-----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, Q8zjiwo7n6cGJqPB+tuL1FbDeMTbp9ActY3Tv69ea+23HpF/Z3NyOxy5yyItKm8Y jcNplT7F2tw2RtkqCJIAUw== 0000912057-99-005688.txt : 19991117 0000912057-99-005688.hdr.sgml : 19991117 ACCESSION NUMBER: 0000912057-99-005688 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991115 FILER: COMPANY DATA: COMPANY CONFORMED NAME: COGENERATION CORP OF AMERICA CENTRAL INDEX KEY: 0000795185 STANDARD INDUSTRIAL CLASSIFICATION: COGENERATION SERVICES & SMALL POWER PRODUCERS [4991] IRS NUMBER: 592076187 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-09208 FILM NUMBER: 99752170 BUSINESS ADDRESS: STREET 1: ONE CARLSON PARKWAY STREET 2: SUITE 240 CITY: MINNEAPOLIS STATE: MN ZIP: 55447-4454 BUSINESS PHONE: 6127457900 MAIL ADDRESS: STREET 1: ONE CARLSON PARKWAY STREET 2: SUITE 240 CITY: MINNEAPOLIS STATE: MN ZIP: 55447-4454 FORMER COMPANY: FORMER CONFORMED NAME: NRG GENERATING U S INC DATE OF NAME CHANGE: 19960507 FORMER COMPANY: FORMER CONFORMED NAME: O BRIEN ENVIRONMENTAL ENERGY INC DATE OF NAME CHANGE: 19920703 FORMER COMPANY: FORMER CONFORMED NAME: OBRIEN ENERGY SYSTEMS INC DATE OF NAME CHANGE: 19910804 10-Q 1 10-Q - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- 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, 1999 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES --- EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 1-9208 COGENERATION CORPORATION OF AMERICA (Exact name of Registrant as Specified in Charter) DELAWARE 59-2076187 (State or other jurisdiction (I.R.S. Employer of incorporation) Identification No.) ----------- ONE CARLSON PARKWAY, SUITE 240 MINNEAPOLIS, MINNESOTA 55447-4454 (Address of principal executive offices) (Zip Code) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (612) 745-7900 Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. X Yes No --- --- APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PRECEDING FIVE YEARS: Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 19-34 subsequent to the distribution of securities under a plan confirmed by a court. X Yes No --- --- APPLICABLE ONLY TO CORPORATE ISSUERS: Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date: 6,857,269 shares of common stock, $0.01 par value per share (the "Common Stock"), as of November 4, 1999. - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- 1 COGENERATION CORPORATION OF AMERICA FORM 10-Q SEPTEMBER 30, 1999 INDEX
PAGE ---- PART I - FINANCIAL INFORMATION: Item 1. Financial Statements.......................................... 3 Consolidated Balance Sheets - September 30, 1999, and December 31, 1998................... 3 Consolidated Statements of Operations - Three months and nine months ended September 30, 1999,and September 30, 1998................... 4 Consolidated Statements of Cash Flows - Nine months ended September 30, 1999, and September 30, 1998.......................................... 5 Notes to Consolidated Financial Statements.................... 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................... 11 Item 3. Quantitative and Qualitative Disclosures about Market Risk.... 25 PART II - OTHER INFORMATION Item 1. Legal Proceedings............................................. 26 Item 6. Exhibits and Reports on Form 8-K.............................. 27 Signature.............................................................. 28 Index to Exhibits...................................................... 29
2 PART 1 FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS COGENERATION CORPORATION OF AMERICA CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS) ASSETS
SEPTEMBER 30, DECEMBER 31, 1999 1998 ------------- ------------- (UNAUDITED) Current assets: Cash and cash equivalents................................... $ 3,175 $ 3,568 Restricted cash and cash equivalents........................ 12,302 12,135 Accounts receivable, net.................................... 19,564 14,326 Receivables from related parties............................ 18 130 Inventories................................................. 2,821 2,683 Other current assets........................................ 1,153 640 --------- --------- Total current assets..................................... 39,033 33,482 Property, plant and equipment, net of accumulated depreciation of $57,340 and $47,819, respectively......... 245,114 244,040 Investments in equity affiliates............................ 39,673 18,179 Deferred financing costs, net............................... 4,880 6,503 Other assets................................................ 15,595 16,470 --------- --------- Total assets............................................. $ 344,295 $ 318,674 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Current portion of loans and payables due NRG Energy, Inc... $ 21,938 $ 7,020 Current portion of nonrecourse long-term debt............... 7,345 8,060 Current portion of recourse long-term debt.................. 1,509 1,550 Short-term borrowings....................................... 2,674 1,887 Accounts payable............................................ 10,708 8,800 Accrued taxes............................................... 5,230 - Prepetition liabilities..................................... 825 803 Other current liabilities................................... 2,965 4,227 --------- --------- Total current liabilities................................. 53,194 32,347 Loans due NRG Energy, Inc................................... 37,933 36,123 Nonrecourse long-term debt.................................. 184,672 189,848 Recourse long-term debt..................................... 45,225 45,225 Deferred tax liabilities, net............................... 2,793 2,793 Other liabilities........................................... 2,160 8,525 --------- --------- Total liabilities......................................... 325,977 314,861 Stockholders' equity: Common stock, par value $.01, 50,000,000 shares authorized 6,897,069 and 6,871,069 shares issued, 6,857,269 and 6,836,769 shares outstanding as of September 30, 1999, and December 31, 1998, respectively....................... 69 68 Additional paid-in capital.................................. 65,813 65,715 Accumulated deficit......................................... (47,171) (61,590) Accumulated other comprehensive income (loss)............... (393) (380) --------- --------- Total stockholder's equity................................ 18,318 3,813 --------- --------- Total liabilities and stockholders' equity................ $ 344,295 $ 318,674 ========= =========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS. 3 COGENERATION CORPORATION OF AMERICA CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
THREE MONTHS ENDED NINE MONTHS ENDED ------------------------------- ------------------------------- SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, 1999 1998 1999 1998 ------------- ------------- ------------- ------------- REVENUES: Energy revenues ............................ $ 25,140 $ 11,153 $ 70,442 $ 32,954 Equipment sales and services ............... 3,803 6,237 10,899 14,571 Rental revenues ............................ - 727 - 2,208 -------- -------- -------- -------- 28,943 18,117 81,341 49,733 COST OF REVENUES: Cost of energy revenues .................... 17,144 4,205 45,982 11,905 Cost of equipment sales and services ....... 3,298 5,229 9,474 12,697 Cost of rental revenues .................... - 585 - 1,759 -------- -------- -------- -------- 20,442 10,019 55,456 26,361 Gross profit .............................. 8,501 8,098 25,885 23,372 Selling, general and administrative expenses .................. 1,910 1,387 6,493 5,923 -------- -------- -------- -------- Income from operations ....................... 6,591 6,711 19,392 17,449 -------- -------- -------- -------- Interest and other income .................. 457 215 1,000 684 Equity in earnings of affiliates ........... 3,039 1,595 7,092 4,241 Gain from settlement of litigation ......... - - 14,536 - Interest and debt expense .................. (5,938) (3,504) (17,248) (10,543) Merger expense ............................. (1,635) - (1,635) - -------- -------- -------- -------- Income before income taxes ................. 2,514 5,017 23,137 11,831 -------- -------- -------- -------- Provision for income taxes ................. 911 1,809 8,718 4,571 -------- -------- -------- -------- Net income ............................. $ 1,603 $ 3,208 $ 14,419 $ 7,260 ======== ======== ======== ======== Basic earnings per share ................... $ 0.23 $ 0.47 $ 2.10 $ 1.06 ======== ======== ======== ======== Diluted earnings per share ................. $ 0.23 $ 0.46 $ 2.06 $ 1.04 ======== ======== ======== ======== Weighted average shares outstanding(Basic) ........................ 6,857 6,837 6,853 6,837 ======== ======== ======== ======== Weighted average shares outstanding (Diluted) ..................... 7,080 6,952 6,990 6,983 ======== ======== ======== ========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS. 4 COGENERATION CORPORATION OF AMERICA CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (DOLLARS IN THOUSANDS)
