, SCMC/RESA claim that proposals to reduce such expenditures are short-sighted and should be rejected. SCMC/RESA assert that competitive choice should be promoted and aggressively pursued as a means of helping customers deal with fluid energy markets. They add that changing customer habits takes time. They contend that the incremental efforts to date have borne fruit, as evidenced by the migration of 1 million customers (state-wide) to retail access service. - ---------- (152) SCMC/RESA Post-hearing Memorandum at 5-7. (153) SCMC/RESA Post-hearing Memorandum at 7-9. -61- CASE 05-E-0934, et al. With respect to the Staff argument that adopting SCMC/RESA's hedging proposal would dilute the hedge's value and require more purchases to achieve the same pricing level, SCMC/RESA say it is unconvincing. SCMC/RESA assert that maintenance of a certain price range is a function of the actual movement in market prices and, thus, the number of hedges will depend on the movement in market prices. SCMC/RESA continue that since Staff cannot predict how prices may actually move, its argument against the SCMC/RESA proposal is speculative. SCMC/RESA add that on a total bill basis, their proposal would not impair rate stability or require the Company to purchase additional hedges to maintain the same level of overall rate stability. Finally, SCMC/RESA aver that, since ESCO customers help sustain and fund the Company through their delivery rates, it is entirely reasonable and equitable to flow the impact of hedging through the delivery component of rates.(154) DISCUSSION The Joint Proposal in these proceedings is the product of settlement negotiations that were noticed and executed in accordance with our settlement guidelines and rules of procedure. We therefore have evaluated it under our standards for reviewing joint proposals.(155) In general, a joint proposal is reviewed for determination that it achieves a reasonable balance among the protection of the ratepayers, fairness to investors, and the long term viability of the utility; consistency with sound environmental, social and economic policies; and results that are within the range of the likely results of a fully litigated proceeding. Moreover, in judging a joint proposal, the Commission gives weight to the fact that it reflects agreement among normally adversarial parties. We have reviewed the terms of this Joint Proposal in the context of the parties' pre-filed testimony and exhibits, the public comments we have received, the parties' statements (154) SCMC/RESA Post-hearing Memorandum at 9-11. (155) 16 NYCRR 3.9; Opinion No. 92-2, supra. -62- CASE 05-E-0934, et al. and post-hearing briefs, and the testimony and exhibits introduced at the evidentiary hearing held on May 4 and 5, 2006. Based on that review, we find that the terms of the Joint Proposal, as modified herein, will establish just and reasonable rates, terms and conditions and that approval, consistent with the discussion herein, is in the public interest. We note that the Joint Proposal is endorsed by Central Hudson, Staff, Multiple Intervenors and DOD and is opposed by CPB, PULP, SCMC/RESA and Select Energy. CPB and PULP propose the addition and formulation of utility-provided fixed price options and they generally oppose the level of rate increases reflected in the Joint Proposal. Select Energy's and SCMC/RESA's opposition is limited, seeking, respectively, modification of certain gas balancing and hedging provisions. As such, we find that the Joint Proposal reflects a reasonable compromise among ordinarily adversarial parties representing a range of interests. The willingness of disparate parties to endorse the Joint Proposal, particularly, where, as here, it calls for unavoidable rate increases, is a strong indicator that the resultant rate plan satisfactorily addresses a variety of interests. We note, in this regard, that CPB, though opposing the Joint Proposal as presented, acknowledges both the inevitability of rate increases in these proceedings and the fact that the proposal, as presented, contains positive elements. Moreover, we received extensive public criticism of the Company's initial proposed rate increases and our call for public comments on the Joint Proposal elicited similar comments. The bulk of the concerns expressed in the public comments, however, are addressed by the rate and service terms and conditions we are adopting, including, in particular, the enhanced low-income program and the phase-in and moderation of the proposed rate increases. The overall electric and gas revenue increases of $53,033,000 million and $14,060,000 million, respectively, are well within the range of litigation outcomes in these proceedings. The revenue requirements were vigorously -63- CASE 05-E-0934, et al. contested. Central Hudson initially proposed electric and gas revenue increases of approximately $72.1 million and $22.2 million, respectively, over a three-year period. Staff initially proposed a one-year plan with electric and gas revenue increases of approximately $40.4 million and $8.8 million, respectively. Key elements in dispute included, not only the rate plan's term and the level of revenue increases, but also the allowed return on equity, future sales forecasts, depreciation expenses and reserve, rate design issues, the cost and timing of MGP/SIR expenditures, and the proper service quality targets. Moreover, significant disputes were not limited to the Company and Staff, but also included CPB, the Department of Defense and Multiple Intervenors. The dispute between the Company and the Department of Defense was very contentious and complex and concerned service to USMA and use of USMA's gas distribution system for service to Central Hudson's customers in Highland Falls. If left unresolved, it could have caused prolonged uncertainty and confusion regarding Central Hudson's rates and rate design. In its Statement in Support of the Joint Proposal, Staff presents its view of the proposed electric and gas revenue increases. Staff has demonstrated to our satisfaction that the revenue requirement and rate increases are necessary and largely unavoidable. Staff highlights the fact that a significant portion of the proposed increases - 55% of the electric rate increase and 47% of the gas rate increase - are attributable to pension and OPEB expenses;(156) while another 20% of the electric increase and 8% of the gas increase are attributable to expenses that are necessary and, in some cases mandated, to ensure safety and system reliability. The presentations by Central Hudson, DOD and Multiple Intervenors further support our finding that the rate levels proposed under the Joint Proposal are reasonable and necessary and satisfy ratepayer and shareholder interests. - ---------- (156) Indeed, another 32% of the gas increase is due to the recovery of regulatory assets for gas, in part, attributable to prior pension and OPEB deferrals. -64- CASE 05-E-0934, et al. The Company's endorsement of the Joint Proposal supports our finding that the revenue requirement is sufficient for Central Hudson to meet its obligations to the public to operate and maintain a safe and adequate system. As such, we find that the rate levels strike an appropriate balance between customer and Company interests. A portion of electric depreciation reserve has been used to moderate the electric increases. Gas increases are mitigated by deferring and amortizing portions of the gas revenue increases. This addresses, to a degree, concerns regarding the impact of the rate increases on residential customers, particularly those on low and fixed incomes, and on schools and small businesses in the Central Hudson service territory. Those with the least ability to pay will benefit from the enhancement and expansion of the low-income program provided by the Joint Proposal. These elements of the proposal are recognized by opponents and proponents alike as positive elements. The Joint Proposal's revenue allocation and rate design recommendations are consistent with our public policy objectives. Its allocation of the revenue requirement increase reflects a reasonable distribution of the increase across service classifications. The rate design reflects an appropriate balance among competing considerations, including, but not limited to, the avoidance of rate shocks, and furthering our policy for hedging electric commodity costs. The new gas balancing program will provide daily balancing procedures for Central Hudson's largest customers and bring the Company's procedures into conformance with our recent balancing orders. With the implementation of the balancing and cashout provisions, imbalances will be properly priced, thus sending correct price signals to customers and enabling them to accurately arrange for commodity delivery. In addition, reliability should be enhanced as deviations between customers' proposed use and actual deliveries are minimized. The resolution of the complex and contentious dispute between Central Hudson and the USMA ensures cost-based rates for -65- CASE 05-E-0934, et al. service to the USMA and avoids the expense, time and uncertainty associated with the litigation that otherwise would have gone before the Armed Services Contract Board of Appeals. These uncontested provisions are clearly in the public interest. The implementation of further rate unbundling will, in conformance with our Unbundling Policy Statement, replace the existing back-out credits with cost-based Merchant Function Charges. The Merchant Function Charges are priced at tiered levels to recognize the costs attributable to supplying commodity to a customer of an ESCO that participates in Central Hudson's Purchase of Receivables program and the costs for those ESCO customers who are outside the ambit of this program. The portion of the rate increases related to maintaining system reliability and enhancing gas safety is necessary to ensure safe and adequate service. These allowances will be used to build a substation, expand electric transmission ROW maintenance efforts (in conformance with our orders) and replace gas cast iron and bare steel pipe. These improvements will enure directly to the benefit of all customers. The expansion and enhancement of Central Hudson's low-income program addresses concerns regarding the rate increases' impact on low-income customers. The program carefully targets assistance to the customers who can benefit the most and tailors assistance to meet the needs of participating households. Program funding will increase from an initial level of $1.148 million in the first rate year to $1.5 million in third rate year. These uncontested provisions are in the public interest. The Customer Service Quality Satisfaction and Gas Safety service metrics are reasonably designed and intended to encourage the Company to maintain and improve service, safety, and reliability. The Company has incentives to operate efficiently, while passing efficiency benefits along to ratepayers, through the earnings sharing provision. As noted above, the contested elements of the Joint Proposal include the overall level of the rate increases, the absence of utility-sponsored fixed price offerings, and certain -66- CASE 05-E-0934, et al. gas balancing and hedging provisions. We have carefully considered the merits of the opposition, as discussed in detail below. Our analysis leads us to reject most of the parties' proposed modifications. CPB recommends that capital expenditures be reduced to the average of capital expenditures in the last four years adjusted for inflation. CPB also recommends that the Company file a deferral petition to recover any expenditures that exceed the amounts it advocates. Staff and the Company assert that the modification is unnecessary because the Joint Proposal requires the Company to defer, for ratepayer benefit, 150% of the return requirement equivalent of any shortfall in expenditures over the three-year rate term. They argue that this precludes the Company from seeking to improve its earnings by deferring capital expenditures. They add that the CPB's proposed modification ignores the fact that the increased funds are dedicated, in part, to constructing facilities needed to extend service to new customers and to make necessary gas infrastructure enhancements. We recognize the importance of constraining rate increases, but all such efforts must be balanced against the equally important goal of ensuring safe and reliable service. Just and reasonable rates include, in this instance, ensuring that required utility infrastructure improvements are adequately funded. We therefore reject CPB's proposal. The shortfall mechanism goes a long way towards alleviating CPB's concerns as it ensures that the rate allowances approved here will either be spent for the designated purpose or be returned (150%) to ratepayers. CPB recommends that the Joint Proposal be modified to reduce ROW maintenance amounts by $3 million per rate year, with any expenditures over the rate allowance recovered, if at all, by deferral petition. CPB also recommends the addition of shortfall protection with respect to the distribution ROW maintenance amounts. Staff argues that a reduction is unjustified because CPB's calculation excludes expenditures funded through the -67- CASE 05-E-0934, et al. Benefit Fund. The Company adds that CPB's calculation excludes tree-trimming costs. With respect to the deferral mechanism, Staff states that the extension of deferral incentive mechanisms to encompass this expense can have adverse consequences on the Company's incentive to control costs and pursue savings. In light of CPB's acknowledgement of errors made in calculating its proposed reduction, the potential negative impacts associated with the reduction to and imposition of a deferral mechanism for these costs, and the importance of ensuring that funds for safe and reliable service are provided, the CPB's proposals to reduce distribution ROW maintenance amounts and implement a deferral mechanism are rejected. With respect to application of a shortfall mechanism to distribution ROW costs, we do not find Staff's and Central Hudson's arguments persuasive. As CPB notes, distribution ROW maintenance expenditures account for the vast majority (about 78%) of total ROW maintenance expenditures. An incentive to encourage the Company to actually use the amounts as intended makes good sense and is consistent which the previously stated goal of ensuring a more reliable system. Further, we note that, when questioned, Staff conceded "there is no disadvantage" to subjecting the distribution ROW costs to the same true-up mechanism that applies to transmission ROW costs.(157) If the Company operates this routine portion of its business properly, the mechanism will not be triggered as the subject allowance will be fully expended. Under the circumstances presented here, adoption of the CPB-proposed shortfall mechanism provides protection for ratepayers and helps ensure reliability, without harming the Company. Accordingly, we require the rate allowances for distribution ROW costs to be subject to the same shortfall mechanism that applies to the transmission ROW costs. CPB asserts that storm expense should be reduced by $2 million from the level reflected in the Joint Proposal. It claims that expected cost savings and additional revenue will result from a reduction in the number and duration of outages - ---------- (157) Tr. 1601. -68- CASE 05-E-0934, et al. and these benefits will offset some costs. Staff asserts that CPB's analysis disregards the most recent data on storm costs. The Company characterizes the CPB's proposed adjustment as an attempt to cast aside proven methodology and claims that CPB's testimony actually confirms the expense levels are correct. We find that the record supports a level of storm expense that is reasonably based on the four-year average of historical expenditures, adjusted for inflation. Consequently, we are not adopting the CPB proposal. CPB recommends that the Company be required to absorb 10% of MGP/SIR costs. Staff and the Company counter that the CPB recommendation is based on outmoded precedent and does not favor a clean environment. We consider the full recovery of MGP/SIR costs to be a reasonable utility expense. Accordingly, we reject the proposed modification. We note that these proceedings are the first to address and incorporate the deferred and projected MGP/SIR costs into a rate plan. The Joint Proposal provides that the carrying charges applicable to MGP/SIR deferrals should be changed from the unadjusted customer deposit rate, currently 4.75%, to a return that equals Central Hudson's pre-tax rate return, 10.01%.(158) CPB opposes this provision. We, however, approve this proposed change based on our finding that it properly recognizes the long-term nature of the MGP/SIR Program and the difficulty of including current funding in the proposed rates. We note the our approval ensures compensation for Central Hudson at its overall cost of capital for cash expenditures that require financing, without increasing proposed rates. CPB urges us to change the pension and OPEBs discount rate to 5.75%, which it states is supported by recalculating the rate using the most recent data available. CPB also recommends that the Joint Proposal be modified to capture any savings that might result if the Company changes its defined benefit pension - ---------- (158) Central Hudson currently has authorization to defer MGP/SIR related expenditures and to accrue carrying charges on the deferred balance at a rate equal to the unadjusted customer deposit rate. -69- CASE 05-E-0934, et al. plan during the three-year rate term. CPB further recommends extending the deferral period for pension plan losses by an additional ten years. Staff asserts a discount rate update now would be immaterial and superfluous and we agree. We also share Staff's concern that extending the length of the deferral period would conflict with the requirements of the Pension and OPEB Statement and Order. Finally, we are also persuaded by arguments that there is no reason or need at this time to attempt to prematurely capture savings that have not even been estimated. We therefore decline to adopt CPB's proposed modifications to pensions and OPEBs. CPB asserts that Central Hudson's cost of equity should be reduced from 9.6% to 8.95%. Staff and the Company assert that the proposed 9.6% ROE is fully justified. Central Hudson further asserts that CPB's efforts to decrease an already low ROE are unreasonable and misapplies the Generic Finance Case's guidance. The method employed to set the allowed equity return is within the range of reasonable results that can be adopted here. In declining to modify the proposed 9.6% equity return allowance, we recognize that this item is but one many elements and interrelated provisions, including the associated but uncontested earnings sharing mechanism and the limitation of certain deferrals. We decline to upset the reasonable balance that has been established with respect to these provisions. We also find that CPB's recommendations against an AMR pilot or a metering study are premature. The Joint Proposal clearly provides that the pilot and the study will be developed by the Company and filed for our approval. They will only proceed if we approve them. Thus, CPB can pursue its objections to such plans when they are filed. In addition, CPB's request to use funds dedicated to the proposed pilot and study to further mitigate rates is likewise rejected because (1) no rate allowances have yet been committed to either of these proposals and (2) CPB has not persuaded us that a change to our prior orders is warranted. CPB opposes the reversal of the 2005 reliability penalty. The Company asserts that CPB's position fails to -70- CASE 05-E-0934, et al. recognize the provision in context with other, interrelated provisions. Staff contends that CPB's opposition ignores the fact that prior rate orders specifically authorize excuse of a failure that is shown to be caused by the OMS introduction. For the reasons provided by Staff and the Company, we reject CPB's recommendation. We find that a reasonable compromise was made on this item in the context of the many other related provisions. Also, given the uncertainty attending this contested issue, the provision represents a reasonable compromise and should not be disturbed. CPB recommends that funds remaining in the electric depreciation reserve account be used to further moderate the proposed rate increases. Staff argues that CPB's presumption as to amount of mitigation that could be funded in this manner is incorrect. The Company asserts, inter alia, that CPB's proposal ignores the nature of the assessment of excess reserve. Given the difficulties associated with forecasting certain types of large, future deferrals and our policies favoring rate stability, we are not persuaded that the several disadvantages attending the complete depletion of excess depreciation reserve outweigh the one and only identified (and purportedly minimal) benefit. We therefore reject CPB's proposal. CPB and PULP oppose the level of expenditures for retail access programs and seek reassignment of a portion of such amounts to outreach and education for purposes other than retail competition. Central Hudson claims that CPB's and PULP's challenges and proposed modifications lack justification and evidentiary support, and are inconsistent with Commission policy. The Company adds that any legitimate concern regarding the level of such expenditures is addressed by the deferral mechanisms. Staff asserts that Central Hudson has only made expenditures that are in conformance with the 2004 Rate Plan Order or that are needed to implement the programs called for in the Retail Access Order. SCMC/RESA claim that proposals to reduce such expenditures are short-sighted and should not be adopted. We are persuaded by the proponents' and SCMC/RESA's arguments that the funding for retail access programs is proper -71- CASE 05-E-0934, et al. and conforms to and furthers our orders and policies favoring of development of the competitive market. The offering of utility-sponsored fixed price options engendered significant controversy in these proceedings. The first question presented is whether utility-sponsored fixed price options can be raised and considered in these proceedings. We are persuaded, mainly by the arguments in CPB's post-hearing brief, that there is no bar to CPB and PULP presenting their proposal in these proceedings. However, as the proponents of utility fixed price options, they must demonstrate sufficient justification for their adoption.(159) CPB and PULP claim that consumers have a strong preference for fixed price energy products from the utility. They state that consumers without substantial financial assets decrease spending on items, such as food, to cover unanticipated increases in their home energy bill. They assert that the availability of reasonably priced fixed price products would help them avoid such dilemmas. They also argue that ESCOs are not offering fixed price electricity or gas products at reasonable prices nor have the number of such providers increased as seemed to be expected in the July 2005 Order. CPB and PULP also claim to have demonstrated that reinstitution of utility-provided fixed price options is consistent with Commission orders on retail competition because the competitive market has not responded adequately and because Central Hudson can be distinguished from other utilities that do not offer fixed price options. On the other hand, Central Hudson, Staff and SCMC/RESA argue that reinstituting utility fixed price offers would do little to remedy the impact of commodity price increases but would cause long-term harm to low-income customers, in particular. They argue it would also distort and retard the - ---------- (159) In its post-hearing brief (at 8) CPB notes that it "may face a difficult burden in overcoming recent precedent set by the Commission's decision in the gas FPO case, but it is not precluded from making the effort." -72- CASE 05-E-0934, et al. development of retail market to the disadvantage of consumers, and not yield better prices for consumers. We agree with Staff that the design that has been suggested for the proposed utility fixed price options lacks sufficient detail to be implemented successfully, and we note that there is insufficient time to remedy such deficiencies and implement utility sponsored fixed price options in time for the 2006-2007 heating season.(160) However, even if these deficiencies could be remedied, we are not convinced that utility-provided fixed price options should be required in these proceedings. We note, in particular, the CPB's testimony that its main intent in proposing the options is to "provide customers a tool for dealing with price volatility."