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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003
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 001-13781
KCS ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware 22-2889587
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5555 San Felipe Road, Houston, TX 77056
(Address of principal executive offices) (Zip Code)
(713) 877-8006
(Registrant's telephone number, including area code)
NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last
report.)
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
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12-b2 of the Exchange Act). | | Yes |X| No
APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE
PRECEDING FIVE YEARS:
Incicate 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 1934 subsequent to the distribution of securities under a plan
confirmed by a court. |_| Yes |_| No
Not applicable. Although the registrant was involved in bankruptcy proceedings
during the
1
preceding five years, the registrant did not distribute securities under its
plan of reorganization.
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Common Stock, $0.01 par value: 38,222,749 shares outstanding as of April
30, 2003.
2
Item 1. Financial Statements.
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
Three Months Ended
March 31,
(Amounts in thousands except --------------------
per share data) Unaudited 2003 2002
- ----------------------------------------------- -------- --------
Oil and gas revenue $ 39,647 $ 29,357
Other revenue, net 793 (533)
- -----------------------------------------------------------------------------------
Total revenue 40,440 28,824
- -----------------------------------------------------------------------------------
Operating costs and expenses
Lease operating expenses 6,331 6,536
Production taxes 2,293 1,323
General and administrative expenses 1,800 2,127
Stock compensation 154 316
Accretion of asset retirement obligation 279 --
Depreciation, depletion and amortization 10,642 13,100
- -----------------------------------------------------------------------------------
Total operating costs and expenses 21,499 23,402
- -----------------------------------------------------------------------------------
Operating income 18,941 5,422
- -----------------------------------------------------------------------------------
Interest and other income, net 27 70
Interest expense (4,614) (4,830)
- -----------------------------------------------------------------------------------
Income before income taxes 14,354 662
Federal and state income (taxes) benefit 482 596
- -----------------------------------------------------------------------------------
Income before cumulative effect of accounting change 14,836 1,258
Cumulative effect of accounting change, net of tax (934) (6,166)
- -----------------------------------------------------------------------------------
Net income (loss) 13,902 (4,908)
Dividends and accretion of issuance costs on preferred stock (309) (253)
- -----------------------------------------------------------------------------------
Income (loss) available to common stockholders $ 13,593 $ (5,161)
===================================================================================
Earnings (loss) per share of common stock - basic
Before cumulative effect of accounting change $ 0.38 $ 0.03
Cumulative effect of accounting change $ (0.02) $ (0.18)
- -----------------------------------------------------------------------------------
Earnings (loss) per share of common stock - basic $ 0.36 $ (0.15)
===================================================================================
Earnings (loss) per share of common stock - diluted
Before cumulative effect of accounting change $ 0.36 $ 0.03
Cumulative effect of accounting change $ (0.02) $ (0.18)
- -----------------------------------------------------------------------------------
Earnings (loss) per share of common stock - diluted $ 0.34 $ (0.15)
===================================================================================
Average shares outstanding for computation of earnings per
share
Basic 37,436 34,986
Diluted 41,120 34,986
===================================================================================
The accompanying notes to the condensed consolidated financial statements are an
integral part of these financial statements.