NINE MONTHS ENDED ------------------------------- SEPTEMBER 30, SEPTEMBER 30, 1999 1998 ------------- ------------- Cash Flows from Operating Activities: Net income .................................................. $ 14,419 $ 7,260 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ........................... 10,388 6,343 Write off of deferred financing costs ................... 890 - Equity in earnings of affiliates ........................ (7,092) (4,241) Gain on disposition of property and equipment ........... - (137) Gain on settlement of litigation ........................ (14,536) - Other, net .............................................. - 57 Changes in operating assets and liabilities: Accounts receivable, net ............................. (5,244) (2,056) Inventories .......................................... (139) (234) Receivables from related parties ..................... 112 (59) Other assets ......................................... 362 276 Accounts payable and other current liabilities ....... 7,578 2,381 -------- -------- Net cash provided by operating activities ........ 6,738 9,590 -------- -------- Cash Flows from Investing Activities: Capital expenditures ........................................ (16,960) (48,971) Proceeds from disposition of property and equipment ......... - 686 Project development costs ................................... - (602) Collections on notes receivable ............................. - 24 Deposits into restricted cash accounts, net ................. (145) (2,629) -------- -------- Net cash used in investing activities ............ (17,105) (51,492) -------- -------- Cash Flows from Financing Activities: Proceeds from long-term debt ................................ 11,267 47,625 Repayments of long-term debt ................................ (10,179) (6,280) Net proceeds of short-term borrowing ........................ 8,787 1,281 Deferred financing costs .................................... - (751) Purchase of treasury stock .................................. (50) - Proceeds from issuance of common stock ...................... 149 - -------- -------- Net cash provided by financing activities ........ 9,974 41,875 -------- -------- Net decrease in cash and cash equivalents ....................... (393) (27) Cash and cash equivalents, beginning of period .................. 3,568 3,444 -------- -------- Cash and cash equivalents, end of period ........................ $ 3,175 $ 3,417 ======== ======== Supplemental disclosure of cash flow information: Interest paid ............................................... $ 15,868 $ 10,622 Income taxes paid ........................................... $ 3,105 $ 1,424 Transfer of construction payables into long-term debt ....... - $ 6,825
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS. 5 COGENERATION CORPORATION OF AMERICA NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) SEPTEMBER 30, 1999 (DOLLARS IN THOUSANDS) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cogeneration Corporation of America ("CogenAmerica" or the "Company") is an independent power producer pursuing "inside-the-fence" cogeneration projects in the U.S. The Company is engaged primarily in the business of developing, owning and managing the operation of cogeneration projects which produce electricity and thermal energy for sale under long-term contracts with industrial and commercial users and public utilities. The Company is currently focusing on natural gas-fired cogeneration projects with long-term contracts for substantially all of the output of such projects. In addition the Company sells and rents power generation and standby/peak shaving equipment and services through several subsidiaries in the United Kingdom operating under the common name "PUMA". The Company has determined and previously announced that its equipment sales, rental and services business is not a part of its strategic plan. As a result of the Company's pending merger (see Part I - Item 2) the Company has suspended efforts for the disposition of PUMA. BASIS OF PRESENTATION The consolidated financial statements include the accounts of all majority-owned subsidiaries and all significant intercompany accounts and transactions have been eliminated. Investments in companies, partnerships and projects that are more than 20% but less than majority-owned are accounted for by the equity method. The accompanying unaudited consolidated financial statements and notes should be read in conjunction with the Company's Report on Form 10-K for the year ended December 31, 1998. In the opinion of management, the consolidated financial statements reflect all adjustments necessary for a fair presentation of the interim periods presented. Results of operations for an interim period may not give a true indication of results for the year. NET EARNINGS PER SHARE Basic earnings per share ("EPS") includes no dilution and is computed by dividing net income (loss) by the weighted average shares of common stock outstanding. Diluted EPS is computed by dividing net income (loss) by the weighted average shares of common stock and dilutive common stock equivalents outstanding. The Company's dilutive common stock equivalents result from stock options and are computed using the treasury stock method. 6
THREE MONTHS ENDED THREE MONTHS ENDED ---------------------------------------- ---------------------------------------- SEPTEMBER 30, 1999 SEPTEMBER 30, 1998 ---------------------------------------- ---------------------------------------- INCOME SHARES INCOME SHARES (NUMERATOR) (DENOMINATOR) EPS (NUMERATOR) (DENOMINATOR) EPS ----------- ------------- ------ ----------- ------------- ------ Net income: Basic EPS $ 1,603 6,857 $ 0.23 $ 3,208 6,837 $ 0.47 Effect of dilutive stock options - 223 115 ------- ------- ------- ------- Diluted EPS $ 1,603 7,080 $ 0.23 $ 3,208 6,952 $ 0.46 ======= ======= ======= =======
NINE MONTHS ENDED NINE MONTHS ENDED ---------------------------------------- ---------------------------------------- SEPTEMBER 30, 1999 SEPTEMBER 30, 1998 ---------------------------------------- ---------------------------------------- INCOME SHARES INCOME SHARES (NUMERATOR) (DENOMINATOR) EPS (NUMERATOR) (DENOMINATOR) EPS ----------- ------------- ------ ----------- ------------- ------ Net income: Basic EPS $14,419 6,853 $ 2.10 $ 7,260 6,837 $ 1.06 Effect of dilutive stock options - 137 - 146 ------- ------- ------- ------- Diluted EPS $14,419 6,990 $ 2.06 $ 7,260 6,983 $ 1.04 ======= ======= ======= =======
2. LOANS AND PAYABLES DUE NRG ENERGY, INC. Amounts owed to NRG Energy, Inc. ("NRG Energy") are comprised of the following:
SEPTEMBER 30, DECEMBER 31, 1999 1998 ------------- ------------ Long-term debt: Note due April 30, 2001 $ 2,539 $ 2,539 Grays Ferry note due July 1, 2005 1,900 1,900 Pryor note due September 30, 2004 22,874 23,947 Morris note due December 31, 2004 20,120 12,027 -------- -------- 47,433 40,413 Less current portion (9,500) (4,290) -------- -------- $ 37,933 $ 36,123 ======== ======== Current maturities of loans and accounts payable: Current maturities: Morris note $ 5,745 $ 2,104 Pryor note 3,755 2,186 Bridge note due December 31, 1999 8,000 - Accounts payable: Management services, operations and other 4,438 2,730 -------- -------- $ 21,938 $ 7,020 ======== ========
7 On June 7, 1999, the Company entered into an $8,000 bridge financing note with NRG Energy. The interest rate on the note evidencing such loan is set at prime plus 1.5%. The note was undertaken due to a delay in converting the Morris construction loan to a term loan and to finance the Morris chiller project. On September 29, 1999, such note was amended and restated to extend the maturity date to December 31, 1999. On October 19, 1999, the note amount was increased to $11,000. 3. COMPREHENSIVE INCOME The Company's comprehensive income is comprised of net income and other comprehensive income, which consists solely of foreign currency translation adjustments. Income taxes have not been provided on the foreign currency translation adjustments as the earnings of the foreign subsidiary are considered permanently reinvested. The components of comprehensive income, for the three months and nine months ended September 30, 1999, and 1998 were as follows:
THREE MONTHS ENDED NINE MONTHS ENDED ------------------------------- ------------------------------- SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, 1999 1998 1999 1998 ------------- ------------- ------------- ------------- Net income $ 1,603 $ 3,208 $ 14,419 $ 7,260 Foreign currency translation gain (loss) 114 47 (13) 73 -------- -------- -------- -------- Comprehensive income $ 1,717 $ 3,255 $ 14,406 $ 7,333 ======== ======== ======== ========
4. INVESTMENT IN EQUITY AFFILIATES Investments in equity affiliates consist of the following:
SEPTEMBER 30, DECEMBER 31, 1999 1998 ------------- ------------ Grays Ferry (50% owned) $ 38,947 $ 17,603 PoweRent Limited (50% owned) 726 576 --------- --------- $ 39,673 $ 18,179 ========= =========