(161) We further note CPB's recognition of the fact that "there's no guarantee that fixed price option[s] will be better for customers than a variable price."(162) Budget or levelized payment plans are available, as required by law,(163) to all utility customers, and they already provide a tool by which customers can achieve certainty with respect to their monthly bills. Moreover, the record shows there is a competitive market in Central Hudson's territory, which includes provision of fixed-price offers from competitive suppliers. Our consideration of these factors, and of the concerns that were raised by Staff, the Company and SCMC/RESA, - ---------- (160) CPB acknowledges that, normally, a fixed price offer involves the announcement of such an offer and receipt of responses, which in turn permit determination of the required volume of hedging instruments and fixed price purchases. In addition, CPB indicates that cost issues - both as to the price to be set for the option and the method of recovering any differences between estimates and actuals, are not addressed by its proposal at this time but are implementation issues that should be addressed by the Commission. Given that the 2006-2007 heating season starts October 1, there would be insufficient time to properly conduct these necessary steps. Tr. 914-918. (161) Tr. 919. (162) Id. (163) Public Service Law ss.38. -73- CASE 05-E-0934, et al. result in our conclusion that the addition of utility-provided fixed price options need not be required here. As discussed in more detail above, Select Energy opposes the Joint Proposal's provisions on balancing, cash-out and delivery proposals for service classifications 6, 12, and 13. Its suggested modifications are opposed by Multiple Intervenors, the Company and Staff. We are persuaded by proponents' arguments that Select Energy's position should be rejected. SCMC/RESA allege that the proposed hedging provision is at odds with Commission policy, acts to hinder competition and is inherently illogical. SCMC/RESA argue that until the Commission determines that residential and small commercial classes have available equivalent hedge products, it must ensure that the utility hedging activity reflected in rates is consistent with the utility's regulated monopoly advantages and is equitable to ESCOs and retail access customers. Staff asserts that SCMC/RESA's position contravenes Commission policy and would dilute the value of the hedge. Staff states that the proposal as it currently stands allows customers to accurately compare utility commodity offerings to ESCO offerings. Parties on both sides of the issue raise policy matters that merit further and more in-depth consideration. As these issues also may be of state-wide relevance, they should be further explored and considered in a new generic proceeding. Depending on the outcome of that generic proceeding, its results could be incorporated into later years of this multi-year rate plan, or deferred to the next rate proceeding. We will review what, if anything, needs to be done for this rate plan at the conclusion of the generic proceeding, after the views of the parties are solicited. However, the treatment set forth in the Joint Proposal, which continues the existing Company practice, will be adopted for now. We expressly note that our approval of the rate plan does not affect our reserved authority to require a change in base rates, should we find that, because of unforeseen circumstances, Central Hudson's actual return in any annual -74- CASE 05-E-0934, et al. period during the rate term is unreasonable or insufficient to support safe and adequate service at just and reasonable rates. In sum, we conclude that the rate plan established here will provide just and reasonable rates, terms and conditions and that approval, consistent with the discussion herein, is in the public interest. The Commission orders: 1. The rates, terms, conditions, and provisions of the Joint Proposal dated April 17, 2006 (Restated April 19, 2006), filed in this proceeding and attached hereto as Attachment 1, are adopted and incorporated herein to the extent consistent with the discussion in this Order. 2. Central Hudson Gas & Electric Corporation shall file a written statement of unconditional acceptance of this Order, as of the date of the tariff filing required by ordering clause number three below. 3. Central Hudson Gas & Electric Corporation is directed to file a supplement, on not less than one day's notice, to be effective on July 31, 2006, to cancel the tariff leaves and supplements listed in Attachment 2. 4. Central Hudson Gas & Electric Corporation is directed to file, on not less than one day's notice, to take effect on August 1, 2006 on a temporary basis,(164) such tariff amendments(165) as are necessary to effectuate the terms of this Order. Upon filing these tariff amendments, Central Hudson Gas & Electric Corporation shall serve copies on all active parties to this proceeding. Any party wishing to comment on the tariff amendments may do so by filing an original and five copies of its comments with the Secretary and serving its comments upon - ---------- (164) Given the tariffs' August 1, 2006 effective date, the make whole approved in this Order applies to the month of July 2006. (165) The tariff amendments that are required to effectuate this Order's gas balancing requirements should be filed on March 1, 2007 and March 1, 2008, to take effect April 1, 2007 and April 1, 2008 respectively. -75- CASE 05-E-0934, et al. all active parties within ten days of service of the tariff amendments. The amendments specified in the compliance filing shall not become effective on a permanent basis until approved by the Commission and will be subject to refund if any showing is made that the revisions are not in compliance with this Order. 5. The requirement of the Public Service Law Section 66(12)(b) that newspaper publication be completed prior to the effective date of the amendments is waived; provided, however, that Central Hudson Gas & Electric Corporation shall file with the Secretary, no later than six weeks following the effective date of the amendments, proof that a notice to the public of the changes set forth in the amendments and their effective date has been published once a week for four consecutive weeks in one or more newspapers having general circulation in the service territory of the Company. 6. Upon acceptance by Central Hudson Gas & Electric Corporation of this Order, the Company shall withdraw its pending petition in Case 04-G-0463 for rehearing concerning gas balancing. 7. Upon acceptance by Central Hudson Gas & Electric Corporation of this Order, the Company shall withdraw its pending petition in Case 00-E-1273 for rehearing of the Commission's Order issued September 30, 2005 concerning electric reliability. 8. These proceedings are continued. By the Commission, (SIGNED) JACLYN A. BRILLING Secretary -76- ATTACHMENT 1 PUBLIC SERVICE COMMISSION OF THE STATE OF NEW YORK - --------------------------------------- : Proceeding on Motion of the : Commission as to the Rates, Charges, : Rules and Regulations of Central : Case 05-E-0934 Hudson Gas & Electric Corporation for : Case 05-G-0935 Electric and Gas Service. : : - --------------------------------------- - -------------------------------------------------------------------------------- JOINT PROPOSAL APRIL 17, 2006 (Restated April 19, 2006) - -------------------------------------------------------------------------------- Table of Contents I. PROCEDURAL BACKGROUND ............................................ 1 II. TERM ............................................................. 2 III. ELECTRIC RATES ................................................... 3 A. Electric Delivery Revenue Requirements .............................. 3 B. Electric Revenue Allocation ......................................... 3 C. Electric Rate Design ................................................ 3 D. Electric Commodity .................................................. 4 IV. GAS RATES ........................................................ 5 A. Gas Delivery Revenue Requirements ................................... 5 B. Gas Cost of Service and Rate Design ................................. 6 C. SC-11 Distribution Large Mains Classification ....................... 6 D. Gas Commodity ....................................................... 10 V. GAS BALANCING .................................................... 10 A. General ............................................................. 10 B. S.C. 9 and 11 ....................................................... 11 C. S.C. 6, 12 and 13 ................................................... 16 VI. RATE UNBUNDLING .................................................. 17 A. Electric Unbundled Rates and Backout Credits ........................ 17 B. Gas Unbundled Rates and Backout Credits ............................. 17 C. Two Tier MFCs ....................................................... 17 D. Full Service Customers .............................................. 18 E. Retail Access Customers ............................................. 18 F. Calculation of MFCs ................................................. 18 G. Short Run Avoided Costs ............................................. 18 H. Forecasting Participation and Reconciliation of Lost Revenues ....... 19 I. Bill Format ......................................................... 22 VII. CAPITAL EXPENDITURES ............................................. 22 A. Electric Plant ...................................................... 22 i B. Gas Plant, Exclusive of Gas Infrastructure Enhancements .............. 22 C. Common Plant ......................................................... 23 VIII. DEPRECIATION ..................................................... 23 A. Depreciation Expense ................................................. 23 B. New Depreciation Study ............................................... 23 C. Negative Salvage ..................................................... 23 IX. DEFERRALS ........................................................ 25 A. Authorization ........................................................ 25 B. Right to Petition .................................................... 26 X. CAPITAL STRUCTURE AND EARNINGS SHARING ........................... 27 A. Capital Structure .................................................... 27 B. Earnings Sharing ..................................................... 27 C. Reporting ............................................................ 29 XI. ADDITIONAL RATE PROVISIONS ....................................... 29 A. Accounting for Gas Mains/Services .................................... 29 B. Balance Sheet Offsets ................................................ 29 C. Benefit Fund Cessation and Continuing Uses ........................... 30 D. Certain Rate Allowances .............................................. 31 E. East Fishkill Substation Deferral .................................... 31 F. Electric Transmission ROW Maintenance ................................ 31 G. Electric Water Heating ............................................... 32 H. Make Whole ........................................................... 32 I. MGP Site Investigation and Remediation Costs ......................... 32 J. Pension/OPEBs ........................................................ 32 K. Property Taxes ....................................................... 33 L. Ratemaking Factors ................................................... 33 XII. LOW INCOME PROGRAM ............................................... 33 A. New Low Income Program ............................................... 33 B. Program Funding and Administration ................................... 34 C. Enhanced Powerful Opportunities ...................................... 34 D. Interim Program ...................................................... 37 ii XIII. CUSTOMER SERVICE QUALITY PERFORMANCE MECHANISM ................... 39 A. Effective Date ....................................................... 39 B. Customer Satisfaction Index ("CSI") .................................. 39 C. PSC Complaint Rate ................................................... 40 D. Appointments Kept .................................................... 40 E. Evaluation of Telephone System Enhancements: ......................... 40 F. Reporting ............................................................ 41 XIV. GAS SAFETY MECHANISM ............................................. 42 A. General .............................................................. 42 B. Leak Management ...................................................... 42 C. Prevention of Excavation Damages ..................................... 42 D. Emergency Response ................................................... 43 E. Gas Infrastructure Enhancement ....................................... 44 F. Reporting ............................................................ 45 XV. ELECTRIC RELIABILITY ............................................. 45 A. SAIFI And CAIDI Targets .............................................. 45 B. Other Electric Reliability Targets ................................... 46 C. Other Provisions ..................................................... 46 XVI. MONTHLY METER READING/BILLING STUDIES ............................ 47 A. Monthly Billing Study ................................................ 47 B. AMR Pilot ............................................................ 47 C. Reporting ............................................................ 48 XVII. RETAIL ACCESS .................................................... 48 A. Market Match Program ................................................. 48 B. Market Expo Program .................................................. 49 C. Energy Fairs ......................................................... 50 D. ESCO & Marketer Satisfaction Mechanism ............................... 51 E. ESCO Ombudsman ....................................................... 51 F. Competition Awareness and Understanding Survey ....................... 51 G. Competition Education Campaign ....................................... 51 H. ESCO Referral Program ................................................ 52 iii XVIII. Further Understandings Between Central Hudson and USMA ........... 52 A. Best Efforts ......................................................... 52 B. Easement ............................................................. 52 C. Refunds of Taxes ..................................................... 53 D. Cost of Service Study ................................................ 53 E. Reporting ............................................................ 53 XIX. TERMS AND CONDITIONS ............................................. 54 A. Complete Resolution .................................................. 54 B. Reservation .......................................................... 54 C. Integrated Document .................................................. 54 D. Dispute Resolution ................................................... 54 E. Non-Precedent ........................................................ 55 F. Application for New Rates ............................................ 55 G. Safe and Adequate Service ............................................ 55 H. Continued Effect ..................................................... 55 APPENDICES Appendix A: Electric Income Statements (for twelve month periods Ending June 30, 2007, 2008 and 2009) Appendix B: Electric Customer Class Rates of Return Appendix C: Table of Electric Delivery Rates Including MFCs Appendix D: Gas Income Statements (for twelve month periods Ending June 30, 2007, 2008 and 2009) Appendix E: Gas Embedded Cost of Service Summary (for twelve month period Ending June 30, 2007) Appendix F: Table of Gas Delivery Rates Including MFCs Appendix G: Deferred Electric and Gas Items for Offset Appendix H: Capital Structure and Allowed Rate of Return iv Appendix I: Certain Deferred Items Subject to Limitation Appendix J: Electric, Gas and Common Depreciation Appendix K: Gas Balancing Methodology Applicable to SC 9 & 11. Appendix L: Detailed CSI Margin of Error Calculation v PUBLIC SERVICE COMMISSION OF THE STATE OF NEW YORK - --------------------------------------- : Proceeding on Motion of the : Commission as to the Rates, Charges, : Rules and Regulations of Central : Case 05-E-0934 Hudson Gas & Electric Corporation for : Case 05-G-0935 Electric and Gas Service. : : - --------------------------------------- JOINT PROPOSAL (April 17, 2006; Restated April 19, 2006) I. PROCEDURAL BACKGROUND On July 29, 2005, Central Hudson Gas & Electric Corporation ("Central Hudson" or the "Company") filed amendments to its tariff schedules, P.S.C. No. 15 - Electricity, and P.S.C. No. 12 - Gas. By Order issued August 24, 2005, the Commission initiated the above-captioned proceedings and suspended the operation of the tariff amendments until December 26, 2005. The suspension period was later extended to June 26, 2006. In addition, Central Hudson proposed a one month extension by letter to the Secretary and an additional one month extension on the record of a Pre-Hearing Conference held on March 9, 2006; both extensions subject to make whole provisions. On September 30, 2005, the Presiding Administrative Law Judges ("ALJs") issued a Ruling establishing the procedural schedule. In accordance with the procedural schedule, Department of Public Service Staff ("Staff") and Intervenor direct testimony was filed on November 21, 2005, and rebuttal testimony was duly filed on December 14, 2005. The supplemental testimony of Company witness Paul Haering was filed on November 19, 2005, and the Department of Defense (DOD), on behalf of the United States Military Academy at West Point ("USMA" or "West Point") filed the initial testimony of Kenneth Kincel on December 19, 2005. Furthermore, the ALJs' Second Procedural Ruling in these proceedings, issued November 5, 2005, determined that monthly gas balancing issues would be heard in these proceedings and the Commission's Order of November 29, 2005 required that Central Hudson make a filing addressing daily gas balancing in these proceedings. Supplemental testimony of Company witness Glynis Bunt was duly filed on January 4, 2006 in response to those requirements. By Ruling issued January 13, 2006, the ALJs cancelled the hearings scheduled for January 18, 2006, upon consideration of a telephone request by several parties seeking additional time to negotiate the development of a Joint Proposal. The procedural schedule was revised by the ALJs in a Ruling issued January 17, 2006, granting a request for a postponement and extension of the procedural schedule for the purpose of accommodating the progression of good faith settlement negotiations. This Ruling established the target date of February 28, 2006 for the parties to submit a Joint Proposal together with an Executive Summary. Settlement discussions were conducted on January 12, 2006, in response to a Notice of Impending Negotiations dated January 6, 2006 filed by the Company. Additional negotiating sessions were conducted upon prior notice to all participating parties on January 18, 19, 24, and 31, February 3, 7, 14, and 17. On March 9, a Settlement Judge, Jeffrey Stockholm, was appointed and conducted mediation of the negotiations commencing on March 10, 2006. Further negotiating sessions were held on March 10, 17, 23, 27, 28, and 30, and April 4, 6, 11, 14, and 17, 2006. On April 3, 2006 a revised schedule was established by the ALJs, calling for the submission of the Joint Proposal on April 17, submission of statements in support or opposition and any evidentiary presentations by parties opposing the Joint Proposal on May 1, 2006, commencement of hearings on May 4, 2006 and submission of briefs (limited to thirty pages) on May 12, 2006. As a result of the extensive settlement processes, the parties listed at the end hereof have reached the agreements on the outcome of these proceedings reflected in this Joint Proposal, and they recommend to the Commission that it approve this Joint Proposal. II. TERM This Joint Proposal is for a three-year electric and gas rate plan, commencing July 1, 2006 and continuing through June 30, 2009 (see also Section XVIII.H). "Rate Year" ("RY") means a 12-month period starting July 1 and 2 ending on the following June 30. RY1 is the twelve months ending June 30, 2007; RY2 is the twelve months ending June 30, 2008 and RY3 is the twelve months ending June 30, 2009. III. ELECTRIC RATES A. Electric Delivery Revenue Requirements. 1. The electric delivery revenue requirements shown in Column A, B, and C, Line 2 of Appendix A, Schedule 1, are prior to rate moderation. 2. Electric delivery revenue requirements have been moderated through use of a portion of electric depreciation reserve that is in excess of the theoretical book reserve, to offset and "shape" the revenue requirement increases, so as to produce three approximately equal increases in revenue requirement over the three rate years. The revenue requirements have been moderated as shown Appendix A, Schedule 2. 3. The Income Statements for Electric Delivery Service set forth in Appendix A show that this Joint Proposal is reasonable. B. Electric Revenue Allocation. For all rate years, the electric revenue allocation among service classifications (SC) is subject to constraints of a minimum increase of 0.75x system average, and a maximum increase of 1.25x system average, with the exception of SC 9. For SC 9, a constraint of 0.50x system average has been applied and a specific allocation of an additional $50,000 of annual revenue requirement responsibility to SC 9 has also been made. The resulting percentage changes by class for each rate year are summarized in Appendix B. C. Electric Rate Design 1. Class billing determinants are shown in Appendix C. 2. Central Hudson's electric rates had previously been separated into delivery and commodity components. As discussed in Section VI below, 3 the electric delivery rates developed in this Joint Proposal reflect further unbundling, through transferring additional commodity-related costs to new Merchant Function Charges ("MFCs") also discussed in Section VI. 3. Beginning on July 1, 2006 (RY1), the rate design for SC 3 and 13 will be changed to a two-part (customer charge and demand charge) rate design, exclusive of MFCs. 4. The electric delivery rates (including MFCs) are set forth in Appendix C. D. Electric Commodity. 1. The existing Energy Cost Adjustment Mechanism ("ECAM") mechanisms being used to recover the costs of electric commodity from Central Hudson customers will continue, subject to the modifications described below. 2. The existing hedges (known as Constellation and Entergy) will be maintained in the Purchased Power Adjustment ("PPA") and Market Price Charge ("MPC") mechanisms, respectively, in accordance with current practices. a) Hedges entered into post-June 30, 2006 will be reflected in MPCs for residential and small commercial customer classes. b) There will be no new hedges for SC 3 or 13, which are real time pricing classes. c) Nothing in this Joint Proposal is intended to alter the pre-existing treatment of legacy hedges established in the existing Commission-approved rate plan. 3. Three MPC Groups will be implemented on July 1, 2006. a) The separate MPCs are: 1) for SC 1, 2 and 9; 2) for SC 6 (residential time-of-use); and 3) for SC 5 and 8. 4 b) MPCs will be based on each group's average load shapes. c) Effective July 1, 2007, the SC 6 MPC shall be differentiated into on-peak and off-peak rates, with the same on-peak rate applied to all SC 6 on-peak rate periods and the same off-peak rate applied to all SC 6 off-peak periods. d) Recovery of NYISO Ancillary Services Charges and NYPA Transmission Access Charges ("NTAC") will be moved from the Miscellaneous Charges Factor of the ECAM into the MPCs and Hourly Pricing Programs as of July 1, 2007. e) As of July 1, 2007, the Company will cease reimbursing Energy Service Company (ESCO) retail commodity suppliers for ancillary service costs and NTAC. f) Commodity-related uncollectibles and working capital costs shall continue to be recovered through commodity charges. There are no net lost revenues associated with the uncollectibles or working capital costs. IV. GAS RATES A. Gas Delivery Revenue Requirements. 1. The gas delivery revenue requirements, as shown in Columns A, B and C, Line 2 of Appendix D reflect rate moderation achieved through deferring a portion of the RY1 increase and amortizing it, along with revenue requirement increases in RY2 and 3, in an amortization commencing in RY2. This approach also permits a zero rate increase in RY3. The amortization of the gas net regulatory assets is addressed in more detail in Section X.B.2 and .3. 