3
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands March 31, December 31,
except share and per share data) Unaudited 2003 2002
- ---------------------------------------------------------- --------- ------------
Assets
Current assets
Cash and cash equivalents $ 2,356 $ 6,935
Trade accounts receivable, less allowance
for doubtful accounts-2003 $4,692; 2002 $4,678 27,601 16,863
Prepaid drilling 220 1,362
Other current assets 2,065 2,034
- ----------------------------------------------------------------------------------------------
Current assets 32,242 27,194
- ----------------------------------------------------------------------------------------------
Oil and gas properties, full cost method, less accumulated
DD&A-2003 $897,222; 2002 $891,124 243,492 231,579
Other property, plant and equipment at cost less accumulated
depreciation; 2003 $10,704; 2002 $10,415 8,651 8,715
- ----------------------------------------------------------------------------------------------
Property, plant and equipment, net 252,143 240,294
- ----------------------------------------------------------------------------------------------
Deferred charges and other assets 2,676 645
- ----------------------------------------------------------------------------------------------
Total Assets $ 287,061 $ 268,133
==============================================================================================
Liabilities and stockholders' deficit
Current liabilities
Accounts payable $ 30,520 $ 23,854
Accrued interest 2,813 8,174
Accrued drilling cost 2,802 2,861
Other accrued liabilities 9,400 8,784
- ----------------------------------------------------------------------------------------------
Current liabilities 45,535 43,673
- ----------------------------------------------------------------------------------------------
Deferred credits and other liabilities
Deferred revenue 58,359 66,582
Asset retirement obligation 11,421 --
Other 940 961
- ----------------------------------------------------------------------------------------------
Deferred credits and other liabilities 70,720 67,543
- ----------------------------------------------------------------------------------------------
Long-term debt
Credit facility 60,500 500
Senior notes -- 61,274
Senior subordinated notes 125,000 125,000
- ----------------------------------------------------------------------------------------------
Long-term debt 185,500 186,774
- ----------------------------------------------------------------------------------------------
Commmitments and contingencies
Preferred stock, authorized 5,000,000 shares, issued 30,000 shares
redeemable convertible preferred stock, par value $0.01 per share,
liquidation preference $1,000 per share - 9,388 and
13,288 shares outstanding, respectively 9,101 12,859
- ----------------------------------------------------------------------------------------------
Stockholders' (deficit)
Common stock, par value $0.01 per share
authorized 75,000,000 shares, issued 40,383,845
and 38,611,816, respectively 404 386
Additional paid-in capital 172,378 167,335
Accumulated deficit (182,722) (196,315)
Unearned compensation (1,408) (880)
Accumulated other comprehensive income (7,706) (8,501)
Less treasury stock, 2,167,096 shares, at cost (4,741) (4,741)
- ----------------------------------------------------------------------------------------------
Total stockholders' (deficit) (23,795) (42,716)
- ----------------------------------------------------------------------------------------------
Total liabilities and stockholders' deficit $ 287,061 $ 268,133
==============================================================================================
The accompanying notes to the condensed consolidated financial statements are an
integral part of these financial statements.
4
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
Three Months Ended
March 31,
---------------------
(Amounts in thousands) Unaudited 2003 2002
- --------------------------------------------------------- -------- --------
Cash flows from operating activities:
Net income (loss) $ 13,902 $ (4,908)
Non-cash charges (credits):
Depreciation, depletion and amortization 10,642 13,100
Amortization of deferred revenue (8,223) (13,002)
Non-cash derivative losses, net 1,378 851
Deferred tax benefit (482) (596)
Cumulative effect of accounting change 934 6,166
Accretion of asset retirement obligation 279 --
Other non-cash charges and credits, net 164 700
Net changes in assets and liabilities:
Change in trade accounts receivable (10,752) (3,773)
Change in accounts payable and accrued liabilities 7,585 (3,890)
Change in accrued interest payable (5,361) (5,050)
Other, net 17 (47)
- -----------------------------------------------------------------------------------
Net cash provided by (used in) operating activities 10,083 (10,449)
- -----------------------------------------------------------------------------------
Cash flows from investing activities:
Investment in oil and gas properties (10,818) (15,552)
Proceeds from sales of oil and gas properties (157) 309
Investment in other property, plant and equipment (225) (54)
- -----------------------------------------------------------------------------------
Net cash used in investing activities (11,200) (15,297)
- -----------------------------------------------------------------------------------
Cash flows from financing activities:
Proceeds from borrowings 69,295 10,800
Repayments of debt (70,569) (7,254)
Deferred financing cost and other, net (2,188) (221)
- -----------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (3,462) 3,325
- -----------------------------------------------------------------------------------
Net decrease in cash and cash equivalents (4,579) (22,421)
Cash and cash equivalents at beginning of period 6,935 22,927
- -----------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 2,356 $ 506
===================================================================================
The accompanying notes to the condensed consolidated financial statements are an
integral part of these financial statements.