GRAYS FERRY On September 30, 1999, CogenAmerica Schuylkill, a wholly-owned subsidiary of the Company, had a 50% partnership interest in the Grays Ferry Cogeneration Partnership ("Grays Ferry"). The other 50% partnership interest as of such date was owned by a wholly-owned subsidiary of Trigen Energy Corporation ("Trigen"). Grays Ferry has constructed a 150 MW cogeneration facility located in Philadelphia which began commercial operations in January 1998. Grays Ferry has a 25-year contract to supply all the steam produced by the project to an affiliate of Trigen through 2022 and two 20-year contracts ("PPAs") to supply all of the electricity produced by the project to PECO Energy Company ("PECO")through 2017. 8 On April 23, 1999, Grays Ferry and PECO reached final settlement on the resolution of litigation concerning the parties' Power Purchase Agreements. Under the terms of the settlement, PECO transferred its one-third ownership interest in the 150-megawatt project to Grays Ferry. As a result, the Company's interest in Grays Ferry increased to 50% from one-third effective April 23, 1999. The Company accounts for its investment in Grays Ferry by the equity method. The Company's equity in earnings of the partnership was $2,983 and $1,583 for the three months ended September 30, 1999, and 1998, respectively, and $6,941 and $4,215 for the nine months ended September 30, 1999, and 1998, respectively. Summarized financial information for Grays Ferry is presented below:
SEPTEMBER 30, SEPTEMBER 30, 1999 1998 ------------- ------------ Current assets $ 32,567 $ 35,441 Non-current assets $ 153,775 $ 160,382 Current liabilities $ 14,437 $ 20,624 Non-current liabilities $ 106,630 $ 127,111
THREE MONTHS ENDED NINE MONTHS ENDED ------------------------------- ------------------------------- SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, 1999 1998 1999 1998 ------------- ------------- ------------- ------------- Net revenues $ 22,330 $ 20,665 $ 62,358 $ 58,128 Cost of sales $ 12,325 $ 10,938 $ 35,259 $ 32,975 Operating income $ 9,186 $ 8,241 $ 21,687 $ 21,538 Partnership net income $ 5,965 $ 4,531 $ 14,538 $ 12,646
POWERENT LIMITED PoweRent Limited ("PoweRent") is a United Kingdom company that sells and rents power generation equipment. The Company owns 50% of PoweRent through its wholly-owned United Kingdom subsidiary, NRG Generating, Ltd. The Company accounts for its investment in PoweRent by the equity method. The Company's equity in earnings was $56 and $12 for the three months ended September 30, 1999, and 1998, respectively, and $151 and $26 for the nine months ended September 30, 1999, and 1998, respectively. 5. GAIN FROM SETTLEMENT OF LITIGATION On April 23, 1999, Grays Ferry and PECO reached final settlement on the resolution of litigation concerning the parties' Power Purchase Agreements. Under the terms of the settlement, PECO transferred its one-third ownership interest in the 150-megawatt project to Grays Ferry. As a result, the Company's interest in Grays Ferry increased to 50% from one-third effective April 23, 1999. 9 The Company recorded the receipt of the additional ownership interest in Grays Ferry using the purchase method and recognized a one-time pre-tax gain in the amount $14,536 representing the fair value of the additional ownership interest received in the settlement. 6. MERGER EXPENSE At September 30, 1999, the Company incurred legal, accounting and investment banking costs of $1,635 related to the pending merger. 7. SEGMENT INFORMATION The Company is engaged principally in developing, owning and managing cogeneration projects and the sale and service of cogeneration related equipment. The Company has classified its operations into the following segments: energy, and equipment sales, rental and services. The energy segment consists of cogeneration and standby/peak shaving projects. The equipment sales, rental and services segment consists of PUMA, the Company's wholly-owned subsidiary based in the United Kingdom and O'Brien Energy Services Company ("OES") until its sale in November 1998. Summarized information about the Company's operations in each industry segment are as follows:
QUARTER ENDED SEPTEMBER 30, 1999 -------------------------------------------------------------- EQUIPMENT SALES, RENTAL ENERGY & SERVICES OTHER TOTAL -------- ------------- --------- -------- Revenues $ 25,140 $ 3,803 $ - $ 28,943 Depreciation and amortization 3,308 29 - 3,337 Other cost of revenues 13,836 3,269 - 17,105 -------- -------- --------- -------- Gross profit 7,996 505 - 8,501 Selling, general & administrative expenses 1,378 342 190 1,910 -------- -------- --------- -------- Income (loss) from operations 6,618 163 (190) 6,591 Interest & other income 228 - 229 457 Interest & debt expense (5,365) (72) (501) (5,938) Equity in earning of affiliates 2,983 56 - 3,039 Merger expense - - (1,635) (1,635) -------- -------- --------- -------- Income (loss) before taxes $ 4,464 $ 147 $ (2,097) $ 2,514 ======== ======== ========= ========
QUARTER ENDED SEPTEMBER 30, 1998 -------------------------------------------------------------- EQUIPMENT SALES, RENTAL ENERGY & SERVICES OTHER TOTAL -------- ------------- --------- -------- Revenues $ 11,153 $ 6,964 $ - $ 18,117 Depreciation and amortization 1,889 63 - 1,952 Other cost of revenues 2,316 5,751 - 8,067 -------- -------- --------- -------- Gross profit 6,948 1,150 - 8,098 Selling, general & administrative expenses 617 656 114 1,387 -------- -------- --------- -------- Income (loss) from operations 6,331 494 (114) 6,711 Interest & other income 128 2 85 215 Interest & debt expense (3,068) (95) (341) (3,504) Equity in earning of affiliates 1,583 12 - 1,595 -------- -------- --------- -------- Income (loss) before taxes $ 4,974 $ 413 $ (370) $ 5,017 ======== ======== ========= ========
10
NINE MONTHS ENDED SEPTEMBER 30, 1999 -------------------------------------------------------------- EQUIPMENT SALES, RENTAL ENERGY & SERVICES OTHER TOTAL -------- ------------- --------- -------- Revenues $ 70,442 $ 10,899 $ - $ 81,341 Depreciation and amortization 9,565 89 - 9,654 Other cost of revenues 36,417 9,385 - 45,802 -------- -------- --------- -------- Gross profit 24,460 1,425 - 25,885 Selling, general & administrative expenses 4,615 1,069 809 6,493 -------- -------- --------- -------- Income (loss) from operations 19,845 356 (809) 19,392 Interest & other income 661 - 339 1,000 Interest & debt expense (15,744) (230) (1,274) (17,248) Equity in earning of affiliates 6,941 151 - 7,092 Gain from settlement of litigation 14,536 - - 14,536 Merger expenses - - (1,635) (1,635) -------- -------- --------- -------- Income (loss) before taxes $ 26,239 $ 277 $ (3,379) $ 23,137 ======== ======== ========= ======== Identifiable assets $332,124 $ 8,453 $ 3,718 $344,295 Capital expenditures $ 16,935 $ 15 $ 10 $ 16,960
NINE MONTHS ENDED SEPTEMBER 30, 1998 -------------------------------------------------------------- EQUIPMENT SALES, RENTAL ENERGY & SERVICES OTHER TOTAL -------- ------------- --------- -------- Revenues $ 32,954 $ 16,779 $ - $ 49,733 Depreciation and amortization 5,694 177 - 5,871 Other cost of revenues 6,211 14,279 - 20,490 -------- -------- --------- -------- Gross profit 21,049 2,323 - 23,372 Selling, general & administrative expenses 3,194 2,039 690 5,923 -------- -------- --------- -------- Income (loss) from operations 17,855 284 (690) 17,449 Interest & other income 378 12 294 684 Interest & debt expense (9,283) (228) (1,032) (10,543) Equity in earning of affiliates 4,215 26 - 4,241 -------- -------- --------- -------- Income (loss) before taxes $ 13,165 $ 94 $ (1,428) $ 11,831 ======== ======== ========= ======== Identifiable assets $263,626 $ 10,695 $ 5,935 $280,256 Capital expenditures $ 48,603 $ 368 $ - $ 48,971