2. The Income Statements for Gas Delivery Service set forth in Appendix D show that this Joint Proposal is reasonable. 5 3. The Gas Income Statements include an interruptible profit imputation of $1.0 million each rate year. Because of the imputation, the Company is permitted to retain the first $1.0 million in revenues in each rate year that it may receive from interruptible service and service to electric generators, subject to the following. a) If the margin does not reach $1.0 million in any rate year, the Company is authorized to surcharge ratepayers for 100% of the first $0.25 million of the shortfall and 90% of the remaining shortfall. b) If the margin exceeds $1.0 million in any rate year, the Company will credit ratepayers for 100% of the first $0.25 million of the excess and 90% of the remaining excess. 4. Central Hudson's gas rates had previously been separated into delivery and commodity components. As discussed in Section VI below, the gas delivery rates developed in this Joint Proposal reflect the transfer of additional commodity-related costs to new MFCs. B. Gas Cost of Service and Rate Design. 1. Gas rates have been developed using the Embedded Cost of Service Study summarized as Appendix E. 2. Revenue Allocation. Class billing determinants and the resulting rates, including MFCs, are shown in Appendix F. 3. For residential gas customers, the minimum charge will be increased to $14 per month, and the volumetric delivery rates for the penultimate block and tail block will be set at a ratio of 1.6:1, respectively. C. SC-11 Distribution Large Mains Classification 1. A new SC-11 subclass, "Distribution Large Mains" ("SC11DLM")" will be established as of July 1, 2006. 6 a) The new SC11DLM subclass will be applicable to customers using over 400,000 Mcf/year, taking service from Company facilities below transmission pressures and from mains at least 6" in diameter. b) The rules and regulations of SC-11 apply to SC11DLM. c) The costs allocated to SC11DLM are shown on Appendix E, subject to the following: (1) The costs of mains below 6-inch in diameter are excluded. (2) The operating expenses resulting from Central Hudson payments to USMA are included in FERC/PSC Account 860 and are allocated to all classes of service other than SC11DLM. (3) All other cost of service treatments applied to SC-11 D are also applied to DLM. (4) The system average rate of return is used to develop the revenue requirement for SC11DLM. d) SC11DLM rate design follows SC11 D and is based on Maximum Daily Quantity ("MDQ"). RY1 through RY3 rates for SC11DLM are shown on Appendix F. e) The SC11DLM MDQ that is in effect for a customer may be revised downwards for permanent reductions to the gas load on the customer's premises caused by installations of, or modifications to, gas equipment, including the possible installation of a propane-air facility. The amount of such downward adjustment to the MDQ will be reasonably determined based on engineering studies prepared by the Customer and furnished to the Company and Staff, on the effect of the gas equipment changes. (1) The downward adjustment to the MDQ shall be effective during the first month for 7 which the changes in gas equipment are placed in service. (2) Any customer proposing to reduce its MDQ based on a propane-air facility will provide Staff and the Company written notice at least six months in advance of the date on which the proposed changes in gas equipment will be placed in service. (3) In the event of reductions in MDQ based on customer conservation measures, the Company will be permitted to defer the lost revenues for future recovery, with carrying charges at the pre-tax authorized rate of return. 2. Treatment of USMA. a) Central Hudson will install demand meters at Hotel Thayer and at the Village of Highland Falls by November 1, 2006. b) USMA will be provided service after June 30, 2006 in accordance with the provisions of the SC11DLM class, and after execution of a contract within 10 days of a Commission decision on this Joint Proposal between Central Hudson and the Department of the Army on behalf of USMA, incorporating the provisions set forth below and filed with the Commission. The contract (Modification P00050) will be a further modification of the current Contract DAAG60-91-C-0087 as modified through Modification P00049. Modification P00050 will not contain the rates referenced in Modification 49. Modification 50 shall include all FAR clauses that were incorporated into the contract by Modification P00049 (effective September 1, 2005) except for FAR 52.241-8 (which shall be replaced by FAR 52.241-7, Change in Rates or Terms and Conditions of Service for Regulated Services (Feb 1995)) and the FAR clause incorporated at Paragraph 10 of Modification P00049 (entitled "Requirement for Certificate of Procurement Integrity (Nov 1990)." 8 c) The contract modification will: (1) Provide for firm transportation service in accordance with all provisions of SC11DLM. (2) Incorporate the rules and regulations of SC11DLM, including balancing. (3) Specify that the Standard SC11DLM tariff rules for adjusting MDQ identified above will apply to USMA and that the current USMA MDQ is 5833 mcf. d) The contract modification will address the use of the USMA system to deliver gas to Central Hudson's customers in the Village of Highland Falls and to the Hotel Thayer as follows. (1) Central Hudson shall credit to USMA $5.53 per Mcf of MDQ for deliveries to Highland Falls and Hotel Thayer during each month of RY1 through RY3. (2) The initial MDQ for Hotel Thayer shall be 27 Mcf. The initial MDQ for Highland Falls shall be 904 Mcf. (3) The MDQ for any given month shall be the highest daily volume delivered during the current month or the preceding 11 billing months. (4) A loss factor of 2.564% shall be applied to the volume of gas delivered to Highland Falls and Hotel Thayer times the unit cost of the gas commodity to USMA for the corresponding month. USMA will provide Central Hudson with copies of invoices to establish the monthly USMA unit cost of gas commodity. e) The contract shall provide that, for the term of the contract, Central Hudson will, subject to the provisions of leaves 65 and 66 of its gas tariff (PSC No. 12), deliver up to 500 Mcf per hour (relating to capacity, not MDQ) at 90 psig or greater at Crow's Nest at 9 no additional charge to USMA and at no premium upon the rates specified in Appendix F. In addition, the contract will further provide that, for the term of the contract, USMA will maintain 30 psig at Thayer Gate provided that the pressure at Crow's Nest is 90 psig or higher, and the flow of gas to the Village of Highland Falls and the Hotel Thayer does not exceed 50 Mcf per hour. f) The contract Term shall be for a fixed term ending June 30, 2009. D. Gas Commodity. 1. The existing mechanisms and practices under the Gas Supply Charge (GSC), Firm Transportation Rate (FTR), Interruptible Transportation Rate (ITR) and Interruptible Gas Rate (IGR) that are related to recovery of costs incurred in supplying gas commodity will continue, subject to the modifications described in Sections V and VI below. 2. Commodity-related uncollectibles and working capital costs shall continue to be recovered through commodity charges. There are no net lost revenues associated with the uncollectibles or working capital costs. V. GAS BALANCING A. General. 1. The new gas balancing approach described below will become effective as of April 1, 2007 for interruptible and firm transportation classes (SC-9 and 11, respectively), and for the aggregated transport classes (SC-6, 12, and 13). Applicable portions of the procedures described in the Company's July 29, 20005 "Report on Gas Balancing and Cashout Issues" will be followed in implementing balancing. 2. Incremental software costs for monthly and daily balancing will receive deferral accounting, for later recovery including carrying charges at the pre-tax authorized rate of return. 10 B. S.C. 9 and 11. 1. A separate volumetric Balancing Service Charge will be implemented as follows: a) There will be two separate rates: one for daily balanced customers and one for monthly balanced customers. b) The methodology for calculating monthly and daily balancing service charges is shown in Appendix K. c) The charges will be updated at least annually, to be effective April 1 of each year, using the methodology shown in Appendix K. The updates will be based on each service classification's total consumption and deliveries during the preceding winter period and the Company's then most recently available gas storage and other relevant costs. At least 30 days prior to the effective date of an update, the Company will file a statement of Gas Balancing Rates. d) Transition. The charges shown below have been developed using the methodology depicted in Appendix K, based on currently available information. These charges are scheduled to be updated as of April 1, 2007, except for SC 11DLM. The rates set forth below will remain in effect for SC 11DLM customers until March 31, 2008. Monthly Daily ------- ----- $/Mcf $/Mcf SC-9 $0.0791 $0.0112 SC-11 0.0463 0.0164 SC11DLM 0.0463 0.0164 e) Effective April 1, 2008, the charges for SC 11 and SC 11DLM will be determined separately, based on the specific peak day history for each class. 2. Customers will be allowed to designate an ESCO retail supplier to be responsible for supply 11 nominations and to effectuate the exchange of any imbalances hereunder with similarly situated customers. 3. Commencing April 1, 2007, Balancing Service Charges will be billed to the customer, and imbalance penalties will be billed to the customer's ESCO. Customers will be obligated to require their ESCOs to enter into an agreement with Central Hudson to pay for such penalties. Prior to April 1, 2007, all charges will continue to be billed to customers. 4. Balancing Service Charge revenues will be credited to the Gas Supply Charge. 5. Customers served under negotiated contracts will be rolled into the provisions applicable to similarly situated tariff customers upon the conclusion of contract negotiations or renegotiations. 6. The term of the balancing option period will be modified to provide customers with a semi-annual election of daily or monthly balancing for the periods November 1 - April 30 and May 1 - October 31. a) An existing customer will be required to notify the Company of its selected balancing option for an applicable period on or before the date published in the Company's Calendar of Gas Transportation Schedule (column 4 - deadline for interruptible transport enrollment). b) A customer taking service under SC 9 will maintain its balancing option for the full balancing period regardless of whether the customer switches to service under another service classification or to its alternate fuel and subsequently returns to SC 9 service. c) Absent timely receipt by the Company, of notification from the customer electing its 12 balancing option, the customer will placed in monthly balancing by default. 7. The following daily balancing provisions in the current tariff will be eliminated: a) If on any day a customer's over-delivery or under-delivery is less than 10% of a customer's actual daily usage, the customer may adjust subsequent daily deliveries to the Company by an amount not to exceed 10% of any day's usage to eliminate any over- or under-deliveries by the end of the month. b) If on any day a customer's cumulative over-delivery exceeds 125% of the customer's maximum daily quantity (MDQ), the cumulative over-delivered volume in excess of 125% of the MDQ will be purchased by the Company at a rate equal to 90% of the daily Index Price for that day. c) If on any day a customer's cumulative under-delivery exceeds 125% of the customer's MDQ, the cumulative under-delivered volume in excess of 125% of the MDQ will be sold to the customer by the Company at a rate equal to 110% of the daily Index Price for that day. 8. For daily balanced customers, daily over- or under-deliveries will be "cashed-out" according to the existing tiering and pricing structure contained in the Company's tariff only when the combined over- or under-delivery for the "pool" of SC 9 and SC 11 daily balanced customers is greater than 10%. 9. The month-end cashout provisions for both daily and monthly balanced customers will allow customers that have cumulative over- or under-deliveries ("imbalances") at the end of the month to exchange the imbalance with another SC 9 or SC 11 customer. Such exchanges of imbalances will be accomplished upon notification to the Company of the exchange by the applicable customer, or its designated supplier, prior to the imbalance resolution due date, which is five business days after the 13 applicable month end. The imbalance resolution due date will be added to the Company's Calendar of Gas Transportation Schedule. The net effect of all imbalance exchanges must improve a customer's relative imbalance position. In no event will the Company process exchanges that result in a larger negative position for the customer. 10. The cash out will be according to the following revised tiering and pricing applicable to SC 9 and SC 11 daily balanced customers: -------------------------------------------------------- November - Over - Under- March Deliveries Deliveries -------------------------------------------------------- 0% to 5% Index Index -------------------------------------------------------- 5% to 10% 90% of Index 110% of Index -------------------------------------------------------- >10% 80% of Index 120% of Index -------------------------------------------------------- -------------------------------------------------------- All Other Over - Under- Months Deliveries Deliveries -------------------------------------------------------- 0% to 10% Index Index -------------------------------------------------------- >10% 80% of Index 120% of Index -------------------------------------------------------- The over-delivery Index Price will be equal to the average of the daily averages of the "Midpoint" rates for "Tennessee, zone 0" and Tennessee, zone 1" (500 and 800 legs) receipt points as published in Platt's gas Daily in the table "Daily Price Survey" for the applicable month, plus the Company's weighted average cost of transportation and fuel losses. The under-delivery Index Price will be equal to the average of the "Midpoint" rates of the higher of "Transco, zone 6 N.Y." and "Iroquois, zone 2" receipt points as published in Platt's Gas Daily in the table "Daily Price Survey" under the Citygates heading for the applicable month. 11. The month-end cashout provisions applicable to the resolution of over- and under-deliveries for SC 9 and SC 11 monthly balanced customers will be revised to correspond to the month-end 14 cashout provisions applicable to SC 9 and SC 11 daily balanced customers: a) Over-deliveries will be purchased according to the tiering and pricing structure applicable to month-end cashouts for daily metered customers. As a result, the SC 11 "banking" provision will be eliminated and Company purchases will be priced at the same rate regardless of service class, and will be based on a published index. b) Under-deliveries will be purchased according to the tiering and pricing structure applicable to month-end cashouts for daily metered customers. As a result, Company sales will be priced at the same rate regardless of service class, and will be based on a published index. 12. At such time as Central Hudson issues an Operational Flow Order ("OFO") to safeguard the operational integrity of its system: a) Gas delivered to Central Hudson's system, less any LAUF adjustment, for a daily balanced customer will be required to be within two percent (2%) of the customer's daily usage; b) The daily cashout tiering provisions of SC 9 and SC 11 will be revised such that the first tier will apply to daily over- and under-deliveries greater than 2% up to and including 15%. c) These requirements will remain in effect for the duration of the OFO. 13. Upon the Commission's adoption of this Joint Proposal, the Company will request the Commission's permission to withdraw the Company's pending petition in Case 04-G-0463 for rehearing concerning gas balancing. 15 C. S.C. 6, 12 and 13. 1. Reconciliations and true-ups will be performed semi-annually; once for the 5 months ending March 31, and once for the seven months ending October 31. 2. Effective 4/1/07, ESCO retail suppliers will be allowed to trade offsetting monthly imbalances as part of the semi-annual reconciliation/true-up. 3. During the summer months, CHG&E will use the monthly average of the daily average of the "midpoint" rates for the Tennessee zone 0 and Tennessee zone 1 (500 and 800 legs) receipt points, plus the company's weighted average cost of transportation and fuel losses, as the cashout price for both under-deliveries and over-deliveries. 4. The pricing for Winter Bundled Sales Service (WBS) gas would be based upon: Inside FERC Gas Market Report - First of Month Index for each month between April - October for the following trading points; 50% "Dawn Ontario" & 50% "TCPL Alberta, AECO" to produce a "blended index" for each month. a) Individual months would be weighted by adding the following monthly values and dividing the total by six: April Blended Index divided by two May Blended Index June Blended Index July Blended Index August Blended Index September Blended Index October Blended Index divided by two b) The above commodity cost would then be adjusted to include storage charges, firm transportation charges, including fuel, from market area storage to the Company's city gates, and carrying charges on the cost of gas in storage. 16 VI. RATE UNBUNDLING A. Electric Unbundled Rates and Backout Credits. 1. The back out credits and related treatment contained in the Commission's October 25, 2001 Rate Plan (Sections IX.D and X.D.1) in Cases 00-E-1273 and 00-G-1274, and its June 14, 2004 Rate Plan in those proceedings will be maintained through June 30, 2007, except that the cost of the electric backout credits will be charged against the excess electric depreciation reserve. 2. At July 1, 2007, the electric backout credits will be replaced by four electric MFC groups, and the lost revenue provisions described below. 3. The four electric MFC groups are 1) MFC 1 for SC 1 and 6, 2) MFC 2 for SC 2 , 3) MFC 3 for SC 3 and 13, and 4) MFC 4 for SC 5, 8, and 9. The new MFCs include cost-based components to represent commodity-related purchasing, credit and collection, call center costs, advertising and promotions, and related Administrative and General (A&G) expenses and rate base items allocated to each group. B. Gas Unbundled Rates and Backout Credits. 1. From July 1, 2006 through June 30, 2007, the existing backout credits will continue to apply and will continue to be recovered through the Gas Supply Charge. 2. Gas delivery service MFCs, analogous to those described above for electric delivery service, will be implemented on July 1, 2007. The two gas MFCs are MFC 1 for SC 1 and MFC 2 for SC 2. C. Two Tier MFCs. Each MFC group will be further sub-divided into an MFC(A) and an MFC(B). 1. MFC(A) will include the allocated portion of credit and collection function costs and 50% of 17 procurement-related call center function costs, plus A&G and rate base items associated with each of the above. 2. MFC(B) will include commodity purchasing function costs, allocated portions of advertising & promotions function costs and 50% of procurement-related call center function costs, plus A&G and rate base items associated with each of the above. D. Full Service Customers. Customers taking commodity service from the Company will be billed by Central Hudson for MFCT, which is equal to the sum of MFC(A) and MFC(B). E. Retail Access Customers. Customers that choose to purchase their commodity service from an energy services company (ESCO) that is participating in the Company's Purchase of Receivables (POR) Program will be billed by Central Hudson for MFC(A) only. The discount rate charged ESCOs that participate in Central Hudson's POR Program will be the same for all service classifications and will consist of an amount reflecting commodity-related uncollectibles costs and a time value of money factor of 0.25%. Customers that choose to purchase their commodity service from an ESCO that is not participating in the Company's POR Program will not be billed a MFC by Central Hudson. F. Calculation of MFCs. The electric and gas MFCs calculated under this Joint Proposal are set forth in Appendices C and F, respectively. These MFCs will be effective as of July 1, 2007 and remain in effect until changed by subsequent order of the Commission. Incremental revenue requirement amounts for RY2 and 3 will be recovered via delivery rate changes. G. Short Run Avoided Costs. At such time as total migration for a month exceeds 30% for either electric (SC 1 and 6) or gas (SC 1) 18 customers, the Company will notify the Commission and the parties and convene discussions among the parties to develop short-run avoided cost curves. For RY2 and subsequent rate years, actual net lost revenues will be offset by the short-run avoided cost calculated from the avoided cost curves, if any; provided however, that no retroactive adjustment will be made prior to the time at which an average 30% migration level is sustained for 6 consecutive months. H. Forecasting Participation and Reconciliation of Lost Revenues. 1. The forecast total retail access participation sales level for RY2 and RY3 for MFC 3 (S.C. 3 & 13) will be equal to the product of 1) the level of total sales eligible to participate in retail access during RY2 and RY3, respectively, and 2) the forecast retail access participation factor. The forecast retail access participation factor is equal to the total SC 3 and 13 retail access participation level, in kWh, for the months of December 2006 or 2007 (for, respectively, RY2 and RY3), divided by the level of SC 3 and 13 sales eligible to participate in retail access during the months of December 2006 or 2007 (for, respectively, RY 2 and RY 3). 2. For all other MFC categories, the forecast total retail access participation sales level for RY2 and RY3 will be calculated separately for each MFC category and will be equal to the product of 1) the level of total sales eligible to participate in retail access during RY2 and RY3, respectively, and 2) the forecast retail access participation factor. The forecast retail access participation factor will be separately calculated for each MFC category and is equal to the greater of a) the total retail access participation level, in kWh or Mcf, for the months of December 2006 or 2007 (for, respectively, RY2 and RY3), divided by the level of sales eligible to participate in retail access during the months of December 2006 or 2007 (for, respectively, RY2 and RY3) or b) the total retail access participation level, in kWh or Mcf, for the months of December 2006 or 2007 19 (for, respectively, RY2 and RY3), divided by the level of sales eligible to participate in retail access during the month of December 2006 or 2007 (for, respectively, RY2 and RY3), plus one-half the change in the retail access participation factor experienced during calendar year 2006 or 2007 (for, respectively, RY2 and RY3). 3. The change in the retail access participation factor equals the total retail access participation level, in kWh or Mcf, for the months of December 2006 or 2007(for, respectively, RY2 and RY3), divided by the level of sales eligible to participate in retail access during the months of December 2006 or 2007 (for, respectively, RY2 and RY3),minus the total retail access participation level, in kWh or Mcf, for the months of December 2005 or 2006 (for, respectively, RY2 and RY3), divided by the level of sales eligible to participate in retail access during the months of December 2005 or 2006 (for, respectively, RY2 and RY3). 4. At least 4 months prior to the beginning of RY2 and RY3, Central Hudson will serve on Staff and the parties to these proceedings its forecasts and calculations of the net lost revenues associated with the MFCs. 5. Forecast net electric and gas lost revenues for MFC 1 for RY2 and RY3 will be equal to the product of 1) the forecast total retail access participation sales level for RY2 or RY3, respectively, as calculated above, and 2) MFC(B). Such calculations assume that all residential retail access customers are served by an ESCO participating in the Company's POR Program and, therefore, are charged MFC(A). 6. Forecast net lost revenues for the remaining MFC categories for RY2 and RY3 will be equal to the product of 1) the forecast total retail access participation sales level for RY2 or RY3, respectively, as calculated above, and 2) the MFC(T). 