5
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' DEFICIT
(Amounts in thousands)
Accumulated
Additional Other
Common Paid-in Accumulated Comprehensive Unearned
Unaudited Stock Capital Deficit Income Compensation
- ------------------------------------------------------- -------------- -------------- -------------- --------------
Balance at December 31, 2002 $ 386 $ 167,335 $ (196,315) $ (8,501) $ (880)
Comprehensive income
Net income -- -- 13,902 -- --
Commodity hedges, net of tax -- -- -- 795 --
Comprehensive income
Conversion of redeemable
preferred stock 13 3,887 -- -- --
Stock issuances - benefit plans and
awards of restricted stock 4 991 -- -- (682)
Stock compensation expense -- -- 154
Dividends and accretion of issuance
costs on preferred stock 1 165 (309) -- --
-------------- -------------- -------------- -------------- --------------
Balance at March 31, 2003 $ 404 $ 172,378 $ (182,722) $ (7,706) $ (1,408)
============== ============== ============== ============== ==============
Total
Stockholders'
Treasury Comprehensive (Deficit)
Unaudited Stock Income Equity
- ------------------------------------------------------- -------------- --------------
Balance at December 31, 2002 $ (4,741) $ (42,716)
Comprehensive income
Net income -- $ 13,902 13,902
Commodity hedges, net of tax -- 795 795
--------------
Comprehensive income $ 14,697
==============
Conversion of redeemable
preferred stock -- 3,900
Stock issuances - benefit plans and
awards of restricted stock -- 313
Stock compensation expense -- 154
Dividends and accretion of issuance
costs on preferred stock -- (143)
-------------- --------------
Balance at March 31, 2003 $ (4,741) $ (23,795)
============== ==============
The accompanying notes to the condensed consolidated financial statements are an
integral part of these financial statements.
6
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. The condensed consolidated interim financial statements included herein have
been prepared by KCS Energy, Inc. ("KCS" or "Company"), without audit, pursuant
to the rules and regulations of the Securities and Exchange Commission ("SEC")
and reflect all adjustments which are of a normal recurring nature and which, in
the opinion of management, are necessary for a fair statement of the results for
the interim periods presented. Certain information and footnote disclosures have
been condensed or omitted pursuant to such rules and regulations. Although KCS
believes that the disclosures are adequate to make the information presented not
misleading, it is suggested that these condensed consolidated financial
statements be read in conjunction with the financial statements and the notes
thereto included in the Company's Annual Report on Form 10-K for the year ended
December 31, 2002. Certain previously reported amounts have been reclassified to
conform with current period presentations.
2. New Accounting Principles
Effective January 1, 2003, the Company adopted Financial Accounting
Standards Board Statement No. 143, "Accounting for Asset Retirement Obligations"
("SFAS No. 143"). SFAS No. 143 requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the periods in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of the
related long-lived asset. The liability is accreted to the fair value at the
time of settlement over the useful life of the asset, and the capitalized cost
is depreciated over the useful life of the related asset. Upon adoption of SFAS
No. 143, the Company's net property, plant and equipment was increased by $10.2
million, an additional asset retirement obligation of $11.1 million was recorded
and a $0.9 million charge, net of tax against net income (or a $.02 loss per
basic and diluted share) was reported in the first quarter of 2003 as a
cumulative effect of a change in accounting principle. Subsequent to adoption,
the effect of the change in accounting principle was immaterial.
Had the provisions of SFAS No. 143 been applied as of January 1, 2002, the
asset retirement obligation would have been $10.1 million. The following table
illustrates the pro forma effect on net loss available to common stockholders
and loss per share if the Company had applied the provisions of SFAS No. 143
during the first quarter of 2002:
For the
Quarter Ended
(Amounts in thousands except for per share data) March 31, 2002
- --------------------------------------------------------- ----------------
Loss available to common stockholders
As reported $(5,161)
Pro forma (5,294)
Loss per share
Basic - as reported $ (0.15)
Basic - pro forma $ (0.15)
Diluted - as reported $ (0.15)
Diluted - pro forma $ (0.15)
Effective January 1, 2002, KCS began amortizing the capitalized costs
related to oil and gas properties on the unit-of-production basis ("UOP") using
proved oil and gas reserves. Previously, KCS had computed amortization on the
basis of future gross revenue ("FGR"). The Company determined that the change to
UOP was preferable under accounting principles generally accepted in the United
States, since among other reasons, it provides a more rational basis for
amortization during periods of volatile commodity prices and also increases
consistency with others in the industry. As a result of this change, the
7
Company recorded a non-cash cumulative effect charge of $6.2 million, net of
tax, (or $0.18 per basic and diluted common share) in the first quarter of 2002.