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information contained in this Item 2 updates, and should be read in conjunction with, the information set forth in Part II, Item 7, of the Company's Report on Form 10-K for the year ended December 31, 1998. Capitalized terms used in this Item 2 which are not defined herein have the meaning ascribed to such terms in the Notes to the Company's consolidated financial statements included in Part I, Item 1 of this Report on Form 10-Q. All dollar amounts (except per share amounts) set forth in this Report are in thousands. Except for the historical information contained in this Report, the matters reflected or discussed in this Report which relate to the Company's beliefs, expectations, plans, future estimates and the like are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange 11 Act of 1934, as amended. Without limiting the generality of the foregoing, the words "believe," "anticipate," "estimate," "expect," "intend," "plan," "seek" and similar expressions, when used in this Report and in such other statements, are intended to identify forward-looking statements. Such forward-looking statements are subject to risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company to differ materially from historical results or from any results expressed or implied by such forward-looking statements. Such factors include, without limitation, operating risks and uncertainties which tend to be greater with respect to new facilities, such as the risk that the breakdown or failure of equipment or processes or unanticipated performance problems may result in lost revenues or increased expenses, and other factors discussed in this Report and the Company's Report on Form 10-K for the year ended December 31, 1998 in the section entitled "Item 1. Business - Risk Factors". Many of such factors are beyond the Company's ability to control or predict, and readers are cautioned not to put undue reliance on such forward-looking statements. By making these forward-looking statements, the Company does not undertake to update them in any manner except as may be required by the Company's disclosure obligations in filings it makes with the Securities and Exchange Commission under the Federal securities laws. GENERAL CogenAmerica is an independent power producer pursuing "inside-the-fence" cogeneration projects in the U.S. The Company is engaged primarily in the business of developing, owning and managing the operation of cogeneration projects which produce electricity and thermal energy for sale under long-term contracts with industrial and commercial users and public utilities. The Company is currently focusing on natural gas-fired cogeneration projects with long-term contracts for substantially all of the output of such projects. The Company's strategy is to develop, acquire and manage the operation of such cogeneration projects and to provide U.S. industrial facilities and utilities with reliable and competitively priced energy from its power projects. CogenAmerica has substantial expertise in the development and operation of power projects. The Company's project portfolio as of September 30, 1999, consisted of: (i) a 122 MW cogeneration facility in Parlin, New Jersey (the "Parlin Project"), which began commercial operation in June 1991 and is owned through its wholly-owned subsidiary, CogenAmerica Parlin; (ii) a 58 MW cogeneration facility in Newark, New Jersey (the "Newark Project"), which began commercial operation in November 1990 and is owned through its wholly-owned subsidiary, CogenAmerica Newark; (iii) a 117 MW cogeneration facility in Morris, Illinois (the "Morris Project"), which began commercial operation in November 1998 and is owned through its wholly-owned subsidiary, CogenAmerica Morris; (iv) a 110 MW cogeneration facility in Pryor, Oklahoma (the "Pryor Project"), which had been in commercial operation prior to acquisition by the Company in October 1998, and is owned through the Company's wholly-owned subsidiary, Oklahoma Loan Acquisition Corporation; 12 (v) two standby/peak shaving facilities with an aggregate capacity of 22 MW in Philadelphia, Pennsylvania (the "PWD Project"), which began commercial operation in September 1993, the principal project agreements of which are held by O'Brien (Philadelphia) Cogeneration, Inc., an 83%-owned subsidiary of the Company; and (vi) a 50% partnership interest in a 150 MW cogeneration facility located at Grays Ferry in Philadelphia, Pennsylvania (the "Grays Ferry Project"), which began operation in January 1998. CogenAmerica's partnership interest increased to 50% on April 23, 1999. Each of the projects is currently producing revenues under long-term power sales agreements that expire at various times. Energy and capacity payment rates are generally negotiated during the development phase of a cogeneration project and are finalized prior to securing project financing and the start of a plant's commercial operation. Pricing provisions of each of the Company's project power sales agreements contain unique features. As a result, different rates exist for each plant and customer pursuant to the applicable power sales agreement. However, in general, electric revenues for each of the Company's cogeneration projects consist of two components: energy payments and capacity payments. Energy payments are based on the power plant's actual net electrical output, expressed in kilowatt-hours of energy, purchased by the customer. Capacity payments are based on the net electrical output the power plant is capable of producing (or portion thereof) and which the customer has contracted to have available for purchase. Energy payments are made for each kilowatt-hour of energy delivered, while capacity payments, under certain circumstances, are made whether or not any electricity is actually delivered. The projects' energy and capacity payments are generally based on scheduled prices and/or base prices subject to periodic indexing mechanisms, as specified in the power sales agreements. In general terms, energy and capacity payments are intended to recover the variable and fixed costs of operating the plant, respectively, plus a return. A power plant may be characterized as one or more of the following: a "base-load" facility, a "dispatchable" facility, a combination "base-load/dispatchable" facility or a "merchant" facility. Such characterization depends upon the manner in which the plant will be used and the requirements of the related power sales agreement(s). A "base-load" facility generally means that the plant is operated continuously to produce a fixed amount of energy and capacity for one or more customers. A "dispatchable" facility generally means that the customer(s) purchased the right to a fixed amount of available capacity, which must be produced if and when requested by the customer(s). A combination "base-load/dispatchable" facility is a plant that operates in both modes, with a portion of the plant's capacity designated as base-load and the remainder available for dispatch. A "merchant" facility generally refers to a plant that operates and sells its output to various customers at prevailing market prices rather than pursuant to a long-term power sales agreement. 13 Under a power sales agreement ("PPA") with Jersey Central Power and Light Company ("JCP&L") extending into 2011, CogenAmerica Parlin has committed 114 MW of the Parlin facility's generating capacity to JCP&L, of which 41 MW are committed as base capacity and 73 MW as dispatchable capacity. JCP&L must purchase energy from the base capacity whenever such energy is available from the Parlin facility. Energy from the dispatchable capacity is purchased by JCP&L only when requested (dispatched) by JCP&L. The Parlin PPA provides for curtailment by JCP&L under such typical conditions as emergencies, inspection and maintenance. JCP&L may also reduce base capacity during periods of low load on the PJM (the local wholesale market) by up to 600 hours in any calendar year, of which 400 may be during on-peak periods, but only when all PJM member utilities are required to reduce generation to minimum levels and PJM has requested JCP&L to reduce or interrupt external generation purchases. The Parlin PPA also provides for an annual average heat rate adjustment that will increase or decrease JCP&L's payments to CogenAmerica Parlin, depending upon whether the average heat rate of the Parlin Project is below or above average 9,500 Btu per kWh (higher heating value). The actual adjustment is calculated by applying a ratio based on this differential to a fuel cost calculation. In addition, the Parlin PPA provides for an annual availability adjustment that will increase or decrease JCP&L's payments under the contract depending upon whether the availability targets set forth in the contract are met during a given contract year. The Newark Project has a power sales agreement with JCP&L extending through 2015 whereby it has committed to sell all of the Newark facility's generating capacity to JCP&L, up to a maximum of 58 MW per hour. The Newark Project is effectively a base-load unit and JCP&L must purchase the energy whenever such energy is available from the Newark facility. Under the terms of the Newark PPA, JCP&L, in its sole discretion, is allowed to curtail production at the facility for 700 hours per year provided that the duration of each curtailment is a minimum of six hours and all curtailments occur only during Saturdays, Sundays and Holidays. Since contract inception in 1996, JCP&L have fully utilized this curtailment option annually and the Company expects JCP&L will continue to do so in future years. JCP&L may also disconnect from CogenAmerica Newark for emergencies, inspections and maintenance for up to 400 hours per year if all PJM member utilities are required to reduce generation to minimum levels and JCP&L has been requested by PJM to reduce or interrupt external generation purchases. The Newark PPA provides for an annual average heat rate adjustment that will increase or decrease JCP&L's payments to CogenAmerica Newark depending upon whether the average heat rate of the Newark Project is below or above 9,750 Btu per kWh (higher heating