7. Central Hudson will recover forecast net lost revenues associated with customer migration from 20 delivery and full service customers during RY2 and RY3. Central Hudson will recover 50% of the forecast net lost revenues from full service customers, on an MFC category-specific basis, by adding a separate component for that cost to MFC(B). Central Hudson will recover the remaining 50% of forecast net lost revenues from electric delivery customers through a class-specific component of the Miscellaneous Charge Factor of the ECAM. For gas, Central Hudson will recover the remaining 50% of forecast net lost revenues from delivery customers through a new class-specific charge applicable to those customer classes subject to an MFC. 8. The actual net lost revenue for each MFC category for RY2 and RY3, respectively, will be equal to: 1) the actual total retail access participation sales level of customers taking service from ESCOs participating in Central Hudson's POR Program for RY2 or RY3, respectively, multiplied by 2) MFC(B), plus 3) the actual total retail access participation sales level of customers taking service from ESCOs not participating in Central Hudson's POR Program for RY2 or RY3, respectively, multiplied by 4) MFC(T). 9. At the end of RY2 and RY3, Central Hudson will calculate for each MFC category, the difference between the actual net lost revenues associated with retail access and the amount of net lost revenue recovered from customers. a) If the sum of the cumulative differences across MFC categories is negative (i.e., Central Hudson over-recovered net lost revenues from customers), Central Hudson will defer the over-recovery, subject to carrying charges calculated at the authorized pre-tax rate of return, for future ratepayer benefit. b) If the sum of the cumulative differences across MFC categories is positive (i.e., Central Hudson under-recovered net lost revenues from customers), and the Company has not earned above the 10.6% earnings sharing threshold, Central Hudson will defer the 21 under-recovery, subject to carrying charges calculated at the authorized pre-tax rate of return for future recovery. c) If the Company has exceeded the 10.6% earnings sharing threshold, it will offset against the under-recovered net lost revenues its share of earnings that are in excess of the 10.6% threshold as described in Section IX.B.1. The amount of under-recovered net lost revenues remaining after the offset, if any, will be deferred subject to carrying charges at the utility's authorized pre-tax rate of return for future recovery. I. Bill Format. Central Hudson will propose, no later than October 1, 2006 an unbundled bill format for approval by the Commission. The schedule for cut-over to unbundled rates described above assumes prompt approval of the proposal, such that adequate time for programming changes will be available prior to July 1, 2007. VII. CAPITAL EXPENDITURES A. Electric Plant. Central Hudson's electric capital expenditures, excluding the Allowance for Funds Used During Construction (AFUDC), will be set at a level of $158.078 million, reflecting $51.944 million for RY1, $52.530 million for RY2, and $53.604 million for RY3. If actual expenditures, excluding AFUDC, fall short of the cumulative total level of $158.078 million by the end of RY3, Central Hudson will defer for ratepayer benefit the amount of the shortfall multiplied by 1.5 times the average authorized pre-tax rate of return. Commencing on July 1, 2009, such deferral will be subject to carrying charges calculated at the authorized pre-tax rate of return. B. Gas Plant, Exclusive of Gas Infrastructure Enhancements. For Gas Plant, exclusive of Gas Infrastructure Enhancements addressed in Section XIII.G, Central Hudson's capital expenditures, excluding AFUDC, will be set at a presumed level of $27.495 million, 22 reflecting $10.397 million for RY1, $9.354 million for RY 2, and $7.744 million for RY3. If actual expenditures, excluding AFUDC, fall short of the cumulative total level of $27.495 million by the end of RY3, Central Hudson will defer for ratepayer benefit the amount of the shortfall multiplied by 1.5 times average authorized pre-tax rate of return Commencing on July 1, 2009, such deferral will be subject to carrying charges calculated at the authorized pre-tax rate of return. If actual expenditures for Gas Infrastructure Enhancements exceed the $15.75 million cumulative total established in Section XIII.G, the amount above $15.75 million may be applied by Central Hudson to reduce any shortfall in this "Gas, Exclusive of Gas Infrastructure Enhancements" target. C. Common Plant. For Common Plant, Central Hudson's capital expenditures will be set, reflecting AFUDC, at a presumed level of $21.693 million, reflecting $7.732 million for RY 1, $7.031 million for RY 2, $6.930 million for RY 3. If actual expenditures, excluding AFUDC, fall short of the total level of $21.693 million by the end of RY 3, Central Hudson will defer for ratepayer benefit the amount of the shortfall multiplied by 1.5 times the average authorized pre-tax rate of return. Commencing on July 1, 2009, such deferral will be subject to carrying charges calculated at the authorized pre-tax rate of return. VIII. DEPRECIATION A. Depreciation Expense. The average service lives, net salvage factors and life tables used in calculating the theoretical depreciation reserve and in establishing depreciation expense in the revenue requirements are set forth on Appendix J. The Company is authorized to use these factors until new factors are approved by the Commission. With respect to the period prior to June 30, 2006, the depreciation rates used are appropriately represented and will not be adjusted. B. New Depreciation Study. The Company will file a new depreciation study when it next files a major gas, electric or combined rate case. 23 1. If a combination gas and electric filing is made, the depreciation study will address gas, electric and common plant accounts; if the filing is limited to one line of business, the study need only address the plant accounts for that line. 2. The new study will include the following: a) Rolling and shrinking band analyses for each account shown in Appendix J that is applicable to the line of business being studied. b) The width of the rolling and shrinking bands analyzed may be as determined by the Company, but in any event the rolling bands will not be greater than 10 years or less than 5 years. c) The shrinking band analysis will start with all the data and decrease to one year of data. d) Statistical results regarding Average Service Life each account will include: e) Analyses of either "h-type" or "Iowa-type" curve fitting analyses and f) The related "fit index" will be provided. g) Plots of the observed and smoothed survivor curve for each account along with the fitted "h-type" or "Iowa-type" survivor curve. h) The Depreciation Study will also include a Net Salvage Study for each plant account showing historical Gross Salvage, Cost of Removal and Net Salvage for each year of historical data included in the Net Salvage Study along with rolling band analysis results, with the width of the rolling band being five years. 3. The Company retains the right to submit additional analyses, and any recommendations, of its choice. 24 C. Negative Salvage. The Company currently expenses the cost to remove gas mains and services when the cost exceeds 60% negative salvage. 1. During RY1 through RY3: a) The 60% negative salvage limitation will not apply. b) The Company will charge all costs associated with the removal of gas mains and services to the appropriate depreciation reserve account, and c) The Company will charge to operating expense ratably over each of RY1 through RY3, $228,000, $233,000 and $238,000, respectively, with the offsetting credit to the same depreciation reserve accounts charged above. This provision expires at the end of RY3. 2. After the end of RY3, the Company will expense removal costs in excess of 60% negative net salvage absent the Commission's authorization to apply a different treatment; provided however, that the Company's agreement to apply such accounting after the end of RY3 in this Joint Proposal is understood to be without prejudice to any request the Company may make to the Commission to revise such accounting treatment after the end of RY3. IX. DEFERRALS A. Authorization. The Company continues to be authorized to defer the following items for recovery in the next electric or gas, as appropriate, base rate change or other Commission-ordered disposition: 1. The Company is authorized to continue its use of deferral accounting with respect to the following expenses and costs, and all other expenses and costs for which Commission authorization for deferral accounting is currently effective whether by reason of Commission order or policy of general 25 applicability or by reason of a Commission determination with specific reference to the Company: a) Pension Expense under Statement of Financial Accounting Standards No. 87; b) Post Employment Benefits Other than Pensions ("OPEB") under Statement of Financial Accounting Standards No. 106; c) Interest Costs on Variable Rate Debt; d) Incremental costs of litigation regarding claims of exposure to asbestos at Company facilities; e) Research and Development costs under Commission Technical Release No. 16(?). f) Changes in accounting standards, subject to the understanding that this specific authority to defer is subject to such orders as the Commission may issue that provide for generic treatment of accounting practices; 2. Changes in federal or state regulations that have an impact of more than 1% of net gas or electric income; 3. Stray Voltage Program; and 4. Others addressed in this Joint Proposal. 5. The uses of deferral accounting authorized herein shall continue and shall not terminate because of the end of the term of this Joint Proposal. 6. It is recognized that certain of the deferrals provided for in this Joint Proposal, as listed at Appendix I, are subject to the Limitation of Deferral provision set forth under the heading "Earnings Sharing." B. Right to Petition. Central Hudson retains the right to petition the Commission for authorization to defer extraordinary expenditures not otherwise addressed by this Joint Proposal. 26 X. CAPITAL STRUCTURE AND EARNINGS SHARING A. Capital Structure. Appendix H shows the capital structure and allowed rates of return that have been incorporated into Appendices A and D. B. Earnings Sharing. 1. In the event that Central Hudson achieves a regulatory rate of return on common equity above 10.60% in either the electric or gas department, on a July 1 through June 30 twelve-month basis commencing July 1, 2006, the earnings above 10.60% and up to 11.60% in such department(s) will be shared 50/50 respectively, between the Company and ratepayers. 2. In the event that Central Hudson achieves a regulatory rate of return on common equity above 11.60% in either the electric or gas department, on a July 1 through June 30 twelve-month basis commencing July 1, 2006, the earnings above 11.60% and up to 14.00% in such department(s) will be shared 35%/65% between the Company and ratepayers, respectively. 3. Any earnings above 14.00% will be deferred for the benefit of customers. 4. Carrying charges at the pre-tax authorized rate of return will be applied to the ratepayers' portion. 5. In the event that Central Hudson achieves a regulatory rate of return on common equity above 10.60% in either the electric or gas department, on a July 1 through June 30 twelve-month basis commencing July 1, 2006, and experiences an under-recovery of migration-related net lost revenues in such department, the net lost revenues will be offset by the Company's portion of the earnings above 10.60%. Central Hudson will defer any remaining net lost revenues for future recovery subject to carrying charges calculated at the authorized pre-tax rate of return. This calculation shall be made prior to 27 the Limitation of Certain Deferrals described below. 6. Limitation on Certain Deferrals: When calculating the level of earned common equity return that may be subject to sharing after the calculation of lost revenues described above, the Company will make the following adjustment if its earnings exceed a 11.00 percent return on equity: a) For earnings above 11.00 percent but less than or equal to 14.00 percent, the Company will reduce qualifying expenses (debits) deferred for later recovery by netting in the fashion described below, up to 50 percent of the deferral against the shareholders' portion of the earnings above 11.00 percent, provided that such reduction in deferrals will not cause the resulting earnings to decrease below an 11.00 percent return on equity. b) The debit deferral amount for purposes of this provision will be determined by netting any credit deferrals against the qualifying debit deferrals. c) The qualifying debit deferrals for purposes of this limitation are comprised of stray voltage, Research and Development, reductions to MDQ (as described in Section IV.C.1.e), variable rate interest, asbestos litigation costs, real property tax, gas balancing software, and "general," meaning other deferrals not addressed in this Joint Proposal that individually exceed 1% of net income. 7. Measurement of Achieved Regulatory Rate of Return on Common Equity for Earnings Sharing Purposes: a) Determinations of the achieved regulatory rate of return on common equity by department, for gas and electric operations, will be made separately for the twelve-month periods ending June 30. 28 b) The achieved regulatory return on common equity will be measured by department on the basis of Central Hudson's actual capitalization for the period being measured; provided, however, that if the actual equity ratio exceeds 47%, then a 47% equity ratio will be used for this purpose. c) The financial consequences of any regulatory incentives, and other exclusions consistent with existing practices, will be excluded in determinations of regulatory rate of return on common equity. C. Reporting. Within 90 days following the end of a rate year, Central Hudson shall provide the Director of the Office of Accounting and Finance with a computation of achieved regulatory rate of return on common equity by department for the preceding period. XI. ADDITIONAL RATE PROVISIONS A. Accounting for Gas Mains/Services. As of January 1, 2006, Central Hudson will implement revised accounting procedures that identify the type of material (i.e., plastic, steel, cast iron, etc.) used in the gas transmission mains, gas distribution mains and gas services recorded in Accounts 367, 376 and 380, respectively. B. Balance Sheet Offsets 1. Projected electric and gas deferred debits and credits to be offset on June 30, 2006 are shown on Appendix G. The net electric deferred balance as of June 30, 2006 will be offset against the Excess Electric Depreciation Reserve. The actual electric balances at June 30, 2006 will be used to record the offset on July 1, 2006. The estimated net excess electric depreciation reserve remaining after offsets and use for rate moderation is also shown on Appendix G. 29 2. The net gas deferred balance as of June 30, 2006 will be recovered over a nominal seven-year period beginning July 1, 2007, the start of RY2; subject to adjustment to the amortization period as may be required in light of variances between the forecast and actual June 30, 2006 balances and recognition of gas "make whole" revenues. Appendix G, Schedule 2 shows the projected net gas balances. The actual gas balances at June 30, 2006 will be used to establish the amount to be recovered. 3. The gas net debit balance shown on Appendix G, Sheet 2 is comprised of a non-interest bearing component and an interest bearing component. a) The non-interest bearing component is amortized on a straight-line basis over seven years beginning July 1, 2007, the start of RY2. b) The balance of the interest-bearing component at July 1, 2007, is amortized over seven years, on a levelized basis recognizing accrued interest on the unamortized balance at the authorized pre-tax rate of return, beginning July 1, 2006. C. Benefit Fund Cessation and Continuing Uses. 1. The Benefit Fund ceases as of June 30, 2006, and the funding previously established for the programs listed below will be preserved. 2. The existing approved uses of the Benefit Fund will continue as follows: a) Rate base offset: $42.5 Million credit continues per prior Commission Order. b) Economic Development: Central Hudson's Economic Revitalization Discount and Economic Development Program shall continue until revised by the Commission or program funding is exhausted. The remaining balance from the $11 million pre-tax set aside in the Commission's Economic Development Order issued October 3, 2002 in Case 00-E-1273, currently estimated at a projected June 30, 2006 pre-tax amount of $4.2 million, will 30 continue to be available to be utilized in accordance with Central Hudson's Economic Revitalization Discount and Economic Development Program until such funding is exhausted or the Program is revised by the Commission. Central Hudson will notify Staff at such time as the Company estimates that the remaining unspent funds will be fully expended within six months. c) Competitive metering: Remaining metering funding balances will be maintained as a stand-alone item reserved for spending on metering purposes. D. Certain Rate Allowances. The amounts shown on Appendix I will be used as the rate allowances for purposes of revenue matching accounting or other deferral purposes as appropriate. E. East Fishkill Substation Deferral. The Company will defer the revenue requirement differences between actual costs and the rate allowance for the East Fishkill Substation incorporated into Appendix A, for future recovery, or return to customers, subject to carrying charges calculated at the authorized pre-tax rate of return in either event. The rate allowance in RY3 for the East Fishkill substation is a placeholder for the actual value, which will not be known until a later time. In the event that the actual costs exceed the estimated costs, the Company will submit a report within 120 days of the project's in-service date detailing the reasons for the increased costs. F. Electric Transmission ROW Maintenance. If actual Electric Transmission ROW Maintenance expenditures during RY1 through RY3 are less than the total RY1 through RY3 level contained in rates of $6.723 million million by the end of RY3, Central Hudson will defer for ratepayer benefit the amount of the shortfall. Commencing July 1, 2009, such deferral 31 will be subject to carrying charges calculated at the authorized pre-tax rate of return. G. Electric Water Heating. Central Hudson will file with the Commission, within 90 days following the Commission Order adopting this Joint Proposal, a proposed plan for unwinding the Company's electric water heating business and exiting from that business. H. Make Whole. The Company is authorized to record gas and electric revenues attributable to the extension of the suspension period. The electric revenues will be offset against the excess depreciation reserve. The gas revenues will be added to the amortization calculation. I. MGP Site Investigation and Remediation Costs. 1. The rate allowances shown on Line 30 of Appendix A and Line 27 of Appendix D are established for MGP Site Remediation Costs. 2. The Company is permitted to defer for future recovery the differences between actual costs for MGP Site Investigation and Remediation Costs and the rate allowances, with carrying charges on the deferred balance (net of tax) for both debit and credit balances at the pre-tax authorized rate of return, including any remaining balance from the Deferred Gas Balances Offset and excluding accrued liabilities. Deferrable expenditures shall exclude Company labor and overhead charges. 3. Annual reporting requirements continue per existing Commission orders, including the Order issued October 25, 2002 in Case 01-G-1821. J. Pension/OPEBs. 1. Central Hudson has been subject to the Commission's Case 91-M-0890, Statement of Policy and Order Concerning the Accounting and Ratemaking Treatment for Pensions and Post- 32 retirement Benefits other than Pensions (issued September 7, 1993) ("Pension and OPEB Policy Statement") and remains subject to the Pension and OPEB Policy Statement. 2. The Company has adopted Staff's position on year end treatment, and made appropriate adjustments on its books. Staff has withdrawn its other objections to the Company's accounting for pensions and OPEBs. K. Property Taxes. The Income Statements in Appendices A and D reflect forecasts of property taxes as rate allowances. The Company is permitted to defer the difference between actual property tax expenses and the forecasts for RY2 and 3 reflected in the Income Statements for future recovery. The differences (positive or negative) will be shared 90/10: Over-collections 90% customers/10% Company and under-collections 10% Company/90% customers. The Company will defer such under-collections and over-collections subject to carrying charges calculated at the Company's authorized pre-tax rate of return. L. Ratemaking Factors. 1. The common cost allocation factor incorporated into Appendices A and D is 85% electric, 15% gas. 2. The electric loss factor incorporated into Appendix A is 1.0420. 3. The factor for lost and unaccounted for gas incorporated into Appendix D is 1.0159. XII. LOW INCOME PROGRAM A. New Low Income Program. Central Hudson will institute a new Low Income Program to replace Central Hudson's current low income program ("Powerful Opportunities" or "POP"). The new program will proceed in two phases. The first phase will be an Interim Program that will replace the POP Program and will continue until the second phase ("Enhanced Powerful Opportunities" or "EPOP") is operational. 33 B. Program Funding and Administration. 1. Effective with the commencement of the Interim Program and continuing with the EPOP Program, Central Hudson will directly administer and manage its low income programs. The costs of administration and management, including staffing, will be included in program expenses and will be paid for through program funding. 2. Program funding for RY1 is $1.148 million, for RY2 is $1.32 million, and for RY3 is $1.50 million and, unless adjusted by Commission Order, for the rate years following will be $1.50 million. 3. Differences between the funding level and actual expenditure during a rate year will be deferred, with carrying charges calculated at the authorized pre-tax rate of return. If such differences are due to over-expenditures, the deferral will be limited to no more than 15% of the rate year funding level, for future recovery by the Company. If such differences are due to under-expenditures, the remaining balance will be rolled over for use in subsequent rate years for low income program expenditures. C. Enhanced Powerful Opportunities. Central Hudson and interested parties will work through a collaborative process to finalize the specific program design, and address implementation and other program issues for the Enhanced Powerful Opportunities Program. Work in this collaborative on some or all aspects of the EPOP program design will begin as soon as possible and no later than 10 days after the Commission's adoption of this Joint Proposal. Working with this collaborative, the Company will complete its development of a detailed EPOP program proposal within 45 days of the Commission's adoption of this Joint Proposal, which will be submitted for Commission approval. Once approved, the EPOP program implementation will be completed as soon as possible but no later than September 1, 2007. 