<PAGE>
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
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.
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1
<PAGE>
COGENERATION CORPORATION OF AMERICA
FORM 10-Q
SEPTEMBER 30, 1999
INDEX
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
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
</TABLE>
2
<PAGE>
PART 1
FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
COGENERATION CORPORATION OF AMERICA
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- -------------
(UNAUDITED)
<S> <C> <C>
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
========= =========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
CONSOLIDATED FINANCIAL STATEMENTS.
3
<PAGE>
COGENERATION CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
------------------------------- -------------------------------
SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
1999 1998 1999 1998
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
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
======== ======== ======== ========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
CONSOLIDATED FINANCIAL STATEMENTS.
4
<PAGE>
COGENERATION CORPORATION OF AMERICA
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
-------------------------------
SEPTEMBER 30, SEPTEMBER 30,
1999 1998
------------- -------------
<S> <C> <C>
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
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
CONSOLIDATED FINANCIAL STATEMENTS.
5
<PAGE>
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
<PAGE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED THREE MONTHS ENDED
---------------------------------------- ----------------------------------------
SEPTEMBER 30, 1999 SEPTEMBER 30, 1998
---------------------------------------- ----------------------------------------
INCOME SHARES INCOME SHARES
(NUMERATOR) (DENOMINATOR) EPS (NUMERATOR) (DENOMINATOR) EPS
----------- ------------- ------ ----------- ------------- ------
<S> <C> <C> <C> <C> <C> <C>
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
======= ======= ======= =======
</TABLE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED NINE MONTHS ENDED
---------------------------------------- ----------------------------------------
SEPTEMBER 30, 1999 SEPTEMBER 30, 1998
---------------------------------------- ----------------------------------------
INCOME SHARES INCOME SHARES
(NUMERATOR) (DENOMINATOR) EPS (NUMERATOR) (DENOMINATOR) EPS
----------- ------------- ------ ----------- ------------- ------
<S> <C> <C> <C> <C> <C> <C>
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
======= ======= ======= =======
</TABLE>
2. LOANS AND PAYABLES DUE NRG ENERGY, INC.
Amounts owed to NRG Energy, Inc. ("NRG Energy") are comprised of the
following:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- ------------
<S> <C> <C>
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
======== ========
</TABLE>
7
<PAGE>
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:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
------------------------------- -------------------------------
SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
1999 1998 1999 1998
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
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
======== ======== ======== ========
</TABLE>
4. INVESTMENT IN EQUITY AFFILIATES
Investments in equity affiliates consist of the following:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- ------------
<S> <C> <C>
Grays Ferry (50% owned) $ 38,947 $ 17,603
PoweRent Limited (50% owned) 726 576
--------- ---------
$ 39,673 $ 18,179
========= =========
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
SEPTEMBER 30, SEPTEMBER 30,
1999 1998
------------- ------------
<S> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
------------------------------- -------------------------------
SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
1999 1998 1999 1998
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
QUARTER ENDED SEPTEMBER 30, 1999
--------------------------------------------------------------
EQUIPMENT
SALES, RENTAL
ENERGY & SERVICES OTHER TOTAL
-------- ------------- --------- --------
<S> <C> <C> <C> <C>
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
======== ======== ========= ========
</TABLE>
<TABLE>
<CAPTION>
QUARTER ENDED SEPTEMBER 30, 1998
--------------------------------------------------------------
EQUIPMENT
SALES, RENTAL
ENERGY & SERVICES OTHER TOTAL
-------- ------------- --------- --------
<S> <C> <C> <C> <C>
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
======== ======== ========= ========
</TABLE>
10
<PAGE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 1999
--------------------------------------------------------------
EQUIPMENT
SALES, RENTAL
ENERGY & SERVICES OTHER TOTAL
-------- ------------- --------- --------
<S> <C> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 1998
--------------------------------------------------------------
EQUIPMENT
SALES, RENTAL
ENERGY & SERVICES OTHER TOTAL
-------- ------------- --------- --------
<S> <C> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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;
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(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.
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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
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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
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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.
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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.
<TABLE>
<CAPTION>
PROJECT ENERGY REVENUES THREE MONTHS ENDED NINE MONTHS ENDED
------------------------------- -------------------------------
SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
1999 1998 1999 1998
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
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
========= ========= ========= =========
</TABLE>
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.
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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.
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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.
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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
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<PAGE>
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
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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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
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
</LEGEND>
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 15,477
<SECURITIES> 0
<RECEIVABLES> 19,564
<ALLOWANCES> 0
<INVENTORY> 2,821
<CURRENT-ASSETS> 39,033
<PP&E> 245,114
<DEPRECIATION> 0
<TOTAL-ASSETS> 344,295
<CURRENT-LIABILITIES> 53,194
<BONDS> 0
0
0
<COMMON> 69
<OTHER-SE> 18,249
<TOTAL-LIABILITY-AND-EQUITY> 344,295
<SALES> 81,341
<TOTAL-REVENUES> 81,341
<CGS> 55,456
<TOTAL-COSTS> 55,456
<OTHER-EXPENSES> (14,500)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 17,248
<INCOME-PRETAX> 23,137
<INCOME-TAX> 8,718
<INCOME-CONTINUING> 14,419
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<EXTRAORDINARY> 0
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<NET-INCOME> 14,419
<EPS-BASIC> 2.10
<EPS-DILUTED> 2.06
</TABLE>