value). The actual adjustment is calculated by applying a ratio based upon this differential to a fuel cost calculation. In addition, the Newark PPA provides for an annual availability adjustment that will increase or decrease JCP&L's payments under the contract depending upon whether the availability targets set forth in the contract are met during a given contract year. The Morris Project has an Energy Service Agreement ("ESA") with Equistar through 2023 to provide base-load power and steam. Equistar has agreed to purchase the entire requirements of Equistar's plant (subject to certain exceptions) for electricity up to the full electric output of two of the three combustion turbines at the Morris Project. In addition, the Morris Project has an arrangement with the local utility to provide standby power. Each combustion turbine at the Morris facility has a nominal rating of 39 MW. The Morris Project designed redundancy into the energy production capability of the facility 14 in order to meet Equistar's demand. The cost of installing and maintaining the reserve capacity was taken into account when the energy services agreement was negotiated. The Morris Project is permitted to arrange for the sale to third parties of interruptible capacity and/or energy from the third turbine and to the extent available, any excess power from the two turbines required to supply Equistar with its actual requirements. The Company is in the process of upgrading the Morris Project by installing inlet chillers to increase the output of the facility during the summer months. The Morris Project is currently negotiating with a third-party power marketer for the sale of this excess capacity/energy. The Pryor Project has a power sales agreement with Oklahoma Gas and Electric Company ("OG&E") through 2008 to provide 110 MW of dispatchable capacity, with a maximum dispatch of 1,500 hours per year. The facility also sells electricity to Public Service Company of Oklahoma ("PSO") when not dispatched by OG&E. The Pryor Project purchases natural gas from Dynegy and Aquila. Under the terms of the agreement with PSO, the pricing of energy sales is indexed to a market fuel rate. Under terms of the agreement with OG&E, energy sales are linked to the average cost of fuel. The power sales agreements for the Parlin, Newark, and Morris projects are structured to avoid or minimize the impact on the Company's revenues from fluctuations in fuel costs. Since the Parlin and Newark power sales agreements were amended in April 1996, JCP&L is responsible for the supply and transportation of natural gas required to operate the Parlin and Newark plants. Thus, revenues from the Parlin and Newark plants exclude any amounts attributable to recovery of fuel costs. Prior to the contract amendments, Parlin and Newark cost of revenues included fuel and related costs and contract provisions for delayed recovery of such costs in revenues caused variability in the projects' gross profit. Under the terms of the Morris Project ESA with Equistar, Equistar is the fuel manager. All of the costs of supplying the fuel for the combustion turbines are effectively a pass-through to Equistar. As a result, although fuel costs are included in the Morris Project revenues and cost of revenues, the Company believes it has minimized any impact on gross profit from fluctuations in the price of natural gas purchases and supply for the Morris Project. The Grays Ferry Project has a gas sales agreement with Aquila providing for the purchase of natural gas to meet the power plant's requirements. For the period from commercial operations in January 1998 until the end of the year 2000, the partnership has purchased a natural gas collar with a cap in order to limit the volatility of natural gas purchases. Beginning in 2001, the price for natural gas supplied by Aquila is indexed to a market electricity rate. During 1998, the Company also sold and rented power generation equipment and provided related services in the U.S. and international markets under the names OES and PUMA. As previously announced, the Company has determined that its equipment sales rental and services segment is no longer a part of its strategic plan. Accordingly, on November 5, 1998, the Company sold OES, a wholly-owned subsidiary of the Company, in a stock transaction to an unrelated third party. The Company is currently pursuing alternatives for the disposition of its remaining equipment sales and services business operated by PUMA. The Company expects that the disposition of PUMA will not have a material adverse effect on the Company's results of operations or financial condition. Although OES was 15 sold in 1998, the equipment sales, rental and services segment has not been reported as a discontinued operation in the financial statements because specific plans regarding the timing and manner of ultimate disposition of PUMA are still under consideration. MERGER ANNOUNCEMENT On August 26, 1999, CogenAmerica entered into a definitive agreement pursuant to which, Calpine Corporation ("Calpine"), through Calpine East Acquisition Corp. ("Acquisition Corp."), a subsidiary of Calpine, will acquire the outstanding common stock of CogenAmerica, other than certain shares held by NRG Energy, Inc. ("NRG"), for $25.00 per share. Pursuant to the transaction, NRG will contribute to Acquisition Corp. approximately 1.5 million shares of the Company representing a 20% interest in Acquisition Corp. and receive the merger consideration of $25.00 per share for the remaining shares of the Company. The transaction contemplates that NRG will retain a 20% interest in CogenAmerica following completion of the transaction. The transaction is subject to various regulatory approvals and approval by shareholders of CogenAmerica. A special meeting of shareholders will be held on December 16, 1999, for shareholders of record as of November 12, 1999. Assuming an affirmative vote by shareholders and subject to the various regulatory approvals, the merger is expected to occur in December 1999. NET INCOME AND EARNINGS PER SHARE Net income for the 1999 third quarter was $1,603 or diluted earnings per share of $0.23, compared to third quarter 1998 net income of $3,208, or diluted earnings per share of $0.46. Net income for the first nine months of 1999 was $14,419, or diluted earnings per share of $2.06 compared to net income of $7,260, or diluted earnings per share of $1.04 for the comparable period in 1998. The decrease in net income and earnings per share for the third quarter was primarily due to curtailments and plant performance adjustments at Newark and Parlin and merger expenses related to an Agreement and Plan of Merger (the "Merger Agreement") dated August 26, 1999, among Calpine Corporation, Calpine East Acquisition Corporation and Cogeneration Corporation of America. The increase in net income and earnings per share for the first nine months of 1999 was primarily due to a one-time gain representing the fair value of the additional ownership interest in the Grays Ferry Project resulting from the April 23, 1999, settlement between the Grays Ferry Cogeneration Partnership and PECO. During 1999, earnings from the energy segment were negatively affected by forced outages, curtailments and plant performance adjustments, higher interest expense due to the addition of the Morris and Pryor Projects, and merger expenses related to an Agreement and Plan of Merger dated August 26, 1999, among Calpine Corporation, Calpine East Acquisition Corporation and Cogeneration Corporation of America. REVENUES Energy revenues for the third quarter of 1999 of $25,140 increased from $11,153 for the comparable period in 1998. Energy revenues for the first nine months of 1999 of $70,442 increased from $32,954 for the comparable period in 1998. Energy revenues primarily reflect billings associated with the Parlin, Newark, Morris, Pryor and PWD Projects. 16 The increase in energy revenues for the third quarter was primarily attributable to the acquisition of the Pryor Project in October 1998, and commencement of Morris operations in November 1998. Energy revenues were negatively impacted by unscheduled outages and curtailments at the Newark and Parlin facilities and a provision for availability and heat rate adjustments at Newark and Parlin. The Company must maintain target availability and heat rate values at Newark and Parlin to avoid adjustments and is currently reviewing the customer's availability calculations. The Company has initiated a plant operating performance review to develop a plan to increase availability and heat rate to levels historically maintained. The increase in energy revenues for the first nine months of 1999 was primarily attributable to the acquisition of the Pryor Project in October 1998, and commencement of Morris operations in November 1998. Energy revenues were negatively impacted by unscheduled outages and curtailments in 1999 at the Newark and Parlin facilities and a provision for availability and heat rate adjustments at Newark and Parlin.