1. The EPOP program design elements that the parties have agreed upon are: 34 a) Eligibility Criteria. The customer must: (1) Use electricity or natural gas as the primary fuel for space heating. (2) Be a HEAP recipient with the HEAP payment paid to Central Hudson. (3) Have arrears of at least $100 remaining after the HEAP payment is applied to the customer's account. (4) Enroll in the Central Hudson Budget Billing Program. (5) Provide a Department of Social Services ("DSS") release for Central Hudson to receive income, expense and other family size verification, and such other information that may be necessary for implementation of the Program. (6) Agree to be referred by Central Hudson to the New York State Energy Research and Development's ("NYSERDA") EmPower NY Program and to complete an application for participation. (7) Renew HEAP eligibility annually. b) Program Elements. (1) In administering the EPOP Program, Central Hudson will refer participants to other local assistance programs and to NYSERDA's EmPower New York Program. (2) The program will be initially designed to serve 800 to 1000 customers on an ongoing basis. Central Hudson will manage participation enrollment to the annual funding level available. (3) Central Hudson will work with DSS to obtain income, expense and family size verification to determine participant eligibility. (4) Central Hudson will have the discretion to include a customer in the program who does not meet all the eligibility criteria upon evidence that program participation will increase the likelihood that the customer will be able to maintain 35 continuous service without compromising other essential household needs. (5) Arrears forgiveness incentive. Collection activity on a participating customer's pre-program arrears will be suspended while the customer is in the program. One twenty-fourth (1/24) of a participating customer's arrears balance, up to a maximum of $100 per month, will be forgiven each month the customer pays current charges on time and in full. A customer failing to make a payment of current charges on time and in full will not receive any arrears forgiveness for that month. The customer may continue in the program for future months by paying the late bill and any associated late payment charges, and paying the bills in future months on time and in full. The arrears forgiveness funded from the program will be provided to program participants over a 24 to 36 month period, if the participant keeps the account current and makes 24 budget bill payments on or before their payment due dates. (6) Customers will not be charged a late payment charge on their suspended arrears, but will be charged a late payment charge if they pay their budget payments late. (7) Customers in the EPOP program will receive an annual bill discount based on their income level and family size. This annual discount amount will be provided over 12 months in monthly bills. The parties will develop the discount amounts and criteria during the collaborative process described above. (8) Participants will exit the program upon completion of the arrears forgiveness provisions of the program or after 24 months, whichever comes later. (9) The Program may be closed to further enrollment each year based on program costs and participant levels. 36 c) The format and schedule for reports will be agreed upon by the parties in the collaborative process described above. As part of the collaborative program design process, the Company and the parties also will describe the content for these reports and the data they will include. An evaluation plan will be developed by the parties for implementation such that the findings are available for consideration for planning regarding the Company's low income program subsequent to Rate Year 3. d) Central Hudson will agree to convene a meeting with Staff and interested parties within 45 days of the conclusion of each rate year to review program operations, accomplishments and spending. If the parties and the Company agree that program modifications are needed, the Company will petition the Commission seeking approval to modify the Program accordingly. D. Interim Program. The parties agree that the Company's current POP program will be replaced by the Interim Program as soon as reasonably feasible. The Interim Program will be reflected in tariffs to be filed timely by the Company so that the Interim Program will be available to existing POP customers when the POP program ends. The Interim Program will have the following program design elements: 1. In administering the Interim Program, Central Hudson will refer participants to other local assistance programs and to the EmPower NY Program. 2. Interim Program Participants must agree to be referred by Central Hudson to NYSERDA's EmPower NY Program and to complete an application for participation. 3. The customers may participate in the program for up to 24 months or until the permanent program is in place, whichever is sooner. 4. Existing POP customers will be automatically enrolled into the interim program. 37 5. New participants must meet the eligibility requirements described above for the EPOP. 6. Participants must agree to budget billing for future bills. 7. Arrears forgiveness incentive. Collection activity on a participating customer's pre-program arrears will be suspended while the customer is in the program. One twenty-fourth (1/24) of the customer's arrears balance up to a maximum of $100 per month will be forgiven each month a participating customer pays current charges on time and in full. A customer failing to make a payment of current charges on time and in full will not receive any arrears forgiveness for that month. The customer may continue in the program for future months by paying the late bill and any associated late payment charges and paying the bills in future months on time and in full. 8. Customers will not be charged a late payment charge on their suspended arrears, but will be charged a late payment charge if they pay their budget payments late. 9. Discounted Customer Charge. The Interim Program will discount the customer charge for participants to $5.00 per month for gas service and to $5.00 per month for electric service ($10 total for dual service customers). 10. Central Hudson will have the discretion to include a customer in the program who does not meet all the eligibility criteria upon evidence that program participation will increase the likelihood that the customer will be able to maintain continuous service without compromising other essential household needs. 11. Reporting. a) Quarterly Reports. (1) Central Hudson will provide Staff and other interested parties with a quarterly report on the Interim Program within 30 days of the end of each Program quarter. The reports will show the following information by month: the number of active program participants, the number of 38 enrollments and departures, the total amount of customer service charge credits provided, amount of arrears forgiven, and administration costs. (2) The quarterly reports may include such other information as the Company and the parties agree may be useful to evaluate the program's impacts on customers and on the Company. (3) An overview of the level of program spending to date should be provided with the intent to keep a check on the level of program spending and budget. b) Annual Reporting. In lieu of a quarterly report for the final operating quarter of the Interim Program in RY1, Central Hudson will prepare an annual report which will provide the same information as in the quarterly reports but on a rate year basis, as well as Central Hudson's assessment of program operations. XIII. CUSTOMER SERVICE QUALITY PERFORMANCE MECHANISM A. Effective Date. The current mechanism set forth in the 2004 Rate Order will remain in effect through December 31, 2006. The new mechanism described below will become effective on January 1, 2007, for a potential total annual rate adjustment of 25 basis points. All basis point rate adjustments for this new mechanism will be calculated on a combined electric and gas basis. B. Customer Satisfaction Index ("CSI"). 1. Central Hudson will calculate its monthly and annual CSI performance consistent with the survey methodology defined in the Central Hudson document entitled "How Did We Do Survey" - Continuous Improvement through Monitoring Customer Satisfaction with Key Customer Processes. 39 2. Thresholds and rate adjustments for the CSI are: ---------------------------------------------------- CSI Annual Performance Basis Points Rate Adjustment ---------------------------------------------------- 85 or Higher None ---------------------------------------------------- 84 = CSI < 85 3.125 ---------------------------------------------------- 83 = CSI <84 6.25 ---------------------------------------------------- 82 = CSI < 83 9.375 ---------------------------------------------------- CSI <82 12.5 ---------------------------------------------------- C. PSC Complaint Rate. 1. The PSC complaint rate is the annual average of the number of monthly complaints per 100,000 customers. 2. The thresholds and rate adjustments are: PSC Annual Basis Point Rate ---------- ---------------- Complaint Rate Adjustment -------------- ---------- <2.5 None 2.5 6.00 2.6 6.65 2.7 7.30 2.8 7.95 2.9 8.60 3.0 9.25 3.1 9.90 3.2 10.55 3.3 11.20 3.4 11.85 3.5 12.50 D. Appointments Kept. The "Appointments Kept" penalty remains at $20 per missed appointment. E. Evaluation of Telephone System Enhancements: 1. Central Hudson will conduct an evaluation of the "virtual hold" telephone enhancements it has made to its telephone answering procedures. The 40 company will report on the results in July 2006, and January and June 2007. 2. Discussions among the parties will be held beginning in July 2007 regarding a possible telephone response metric (and redistribution of the existing 25 Basis Point rate adjustment for CSI/PSC Complaint Rate) to go into effect prospectively. F. Reporting. 1. The Company will provide annual reports to the Director of the Office of Consumer Services (OCS) on its performance under each customer service quality performance measure within 45 days of the end of the reporting period. The annual report shall include information on whether any revenue adjustments are warranted under the Customer Service Quality Performance Mechanism. 2. A Report on the CSI for the period ending December 31, 2006 will be submitted within 45 days of the end of that year. It will include the presentation of quantitative and qualitative analysis of results, and the factors that the Company expects influenced the results, as well as the following: a) The CSI margin of error calculated as shown in Appendix L. b) Number and percent of responses received by each survey type; c) Percent satisfaction for each survey question by survey type; d) Any planned changes in customer service operations due to survey results; and e) An appendix (based primarily on existing materials) that describes in detail the survey and analysis methodology will be included with the first annual report submitted. 41 3. Subsequent to the initial Report, the CSI Report will be filed on an annual basis with the Customer Service Quality Performance Mechanism Report. The company will convene a meeting with interested parties within 30 days of issuing the annual CSI Report to discuss the customer satisfaction survey and any changes in customer service operations proposed as a result of the survey. XIV. GAS SAFETY MECHANISM A. General. All Gas Safety targets metrics are measured on a calendar year basis. The Gas Safety targets and rate adjustment levels applicable in calendar year 2006 are set in the 2004 Rate Plan. The calendar year 2008 Gas Safety targets set forth below will continue until changed by the Commission. Basis point rate adjustments will be calculated on the gas equity component of gas rate base that is shown on Appendix H, Schedule 2. B. Leak Management. 1. For the calendar year ending December 31, 2007, Central Hudson will incur a rate adjustment if a year-end total leak backlog of 270 is exceeded, unless the Company repairs 340 leaks during that calendar year. The rate adjustment if the target thresholds are not met is 6 basis points. 2. For the calendar year ending December 31, 2008, Central Hudson will incur a rate adjustment if a year-end total leak backlog of 250 is exceeded, unless the Company repairs 340 leaks during that calendar year. The rate adjustment if the target thresholds are not met is 8 basis points. C. Prevention of Excavation Damages. 1. Overall Damages. a) For the calendar year ending December 31, 2007, Central Hudson will incur a rate adjustment if the year-end total of 5.9 42 excavation damages per 1000 One-Call Tickets is exceeded during that calendar year. The rate adjustment if the target threshold is not met is 2 basis points. b) For the calendar year ending December 31, 2008, Central Hudson will incur a rate adjustment if the year-end total of 5.8 excavation damages per 1000 One-Call Tickets is exceeded during that calendar year. The rate adjustment if the target threshold is not met is 3 basis points. 2. Mismark Damages. a) Mismarks will be determined based on Central Hudson's current procedures, including recognition of the Tolerance Zone as defined in 16 NYCRR Part 753-1.2(t). b) For the calendar year ending December 31, 2007, Central Hudson will incur a rate adjustment if the year-end total of 0.9 excavation damages due to mismarks per 1000 One-Call Tickets is exceeded during that calendar year. The rate adjustment if the target threshold is not met is 5 basis points. c) For the calendar year ending December 31, 2008, Central Hudson will incur a rate adjustment if the year-end total of 0.8 excavation damages due to mismarks per 1000 One-Call Tickets is exceeded during that calendar year. The rate adjustment if the target threshold is not met is 5 basis points. D. Emergency Response. For the calendar years ending December 31, 2007, and 2008, Central Hudson will incur a rate adjustment if the following targets for response to gas leak and odor calls are not met: (a) respond to 75% of all gas leak and odor calls within 30 minutes, (b) respond to 90% of all gas leak and odor calls within 45 minutes, and (c) respond to 95% of all gas leak and odor calls 43 within 60 minutes. The rate adjustments if the target thresholds are not achieved, are as follows: 2007 - 3 basis points for the 30 minute response time and 2 basis points for each of the 45 and 60 minute response times; 2008 and thereafter - 3 basis points for each of the 30, 45, and 60 minute response times. E. Gas Infrastructure Enhancement. 1. A target of $15.75 million is established for expenditures on Gas Cast Iron/Steel pipe replacement over the three-year period of the Rate Plan, subject to expenditure of no less than $4.5 million in each calendar year, ending 12/31/2009. 2. The $15.75 million amount is comprised of the costs of installation and removal of Gas Cast Iron/Steel pipe replacement associated among: (1) the total category of New Business Gas Service Replacements blanket work orders, (2) the total category of Distribution Improvements Cast Iron Main Replacements blanket work orders, (3) the total category of Distribution Improvements Main Replacement blanket work orders, and (4) the summation of individual Distribution Improvement specific projects involving the replacement of non-plastic gas main. 3. If actual expenditures fall short of the total $15.75 million target level by the end of 2009, Central Hudson will defer for ratepayer benefit the amount of the shortfall multiplied by 1.5 times average authorized pre-tax rate of return. Such deferral shall represent the sole remedy against the Company for failure to make expenditures at the total forecast level for replacement of cast iron and steel mains and services in the categories set forth in subsection 1 above. Commencing on January 1, 2010 such deferral will be subject to carrying charges calculated at the authorized pre-tax rate of return. 4. The $15.75 million target exceeds Central Hudson's forecast of construction costs for 44 these items by $1.15 million. That amount is included in the forecast rate base included in the Income Statements in Appendix D. F. Reporting. 1. Central Hudson will, by January 31st of each year, file a report with the Director of the Office of Gas & Water on its performance in meeting each of the above Gas Safety mechanismss. 2. By August 1 of each calendar year under this Joint Proposal, the Company will file a progress report with the Director of the Office of Gas & Water on its performance in meeting each of the above Gas Safety mechanisms. 3. The Company will cooperate with Staff in making back-up records and documentation related to the targets available for review and verification. XV. ELECTRIC RELIABILITY A. SAIFI And CAIDI Targets. Effective January 1, 2006, for each calendar year, the target for the Customer Average Interruption Duration Index (CAIDI) is set at 2.50, and the target for the System Average Interruption Frequency Index (SAIFI) is set at 1.45. 1. A rate adjustment of 10 basis points (electric) will be assessed against Central Hudson for each failure to satisfy an annual target threshold. 2. Outages caused by "Major Storms," as defined at 16 NYCRR ss.97.1, and the following events, are excluded from the calculation of the indices: a) Any incident resulting from a strike or a catastrophic event beyond the control of the Company, including but not limited to plane crash, water main break, or natural disaster (e.g., hurricane, flood, earthquake). This exclusion does not include heat-related outages. b) Any incident where a problem beyond the Company's control involving generation or the bulk transmission system is the key factor in the outage, including, but not limited to, 45 NYISO mandated load shedding. This criterion is not intended to exclude incidents that occur as a result of unsatisfactory performance by the Company. B. Other Electric Reliability Targets. In addition to the SAIFI and CAIDI targets, reliability-oriented targets for significant construction projects targets are established as follows: 1. Central Hudson will be assessed a rate adjustment of 5 basis points (electric) for RY1, RY2, and RY3, if it does not complete 100 circuit miles of enhanced distribution line clearing during each respective RY. Lines eligible for enhanced clearing are the 300 miles of circuits that were not cleared previously under the Full Circuit Mainline Program that was part of the Enhanced Reliability Program approved in the 2001 Rate Plan. 2. Central Hudson will be assessed a rate adjustment of 5 basis points (electric) if it does not complete and energize its proposed East Kingston substation by June 30, 2007. 3. Central Hudson will be assessed a rate adjustment of 5 basis points for failing to complete reliability-related construction projects in calendar years 2007 and 2008, respectively, similar to the project described in (2) above that will be identified by Staff by January 1, 2007 and 2008, respectively, from among the electric reliability-related projects identified in the Company's updated capital forecasts, which will be presented to Staff during the third quarter of 2006 and 2007, respectively, in the meetings referred to below. C. Other Provisions. 1. The Company will, following the Commission's adoption of this Joint Proposal, petition the Commission for permission to withdraw the Company's pending petition for rehearing of the Commission's Order issued September 30, 2005 concerning electric reliability. The 37.5 basis 46 points penalties for not meeting reliability target thresholds in 2002 and 2004 are reflected in Appendix G. Upon Commission adoption of this Joint Proposal, the Company is authorized to reverse the previous entry of the 2005 reliability penalty. 2. A forecast of 855 employees was recognized in rates for the purpose of allowing Central Hudson to fund the hiring of additional line mechanics. 3. Staff and the Company will meet quarterly in Company operating areas to discuss reliability and employee levels and utilization. 4. The Company will report on its compliance with electric reliability targets within 45 days of the end of each calendar year. 5. This reliability performance mechanism will remain in place until a subsequent approach is adopted by the Commission. XVI. MONTHLY METER READING/BILLING STUDIES A. Monthly Billing Study. Central Hudson will develop and file with the Commission within 150 days following Commission adoption of this Joint Proposal, a study of the costs and benefits of converting from bi-monthly meter reading and billing to monthly meter reading and billing for all customers using existing metering. The study will identify the one-time and on-going incremental costs associated with the conversion to monthly metering and billing and the net effect on the Company revenue requirements. The study will include an implementation plan detailing the period of time that would be needed to accomplish the conversion. The study maybe updated following the completion the AMR Pilot described below. B. AMR Pilot. Central Hudson will develop and file with the Commission by January 1, 2007, an Automated Meter Reading (AMR) Pilot proposal, which will have the following characteristics: 47 1. The AMR Pilot will include 5000 meters (gas and electric combined). 2. A fixed network meter technology will be utilized. 3. The Pilot will be funded from the unused competitive metering funds held in the Benefit Fund, or excess depreciation reserve, up to a total program cost of $1,500,000. 4. Quarterly status reports will be filed with the Director of OCS providing the program status and costs. 5. A final report summarizing the results of twelve months of operational experience, and making any appropriate recommendations, will also be submitted. C. Reporting. Following completion of the final report on the AMR Pilot, Central Hudson may update the study discussed above, to reflect any demonstrated benefits to be realized from implementation of monthly meter reading and billing using AMR technology, and make any appropriate recommendations to the Commission. XVII. RETAIL ACCESS A. Market Match Program. The Market Match Program will continue, consisting of following elements: 1. A system on Central Hudson's Web site enabling the exchange of customer usage data with ESCOs for customers interested in obtaining competitive price offers from ESCOS. 2. Notification informing all non-residential customers of the Program annually via bill inserts or other mailings. 48 3. Responses from customers via the Web site indicating their interest in receiving solicitations for competitive price commodity options, contact information, and authorization for Central Hudson to provide the customer's service class, historical demand, energy consumption, etc. to participating ESCOs. 4. ESCO access to Central Hudson's Web site via a secure Web page that will allow ESCOs to obtain participating customer information and solicit customers by providing competitive price options. 5. Provisions for customers to exit the Market Match Program at any time via the Web site. B. Market Expo Program. The Market Expo Program will continue, consisting of the following elements: 1. The Market Expo will continue to bring the ESCOs, business customers, and Central Hudson together to provide a forum for an exchange of customer data for customers interested in obtaining a competitive price. 2. The Expo will also provide a setting for customers to meet with ESCOs during the day. 3. Staff and Central Hudson will work together to develop the work plan for the Market Expo Program. 4. The work plan will detail how a maximum of two Expos annually should be held, the dates of the Expos, and describe the customers that will be invited. 5. E-mail and/or program announcement letters for ESCOs and customers will be developed and sent out at least two weeks prior to the event(s). 49 6. Central Hudson will: a) Invite all non-residential utility commodity customers sized greater than 100 kW to the Expo. b) Conduct Expos that include giving an overview presentation on the status of the electricity and gas markets in New York, along with an explanation of Central Hudson's retail access rules. C. Energy Fairs. 1. One or two Energy Fairs will be conducted annually by the Company, in collaboration with Staff and ESCOs, prior to the winter heating season in each rate year. 2. Staff, the Company, and ESCOs will meet at least one month prior to the Energy Fairs to discuss the administrative details and logistics of the event. 3. Central Hudson will: a) Secure the location and fund the reasonable logistics costs for the Energy Fair. b) Provide for adequate signage at the location to direct customers to the event. c) Issue invitations to targeted residential and small commercial customers to attend the event at least two weeks prior to the event. d) Issue a press release publicizing the event at least two weeks prior to the event. e) Invite ESCO participation and arrange for reasonable and appropriate ESCO facilities at the event. At least two ESCOs offering residential commodity service must agree to participate in the Energy Fairs prior to advertising the event to the public. 50 f) Current utility customer account data will be made accessible to the customer by the Company at the site of an Energy Fair. D. ESCO & Marketer Satisfaction Mechanism. 1. Central Hudson will conduct annually a telephone or e-mail survey, with a goal of attempting to maintain its current 100% ESCO participation in the survey. 2. Central Hudson will report to the Office of Retail Market Development within 60 days after the survey is conducted, on the results of the survey and its plans for addressing marketer concerns, if any, which were expressed in the survey. E. ESCO Ombudsman. 1. The existing Ombudsman program will continue. 2. Central Hudson shall report quarterly on all ESCO contacts to the Ombudsman to the Director of the Office of Retail Market Development, including a brief description of any issues and concerns expressed to the Ombudsman. F. Competition Awareness and Understanding Survey. 