PROJECT ENERGY REVENUES THREE MONTHS ENDED NINE MONTHS ENDED ------------------------------- ------------------------------- SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, 1999 1998 1999 1998 ------------- ------------- ------------- ------------- COGENERATION PROJECTS Parlin $ 5,614 $ 6,022 $ 15,197 $ 16,535 Newark 4,408 4,070 12,379 13,258 Morris 9,749 - 27,903 - Pryor 4,895 - 12,375 - STANDBY/PEAK SHAVING FACILITIES PWD 474 1,061 2,588 3,161 --------- --------- --------- --------- $ 25,140 $ 11,153 $ 70,442 $ 32,954 ========= ========= ========= =========
Equipment sales and services revenues for the third quarter 1999 of $3,803 decreased from $6,237 for the comparable period in 1998. Equipment sales and services revenues of $10,899 for the first nine months of 1999 decreased from $14,571 for the comparable period in 1998. The decrease in revenues for the third quarter and first nine months was primarily attributable to the sale of OES in November 1998. Rental revenues in the 1998 third quarter and first nine months were attributable to OES, which was sold in November 1998. COSTS AND EXPENSES Cost of energy revenues for the third quarter 1999 of $17,144 increased from $4,205 for the comparable period in 1998. Cost of energy revenues for the first nine months of 1999 of $45,982 increased from $11,905 for the comparable period in 1998. The increase in cost of energy revenues for the third quarter and the first nine months of 1999 was primarily the result of commencement of the Morris Project operations and the Pryor Project acquisition. Cost of equipment sales and services for the third quarter 1999 of $3,298 decreased from $5,229 for the comparable period in 1998. Cost of equipment sales and services for the first nine months of 1999 of $9,474 decreased from $12,697 for the comparable period in 1998. The change is primarily attributable to the sale of OES in November 1998. 17 Cost of rental revenues in the 1998 third quarter and first nine months were attributable to OES, which was sold in November 1998. The Company's gross profit for the third quarter of 1999 of $8,501 (29.4% of sales) increased from the third quarter 1998 gross profit of $8,098 (44.7% of sales). Gross profit for the first nine months of 1999 of $25,885 (31.8% of sales) increased from gross profit of $23,372 (47.0% of sales) for the first nine months of 1998. The gross profit increase for the third quarter and first nine months of 1999 was primarily attributable to the addition of the Morris and Pryor Projects. The decline in gross profit, as a percentage of sales, was primarily attributable to the addition of the Morris and Pryor Projects which have lower operating margins than the Newark and Parlin Projects. It is expected that competition will continue to put pressure on the margins of new projects in the future. SELLING, GENERAL AND ADMINISTRATIVE EXPENSES Selling, general and administrative expenses ("SG&A") for the third quarter 1999 of $1,910 increased from third quarter 1998 SG&A expenses of $1,387. Selling, general and administrative expenses for the first nine months of 1999 of $6,493 increased from $5,923 for the comparable period in 1998. The increase for the third quarter was primarily the result of commencement of the Morris Project operations and the Pryor acquisition. The increase for the first nine months of 1999 was primarily due to a second quarter charge of $890 to write off deferred costs related to a capital markets financing plan that was terminated in addition to the commencement of the Morris Project operations and the Pryor acquisition. Such charges were partially offset by lower legal expenses. INTEREST AND OTHER INCOME Interest and other income for the third quarter 1999 of $457 increased from interest and other income of $215 for the comparable period in 1998. Interest and other income for the first nine months of 1999 of $1,000 increased from $684 for the comparable period in 1998. The increase is primarily attributable to interest earned on escrow funds required by the terms of the Morris Project credit agreement, and a gain on the sale of investments of $170. EQUITY IN EARNINGS OF AFFILIATES Equity in earnings of affiliates for the third quarter 1999 of $3,039 increased from $1,595 in the comparable period in 1998. Equity in earnings of affiliates for the first nine months of 1999 of $7,092 increased from $4,241 for the comparable period in 1998. The increase is primarily attributable to higher earnings from Grays Ferry due to an increase in ownership interest from one-third to 50% effective April 23, 1999. GAIN ON SETTLEMENT OF LITIGATION On April 23, 1999, Grays Ferry and PECO reached final settlement on the resolution of litigation concerning the parties' Power Purchase Agreements. Under the terms of the settlement, PECO transferred its one-third ownership interest in the 150-megawatt project to Grays Ferry. As a result, the Company's interest in Grays Ferry increased to 50% from one-third effective April 23, 1999. 18 Gain from settlement of litigation for the first nine months of 1999 represents a one-time pre-tax gain in the amount $14,536 representing the fair value of the additional ownership interest resulting from settlement of litigation. INTEREST AND DEBT EXPENSE Interest and debt expense for the third quarter 1999 of $5,938 increased from interest and debt expense of $3,504 for the comparable period in 1998. Interest and debt expense for the first nine months of 1999 of $17,248 increased from $10,543 for the comparable period in 1998. The increase was primarily attributable to the financing of the Pryor and Morris Projects, both of which were acquired and commenced commercial operations, respectively, in the fourth quarter of 1998. MERGER EXPENSE On August 26, 1999, CogenAmerica entered into a definitive agreement pursuant to which, Calpine Corporation ("Calpine"), through Calpine East Acquisition Corp. ("Acquisition Corp."), a subsidiary of Calpine, will acquire the outstanding common stock of CogenAmerica, other than certain shares held by NRG Energy, Inc. ("NRG"), for $25.00 per share. Pursuant to the transaction, NRG will contribute to Acquisition Corp. approximately 1.5 million shares of the Company representing a 20% interest in Acquisition Corp. and receive the merger consideration of $25.00 per share for the remaining shares of the Company. The transaction contemplates that NRG will retain a 20% interest in CogenAmerica following completion of the transaction. The transaction is subject to various regulatory approvals and approval by shareholders of CogenAmerica. A special meeting of shareholders will be held on December 16, 1999, for shareholders of record as of November 12, 1999. Assuming an affirmative vote by shareholders and subject to the various regulatory approvals, the merger is expected to occur in December 1999. Merger expense for the third quarter of 1999 represents costs related to such merger. INCOME TAXES Income tax expense for the third quarter of 1999 of $911 decreased from $1,809 for the comparable period in 1998. Income tax expense for the first nine months of 1999 of $8,718 increased from $4,571 for the comparable period in 1998. The decrease for the third quarter was primarily due to lower pre-tax earnings driven by interest and debt expense attributable to the financing of the Pryor and Morris Projects in addition to merger expenses. The increase for the first nine months of 1999 was primarily due to higher pre-tax earnings driven by the one-time gain resulting from the settlement between Grays Ferry and PECO, partially offset by Morris and Pryor Project financing costs and merger expenses. The consolidated effective tax rate for the quarters ended September 30, 1999, and 1998 was 36.2% and 36.1%, respectively. The consolidated effective tax rate for the nine months ended September 30, 1999, and 1998 was 37.7% and 38.6%, respectively. 19 LIQUIDITY AND CAPITAL RESOURCES The development, construction and operation of cogeneration projects and other power generation facilities requires significant capital. Historically, the Company has employed substantial leverage at both the project and parent company level to finance its capital requirements. Debt financing at the project level is typically nonrecourse to the parent. Nonrecourse project financing agreements usually require initial equity investments at the project level. The Company has financed such equity investments through cash generated from operations and other borrowings, including borrowings at the parent level. Almost all of the Company's operations are conducted through subsidiaries and other affiliates. As a result, the Company depends almost entirely upon their earnings and cash flow to service consolidated indebtedness, including indebtedness of the parent, CogenAmerica. The nonrecourse project financing agreements of certain subsidiaries and other affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to the parent prior to the payment of other obligations, including operating expenses, debt service and reserves. At September 30, 1999, cash and cash equivalents totaled $3,175 and restricted cash totaled $12,302. The restricted cash primarily represents escrow funds for debt service and major maintenance as required by the terms of credit agreements for the Newark, Parlin and Morris projects. Cash provided by operating activities was $6,738 and $9,590 for the nine months ended September 30, 1999, and 1998, respectively. Cash provided by operating activities decreased primarily due to a higher investment in working capital. Cash used in investing activities was $17,105 and $51,492 for the nine months ended September 30, 1999, and 1998, respectively. Cash used by investing activities primarily represents funds used for construction of the Morris facility and chiller project. Cash provided by financing activities was $9,974 and $41,875 for the nine months ended September 30, 1999, and 1998, respectively. During the first nine months of 1999, proceeds from borrowing totaled $20,054 consisting of loans due NRG Energy related to the Morris Project and a June 7, 1999, bridge financing note with NRG Energy. Repayments of long-term debt totaled $10,179. In May 1996, the Company's wholly-owned subsidiaries the Newark Project and the Parlin Project entered into a credit agreement (the "Newark and Parlin Credit Agreement") which established provisions for a $155,000 fifteen-year loan and a $5,000 five-year debt service reserve line of credit. The loan is secured by all of the Newark and Parlin Project assets and a pledge of the capital stock of such subsidiaries. The Company has guaranteed repayment of $20,600 of the amount outstanding under the Credit Agreement. The interest rate on the outstanding principal is variable based on, at the option of CogenAmerica Newark and CogenAmerica Parlin, LIBOR plus a 1.125% margin or a defined base rate plus a 0.375% margin, with