1. Central Hudson will continue to survey a sample of its residential customers annually for the purpose of tracking changes in customer awareness and understanding of competition in electricity and gas markets. 2. The Company will report the results of the survey to the Office of Retail Market Development as a component of its report on its outreach and education plan. G. Competition Education Campaign. Central Hudson's rate allowance includes $350,000 in each of the Rate Years ending June 30, 2007, June 30, 2008, and June 30, 2009 for spending on a competition education campaign aimed at promoting customer migration. The Company will develop the campaign in 51 collaboration with Staff and interested ESCOs. Actual expenditure shortfalls below the $350,000 rate allowances will be deferred for expenditure on the same purposes in future rate years. H. ESCO Referral Program. This Joint Proposal does not affect Central Hudson's ESCO Referral Program, which was approved in an Order issued December 22, 2005 in Case 05-M-0332; provided, however, that incremental costs incurred in implementing the Energy Switch Program to July 1, 2006 will be deferred for future recovery subject to carrying charges at the authorized pre-tax rate of return. XVIII. Further Understandings Between Central Hudson and USMA. A. Best Efforts. Central Hudson and USMA will mutually use best efforts to accomplish the following by June 1, 2006: 1. Provision by Central Hudson to USMA of a quit claim deed, in recordable form, to USMA for all regulators, valves and pipelines and all other natural gas facilities located between Crow's Nest and Thayer Gate, except for the existing six meters (5 for the material balance for USMA and one for Hotel Thayer) along with directly associated regulators and valves supporting these meters. 2. Provision by either USMA or the Army Corps of Engineers, on behalf of USMA, of a written authorization that confirming that, pending receipt of the easement referred to below, CHGE is authorized by the government to have installed its pipelines and other facilities up to Crow's Nest, and that CHGE has the right to enter for purposes of maintenance and repair, subject to reasonable notification procedures. B. Easement. USMA will support CHGE's request for a 50 year standard government easement before the U.S. Army 52 Corps of Engineers for CHGE's pipeline facilities to Crow's Nest and request expedited issuance. C. Refunds of Taxes. Central Hudson will cooperate with USMA concerning USMA's efforts to receive refunds of taxes that have been charged to USMA in CHGE's gas rates for which USMA believes it is not liable; subject to the understandings that the responsibility for identifying the taxes that USMA is interested in and all relevant information (aside from information related to Central Hudson's rates) rests with USMA, that Central Hudson will not perform any legal research for USMA in connection with USMA's tax status, that Central Hudson will not be obliged to make any representations to any taxing authorities as to USMA or USMA's tax status, that Central Hudson makes and will make no representations to USMA concerning USMA's tax responsibility, and that any tax refunds which CHGE receives will be subject to Section 113(2) of the Public Service Law. D. Cost of Service Study. When it next files a new general combined or gas rate case, the Company will include in its gas cost of service study identification of those costs attributable to serving USMA and include with its rate design rates for USMA, or its parent service classification, based on no greater than a 100% revenue allocation of those costs to USMA and based on no greater than a 1.0 factor for application of any system average increase requested; provided, however, that nothing in this provision shall preclude the Company from filing and advocating such cost of service, class rates of return, revenue allocation or rate design as it may deem appropriate. E. Reporting. Subsequent to the time it receives the easement referred to above, Central Hudson will provide to the West Point Contracting Officer an annual report of maintenance, testing, maintenance and repair of all Central Hudson-owned facilities located on-post. The report will be due by February 1 for all such activities conducted during the prior calendar year. 53 XIX. TERMS AND CONDITIONS A. Complete Resolution. This Joint Proposal is intended to be a complete resolution of all issues in Cases 05-E-0934 and 05-G-0935. The Signatories to the Joint Proposal agree that the provisions of the Joint Proposal are, in aggregate, a reasonable resolution of each of the proceedings. Each provision hereof is in consideration and support of all the other provisions, and each Signatory has expressly conditioned its support upon the acceptance of this Joint Proposal in its entirety by the Commission. B. Reservation. In the event that the Commission alters any provision of the Joint Proposal, each Signatory will be deemed to have fully reserved its rights to contest the altered Joint Proposal, and any such alteration. C. Integrated Document. This Joint Proposal is an integrated whole, with each provision in consideration for, in support of, and dependent on the others. Thus, if the Commission does not approve this Joint Proposal in its entirety without modification, each of the Signatories reserves the right to withdraw its participation and support by serving written notice on the Commission and the other Signatories and, if necessary, to litigate, without prejudice, any or all issues as to which such Signatory agreed in this Joint Proposal; in such event, any such Signatory shall not be bound by the provisions of this Joint Proposal, as executed or as modified. D. Dispute Resolution. In the event of any disagreement over the interpretation of this Proposal or the implementation of any of the provisions hereof, which cannot be resolved informally among the Signatories, such disagreement shall be resolved in the following manner: The Signatories shall promptly convene a conference and in good faith shall attempt to resolve 54 such disagreement. If any such disagreement cannot be resolved by the Signatories, an affected Signatory may petition the Commission for relief on a disputed matter. E. Non-Precedent. None of the terms and provisions of this Joint Proposal and none of the positions taken herein by any party may be cited or relied upon by any other party in any fashion as precedent in any proceeding before the Commission, or before any other regulatory agency or any court of law for any purpose, except in furtherance of the purposes and results of the Signatories' settlement. F. Application for New Rates. Central Hudson may file an application(s) for new rates at any time, provided that any such rates will not become effective until after June 30, 2009. Nothing in this provision shall affect the Commission's authority to suspend the effective date of a rate filing. G. Safe and Adequate Service. Central Hudson may petition for new rates at any time on the grounds that without new rates safe, adequate and reliable service at just and reasonable rates would be jeopardized. H. Continued Effect. Unless otherwise provided herein, the provisions of this Joint Proposal shall remain in effect until changed by the Commission. WHEREFORE, this Joint Proposal has been agreed to as of the 17th day of April, 2006, by and among the following, each of whom, by its signature, represents that it is fully authorized to execute this Joint Proposal and, if executing this Joint Proposal in a representative capacity, that it is fully authorized to execute it on behalf of its principal(s). ____________________________ 55 Appendix A, Schedule 1 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Electric Income Statements ($000)
Rate Years Ending ------------------------------ 6/30/07 6/30/08 6/30/09 Line No. (A) (B) (C) - -------- -------- -------- -------- Operating Revenues 1 Delivery Revenues - Before Increase $170,486 $215,741 $225,615 2 Rate Increase - Before Moderation 41,383 6,121 5,529 3 Other Operating Revenues 6,145 6,172 6,196 -------- -------- -------- 4 Total Operating Revenues 218,014 228,034 237,340 -------- -------- -------- Operating Expenses 5 Production Maintenance 143 146 149 6 Transmission Right of Way Maintenance 2,187 2,240 2,296 7 Distribution Right of Way Maintenance 7,804 8,116 8,442 8 Labor 38,920 39,955 40,966 9 Research and Development 1,846 1,857 1,860 10 Expenses Projected Based on Inflation 9,249 9,452 9,660 11 Miscellaneous General Expenses 2,408 2,453 2,498 12 Transportation Depreciation 1,334 1,363 1,393 13 Fringe Benefits 6,011 6,158 6,329 14 Other Post Employee Benefits 8,382 8,382 8,382 15 Pension Plan 10,568 10,568 10,568 16 Contract Rents 2,120 2,167 3,414 17 Uncollectible Accounts 1,199 1,250 1,297 18 Regulatory Commission Expenses 1,349 1,379 1,409 19 Data Processing Expense 3,000 3,066 3,133 20 Other Operating Insurance 1,440 1,472 1,504 21 Telephone 1,550 1,583 1,618 22 Legal Services 2,316 2,367 2,419 23 Special Services 1,483 1,516 1,549 24 Injuries and Damages 1,959 2,002 2,046 25 Storm Expense 5,197 5,311 5,428 26 Environmental 309 316 323 27 Powerful Opportunities Program 976 1,125 1,275 28 Expenses Allocated to Affiliates (491) (502) (513) 29 Stray Voltage Testing 2,200 2,250 2,300 30 MGP Remediation Cost Recovery -- 1,400 1,400 31 Recovery of Net Regulatory Assets -- -- -- 32 Competition Education Program 298 298 298 33 Productivity (149) (149) (149) -------- -------- -------- 33 Total Operating Expenses 113,608 117,541 121,296 -------- -------- -------- 34 Other Deductions 35 Property Taxes 19,758 20,460 21,183 36 Revenue Taxes 3,712 3,963 4,197 37 Payroll Taxes 2,953 3,018 3,084 38 Other Taxes 1,254 1,282 1,310 39 Depreciation 21,682 22,554 23,746 40 Moderator - Amortize Excess Reserves -- -- -- -------- -------- -------- 41 Total Other Deductions 49,359 51,277 53,520 -------- -------- -------- 42 State Income Taxes 2,942 3,099 3,184 43 Federal Income Taxes 13,753 15,130 15,450 -------- -------- -------- 44 Total Income Taxes 16,695 18,230 18,634 -------- -------- -------- 45 Total Operating Revenue Deductions 179,662 187,048 193,450 -------- -------- -------- 46 Operating Income $ 38,353 $ 40,986 $ 43,890 ======== ======== ======== 47 Rate Base $544,007 $578,065 $615,375 ======== ======== ======== 48 Rate of Return 7.05% 7.09% 7.13% ======== ======== ========
Appendix A, Schedule 2 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Electric Rate Increase Phase-In ($000)
Rate Years Ending -------------------------------- 6/30/07 6/30/08 6/30/09 --------- --------- -------- Line No. (A) (B) (C) - -------- --------- --------- -------- Electric Rate Increase Phase-In: 1 Required Electric Rate Increases $ 41,383 $ 6,121 $ 5,529 Moderation of Rate Increases: 2 RY1 Moderation (23,495) 23,918 3 RY2 Moderation (12,150) 12,357 4 RY3 Moderation 0 --------- --------- -------- 5 Phase-In Electric Rate Increases $ 17,888 $ 17,889 $ 17,888 ========= ========= ======== Use of Moderators: 6 Amount of Moderators ($ 22,887) ($ 11,840) $ 0 7 / Gross up Factor 0.97410 0.97410 0.97410 --------- --------- -------- 8 Revenue Requirement ($ 23,495) ($ 12,150) $ 0 ========= ========= ======== Loss of Revenue Growth Due to Phase-In: 9 RY1 Moderation ($ 23,495) 10 x Revenue Growth Rate 1.018 = $ 23,918 --------- ========= 11 RY2 Moderation (12,150) 12 x Revenue Growth Rate 1.017 = $ 12,357 -------- ========
Appendix A, Schedule 3 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Electric Rate Base ($000)
Electric ----------------------------------- Rate Years Ending ----------------------------------- 6/30/07 6/30/08 6/30/09 --------- --------- --------- Book Cost of Utility Plant $ 862,277 $ 907,246 $ 960,008 Less: Accumulated Provision for Depreciation and Amortization (302,582) (314,239) (327,595) --------- --------- --------- Net Plant 559,695 593,007 632,413 Noninterest-Bearing Construction Work in Progress 39,705 44,887 48,105 Preliminary Survey & Investigation 0 0 0 Customer Advances for Undergrounding (179) (179) (179) Deferred Charges 14,978 14,773 13,347 Accumulated Deferred Federal Taxes (90,257) (94,567) (98,715) Accumulated Deferred State Taxes (2,739) (3,468) (4,206) Working Capital 30,425 31,232 32,232 --------- --------- --------- Unadjusted Rate Base 551,628 585,686 622,996 Capitalization Adjustment to Rate Base (7,621) (7,621) (7,621) --------- --------- --------- Total $ 544,007 $ 578,065 $ 615,375 ========= ========= =========
Appendix B Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Electric Revenue Allocation Min .75x, Max 1.25x, S.C. No. 13 Set to S.C. No. 1 Average Rate Year 1
(1) (2) (3) (4) (5) Rate Adj Adj to Initial Net of 2.59% Net Initial Net Income Return +/- 15% Income Income ----------- ------- ------- -------- ----------- Total $ 14,142 2.59% $ 12,973 $ 14,142 SC 1 Residential $ 6,564 1.94% 2.20% $ 7,449 $ 8,120 SC 2 Non Demand $ (2,377) -6.36% 2.20% $ 823 $ 897 SC 2 Secondary $ 7,650 7.77% 2.98% $ 2,934 $ 3,198 SC 2 Primary $ 460 4.65% 2.98% $ 295 $ 321 SC 3 Primary $ 1,064 7.18% 2.98% $ 442 $ 481 SC 5 Area Lighting $ 148 2.45% $ 148 $ 161 SC 6 Residential TOU $ 497 8.65% 2.98% $ 171 $ 187 SC 8 Street Lighting $ (52) -0.63% 2.20% $ 182 $ 198 SC 13 Substation $ 56 1.36% 2.20% $ 91 $ 99 SC 13 Transmission $ 132 0.66% 2.20% $ 440 $ 480 SC 9 Traffic Signals $ (49) -16.22% 2.20% $ 7 $ 7 Excludes Revenue Taxes --------------------------------- (6) (7) (8) (9) (10) (11) (5)-(1) (6)/.60125 (7)+(9) (10)/(8) Adj Base Base Rev Total % Increase Difference FIT/SIT Rates Increase Increase Unadjusted ---------- ---------- --------- -------- -------- ---------- Total $ 167,722 $ 17,433 $ 17,433 10.39% SC 1 Residential $ 1,556 $ 2,588 $ 101,450 $ 10,545 $ 13,132 12.94% SC 2 Non Demand $ 3,274 $ 5,445 $ 7,416 $ 771 $ 6,216 83.82% SC 2 Secondary $ (4,452) $ (7,404) $ 38,878 $ 4,041 $ (3,363) -8.65% SC 2 Primary $ (139) $ (231) $ 3,353 $ 349 $ 118 3.52% SC 3 Primary $ (583) $ (969) $ 5,630 $ 585 $ (384) -6.82% SC 5 Area Lighting $ 13 $ 22 $ 917 $ 95 $ 117 12.81% SC 6 Residential TOU $ (310) $ (516) $ 2,311 $ 240 $ (276) -11.94% SC 8 Street Lighting $ 250 $ 416 $ 2,578 $ 268 $ 684 26.52% SC 13 Substation $ 43 $ 71 $ 1,184 $ 123 $ 194 16.40% SC 13 Transmission $ 348 $ 578 $ 4,005 $ 416 $ 994 24.83% Tot. Rev. --------- SC 9 Traffic Signals $ 56 $ 94 $ 176 53.15%
(12) (13) (14) (15) (16) (17) (8)*(12) (8)*(13) (14)+(15) (10)-(16) % Increase % Increase $ Increase $ Increase Revenue Constrained Unadjusted Constrained Unadjusted Total Shortfall ----------- ---------- ----------- ---------- --------- --------- $ 5,219 $ 13,921 $ 19,140 $ (1,707) SC 1 Residential 0.00% 12.94% $ -- $ 13,132 $ 13,132 $ (1,257) SC 2 Non Demand 12.99% 0.00% $ 964 $ -- $ 964 $ -- SC 2 Secondary 7.80% 0.00% $ 3,031 $ -- $ 3,031 $ (290) SC 2 Primary 7.80% 0.00% $ 261 $ -- $ 261 $ (25) SC 3 Primary 7.80% 0.00% $ 439 $ -- $ 439 $ (42) SC 5 Area Lighting 0.00% 12.81% $ -- $ 117 $ 117 $ (11) SC 6 Residential TOU 7.80% 0.00% $ 180 $ -- $ 180 $ (17) SC 8 Street Lighting 12.99% 0.00% $ 335 $ -- $ 335 $ -- SC 13 Substation 0.00% 12.94% $ -- $ 153 $ 153 $ (15) SC 13 Transmission 0.00% 12.94% $ -- $ 518 $ 518 $ (50) SC 9 Traffic Signals 5.20% $ 9 $ 9 $ (1) (18) (19) (20) (21) (22) (23) (16)+(17) (18)/(8) (18)+(20) (21)/(8) (18)/(18) System Revenue Revenue Revenue Adj Final Increase as a $ Increase % Increase Adjustment $ Increase % Increase % of System ---------- ---------- ---------- ---------- ---------- ---------------- $ 17,433 10.39% $ 17,434 10.39% 100.00% SC 1 Residential $ 11,876 11.71% $ (34) $ 11,842 11.67% 68.11% SC 2 Non Demand $ 964 12.99% $ (3) $ 961 12.95% 5.53% SC 2 Secondary $ 2,741 7.05% $ (8) $ 2,733 7.03% 15.72% SC 2 Primary $ 236 7.05% $ (1) $ 235 7.02% 1.36% SC 3 Primary $ 397 7.05% $ (1) $ 396 7.03% 2.28% SC 5 Area Lighting $ 106 11.59% $ -- $ 106 11.59% 0.61% SC 6 Residential TOU $ 163 7.05% $ -- $ 163 7.05% 0.93% SC 8 Street Lighting $ 335 12.99% $ (1) $ 334 12.95% 1.92% SC 13 Substation $ 139 11.71% $ -- $ 139 11.71% 0.80% SC 13 Transmission $ 469 11.71% $ (1) $ 468 11.68% 2.69% SC 9 Traffic Signals $ 8 4.70% $ 50 $ 58 33.11% 0.05%
Increase -------- Avg. 10.39% Min 0.75x 7.80% Max 1.25x 12.99% Rate Years 2 & 3
Rate Year 2 ----------------------------------------------------- Increase as a Base Rev % Adj. for Rev Unbundled to MFCs % of System Increase Increase MWh MFC/kWh Total ------------- -------- -------- --------- --------- ------- Total 100.00% $ 17,434 9.42% $ 8,766 SC 1 Residential 68.11% $ 11,874 10.48% 2,123,820 $ 0.00321 $ 6,817 SC 2 Non Demand 5.53% $ 964 11.51% 187,020 $ 0.00072 $ 135 SC 2 Secondary 15.72% $ 2,741 6.59% 1,501,650 $ 0.00072 $ 1,081 SC 2 Primary 1.36% $ 237 6.61% 240,630 $ 0.00072 $ 173 SC 3 Primary 2.28% $ 397 6.60% 385,910 $ 0.00021 $ 81 SC 5 Area Lighting 0.61% $ 106 10.39% 14,210 $ 0.00082 $ 12 SC 6 Residential TOU 0.93% $ 162 6.55% 54,000 $ 0.00321 $ 173 SC 8 Street Lighting 1.92% $ 335 11.50% 22,460 $ 0 00082 $ 18 SC 13 Substation 0.80% $ 139 10.55% 165,620 $ 0.00021 $ 35 SC 13 Transmission 2.69% $ 469 10.48% 1,134,220 $ 0.00021 $ 238 SC 9 Traffic Signals 0.05% $ 9 14.96% 3,430 $ 0.00082 $ 3 Rate Year 3 ----------------------------------------------------- Base Rev % Adj. for Rev Unbundled to MFCs Increase Increase MWh MFC/kWh Total -------- -------- --------- --------- ------- Total $ 17,433 8.61% $ 8,942 SC 1 Residential $ 11,874 9.49% 2,168,620 $ 0.00321 $ 6,961 SC 2 Non Demand $ 964 10.32% 188,290 $ 0.00072 $ 136 SC 2 Secondary $ 2,740 6.18% 1,537,710 $ 0.00072 $ 1,107 SC 2 Primary $ 237 6.20% 244,970 $ 0.00072 $ 176 SC 3 Primary $ 397 6.19% 392,270 $ 0.00021 $ 82 SC 5 Area Lighting $ 106 9.41% 14,540 $ 0.00082 $ 12 SC 6 Residential TOU $ 162 6.15% 54,000 $ 0.00321 $ 173 SC 8 Street Lighting $ 335 10.31% 22,390 $ 0.00082 $ 18 SC 13 Substation $ 139 9.54% 165,620 $ 0.00021 $ 35 SC 13 Transmission $ 469 9.49% 1,136,850 $ 0.00021 $ 239 SC 9 Traffic Signals $ 9 13.01% 3,410 $ 0.00082 $ 3
Appendix C Sheet 1 of 8 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Summary of Proposed Monthly Electric Delivery Rates (Excludes S.C. Nos. 5 & 8)
Current Rates Rate Year 1 Rate Year 2 Rate Year 3 ------------- ----------- ----------- ----------- S.C. No. 1 Customer Charge $ 12.00 $ 13.50 $ 15.00 $ 16.00 kWh $ 0.03167 $ 0.03523 $ 0.03544 $ 0.03955 S.C. No. 2 - Non-Demand Customer Charge $ 14.00 $ 16.00 $ 18.00 $ 20.00 kWh $ 0.01432 $ 0.01583 $ 0.01662 $ 0.01810 S.C. No. 2 - Secondary Customer Charge $ 20.00 $ 23.50 $ 27.00 $ 30.00 kWh $ 0.00486 $ 0.00501 $ 0.00431 $ 0.00431 kW $ 6.18 $ 6.61 $ 7.07 $ 7.53 S.C. No. 2 - Primary Customer Charge $ 80.00 $ 90.00 $ 100.00 $ 110.00 kWh $ 0.00107 $ 0.00116 $ 0.00126 $ 0.00135 kW $ 4.61 $ 4.91 $ 4.94 $ 5.23 S.C. No. 3 Customer Charge $ 250.00 $ 400.00 $ 400.00 $ 400.00 kWh $ 0.00250 $ -- $ -- $ -- kW $ 5.22 $ 6.69 $ 7.05 $ 7.49 Rkva $ 0.44 $ 0.44 $ 0.44 $ 0.44 S.C. No. 6 Customer Charge $ 12.00 $ 14.50 $ 17.00 $ 19.00 On-Peak kWh $ 0.06423 $ 0.06708 $ 0.06418 $ 0.06751 Off-Peak kWh $ 0.02141 $ 0.02236 $ 0.02139 $ 0.02250 S.C. No. 9 - Traffic Signals Charge per Signal Face $ -- $ 1.90 $ 2.10 $ 2.40 S.C. No. 13 - Substation Customer Charge $ 500.00 $ 500.00 $ 500.00 $ 500.00 kWh $ 0.00150 $ -- $ -- $ -- kW $ 2.90 $ 4.18 $ 4.52 $ 4.98 Rkva $ 0.44 $ 0.44 $ 0.44 $ 0.44 S.C. No. 13 - Transmission Customer Charge $ 500.00 $ 500.00 $ 500.00 $ 500.00 kWh $ 0.00100 $ -- $ -- $ -- kW $ 1.52 $ 2.39 $ 2.51 $ 2.75 Rkva $ 0.44 $ 0.44 $ 0.44 $ 0.44
Appendix C Sheet 2 of 8 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Electric Billing Determinants (Excludes S.C. Nos. 5 & 8, Unbilled & Interdepartmental)
Rate Year 1 Rate Year 2 Rate Year 3 ------------- ------------- ------------- S.C. No. 1 Customer Months 2,978,064 3,000,048 3,020,808 kWh 2,074,960,000 2,123,820,000 2,168,620,000 S.C. No. 2 - Non-Demand Customer Months 339,696 341,112 342,648 kWh 185,770,000 187,020,000 188,290,000 S.C. No. 2 - Secondary Customer Months 140,364 143,964 147,936 kWh 1,463,470,000 1,501,650,000 1,537,710,000 kW 4,685,870 4,808,210 4,923,750 S.C. No. 2 - Primary Customer Months 2,100 2,148 2,184 kWh 235,970,000 240,630,000 244,970,000 kW 636,180 648,750 660,450 S.C. No. 3 Customer Months 540 552 564 kWh 379,190,000 385,910,000 392,270,000 kW 861,380 876,650 891,130 Rkva 115,280 117,320 119,230 S.C. No. 6 Customer Months 30,720 30,720 30,720 On-Peak kWh 18,360,000 18,360,000 18,360,000 Off-Peak kWh 35,640,000 35,640,000 35,640,000 S.C. No. 9 - Traffic Signals Signal Face Months 30,734.16 30,734.16 30,554.95 S.C. No. 13 - Substation Customer Months 84 84 84 kWh 165,620,000 165,620,000 165,620,000 kW 302,507 304,716 304,716 Rkva 37,250 37,250 37,250 S.C. No. 13 - Transmission Customer Months 96 96 96 kWh 1,135,560,000 1,134,220,000 1,136,850,000 kW 1,839,929 1,907,337 1,911,580 Rkva 56,140 56,140 56,140
Appendix C Sheet 3 of 8 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Electric Commodity Related Merchant Function Charges MFC (A) MFC (B) MFC (T) Applicable to S. C. No. $/kWh $/kWh $/kWh ------- ------- ------- MFC-1 1 & 6 0.00145 0.00176 0.00321 MFC-2 2 0.00037 0.00035 0.00072 MFC-3 3 & 13 0.00013 0.00008 0.00021 MFC-4 5, 8 & 9 0.00013 0.00069 0.00082 Notes: 1. Customers taking commodity service from Central Hudson will be billed by Central Hudson for MFC(T), which is equal to the sum of MFC(A) and MFC(B). 2. MFC(A) will include the allocated portion of collection function costs and 50% of procurement-related call center function costs, plus administrative & general and rate base items associated with each of these items. Customers that choose to purchase their commodity service from an energy services company (ESCO) that is participating in Central Hudson's Purchase of Receivables (POR) Program will be billed by Central Hudson for MFC(A) only. 3. MFC(B) will include commodity purchasing function costs, allocated portions of advertising & promotions function costs and 50% of procurement-related call center function costs, plus administrative & general and rate base items associated with each of these items. Appendix C Sheet 4 of 8 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Electric & Gas Embedded Cost of Service Studies Summary of Revisions to Exhibits (LGA-1) & (LGA-2): o The delivery/commodity relationship used for the functionalization of certain unbundled costs within the electric and gas embedded cost of service studies was revised to reflect the delivery/commodity relationship of revenues for the twelve months ended December 31, 2005. o Procurement Function - The Company developed a new allocation factor to replace the "ENERGY" COS class allocation factor for the "Procurement Function" shown on Exhibits ____(LGA-2), Schedule C, Page 1 (electric) and ____(LGA-1), Schedule C, Page 1 (gas). The new allocator is a blended factor that attributes the components of the procurement function to the COS classes as follows: o CHG&E Commodity-buyers costs - allocated to classes on ENERGY as per the company's negotiated revisions to the rate year #1 sales forecast by class; o Credit and Collections on Commodity - allocated to the COS classes on number of customers via the CODBT allocation factor; o Call Center costs related to Commodity - allocated to COS classes on number of customers via CODBT allocation factor. o Delivery Service Uncollectibles, Credit and Collections: o All of Line 28 was redistributed vertically within each COS class to all other functions except "Procurement" re: Exhibit _____(LGA-1), Schedule C, Page 1 (gas); o All of Line 31 was re-distributed vertically within each COS class to all functions other than "Procurement". re: Exhibit_(LGA-2), Schedule C, Page 1. o The amount originally (mistakenly) attributed to electric O&M account 565 was re-distributed among the other O&M Transmission accounts; o Gas(i) and Electric demand, sales, revenue and customer allocators were revised to reflect Staff and Company revisions to the gas and electric sales forecasts. The demand allocators for SD, PD, LGP, LGS and LGT were developed from Ms. Bunt's forecasts; o The classification of electric distribution lines was revised per agreement with Staff witness Allen; o The inputs to the gas and electric rate year #1 COS studies were revised to reflect Staff rate year #1 Income Statement changes to rate base, revenues, O&M and taxes as provided to the Company for electric and gas. - ---------- (i) Some specific changes included elimination of < 6" lines from West Point gross plant; reduction of West Point MDQ from 7104 to 5833 Mcf; reduction in SC11 transmission customers and sales due to closure of IBM West complex. Appendix C Sheet 5 of 8 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Comparison of Present and Proposed Electric Rates Single Phase Residential Service Service Classification No. 1 - General Service Energy kWh Present Rates Proposed Rates Change ($) Change (%) - ---------- ------------- -------------- ---------- ---------- -- $ 12.29 $ 13.82 $ 1.54 12.50% 12 $ 13.48 $ 15.06 $ 1.58 11.72% 25 $ 14.77 $ 16.40 $ 1.63 11.02% 50 $ 17.25 $ 18.97 $ 1.72 9.96% 75 $ 19.73 $ 21.54 $ 1.81 9.17% 100 $ 22.21 $ 24.11 $ 1.90 8.56% 132 $ 25.39 $ 27.41 $ 2.02 7.94% 150 $ 27.18 $ 29.26 $ 2.08 7.66% 175 $ 29.66 $ 31.83 $ 2.17 7.33% 200 $ 32.14 $ 34.40 $ 2.26 7.05% 250 $ 37.10 $ 39.55 $ 2.45 6.60% 300 $ 42.07 $ 44.69 $ 2.63 6.25% 350 $ 47.03 $ 49.84 $ 2.81 5.98% 400 $ 51.99 $ 54.98 $ 2.99 5.76% 450 $ 56.95 $ 60.13 $ 3.18 5.58% 500 $ 61.92 $ 65.28 $ 3.36 5.42% 600 $ 71.84 $ 75.57 $ 3.72 5.18% 700 $ 81.77 $ 85.86 $ 4.09 5.00% 800 $ 91.69 $ 96.15 $ 4.45 4.86% 900 $ 101.62 $ 106.44 $ 4.82 4.74% 1,000 $ 111.55 $ 116.73 $ 5.18 4.64% 1,200 $ 131.40 $ 137.31 $ 5.91 4.50% 1,500 $ 161.18 $ 168.18 $ 7.00 4.35% 2,000 $ 210.81 $ 219.63 $ 8.83 4.19% 2,500 $ 260.43 $ 271.08 $ 10.65 4.09% 3,000 $ 310.06 $ 322.54 $ 12.47 4.02% 3,500 $ 359.69 $ 373.99 $ 14.29 3.97% 4,000 $ 409.32 $ 425.44 $ 16.12 3.94% 4,500 $ 458.95 $ 476.89 $ 17.94 3.91% 5,000 $ 508.58 $ 528.34 $ 19.76 3.89% 10,000 $ 1,004.88 $ 1,042.86 $ 37.99 3.78% 20,000 $ 1,997.46 $ 2,071.90 $ 74.44 3.73% The following rates were used in the development of these bills: Market Price Charge $ 0.06701 per kWh Market Price Adjustment $ -- per kWh Purchased Power Adjustment $ (0.00225) per kWh Miscellaneous Charges $ 0.00066 per kWh SBC/RPS $ 0.00116 per kWh Revenue Tax Rate - Commodity 0.339% Revenue Tax Rate - Delivery 2.339% Appendix C Sheet 6 of 8 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Comparison of Present and Proposed Electric Rates Non-Demand Metered Service Classification No. 2 - General Service Energy kWh Present Rates Proposed Rates Change ($) Change (%) - ---------- ------------- -------------- ---------- ---------- -- $ 14.05 $ 16.05 $ 2.01 14.29% 12 $ 15.02 $ 17.05 $ 2.02 13.48% 25 $ 16.08 $ 18.12 $ 2.04 12.72% 50 $ 18.11 $ 20.19 $ 2.08 11.50% 75 $ 20.14 $ 22.26 $ 2.12 10.53% 100 $ 22.17 $ 24.32 $ 2.16 9.74% 132 $ 24.76 $ 26.97 $ 2.21 8.91% 150 $ 26.22 $ 28.46 $ 2.23 8.52% 175 $ 28.25 $ 30.53 $ 2.27 8.04% 200 $ 30.28 $ 32.59 $ 2.31 7.63% 500 $ 54.64 $ 57.40 $ 2.76 5.06% 750 $ 74.93 $ 78.07 $ 3.14 4.19% 1,000 $ 95.22 $ 98.74 $ 3.52 3.70% 2,500 $ 216.99 $ 222.78 $ 5.79 2.67% 5,000 $ 419.92 $ 429.51 $ 9.58 2.28% 10,000 $ 825.80 $ 842.96 $ 17.16 2.08% 20,000 $ 1,637.55 $ 1,669.86 $ 32.31 1.97% The following rates were used in the development of these bills: Market Price Charge $ 0.06701 per kWh Market Price Adjustment $ -- per kWh Purchased Power Adjustment $ (0.00225) per kWh Miscellaneous Charges $ 0.00066 per kWh SBC/RPS $ 0.00116 per kWh Revenue Tax Rate - Commodity 0.339% Revenue Tax Rate - Delivery 0.339% Appendix C Sheet 7 of 8 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Comparison of Present and Proposed Electric Rates Small General Demand Metered Service Service Classification No. 2 - Secondary Customers
Demand kW Energy kWh Present Rates Proposed Rates Change ($) Change (%) - ---------- ---------- ------------- -------------- ---------- ---------- 7 2,500 $ 242.68 $ 249.59 $ 6.91 2.85% 10 2,500 $ 261.29 $ 269.49 $ 8.20 3.14% 17 2,500 $ 304.69 $ 315.92 $ 11.22 3.68% 14 5,000 $ 465.30 $ 475.60 $ 10.30 2.21% 20 5,000 $ 502.50 $ 515.40 $ 12.89 2.57% 33 5,000 $ 583.12 $ 601.62 $ 18.50 3.17% 29 10,000 $ 916.73 $ 934.26 $ 17.53 1.91% 40 10,000 $ 984.94 $ 1,007.21 $ 22.28 2.26% 67 10,000 $ 1,152.37 $ 1,186.29 $ 33.93 2.94% 57 20,000 $ 1,807.19 $ 1,838.30 $ 31.12 1.72% 80 20,000 $ 1,949.81 $ 1,990.85 $ 41.04 2.10% 133 20,000 $ 2,278.46 $ 2,342.37 $ 63.91 2.80% 90 50,000 $ 4,162.31 $ 4,212.18 $ 49.87 1.20% 115 50,000 $ 4,317.34 $ 4,377.99 $ 60.66 1.40% 230 50,000 $ 5,030.45 $ 5,140.73 $ 110.27 2.19% 175 100,000 $ 8,273.55 $ 8,367.62 $ 94.07 1.14% 230 100,000 $ 8,614.60 $ 8,732.40 $ 117.80 1.37% 460 100,000 $ 10,040.84 $ 10,257.87 $ 217.04 2.16% 350 200,000 $ 16,527.03 $ 16,711.65 $ 184.63 1.12% 460 200,000 $ 17,209.14 $ 17,441.23 $ 232.09 1.35% 920 200,000 $ 20,061.61 $ 20,492.17 $ 430.56 2.15% 520 300,000 $ 24,749.50 $ 25,022.53 $ 273.03 1.10% 700 300,000 $ 25,865.68 $ 26,216.37 $ 350.69 1.36% 700 400,000 $ 33,033.99 $ 33,399.73 $ 365.74 1.11% 920 400,000 $ 34,398.21 $ 34,858.87 $ 460.66 1.34% 868 500,000 $ 41,244.06 $ 41,697.33 $ 453.28 1.10%
The following rates were used in the development of these bills: Market Price Charge $ 0.06701 per kWh Market Price Adjustment $ -- per kWh Purchased Power Adjustment $ (0.00225) per kWh Miscellaneous Charges $ 0.00066 per kWh SBC/RPS $ 0.00116 per kWh Revenue Tax Rate - Commodity 0.339% Revenue Tax Rate - Delivery 0.339% Appendix C Sheet 8 of 8 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Comparison of Present and Proposed Electric Rates Small General Demand Metered Service Service Classification No. 2 - Primary Customers
Demand kW Energy kWh Present Rates Proposed Rates Change ($) Change (%) - --------- ---------- ------------- -------------- ---------- ---------- 7 2,500 $ 282.35 $ 294.72 $ 12.37 4.38% 10 2,500 $ 296.23 $ 309.50 $ 13.27 4.48% 17 2,500 $ 328.61 $ 343.99 $ 15.38 4.68% 14 5,000 $ 484.43 $ 499.13 $ 14.70 3.03% 20 5,000 $ 512.19 $ 528.69 $ 16.51 3.22% 33 5,000 $ 572.32 $ 592.74 $ 20.42 3.57% 29 10,000 $ 893.22 $ 912.88 $ 19.67 2.20% 40 10,000 $ 944.10 $ 967.08 $ 22.98 2.43% 67 10,000 $ 1,068.99 $ 1,100.10 $ 31.11 2.91% 57 20,000 $ 1,701.54 $ 1,730.54 $ 29.00 1.70% 80 20,000 $ 1,807.93 $ 1,843.85 $ 35.92 1.99% 133 20,000 $ 2,053.09 $ 2,104.97 $ 51.88 2.53% 90 50,000 $ 3,890.59 $ 3,932.23 $ 41.64 1.07% 115 50,000 $ 4,006.23 $ 4,055.40 $ 49.17 1.23% 230 50,000 $ 4,538.18 $ 4,621.97 $ 83.78 1.85% 175 100,000 $ 7,677.78 $ 7,749.52 $ 71.74 0.93% 230 100,000 $ 7,932.19 $ 8,020.49 $ 88.30 1.11% 460 100,000 $ 8,996.10 $ 9,153.63 $ 157.53 1.75% 350 200,000 $ 15,275.28 $ 15,408.74 $ 133.45 0.87% 460 200,000 $ 15,784.11 $ 15,950.67 $ 166.56 1.06% 920 200,000 $ 17,911.92 $ 18,216.96 $ 305.03 1.70% 520 300,000 $ 22,849.66 $ 23,043.32 $ 193.66 0.85% 700 300,000 $ 23,682.28 $ 23,930.12 $ 247.84 1.05% 700 400,000 $ 30,470.29 $ 30,727.17 $ 256.87 0.84% 920 400,000 $ 31,487.94 $ 31,811.04 $ 323.10 1.03% 868 500,000 $ 38,035.42 $ 38,351.89 $ 316.47 0.83%
The following rates were used in the development of these bills: Market Price Charge $ 0.06701 per kWh Market Price Adjustment $ -- per kWh Purchased Power Adjustment $ (0.00225) per kWh Miscellaneous Charges $ 0.00066 per kWh SBC/RPS $ 0.00116 per kWh Revenue Tax Rate - Commodity 0.339% Revenue Tax Rate - Delivery 0.339% Appendix D, Schedule 1 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Gas Income Statements ($000)
Rate Years Ending -------------------------------- 6/30/07 6/30/08 6/30/09 Line No. (A) (B) (C) - -------- -------- --------- --------- Operating Revenues 1 Gas Delivery Revenues - Before Increase $ 42,041 $ 51,457 $ 59,008 2 Rate Increase 8,003 6,057 -- 3 Interruptible & Sales to Generators 1,000 1,000 1,000 4 Other Operating Revenues 1,982 914 943 -------- --------- --------- 5 Total Operating Revenues 53,027 59,428 60,950 6 Operating Expenses 7 Labor 9,523 9,820 10,101 8 Research and Development 299 304 306 9 Expenses Projected Based on Inflation 3,064 3,131 3,200 10 Miscellaneous General Expenses 462 470 479 11 Transportation - Depreciation 341 349 356 12 Fringe Benefits 1,369 1,403 1,442 13 Other Post Employee Benefits (OPEB) 1,943 1,943 1,943 14 Pension Plan 2,413 2,413 2,413 15 Environmental 64 65 67 16 Contract Rents 187 191 195 17 Uncollectible Accounts 462 531 545 18 Regulatory Commission Expenses 380 388 397 19 Data Processing Expense 527 539 550 20 Other Operating Insurance 214 219 224 21 Telephone 225 230 236 22 Legal Services 576 589 602 23 Special Services 324 331 338 24 Injuries and Damages 448 458 468 25 Powerful Opportunities Program 172 199 225 26 Expenses Allocated to Affiliates (87) (89) (91) 27 MGP Remediation Cost Recovery -- 250 250 28 Recovery of Net Requlatory Assets -- 4,274 4,346 29 Competition Education Program 53 53 53 30 Productivity (34) (34) (34) -------- --------- --------- 31 Total Operating Expenses 22,925 28,026 28,611 -------- --------- --------- Other Deductions 32 Property Taxes 5,342 5,531 5,727 33 Revenue Taxes 1,022 1,244 1,288 34 Payroll Taxes 680 695 710 35 Other Taxes 173 177 181 36 Depreciation 6,478 6,335 6,192 -------- --------- --------- 37 Total Other Deductions 13,695 13,981 14,098 -------- --------- --------- 38 State Income Taxes 984 1,054 1,110 39 Federal Income Taxes 4,885 5,243 5,475 -------- --------- --------- 40 Total Income Taxes 5,869 6,296 6,585 -------- --------- --------- 41 Total Operating Revenue Deductions 42,489 48,304 49,294 -------- --------- --------- 42 Operating Income 10,538 11,124 11,657 ======== ========= ========= 43 Rate Base $149,521 $ 156,889 $ 163,440 ======== ========= ========= 44 Rate of Return 7.05% 7.09% 7.13% ======== ========= =========
Appendix D, Schedule 2 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Gas Rate Base
Gas -------------------------------- Rate Years Ending -------------------------------- 6/30/07 6/30/08 6/30/09 --------- --------- --------- Book Cost of Utility Plant $ 250,779 $ 265,176 $ 279,055 Less: Accumulated Provision for Depreciation and Amortization (94,887) (100,183) (105,299) --------- --------- --------- Net Plant 155,892 164,993 173,756 Noninterest-Bearing Construction Work in Progress 9,930 10,207 10,319 Preliminary Survey & Investigation 0 0 0 Customer Advances for Undergrounding (2) (2) (2) Deferred Charges 4,382 4,247 3,877 Accumulated Deferred Federal Taxes (24,504) (26,326) (28,221) Accumulated Deferred State Taxes (206) (419) (638) Working Capital 6,569 6,729 6,889 --------- --------- --------- Unadjusted Rate Base 152,061 159,429 165,980 Capitalization Adjustment to Rate Base (2,540) (2,540) (2,540) --------- --------- --------- Total $ 149,521 $ 156,889 $ 163,440 ========= ========= =========
Appendix E Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Gas Cost of Service Summary
- ------------------------------------------------------------------------------------------------------------------------------------ Rev. Req. for Bundled Functions @ ROR on RB = 7.06% Residential Commercial/Industrial Total System Heating Non-heat Heating Non-heat - ------------------------------------------------------------------------------------------------------------------------------------ 40 Demand-related functions L35 $ 19,893,626 $ 8,690,069 $ 248,484 $ 8,449,553 $1,316,567 41 Commodity-related functions L36-L45 $ 0 $ 0 $ 0 $ 0 $ 0 42 Customer-related functions L37 - 46:48 $ 27,433,547 $17,345,324 $3,503,338 $ 4,910,491 $ 717,711 - ------------------------------------------------------------------------------------------------------------------------------------ 43 sub-total $ 47,327,173 $26,035,393 $3,751,822 $13,360,044 $2,034,278 44 Rev. Req. for Unbundled Functions 45 Procurement function L4 $ 1,061,424 $ 694,432 $ 113,470 $ 213,236 $ 39,685 46 DS Uncollectibles, Credit & Collections function L28 spread vertically within each column to all functions except Procurement 47 Bill Printing, Mailing & Receipt function L29 $ 500,856 $ 313,473 $ 58,947 $ 110,423 $ 17,942 48 Competitive Energy Services function L30 $ 428,882 $ 306,292 $ 57,597 $ 55,878 $ 9,079 - ------------------------------------------------------------------------------------------------------------------------------------ 49 sub-total $ 1,991,163 $ 1,314,197 $ 230,013 $ 379,536 $ 66,705 50 Total Delivery Service Rev. Req. L43 + L49 $ 49,318,335 $27,349,590 $3,981,836 $13,739,581 $2,100,983 - ------------------------------------------------------------------------------------------------------------------------------------ RY#1 Billing Units 51 GAS Deliveries @ meter, Mcf 16,535,558 5,460,256 200,465 5,369,003 1,117,222 52 Number of Customers 72,813 52,220 9,810 9,218 1,498 - ------------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------- Rev. Req. for Bundled Functions @ ROR on RB = 7.06% SC8/9 Firm Firm Interruptible SC11-DLM Intrdprtmntl SC11 t SC11 d - ------------------------------------------------------------------------------------------------------------- 40 Demand-related functions $ 0 $457,718 $ 56,070 $ 609,699 $ 65,465 41 Commodity-related functions $ 0 $ 0 $ 0 $ 0 $ 0 42 Customer-related functions $ 0 $ 21,025 $ 765,042 $ 152,885 $ 17,731 - ------------------------------------------------------------------------------------------------------------- 43 sub-total $ 0 $478,743 $ 821,112 $ 762,585 $ 83,196 44 Rev. Req. for Unbundled Functions 45 Procurement function $ 0 $ 11 $ 535 $ 33 $ 22 46 DS Uncollectibles, Credit & Collections function 47 Bill Printing, Mailing & Receipt function $ 0 $ 12 $ 0 $ 36 $ 24 48 Competitive Energy Services function $ 0 $ 6 $ 0 $ 18 $ 12 - ------------------------------------------------------------------------------------------------------------- 49 sub-total $ 0 $ 29 $ 535 $ 88 $ 58 50 Total Delivery Service Rev. Req. $ 0 $478,772 $ 821,647 $ 762,672 $ 83,254 - ------------------------------------------------------------------------------------------------------------- RY#1 Billing Units 51 GAS Deliveries @ meter, Mcf 1,802,120 847,692 26,000 1,540,000 172,800 52 Number of Customers 61 1 1 3 2 - -------------------------------------------------------------------------------------------------------------
Appendix F Sheet 1 of 6 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Gas Revenue Allocation Min .5x, Max 1.5x
(1) (2) (3) (4) (5) (6) Rate Adj Adj to (5)-(1) Initial Net of 3.95% Net Initial Net Income Return +/- 15% Income Income Difference ----------- ------ ------- ------ ----------- ----------- Total $ 5,894 3.95% $5,623 $ 5,894 SC 1 & 12 Residential Heat $ 4,035 4.51% 4.51% SC 1 & 12 Residential Nonheat $ (535) -4.14% 3.36% - ----------------------------------------------------------------------------------------------------- Total SC 1 & 12 Residential $ 3,500 3.42% 3.42% $3,500 $ 3,669 $ 169 - ----------------------------------------------------------------------------------------------------- SC 2, 6, & 13 Com & Ind Heat $ 1,870 4.62% 4.54% SC 2, 6, & 13 Com & Ind Nonheat $ 524 8.37% 4.54% - ----------------------------------------------------------------------------------------------------- Total SC 2, 6, & 13 $ 2,394 5.12% 4.54% $2,123 $ 2,225 $ (169) - ----------------------------------------------------------------------------------------------------- SC 11 Transmission $ 264 19.51% SC 11 Distribution $ 37 15.89% SC 11 DLM $ 170 15.04% Excludes Revenue Taxes ------------------------------ (7) (8) (9) (10) (11) (6)/.60125 (7)+(9) (10)/(8) Adj Base Base Rev Total % Increase FIT/SIT Rates Increase Increase Unadjusted ---------- -------- -------- -------- ---------- Total $ 39,312 $ 8,765 $ 8,765 22.30% SC 1 & 12 Residential Heat SC 1 & 12 Residential Nonheat - ------------------------------------------------------------------------------------------ Total SC 1 & 12 Residential $ 281 $ 24,850 $ 5,541 $ 5,821 23.43% - ------------------------------------------------------------------------------------------ SC 2, 6, & 13 Com & Ind Heat SC 2, 6, & 13 Com & Ind Nonheat - ------------------------------------------------------------------------------------------ Total SC 2, 6, & 13 $ (281) $ 14,462 $ 3,224 $ 2,944 20.36% - ------------------------------------------------------------------------------------------ SC 11 Transmission $ 1,053 SC 11 Distribution $ 118 SC 11 DLM $ 636
(12) (13) (14) (15) (16) (17) (8)*(12) (8)*(13) (14)+(15) (10)-(16) % Increase % Increase $ Increase $ Increase Revenue Constrained Unadjusted Constrained Unadjusted Total Shortfall ----------- ---------- ----------- ---------- --------- --------- $ -- $ 8,765 $ 8,765 $ -- SC 1 & 12 Residential Heat SC 1 & 12 Residential Nonheat - ------------------------------------------------------------------------------------------------------------- Total SC 1 & 12 Residential 0.00% 23.43% $ -- $ 5,821 $ 5,821 $ -- - ------------------------------------------------------------------------------------------------------------- SC 2, 6, & 13 Com & Ind Heat SC 2, 6, & 13 Com & Ind Nonheat - ------------------------------------------------------------------------------------------------------------- Total SC 2, 6, & 13 0.00% 20.36% $ -- $ 2,944 $ 2,944 $ -- - ------------------------------------------------------------------------------------------------------------- SC 11 Transmission SC 11 Distribution SC 11 DLM (18) (19) (20) (21) (22) (23) (16)+(17) (18)/(8) (18)+(20) (21)/(8) (19)/(19) System Revenue Revenue Revenue Adj Final Increase as a $ Increase % Increase Adjustment $ Increase % Increase % of System ---------- ---------- ---------- ---------- ---------- --------------- $ 8,765 22.30% $ 8,765 22.30% 100.00% SC 1 & 12 Residential Heat SC 1 & 12 Residential Nonheat - ------------------------------------------------------------------------------------------------------------------- Total SC 1 & 12 Residential $ 5,821 23.43% $ 104 $ 5,925 23.84% 66.41% - ------------------------------------------------------------------------------------------------------------------- SC 2, 6, & 13 Com & Ind Heat SC 2, 6, & 13 Com & Ind Nonheat - ------------------------------------------------------------------------------------------------------------------- Total SC 2, 6, & 13 $ 2,944 20.36% $ 53 $ 2,997 20.72% 33.59% - ------------------------------------------------------------------------------------------------------------------- SC 11 Transmission SC 11 Distribution SC 11 DLM $ (157) $ (157) -24.69% 0.00%
Increase -------- Avg. 22.30% Min 0.50x 11.15% Max 1.50x 33.44% Rate Years 2 & 3
Rate Year 2 Rate Year 3 ---------------------------------------- ------------------------------------------ Increase as a Base Rev Adj. for Rev Unbundled to MFCs Base Rev Adj. for Rev Unbundled to MFCs % of System Increase Mcf MFC/Ccf Total Increase MWh MFC/kWh Total ------------- -------- --------- --------- ------ -------- --------- --------- ------ Total 100.00% $ 6,877 $1,532 $1,572 SC 1 & 12 Residential Heat 5,605,780 $ 0.02070 $1,160 5,755,130 $ 0.02070 $1,191 SC 1 & 12 Residential Nonheat 196,270 $ 0.02070 $ 41 192,160 $ 0.02070 $ 40 Total SC 1 & 12 Residential 66.41% $ 4,567 5,802,050 $ 0.02070 $1,201 5,947,290 $ 0.02070 $1,231 SC 2, 6, & 13 Com & Ind Heat 5,553,480 $ 0.00490 $ 272 5,744,040 $ 0.00490 $ 281 SC 2, 6, & 13 Com & Ind Nonheat 1,197,446 $ 0.00490 $ 59 1,222,856 $ 0.00490 $ 60 Total SC 2, 6, & 13 33.59% $ 2,310 6,750,926 $ 0.00490 $ 331 6,966,896 $ 0.00490 $ 341
Appendix F Sheet 2 of 6 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Summary of Proposed Monthly Gas Delivery Rates
Current Rates Rate Year 1 Rate Year 2 Rate Year 3 ------------- ----------- ----------- ----------- S.C. No. 1 & 12 Billing Block 1 First 2 Ccf $ 7.20 $ 14.00 $ 14.00 $ 14.00 Billing Block 2 per Ccf Next 48 Ccf $ 0.4250 $ 0.4620 $ 0.5284 $ 0.5284 Billing Block 3 per Ccf Additional $ 0.3028 $ 0.2892 $ 0.3300 $ 0.3300 S.C. No. 2, 6 & 13 Billing Block 1 First 2 Ccf $ 7.20 $ 20.00 $ 20.00 $ 20.00 Billing Block 2 per Ccf Next 98 Ccf $ 0.3307 $ 0.3505 $ 0.3843 $ 0.3843 Billing Block 3 per Ccf Next 4900 Ccf $ 0.2041 $ 0.2163 $ 0.2372 $ 0.2372 Billing Block 4 per Ccf Additional $ 0.1760 $ 0.1869 $ 0.2048 $ 0.2048 S.C. No. 11 Transmission Customer Charge $ 317.00 $ 317.00 $ 317.00 $ 317.00 MDQ $ 6.46 $ 6.46 $ 6.46 $ 6.46 S.C. No. 11 Distribution Customer Charge $ 317.00 $ 317.00 $ 317.00 $ 317.00 MDQ $ 11.76 $ 11.76 $ 11.76 $ 11.76 S.C. No. 11 DLM Customer Charge $ -- $ 317.00 $ 317.00 $ 317.00 MDQ $ -- $ 6.79 $ 6.79 $ 6.79
Appendix F Sheet 3 of 6 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Gas Billing Determinants (Excludes Unbilled)
Rate Year 1 Rate Year 2 Rate Year 3 ----------- ----------- ----------- S.C. No. 1 & 12 Res. Heat Block 1 - Customer Months 626,640 643,344 660,480 Block 1 - Mcf - Not Billed 119,680 122,860 126,150 Block 2 - Mcf 2,140,570 2,197,630 2,256,170 Block 3 - Mcf 3,199,990 3,285,290 3,372,810 S.C. No. 1 & 12 Res. Non-Heat Block 1 - Customer Months 117,720 115,260 112,848 Block 1 - Mcf - Not Billed 19,960 19,510 19,130 Block 2 - Mcf 128,490 125,830 123,180 Block 3 - Mcf 52,010 50,930 49,850 S.C. No. 2, 6 & 13 Heat Block 1 - Customer Months 110,616 114,600 118,716 Block 1 - Mcf - Not Billed 17,290 17,880 18,500 Block 2 - Mcf 611,690 632,790 654,600 Block 3 - Mcf 3,728,300 3,856,360 3,988,670 Block 4 - Mcf 1,011,750 1,046,450 1,082,270 S.C. No. 2, 6 & 13 Non-Heat Block 1 - Customer Months 17,964 18,504 19,068 Block 1 - Mcf - Not Billed 2,380 2,490 2,560 Block 2 - Mcf 67,760 70,290 72,940 Block 3 - Mcf 289,700 300,540 311,790 Block 4 - Mcf 757,374 824,126 835,566 S.C. No. 11 Transmission Customer Months 36 36 36 MDQ 161,412 161,412 161,412 S.C. No. 11 Distribution Customer Months 24 24 24 MDQ 9,444 9,444 9,444 S.C. No. 11 - DLM Customer Months 12 12 12 MDQ 69,996 69,996 69,996 Interdepartmental (S.C. No. 2) Block 4 - Mcf 26,000 26,000 26,000
Appendix F Sheet 4 of 6 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Gas Commodity Related Merchant Function Charges MFC (A) MFC (B) MFC (T) Applicable to S. C. No. $/ccf $/ccf $/ccf ------- ------- ------- MFC-1 1 0.00680 0.01390 0.02070 MFC-2 2 0.00213 0.00277 0.00490 Notes: 1. Customers taking commodity service from Central Hudson will be billed by Central Hudson for MFC(T), which is equal to the sum of MFC(A) and MFC(B). 2. MFC(A) will include the allocated portion of collection function costs and 50% of procurement-related call center function costs, plus administrative & general and rate base items associated with each of these items. Customers that choose to purchase their commodity service from an energy services company (ESCO) that is participating in Central Hudson's Purchase of Receivables (POR) Program will be billed by Central Hudson for MFC(A) only. 3. MFC(B) will include commodity purchasing function costs, allocated portions of advertising & promotions function costs and 50% of procurement-related call center function costs, plus administrative & general and rate base items associated with each of these items. Appendix F Sheet 5 of 6 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Comparison of Bills Under Present and Proposed Rates P.S.C. No. 12 - Gas Service Classification Nos. 1 & 12 Monthly Monthly Bill Change in Monthly Bill Usage ------------ ------------------------ Ccf Present Proposed Amount Increase ------------------------------------------------------------ 2 $ 9.16 $ 16.15 $ 6.98 76.20% 4 11.81 18.87 7.06 59.78% 6 14.45 21.58 7.13 49.37% 8 17.09 24.30 7.21 42.18% 10 19.74 27.02 7.29 36.92% 15 26.34 33.82 7.48 28.38% 20 32.95 40.62 7.67 23.26% 25 39.56 47.42 7.86 19.86% 30 46.17 54.21 8.05 17.43% 35 52.78 61.01 8.24 15.61% 40 59.38 67.81 8.43 14.19% 50 72.60 81.41 8.81 12.13% 60 84.56 93.23 8.67 10.25% 80 108.49 116.87 8.39 7.73% 100 132.41 140.52 8.11 6.12% 130 168.29 175.98 7.69 4.57% 170 216.14 223.27 7.13 3.30% 200 252.02 258.73 6.71 2.66% 300 371.64 376.95 5.31 1.43% 1000 1,208.93 1,204.47 (4.46) -0.37% Typical Annual Heating Customer @ 1100 Ccf Per Year --------------------------------------------------- $ 1,454.23 $ 1,546.68 $ 92.45 6.36% Revenue Tax Factor: Delivery 0.02612 Commodity 0.00612 Gas Supply Charge: $ 0.8798 Appendix F Sheet 6 of 6 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Comparison of Bills Under Present and Proposed Rates P.S.C. No. 12 - Gas Service Classification Nos. 2 & 13 Monthly Monthly Bill Change in Monthly Bill Usage ------------ ----------------------- Ccf Present Proposed Amount Increase ------------------------------------------------------------- 2 $ 9.01 $ 21.89 $ 12.88 142.86% 10 18.76 31.80 13.04 69.51% 30 43.12 56.55 13.44 31.16% 50 67.48 81.31 13.84 20.50% 100 128.37 143.21 14.83 11.55% 150 182.90 198.35 15.44 8.44% 200 237.43 253.49 16.06 6.76% 250 291.96 308.63 16.67 5.71% 300 346.49 363.78 17.29 4.99% 400 455.55 474.06 18.51 4.06% 500 564.60 584.35 19.74 3.50% 600 673.66 694.63 20.97 3.11% 800 891.78 915.20 23.42 2.63% 1000 1,109.89 1,135.77 25.88 2.33% 1500 1,655.18 1,687.19 32.02 1.93% 2000 2,200.47 2,238.62 38.15 1.73% 3000 3,291.04 3,341.47 50.43 1.53% 5000 5,472.19 5,547.17 74.98 1.37% 7500 8,127.94 8,230.34 102.40 1.26% 10000 10,783.69 10,913.51 129.81 1.20% 12000 12,908.30 13,060.05 151.75 1.18% 14000 15,032.90 15,206.58 173.68 1.16% 16000 17,157.50 17,353.12 195.62 1.14% 20000 21,406.71 21,646.19 239.49 1.12% Annual Heating Customer @ 5300 Ccf Per Year ------------------------------------------- $ 5,937.16 $ 6,161.32 $ 224.16 3.78% Revenue Tax Factor: Delivery 0.00612 Commodity 0.00612 Gas Supply Charge: $ 0.8798 Appendix G, Schedule 1 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Electric Deferred Items For Offset - Projected as of June 30, 2006 ($000)