nominal margin increases in the sixth and eleventh year. For any quarterly period where the debt service coverage ratio is in excess of 1.4:1, both margins are reduced by 0.125%. Concurrently with the Newark and Parlin Credit Agreement, CogenAmerica Newark and CogenAmerica Parlin entered into an interest rate swap agreement with respect to 50% of the principal amount outstanding under the Credit Agreement. This 20 interest rate swap agreement fixes the interest rate on such principal amount at 6.9% plus the margin. At September 30, 1999, the principal amount outstanding under the credit agreement was $127,720. CogenAmerica Schuylkill, a wholly-owned subsidiary of the Company, owned as of September 30, 1999, a 50% partnership interest in the Grays Ferry Project which commenced operation in January 1998. CogenAmerica's partnership interest increased to 50% on April 23, 1999. In March 1996, the Grays Ferry Partnership entered into a credit agreement to finance the project. The credit agreement obligated each of the project's three partners to make a $10,000 capital contribution prior to the commercial operation of the facility. The Company made its required capital contribution in 1997. NRG Energy entered into a loan commitment to provide CogenAmerica Schuylkill the funding, if needed, for the CogenAmerica Schuylkill capital contribution obligation to the Grays Ferry Partnership. Prior to December 31, 1997, CogenAmerica Schuylkill had borrowed $10,000 from NRG Energy under this loan agreement, of which $1,900 remained outstanding to NRG Energy at September 30, 1999. Under the terms of the merger, the amount outstanding to NRG Energy will be repaid at the closing of the merger. In connection with its acquisition of the Morris Project, CogenAmerica Funding, a wholly-owned subsidiary of the Company, assumed all of the obligations of NRG Energy to provide future equity contributions to the project, which obligations are limited to the lesser of 20% of the total project cost or $22,000. NRG Energy had guaranteed to the Morris Project's lenders that CogenAmerica Funding would make these equity contributions, and the Company had guaranteed to NRG Energy the obligation of CogenAmerica Funding to make these equity contributions (which guarantee is secured by a second priority lien on the Company's interest in the Morris Project). In addition, NRG Energy had committed in a Supplemental Loan Agreement between the Company, CogenAmerica Funding and NRG Energy to loan CogenAmerica Funding and the Company (as co-borrowers) the full amount of such equity contributions by CogenAmerica Funding, subject to certain conditions precedent, at CogenAmerica Funding's option. Any such loan will be secured by a second priority lien on all of the membership interests of the project and will be recourse to CogenAmerica Funding and the Company. Effective November 30, 1998 the Company and NRG Energy agreed to a First Amendment to the Supplemental Loan Agreement that allowed the Company to contribute the $22,000 of equity in installments to match the construction draw payments. At September 30, 1999, the entire $22,000 had been drawn and contributed as equity. The Supplemental Loan Agreement calls for an interest rate of prime plus 1.5%. Effective with the First Amendment the interest rate was changed to prime plus 3.5% until the possible event of default related to the Grays Ferry Project had been eliminated. On February 16, 1999, NRG Energy agreed to reduce the interest rate under the loan back to prime plus 1.5%. This adjustment was made effective January 1, 1999. At September 30, 1999, $20,119 was due NRG Energy under the Supplemental Loan Agreement. On September 29, 1999, NRG Energy agreed to extend the scheduled September 30 repayment of principal until the closing of the merger. In return, the Company agreed to increase the interest rate on the amount outstanding to prime plus three and one-half percent. Under the terms of the merger, this amount outstanding to NRG Energy will be repaid at the closing of the merger. On September 15, 1997, Morris LLC (which was at that time an affiliate of NRG Energy) entered into a $91,000 construction and term loan agreement (the "Agreement") to provide nonrecourse project financing for a major portion of the Morris Project. The Company assumed the Agreement in December 1997 upon acquiring Morris LLC. The Agreement provided $85,600 of 20-month construction loan commitments and $5,400 in letter of credit commitments (the "LOC Commitment"). Upon satisfaction of all completion criteria as set 21 forth in the Agreement, the construction loan was due and payable or, if certain criteria were satisfied, would be converted to a five year term loan based on a 25-year amortization with a balloon payment at maturity. Interest on the term loan is variable based on, at the Company's option, either the base rate, as defined in the Agreement, or LIBOR plus 0.75%. The interest rate resets based on the Company's selection of the borrowing period ranging from one to six months. On June 15, 1999, the Company satisfied all conversion criteria and converted the construction loan into a five-year term loan of $85,600. In addition, the Company secured a line of credit to fund debt service reserves as required by the Agreement. Borrowings are secured by CogenAmerica Funding's ownership interest in Morris LLC, its cash flows, dividends and any other property that CogenAmerica Funding may be entitled to as owner of Morris LLC. At September 30, 1999, $85,600 was outstanding under the term loan and no amounts were pledged under the LOC Commitment. On December 17, 1997, the Company entered into the MeesPierson Credit Agreement providing for a $30,000 reducing revolving credit facility. The facility is secured by the assets and cash flows of the PWD Project as well as the distributable cash flows of the Parlin and Newark Projects, and the Grays Ferry Partnership. On December 19, 1997 the Company borrowed $25,000 under this facility. The proceeds were used to repay $16,949 to NRG Energy, to repay $6,551 of obligations of the PWD Project and $1,500 for general corporate purposes. The MeesPierson Credit Agreement includes cross default provisions that cause defaults to occur in the event certain defaults or other adverse events occur under certain other instruments or agreements (including financing and other project documents) to which the Company or one or more of its subsidiaries or other entities in which it owns an ownership interest is a party. The actions taken by the power purchaser of the Grays Ferry Project resulted in a cross default under the MeesPierson Credit Agreement. On August 14, 1998 the lender agreed to waive the default until July 1, 1999, by imposing a 2.0% increase in the interest rate effective October 1, 1998. On February 12, 1999, the lender agreed to a permanent waiver of the Grays Ferry Project cross default and eliminated the 2.0% increase in the interest rate effective January 1, 1999. The Company also reduced the size of the facility to $25,000. The repayment of the $25,000 is due in full on December 17, 2000. The Company's principal credit agreements (including the Newark and Parlin Credit Agreement) include cross-default provisions that generally permit its lenders to accelerate the indebtedness owed thereunder, to decline to make available any additional amounts for borrowing thereunder, and to exercise certain other remedies in respect of any collateral securing such indebtedness in the event certain defaults or other adverse events occur under certain other instruments or agreements (including financing and other project documents) to which the Company or one or more of its subsidiaries or other entities in which it owns an ownership interest is a party. As a result, a default under one such other instrument or agreement could have a material adverse effect on the Company by causing one or more cross-defaults to occur under one or more of the Company's principal credit agreements, potentially having one or more of the effects set forth above and otherwise adversely affecting the Company's liquidity and capital position. During 1998 the Company incurred approximately $890 of third-party costs related to a capital markets financing transaction expected to be completed during 1999. These costs were deferred and reported in the balance sheet as "Deferred financing costs, net" at December 31, 1998. During the second quarter ended June 30, 1999, the Company terminated the financing activities and expensed the deferred financing costs related to the capital markets financing in full. 22 In October 1998, NRG Energy loaned the Company and CogenAmerica Pryor approximately $23,900 to finance the acquisition of the Pryor Project. The loan is a six-year term facility calling for principal and interest payments on a quarterly basis, based on project cash flows. The interest rate on the note relating to such loan was initially set at prime rate plus 3.5% and such rate reduces by two percentage points upon the occurrence of certain events related to elimination of default risk under the loan. On February 16, 1999, NRG Energy agreed to reduce the interest rate under the loan to prime plus 1.5%. This adjustment was made effective January 1, 1999. At September 30, 1999, $22,875 was due NRG Energy under the loan. On September 29, 1999, NRG Energy agreed to extend the scheduled September 30 repayment of principal until the closing of the merger. In return, the Company agreed to increase the interest rate on the amount outstanding to prime plus three and one-half percent. Under the terms of the merger, this amount outstanding to NRG Energy will be repaid at the closing of the merger. On June 7, 1999, NRG Energy loaned the Company $8,000 in bridge financing. The loan is a revolving note maturing on December 31, 1999, calling for interest payments on a monthly basis. The interest rate on the note to such loan is set at prime plus 1.5%. On September 29, 1999, such note was amended and restated to extend the maturity date to December 31, 1999. On October 19, 1999, the note amount was increased to $11,000. At September 30, 1999, $8,000 was due NRG Energy under the loan. YEAR 2000 The Year 2000 issue refers generally to the data structure problem that may prevent systems from properly recognizing dates after the year 1999. The Year 2000 issue affects information technology ("IT") systems, such as computer programs and various types of electronic equipment that process date information by using only two digits rather than four digits to define the applicable year, and thus may recognize a date using "00" as the year 1900 rather than the year 2000. The issue also affects some non-IT systems, such as devices which rely on a microcontroller to process date information. The Year 2000 issue could result in system failures or miscalculations, causing disruptions of a company's operations. Moreover, even if a company's systems are Year 2000 compliant, a problem may exist to the extent that the data that such systems process is not. The following discussion contains forward-looking statements reflecting management's current assessment and estimates with respect to the Company's Year 2000 compliance efforts and the impact of Year 2000 issues on the Company's business and operations. Various factors, many of which are beyond the control of the Company, could cause actual plans and results to differ materially from those contemplated by such assessments, estimates and forward-looking statements. Some of these factors include, but are not limited to, representations by the Company's vendors and counterparties, technological advances, economic considerations and consumer perceptions. The Company's Year 2000 compliance program is an ongoing process involving continual evaluation and may be subject to change in response to new developments. THE COMPANY'S STATE OF READINESS The Company has implemented a Year 2000 compliance program designed to ensure that the Company's computer systems and applications will function properly beyond 1999. The Company believes that it has allocated adequate resources for this purpose and expects its Year 2000 conversions to be completed on a timely basis. In light of its compliance 23 efforts, the Company does not believe that the Year 2000 issue will materially adversely affect operations or results of operations, and does not expect implementation to have a material impact on the Company's financial statements. However, there can be no assurance that the Company's systems will be Year 2000 compliant prior to December 31, 1999, or that the failure of any such system will not have a material adverse effect on the Company's business, operating results and financial condition. In addition, to the extent the Year 2000 problem has a material adverse effect on the business, operations or financial condition of third parties with whom the Company has material relationships, such as vendors, suppliers and customers, the Year 2000 problem could have a material adverse effect on the Company's business, results of operations and financial condition. IT SYSTEMS. The Company has reviewed and continues to review all of its IT systems as they relate to the Year 2000 issue. The Company's accounting system has been upgraded to alleviate any potential Year 2000 issues. The Company outsources its human resource and payroll systems and is in the process of working with the outside vendor to identify and correct any potential Year 2000 issues. This process is expected to be complete and any changes implemented by December 31, 1999. The Company's billing systems are either provided by the customer or are performed internally on microcomputer systems. In these cases, the collection of data is the most important feature and any impact from a Year 2000 issue is expected to be immaterial. NON-IT SYSTEMS. As indicated above, the Company is dependent upon some of its customers for billing data related to the amount of electricity and steam sold and delivered during the month. For the most part, the collection of this data is done mechanically rather than electronically. Only data storage is managed electronically. The collection of this data also occurs within the control systems of the Company's various facilities. The Company has requested that the control system vendors audit their software to identify any potential Year 2000 issues and provide recommendations for alleviating any potential problems. This process has been completed for all of the Company's facilities and the various solutions have been implemented. The Company does not believe that any further upgrades, if necessary, will be material to its financial condition or results of operation. YEAR 2000 ISSUES RELATING TO THIRD PARTIES. As described above, the Company, in some cases, is dependent upon certain customers to provide billing data. However, the Company also captures and processes this data as a redundancy. The Company's control systems have been upgraded as described above and the Company does not believe that any loss of data will occur due to a Year 2000 issue. In addition, the Company's third parties are major utilities and sophisticated industrial concerns who are participants in sophisticated Year 2000 readiness programs. The Company has participated in vendor surveys to determine the readiness of various Company systems for any potential Year 2000 issues. In addition, the Company has obtained written disclosure from a number of vendors relating to their Year 2000 preparedness. COSTS TO ADDRESS THE COMPANY'S YEAR 2000 ISSUES The Company's costs to review and assess the Year 2000 issue have not been material. The Company believes that its future costs to implement Year 2000 solutions will also be immaterial to the financial statements. 24 THE RISKS OF THE COMPANY'S YEAR 2000 ISSUES The Company believes that its most likely Year 2000 worst case scenario would be the loss of billing data to utilities and industrial companies which purchase the Company's electricity and steam. This billing information, as explained above, is also captured by the Company's control systems at its various facilities. THE COMPANY'S CONTINGENCY PLANS As described above, the contingency plan for the loss of billing data is to use the data provided by the Company's internal control systems which are in the process of being upgraded to eliminate any Year 2000 issues. NEW ACCOUNTING STANDARDS In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS No. 133, as amended by SFAS No. 137, is required to be adopted for fiscal years beginning after June 15, 2000, (fiscal year 2001 for the Company). SFAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are to be recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is the type of hedge transaction. Management has not yet determined the impact that adoption of SFAS No. 133 will have on its earnings or financial position, but it may increase earnings volatility. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company's market risk is primarily impacted by changes in interest rates and changes in natural gas prices. The Company's market risk has not materially changed from that reported in Part II, Item 7a, of the Company's Report on Form 10-K for the year ended December 31, 1998. 25 PART II OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS IN RE: O'BRIEN ENVIRONMENTAL ENERGY, Case No. 94-26723, U.S. Bankruptcy Court for the District of New Jersey, filed September 29, 1994. Calpine Corporation ("Calpine") an unsuccessful bidder for the acquisition of O'Brien in the bankruptcy case, filed an application for allowance of an administrative claim for approximately $4,500 in break-up fees and expenses in the bankruptcy case. The Bankruptcy Court denied the application in full, by order dated November 27, 1996. Calpine filed an appeal from the Bankruptcy Court's order denying its application. On May 29, 1998, the United States District Court for the District of New Jersey upheld the Bankruptcy Court's order. Calpine filed an appeal with the United States Third Circuit Court of Appeals on June 26, 1998. On July 19, 1999, the United States Third Circuit Court of Appeals denied Calpine's appeal for break-up fees and expenses. Calpine did not file an appeal of the Third Circuit Court of Appeals' decision, and the case has therefore been resolved in favor of the Company. STEVENS, ET AL. V. O'BRIEN ENVIRONMENTAL ENERGY, INC., ET AL., United States District Court for the Eastern District of Pennsylvania, Civil Action No. 94-cv-4577, filed July 27, 1994. This action was filed by certain purchasers of the Class A Common Stock of the Company's predecessor, O'Brien Environmental Energy, Inc. ("O'Brien"), during the class period of O'Brien's bankruptcy. The plaintiffs alleged various violations of the Federal securities laws, claiming that certain material misrepresentations and nondisclosures concerning the Company's financial conditions and prospects allegedly caused the price of the Common Stock to be artificially inflated during the class period. The parties in this action have agreed on a proposed settlement, which was filed with the District Court for its approval on March 18, 1999. On June 8, 1999 the District Court approved the proposed settlement. BLACKMAN AND FRANTZ V. O'BRIEN, United States District Court, Eastern District of Pennsylvania, Civil Action No. 94-cv-5686, filed October 25, 1995. This action was filed by purchasers of O'Brien debentures during the class period. The Plaintiffs objected to treatment of the class under the Plan. This matter has been consolidated with the Stevens class action case described in paragraph number 1 above. The parties in this action have agreed on a proposed settlement, and on February 11, 1999, filed the proposed settlement with the District Court for its approval. On July 1, 1999 the District Court approved the proposed settlement. The Company is subject from time to time to various other claims that arise in the normal course of business, and management believes that the outcome of any such matters as currently may be pending (either individually or in the aggregate) will not have a material adverse effect on the business or financial condition of the Company. 26 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits The "Index to Exhibits" following the signature page is incorporated herein by reference. (b) Reports on Form 8-K On September 2, 1999, the Company filed a Report on Form 8-K dated August 27, 1999 announcing an Agreement and Plan of Merger dated August 26, 1999, among Calpine Corporation, Calpine East Acquisition Corporation and Cogeneration Corporation of America. 27 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned hereunto duly authorized. Cogeneration Corporation of America ----------------------------------- Registrant Date: November 11,1999 By: /s/ Timothy P. Hunstad -------------------------------- Timothy P. Hunstad VICE PRESIDENT AND CHIEF FINANCIAL OFFICER (Principal Financial Officer and Duly Authorized Officer) 28 INDEX TO EXHIBITS 27 Financial Data Schedule for the nine months ended September 30, 1999, (for SEC filing purposes only). 10.1 Agreement and Plan of Merger dated August 26, 1999 among Calpine Corporation, Calpine East Acquisition Corporation and Cogeneration Corporation of America and incorporated herein by this reference. 29 EX-27 2 EXHIBIT 27
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE REGISTRANT'S FINANCIAL STATEMENTS FOR ITS THIRD QUARTER YEAR-TO-DATE OF FISCAL YEAR 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS 9-MOS DEC-31-1999 SEP-30-1999 15,477 0 19,564 0 2,821 39,033 245,114 0 344,295 53,194 0 0 0 69 18,249 344,295 81,341 81,341 55,456 55,456 (14,500) 0 17,248 23,137 8,718 14,419 0 0 0 14,419 2.10 2.06
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