Electric Department -------------------------------- Deferred Deferred Charge Tax Net -------------------------------- Deferred Debits Pension Costs - Under/(Over) Collection $ 29,616 ($11,809) $ 17,807 OPEB Costs - Excluding Medicare Subsidy - Under/(Over) Collection 11,113 (4,433) 6,680 Pension Reserve Carrying Charges 7,172 (2,860) 4,312 Stray Voltage Testing Costs 2,050 (818) 1,232 Carrying Charges on Stray Voltage Testing Costs 65 (24) 41 NYS Income Taxes (00-M-1556) 260 3,678 3,938 Research & Development Costs 369 (149) 220 -------------------------------- Total Deferred Debits $ 50,645 ($16,415) $ 34,230 -------------------------------- Deferred Credits Proceeds from Sale of Clean Air Act Allowances ($ 13,576) $ 5,414 ($ 8,162) Benefit Fund Principle & Carrying Charges (1) (12,450) 4,450 (8,000) Variable Rate Notes (3,666) 1,461 (2,205) NMP-2 Settlement Agreement Costs (1,930) 775 (1,155) Reliability Service Quality Penalty (1,138) 454 (684) OPEB Reserve Carrying Charges (1,220) 487 (733) Carrying Charges - Deferred NYS Taxes (1,014) 404 (610) Carrying Charges - CAA Allowance Proceeds (724) 288 (436) Carrying Charge on NMP-2 Settlement Agreement Costs (490) 201 (289) NYS Deferred Tax - Restate 8.50% & 8.00% Balances to 7.50% 0 (172) (172) Powerful Opportunity Costs 0 0 0 -------------------------------- Total Deferred Credits ($ 36,208) $13,762 ($ 22,446) -------------------------------- Net Deferred Debit 14,437 (2,653) 11,784 Amount Recovered from Excess Depreciation Reserve (14,437) 2,653 (11,784) -------------------------------- Net Remaining Deferred Balance $ 0 $ 0 $ 0 ================================
(1) Includes Shared Earnings deferred for Customer benefit of $ 22.3 million Appendix G, Schedule 2 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Gas Deferred Items For Offset - Projected as of June 30, 2006 ($000)
Gas Department ---------------------------------- Deferred Deferred Charge Tax Net ---------------------------------- Deferred Debits Pension Costs - Under/(Over) Collection a $ 19,206 ($ 7,658) $11,548 Pension Reserve Carrying Charges b 6,790 (2,708) 4,082 OPEB Costs - Excluding Medicare Subsidy - Under/(Over) Collection a 6,179 (2,463) 3,716 Gas Earnings Restoration b 1,272 (508) 764 NYS Income Taxes (00-M-1556) b 87 426 513 ---------------------------------- Total Deferred Debits $ 33,534 ($12,911) $20,623 ---------------------------------- Deferred Credits Gas Shared Earnings (Rate Years 1 through 3) b (1,486) 592 (894) Variable Rate Notes b (1,149) 460 (689) OPEB Reserve Carrying Charges b (502) 204 (298) Research & Development Costs b (11) 6 (5) Carrying Charges - Deferred NYS Taxes b (96) 39 (57) NYS Deferred Tax - Restate 8.50% & 8.00% Balances to 7.50% 0 (150) (150) Powerful Opportunity Costs b 0 0 0 ---------------------------------- Total Deferred Credits ($ 3,244) $ 1,151 ($ 2,093) ---------------------------------- Net Deferred Debit $ 30,290 ($11,760) $18,530 ================================== Recovery of Gas Net Regulatory Asset Net Deferred Items Not Subject to Interest a $ 25,387 ($10,123) $15,264 Net Deferred Items Subject to Interest b 4,903 (1,637) 3,266 --------- -------- -------- $ 30,290 ($11,760) $18,530 --------- -------- -------- The non-interest bearing components ("a" references) of the gas net regulatory asset balance are amortized on a straight-line basis over 7 years beginning July 1, 2007, the start of RY2. $ 25,387 / 7 years = $ 3,627 The interest bearing components ("b" references) of the gas net regulatory asset balance accrue interest during RY1 at the carrying charge rate. The balance at July 1, 2007, which includes interest accrued in RY1, is amortized over 7 years, on a levelized basis recognizing accrued interest over 7 on the unamortized balance at the carrying charge rate, beginning July 1, years plus 2007, the start of RY2 (1). $ 4,903 interest = 719 ------- $ 4,346 Total Annual Amortization of Net Gas Regulatory Asset =======
(1) The amount for RY2 shown on Appendix D, Schedule 1, Line 28 has been moderated to eliminate the need for a RY3 gas rate change. Appendix G, Schedule 3 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Deprecation Reserve Rate Moderator ($000) Settlement Excess Electric Depreciation Reserve $ 52,500 Recovery of Net Electric Regulatory Assets Net Regulatory Assets Remaining After Offset $ 14,437 Deferred Taxes on Above (2,653) 11,784 ---------- -------- Remaining Balance After Offset 40,716 Amounts Applied to Phase-in Electric Rate Increase Rate Year 1 (22,887) Rate Year 2 (11,840) ---------- (34,727) 0.60125 (20,880) ---------- Remaining Balance After Offset & Phase-In $ 19,837 ======== Pre-tax Equivalent $ 32,992 ========
Appendix H, Schedule 1 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Capital Structure and Allowed Rate of Return ($000)
Pre-Tax Weighted Weighted Rate Year 1: Amount Ratio Cost Cost Cost - ------------ ---------- ------ ----- -------- -------- Long-Term Debt $ 367,579 51.2% 4.99% 2.55% 2.55% Customer Deposits 6,359 0.9% 3.00% 0.03% 0.03% Preferred Stock 21,030 2.9% 5.04% 0.15% 0.25% Common Equity 323,094 45.0% 9.60% 4.32% 7.18% ---------- ------ ----- -------- -------- $ 718,062 100.0% 7.05% 10.01% ========== ====== ======== ========
Pre-Tax Weighted Weighted Rate Year 2: Amount Ratio Cost Cost Cost - ------------ ---------- ------ ----- -------- -------- Long-Term Debt $ 382,837 51.3% 5.07% 2.60% 2.60% Customer Deposits 6,359 0.9% 3.00% 0.03% 0.03% Preferred Stock 21,030 2.8% 5.04% 0.14% 0.24% Common Equity 335,686 45.0% 9.60% 4.32% 7.19% ---------- ------ ----- -------- -------- $ 745,912 100.0% 7.09% 10.05% ========== ====== ======== ========
Pre-Tax Weighted Weighted Rate Year 3: Amount Ratio Cost Cost Cost - ------------ ---------- ------ ----- -------- -------- Long-Term Debt $ 411,042 51.6% 5.15% 2.66% 2.66% Customer Deposits 6,359 0.8% 3.00% 0.02% 0.02% Preferred Stock 21,030 2.6% 5.04% 0.13% 0.22% Common Equity 358,658 45.0% 9.60% 4.32% 7.18% ---------- ------ ----- -------- -------- $ 797,089 100.0% 7.13% 10.09% ========== ====== ======== ========
Appendix H, Schedule 2 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Electric and Gas Basis Point Values Electric --------------------------------- Basis Point Values: RY1 RY2 RY2 - ------------------- --------- --------- --------- Rate Base ($000) $ 544,007 $ 578,065 $ 615,375 x Equity Ratio 45% 45% 45% --------- --------- --------- Equity component of Rate Base ($000) $ 244,803 $ 260,129 $ 276,919 x 1 BP 0.01% 0.01% 0.01% --------- --------- --------- After-tax value of 1 BP - whole dollars $ 24,500 $ 26,000 $ 27,700 ========= ========= ========= Pre-tax value of 1 BP - whole dollars $ 40,700 $ 43,200 $ 46,100 ========= ========= ========= Gas --------------------------------- Basis Point Values: RY1 RY2 RY2 - ------------------- --------- --------- --------- Rate Base ($000) $ 149,521 $ 156,889 $ 163,440 x Equity Ratio 45% 45% 45% --------- --------- --------- Equity component of Rate Base ($000) $ 67,284 $ 70,600 $ 73,548 x 1 BP 0.01% 0.01% 0.01% --------- --------- --------- After-tax value of 1 BP - whole dollars $ 6,700 $ 7,100 $ 7,400 ========= ========= ========= Pre-tax value of 1 BP - whole dollars $ 11,100 $ 11,800 $ 12,300 ========= ========= ========= Appendix H, Schedule 3, Sheet 1 of 3 CENTRAL HUDSON GAS & ELECTRIC CORPORATION Cases 05-E-0934 & 05-G-0935 LONG TERM DEBT - AVERAGE CAPITALIZATION AND COST FOR THE TWELVE MONTHS ENDING JUNE 30, 2007 ($000)
Average Principal Amount Interest Amount Charges Outstanding Expense Maturity Interest Outstanding During Months During During Date Rate % 6/30/2006 Rate Year Outstanding Rate Year Rate Year ------------------ -------- ----------- --------- ----------- ----------- --------- (1) (2) (3) (4) (5) (6) (7) Long Term Debt Outstanding Issues NYSERDA Series A August 1, 2027 5.45 33,400 -- 12 33,400 1,820 NYSERDA Var Rate August 1, 2028 3.10 41,150 -- 12 41,150 1,276 NYSERDA Var Rate August 1, 2028 3.02 41,000 -- 12 41,000 1,238 Polution Control Note December 1, 2028 3.00 16,700 -- 12 16,700 501 NYSERDA Var Rate July 1, 2034 3.38 33,700 -- 12 33,700 1,139 March 28, 2007 5.87 33,000 (33,000) 9 24,750 1,453 January 15, 2009 6.00 20,000 -- 12 20,000 1,200 September 23, 2010 4.33 24,000 -- 12 24,000 1,039 March 28, 2012 6.64 36,000 -- 12 36,000 2,390 February 27, 2014 4.73 7,000 -- 12 7,000 331 November 5, 2014 4.80 7,000 -- 12 7,000 336 December 1, 2035 5.84 24,000 -- 12 24,000 1,402 October 1, 2016 6.25 -- 11,169 9 8,377 524 February 1, 2017 6.25 -- 39,000 5 16,250 1,016 November 4, 2019 5.05 27,000 -- 12 27,000 1,364 Average Long Term Debt Outstanding $ 360,327 =========== Interest Charges for the Rate Year $ 17,028 --------- Plus: Amortization of Debt Discount and Expense 973 Less: Amortization of Premium on Debt 3 Total Cost of Debt Amount $ 17,998 ========= % of Average Long Term Debt Outstanding 4.99% =========
Appendix H, Schedule 3, Sheet 2 of 3 CENTRAL HUDSON GAS & ELECTRIC CORPORATION Cases 05-E-0934 & 05-G-0935 LONG TERM DEBT - AVERAGE CAPITALIZATION AND COST FOR THE TWELVE MONTHS ENDING JUNE 30, 2008 ($000)
Average Principal Amount Interest Amount Charges Outstanding Expense Maturity Interest Outstanding During Months During During Date Rate % 6/30/2007 Rate Year Outstanding Rate Year Rate Year ------------------ -------- ----------- --------- ----------- ----------- --------- (1) (2) (3) (4) (5) (6) (7) Long Term Debt Outstanding Issues NYSERDA Series A August 1, 2027 5.45 33,400 -- 12 33,400 1,820 NYSERDA Var Rate August 1, 2028 3.10 41,150 -- 12 41,150 1,276 NYSERDA Var Rate August 1, 2028 3.02 41,000 -- 12 41,000 1,238 Polution Control Note December 1, 2028 3.00 16,700 -- 12 16,700 501 NYSERDA Var Rate July 1, 2034 3.38 33,700 -- 12 33,700 1,139 January 15, 2009 6.00 20,000 -- 12 20,000 1.200 September 23, 2010 4.33 24,000 -- 12 24,000 1,039 March 28, 2012 6.64 36,000 -- 12 36,000 2,390 February 27, 2014 4.73 7,000 -- 12 7,000 331 November 5, 2014 4.80 7,000 -- 12 7,000 336 December 1, 2035 5.84 24,000 -- 12 24,000 1,402 October 1, 2016 6.25 11,169 -- 12 11,169 698 February 1, 2017 6.25 39,000 -- 12 39,000 2,438 January 1, 2018 6.25 -- 28,515 6 14,258 891 November 4, 2019 5.05 27,000 -- 12 27,000 1,364 Average Long Term Debt Outstanding $ 375,377 =========== Interest Charges for the Rate Year $ 18,063 --------- Plus: Amortization of Debt Discount and Expense 959 Less: Amortization of Premium on Debt 3 Total Cost of Debt Amount $ 19,019 ========= % of Average Long Term Debt Outstanding 5.07% =========
Appendix H, Schedule 3, Sheet 3 of 3 CENTRAL HUDSON GAS & ELECTRIC CORPORATION Cases 05-E-0934 & 05-G-0935 LONG TERM DEBT - AVERAGE CAPITALIZATION AND COST FOR THE TWELVE MONTHS ENDING JUNE 30, 2009 ($000)
Average Principal Amount Interest Amount Charges Outstanding Expense Maturity Interest Outstanding During Months During During Date Rate % 6/30/2008 Rate Year Outstanding Rate Year Rate Year ------------------ -------- ----------- --------- ----------- ----------- --------- (1) (2) (3) (4) (5) (6) (7) Long Term Debt Outstanding Issues NYSERDA Series A August 1, 2027 5.45 33,400 -- 12 33,400 1,820 NYSERDA Var Rate August 1, 2028 3.10 41,150 -- 12 41,150 1,276 NYSERDA Var Rate August 1, 2028 3.02 41,000 -- 12 41,000 1,238 Polution Control Note December 1, 2028 3.00 16,700 -- 12 16,700 501 NYSERDA Var Rate July 1, 2034 3.38 33,700 -- 12 33,700 1,139 January 15, 2009 6.00 20,000 (20,000) 7 10,833 650 September 23, 2010 4.33 24,000 -- 12 24,000 1,039 March 28, 2012 6.64 36,000 -- 12 36,000 2,390 February 27, 2014 4.73 7,000 -- 12 7,000 331 November 5, 2014 4.80 7,000 -- 12 7,000 336 December 1, 2035 5.84 24,000 -- 12 24,000 1,402 October 1, 2016 6.25 11,169 12 11,169 698 February 1, 2017 6.25 39,000 -- 12 39,000 2,438 January 1, 2018 6.25 28,515 -- 12 28,515 1,782 July 1, 2018 6.25 14,000 -- 12 14,000 875 April 1, 2019 6.25 -- 34,380 3 8,595 537 November 4, 2019 5.05 27,000 -- 12 27,000 1,364 Average Long Term Debt Outstanding $ 403,062 =========== Interest Charges for the Rate Year $ 19,816 --------- Plus: Amortization of Debt Discount and Expense 944 Less: Amortization of Premium on Debt 3 Total Cost of Debt Amount $ 20,757 ========= % of Average Long Term Debt Outstanding 5.15% =========
Appendix I, Schedule 1 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Deferral Items ($000)
ELECTRIC OPERATIONS GAS OPERATIONS --------------------------- ------------------------- Rate Allowance Items: Method RY1 RY2 RY3 RY1 RY2 RY3 - --------------------- ------ ------- ------- ------- ------- ----- ------- Asbestos Litigation B $ 0 $ 0 $ 0 $ 0 0 $ 0 Competition Education Program C $ 298 $ 298 $ 298 $ 53 53 $ 53 Gas Balancing Software B $ 0 $ 0 $ 0 $ 0 0 $ 0 MGP Remediation A $ 0 $ 1,400 $ 1,400 $ 0 250 $ 250 OPEB A $ 8,382 $ 8,382 $ 8,382 $ 1,943 1943 $ 1,943 Pension Plan A $10,568 $10,568 $10,568 $ 2,413 2413 $ 2,413 Powerful Opportunities Program B $ 976 $ 1,125 $ 1,275 $ 172 199 $ 225 Property Taxes D $19,758 $20,460 $21,183 $ 5,342 5531 $ 5,727 Research & Development B $ 1,846 $ 1,857 $ 1,860 $ 299 304 $ 306 Stray Voltage Testing B $ 2,200 $ 2,250 $ 2,300 n/a n/a n/a Real-Time Gas Meters 04-G-0463 A n/a n/a n/a $ 0 $ 0 $ 0
Capital & Expense Expenditure Targets (cumulative totals through Rate Year 3): Category Type Target Method - -------- ---- -------- ------ Electric Cap $158,078 C Gas Cap $ 27,495 C Common Cap $ 21,693 C Steel/Cast Iron Replacement Cap $ 15,750 C Transmission ROW Maintenance Exp $ 6,723 C East Fishkill Substation Cap & Exp A Cost of Capital: Variable Rate Debt Interest Rate (all rate years): Target Method ------ ------ $41.150 Million Issue 3.10% B $41.000 Million Issue 3.02% B $33.700 Million Issue 3.38% B Method of Deferral: A - Deferral of costs over/under rate allowance, no limitation B - Deferral of costs over/under rate allowance subject to limitation C - Deferral of costs less than rate allowance D - Shared deferral of costs over/under rate allowance subject to limitation Appendix I, Schedule 2 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Revenue Matching Factors
Rate Year #1 Rate Year #2 Rate Year #3 ------------ ------------ ------------ ELECTRIC: Research & Development: Rate Allowance ($000) $ 1,846 $ 1,857 $ 1,860 SC 1, 2, 3, 5, 6, 8, 9 & 13 Sales (mWh) 5,756,150 5,870,650 5,966,350 Revenue Matching Factor - $/kWh $ 0.000321 $ 0.000316 $ 0.000312 ============ ============ ============ Pension Plan: Rate Allowance ($000) $ 10,568 $ 10,568 $ 10,568 SC 1, 2, 3, 5, 6, 8, 9 & 13 Sales (mWh) 5,756,150 5,870,650 5,966,350 Revenue Matching Factor - $/kWh $ 0.001836 $ 0.001800 $ 0.001771 ============ ============ ============ OPEB's: Rate Allowance ($000) $ 8,382 $ 8,382 $ 8,382 SC 1, 2, 3, 5, 6, 8, 9 & 13 Sales (mWh) 5,756,150 5,870,650 5,966,350 Revenue Matching Factor - $/kWh $ 0.001456 $ 0.001428 $ 0.001405 ============ ============ ============ GAS: Research & Development: Rate Allowance ($000) $ 299 $ 304 $ 306 SC 1, 2, 6, 12 & 13 Sales (Mcf) 12,146,946 12,553,010 12,914,218 Revenue Matching Factor - $/Mcf $ 0.024615 $ 0.024217 $ 0.023695 ============ ============ ============ Pension Plan: Rate Allowance ($000) $ 2,413 $ 2,413 $ 2,413 SC 1, 2, 6, 12 & 13 Sales (Mcf) 12,146,946 12,553,010 12,914,218 Revenue Matching Factor - $/Mcf $ 0.198651 $ 0.192225 $ 0.186848 ============ ============ ============ OPEB's: Rate Allowance ($000) $ 1,943 $ 1,943 $ 1,943 SC 1, 2, 6, 12 & 13 Sales (Mcf) 12,146,946 12,553,010 12,914,218 Revenue Matching Factor - $/Mcf $ 0.159958 $ 0.154784 $ 0.150454 ============ ============ ============
Appendix J Sheet 1 of 2 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 DEPRECIATION RATES
PSC Average Annual Allocation ACCT Service Net Deprec Survivor of Excess NO PLANT ACCOUNT Life Salvage Rate Curve Reserve - --------- ------------------------------------------------------- ------- ------- ------ ------------- ----------- ELECTRIC PLANT IN SERVICE HYDRO PLANT 331.00 STRUCTURES AND IMPROVEMENT 60 (50) 2.50 R3 (59,000) 332.00 RESERVOIRS, DAMS AND WATERWAYS 75 (60) 2.13 L5 (230,700) 333.00 TURBINES AND GENERATORS 60 (60) 2.67 R4 (290,000) 334.10 ACCESSORY ELECTRIC EQUIPMENT 55 (60) 2.91 R1.5 40,400 335.00 MISCELLANEOUS POWER PLANT EQUIPMENT 40 (40) 3.50 S2.5 (50,900) OTHER PRODUCTION PLANT 341.00 STRUCTURES AND IMPROVEMENTS 27 (5) 3.89 R5 (62,300) 342.00 FUEL HOLDERS, PRODUCERS & ACCESSORIES 27 (5) 3.89 R5 (102,700) 343.00 PRIME MOVERS 27 (5) 3.89 R5 (361,500) 344.00 GENERATORS 27 (5) 3.89 R5 (198,200) 345.00 ACCESSORY ELECTRIC EQUIPMENT 27 (5) 3.89 R5 92,200 346.00 MISCELLANEOUS POWER PLANT EQUIPMENT 27 (5) 3.89 R5 (1,100) TRANSMISSION PLANT 350.11 LAND AND LAND RIGHTS-LINES 85 10 1.06 R4 (68,000) 352.00 STRUCTURES AND IMPROVEMENTS 65 (40) 2.15 R3 145,000 353.11-20 STATION EQUIPMENT-IN USE 55 (20) 2.18 R1 (7,919,600) 353.12 SUPERVISORY EQUIPMENT-IN USE 28 (10) 3.93 S1 (775,300) 354.00 TOWERS AND FIXTURES 65 (30) 2.00 R3 (490,400) 355.00 POLES AND FIXTURES 55 (50) 2.73 R3 1,049,200 355.15 POLES AND FIXTURES-345KV LINE 55 (50) 2.73 R3 353,500 356.10 OVERHEAD CONDUCTORS AND DEVICES 60 (25) 2.08 R2 (526,100) 356.15 OVERHEAD CONDUCTORS AND DEVICES-345KV LINE 60 (35) 2.25 R2 (81,300) 356.20 CLEARING 60 (35) 2.25 R2 (33,100) 356.25 CLEARING-345KV LINE 60 (35) 2.25 R2 (9,500) 357.00 UNDERGROUND CONDUIT 40 (5) 2.63 L0.5 (7,400) 358.00 UNDERGROUND CONDUCTORS AND DEVICES 40 (20) 3.00 R3 (1,094,500) DISTRIBUTION PLANT 360.11 LAND AND LAND RIGHTS-OVERHEAD LINES 60 10 1.50 S4 (39,900) 360.22 LAND AND LAND RIGHTS-UNDERGROUND 60 10 1.50 S4 (200) 361.00 STRUCTURES AND IMPROVEMENTS 80 (25) 1.56 R3 (108,400) 362.11-20 STATION EQUIPMENT-IN USE 52 (20) 2.31 R1.5 397,000 362.12 SUPERVISORY EQUIPMENT-IN USE 30 (10) 3.67 R2 (437,400) 364.00 POLES, TOWERS AND FIXTURES 55 (25) 2.27 O1 (11,591,300) 365.00 OVERHEAD CONDUCTORS AND DEVICES 60 (30) 2.17 R1 (9,817,300) 366.00 UNDERGROUND CONDUIT 65 (25) 1.92 R3 (10,600) 367.00 UNDERGROUND CONDUCTOR AND DEVICES 55 (10) 2.00 R2.5 (2,330,500) 368.00 TRANSFORMERS 43 (10) 2.56 L1 (6,657,700) 369.10 SERVICES OVERHEAD 52 (75) 3.37 R1.5 (5,497,100) 369.20 SERVICES UNDERGROUND 52 (25) 2.40 R1.5 (517,600) 370.00 METERS 32 0 3.13 R1.5 (589,000) 371.00 INSTALLATIONS ON CUSTOMER PREMISES 20 (15) 5.75 R0.5 (878,500) 372.00 LEASED PROPERTY ON CUSTOMER PREMISES 11 0 9.09 L2 (456,000) 373.00 STREET LIGHTING 30 (25) 4.17 L0 (3,136,000) 390.00 STRUCTURES AND IMPROVEMENTS 40 (30) 3.25 R1.5 (148,200) ----------- (52,500,000) ===========
Appendix J Sheet 2 of 2 Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 DEPRECIATION RATES
PSC Average Annual Allocation ACCT Service Net Deprec Survivor of Excess NO PLANT ACCOUNT Life Salvage Rate Curve Reserve - --------- ------------------------------------------------------ ------- ------- ------ ------------- ---------- GAS PLANT IN SERVICE MANUFACTURING GAS PLANT - PROPANE 305.00 STRUCTURES AND IMPROVEMENTS 75 (10) 1.47 Undetermined 311.00 LIQUIFIED PETROLEUM GAS EQUIPMENT 60 (45) 2.42 Undetermined 320.10 OTHER EQUIPMENT 25 0 4.00 S3 TRANSMISSION PLANT 365.11 LAND 0 0 -- 365.20 LAND RIGHTS 70 0 1.43 S4 365.50 LAND RIGHTS-IROQUOIS 70 0 1.43 S4 366.20 STRUCTURES AND IMPROVEMENTS 45 (40) 3.11 R3 366.50 STRUCTURES AND IMPROVEMENTS-REG STATION IROQUOIS 45 (40) 3.11 R3 367.00 MAINS 68 (40) 2.06 Undetermined 367.50 MAINS - IROQUOIS 68 (40) 2.06 Undetermined 369.11 REGULATING STATION EQUIPMENT 35 (30) 3.71 Undetermined 369.12 REGULATING STATION EQUIPMENT-SUPERVISORY 18 (20) 6.67 S0.5 369.51 REGULATING STATION EQUIPMENT-IROQUOIS 35 (30) 3.71 Undetermined 369.52 REGULATING STATION EQUIPMENT-SUPERVISORY IROQUOIS 18 (20) 6.67 S0.5 DISTRIBUTION PLANT 374.11 LAND AND LAND RIGHTS-MAINS 70 0 1.43 R3 375.00 STRUCTURES AND IMPROVEMENTS 60 (30) 2.17 Undetermined 376.00 MAINS 85 (60) 1.88 R3 378.11 REGULATING STATION EQUIPMENT 35 (35) 3.86 Undetermined 378.12 REGULATING STATION EQUIPMENT-SUPERVISORY 30 (15) 3.83 Undetermined 380.00 SERVICES 70 (60) 2.29 R2 381.00 METERS 32 (10) 3.44 R1.5 382.00 METER INSTALLATIONS 40 (15) 2.88 Undetermined 383.00 HOUSE REGULATORS 55 0 1.82 Undetermined 384.00 HOUSE REGULATOR INSTALLATION 45 (20) 2.67 L5 385.00 INDUSTRIAL REGULATING STATION EQUIPMENT 55 (30) 2.36 Undetermined 385.10 INDUSTRIAL REGULATING STATION REMOTE METERING 55 (30) 2.36 Undetermined COMMON PLANT IN SERVICE 390.00 STRUCTURES AND IMPROVEMENTS 50 (50) 3.00 L0 390.10 STRUCTURES AND IMPROVEMENTS-LEASED PROPERTY 50 (50) 3.00 L0 391.11 OFFICE EQUIPMENT-EDP-GENERAL 8 0 12.50 L3 391.12 OFFICE EQUIPMENT-EDP-SYSTEM OPERATION 12 0 8.33 L2 391.21 OFFICE EQUIPMENT-DATA HANDLING 20 0 5.00 L0 391.22 OFFICE FURNITURE AND EQUIPMENT-OTHER 20 0 5.00 L0 392.10 TRANSPORTATION EQUIPMENT 8 10 11.25 L3 392.20 TRANSPORTATION EQUIPMENT-GAS 8 10 11.25 L3 392.40 TRANSPORTATION EQUIPMENT-COMMON 8 10 11.25 L3 393.00 STORES EQUIPMENT 35 0 2.86 L2 393.20 STORES EQUIPMENT - FORKLIFTS 35 0 2.86 L2 394.10 GARAGE & REPAIR EQUIPMENT 30 0 3.33 R1.5 394.20 SHOP EQUIPMENT 30 0 3.33 R1.5 394.30 TOOLS AND WORK EQUIPMENT 30 0 3.33 R1.5 395.10 LABORATORY EQUIPMENT 35 0 2.86 L1 395.20 LABORATORY EQUIPMENT-R&D 35 0 2.86 L1 396.10 POWER OPERATED EQUIP-ELECTRIC 12 15 7.08 L3 396.20 POWER OPERATED EQUIPMENT-GAS 12 15 7.08 L3 396.40 POWER OPERATED EQUIPMENT-COMMON 12 15 7.08 L3 397.10 COMMUNICATION EQUIPMENT-RADIO 20 0 5.00 R2.5 397.20 COMMUNICATION EQUIPMENT-TELEPHONE 10 0 10.00 L3 398.00 MISCELLANEOUS EQUIPMENT 30 0 3.33 R0.5
Appendix K Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Gas Balancing Methodology Applicable to S.C. 9 and 11 Monthly Balanced Service
Normalized Balancing Allocation Throughput Svc Chg Peak Requirements Mcf % Mcf of Costs (Mcf) ($/Mcf) ------- -------- ----------- ---------- --------- S.C. No. 9 (a) 420 1.22% $ 63,071 797,600 $ 0.0791 S.C. No. 11 - Trans. & Dist. (a) 614 1.78% $ 92,235 1,992,800 $ 0.0463 S.C. No. 11 - DLM (a) 1,436 4.17% $ 215,468 847,692 $ 0.2542 Other Classes 31,995 92.83% $ 4,802,322 12,228,595 $ 0.3927 ------- -------- ----------- ---------- Total 34,465 100.00% $ 5,173,095 15,866,687
Daily Balanced Service
2% % of Total Balancing Peak Peaking Svc Chg Peak Consumption Mcf Consumption Requirements ($/Mcf) ------- ----------- ------------ --------- S.C. No. 9 2,968 59 14.13% $ 0.0112 S.C. No. 11 - Trans. & Dist. 10,860 217 35.35% $ 0.0164 S.C. No. 11 - DLM 5,741 115 8.00% $ 0.0203 Other Classes 107,142 2,143 6.70% $ 0.0263 ------- 126,711
(a)
Total Extreme Total Extreme Day Demand Total Extreme Day Demand w/LAUF Day Delivery Deficiency % of (Mcf) 2.50% (Mcf) (Mcf) Demand ------------- ------------- ------------- ---------- ------ S.C. No. 9 2,968 3,042 2,622 420 14% S.C. No. 11 - Trans. & Dist. 10,860 11,132 10,517 614 6% S.C No. 11 - DLM 5,741 5,885 4,449 1,436 25% ------------- ------------- ------------- ---------- Total 16,601 17,016 14,966 2,050
Note: The above amounts are based on actual data as of February 1, 2006. Appendix L Central Hudson Gas & Electric Corporation Cases 05-E-0934 & 05-G-0935 Detailed CSI Margin of Error Calculation For purposes of supplementing the Customer Satisfaction Index (CSI) value which is currently provided by Central Hudson at the end of the year, and for purposes of determining if that CSI value has changed in a significant manner from the prior year's CSI level, Central Hudson will provide the following margin of error (MOE) calculations. 1. To provide an estimate of the 95% confidence interval regarding the responses to each of the eight individual survey questions whose results are combined to create the overall CSI, Central Hudson will perform the following MOE calculation for each question. MOE(Qi) = P(Qi)+/-1.96 x (square root) P(Qi)*(1-P(Qi))/n(Qi) Where the subscript "Qi" signifies each of the eight individual satisfaction survey questions, "p" is the proportion of customers surveyed who answered "Very Satisfied" or "Satisfied" on each individual question and "n" the base number of customers who responded to that individual question in that year. 2. To provide a reasonable approximation of the MOE for the overall CSI level for each year, (which is a weighted combination of the proportions of "Very Satisfied" or "Satisfied" customer responses to the eight individual questions), Central Hudson will provide the following calculation MOE(CSI) = P(CSI)+/-1.96 x (square root) P(CSI)*(1-P(CSI))/n Where the CSI level for the year will be treated as signifying the proportion, "p" of customers who are satisfied overall (as if each surveyed customer were asked a single question, "are you satisfied overall"), and "n" will signify the maximum number of annual customer survey responses received on any of the questions in that year. ATTACHMENT 2 CASES 05-E-0934 and 05-G-0935 ATTACHMENT 2 SUBJECT: Filings by CENTRAL HUDSON GAS & ELECTRIC CORPORATION Amendments to Schedule P.S.C. No. 15 - Electricity First Revised Leaf No. 218.2 Second Revised Leaf No. 231 Fourth Revised Leaves Nos. 106, 218.1, 219 Fifth Revised Leaves Nos. 165, 185, 205.1, 210, 217, 222 Sixth Revised Leaves Nos. 105, 220, 246 Seventh Revised Leaves Nos. 104, 169, 205, 218 Supplements Nos. 30, 31, 32 Amendments to Schedule P.S.C. No. 12 - Gas First Revised Leaf No. 181 Third Revised Leaves Nos. 68, 71, 72, 158 Fourth Revised Leaves Nos. 151, 152, 188, 193 Fifth Revised Leaf No. 149 Sixth Revised Leaves Nos. 186, 191 Eighth Revised Leaf No. 159 Supplements Nos. 20, 22, 23 -----END PRIVACY-ENHANCED MESSAGE-----