3. Deferred Revenue
In 2001, the Company entered into a production payment transaction whereby
it sold 43.1 Bcfe (38.3 Bcf of gas and 797,000 barrels of oil) (the "Production
Payment"). Net proceeds from the Production Payment of approximately $175
million were recorded as deferred revenue on the balance sheet. In accordance
with SFAS No. 19 "Financial Accounting and Reporting by Oil and Gas Producing
Companies," deliveries under the Production Payment are recorded as non-cash oil
and gas revenue with a corresponding reduction of deferred revenue at the
average discounted price per Mcf of natural gas and per barrel of oil received
when the Production Payment was sold. The Company also reflects the production
volumes and depletion expense as deliveries are made. However, the associated
oil and gas reserves are excluded from the Company's reserve data. For the three
months ended March 31, 2003, the Company delivered 2.0 Bcfe and recorded $8.2
million of oil and gas revenue. Since the sale of the Production Payment in
February 2001 through March 31, 2003, the Company has delivered 28.9 Bcfe, or
67% of the total quantity to be delivered.
4. Redeemable Convertible Preferred Stock
As a result of conversions of the redeemable convertible preferred stock
issued in 2001, 1.3 million shares of common stock were issued in the three
months ended March 31, 2003.
5. Earnings Per Share
The following table sets forth the computation of basic and diluted
earnings per share:
Three months ended
March 31
(amounts in thousands -------------------
except per share data) 2003 2002
- ------------------------------------------------------------------ --------
Basic earnings (loss) per share:
Income (loss) available to common stockholders $ 13,593 $ (5,161)
-------- --------
Average shares of common stock outstanding 37,436 34,986
-------- --------
Basic earnings (loss) per share $ 0.36 $ (0.15)
======== ========
Diluted earnings (loss) per share:
Income (loss) available to common stockholders $ 13,593 $ (5,161)
Dividends and accretion of issuance costs
on preferred stock 309 N/A
-------- --------
Diluted earnings (loss) $ 13,902 $ (5,161)
-------- --------
Average shares of common stock outstanding 37,436 34,986
Assumed conversion of convertible
preferred stock 3,566 N/A
Dividends on convertible preferred stock 66 N/A
Stock options and warrants 52 --
-------- --------
Average diluted shares of common stock outstanding 41,120 34,986
-------- --------
Diluted earnings (loss) per share $ 0.34 $ (0.15)
======== ========
Common shares on assumed conversion of convertible preferred stock
amounting to 5.3 million shares in the 2002 three-month period were not included
in the computation of diluted loss per common share nor were accrued dividends
on convertible preferred stock or stock options and warrants since they would be
anti-dilutive.
8
6. Derivatives
Oil and gas prices have historically been volatile. The Company has at
times utilized derivative contracts, including swaps, futures contracts, options
and collars, to manage this price risk.
Commodity Price Swaps. Commodity price swap agreements require the Company
to make or receive payments from the counter parties based upon the differential
between a specified fixed price and a price related to those quoted on the New
York Mercantile Exchange for the period involved.
Futures Contracts. Oil or natural gas futures contracts require the
Company to sell and the counter party to buy oil or natural gas at a future time
at a fixed price.
Option Contracts. Option contracts provide the right, not the obligation,
to buy or sell a commodity at a fixed price. By buying a "put" option, the
Company is able to set a floor price for a specified quantity of its oil or gas
production. By selling a "call" option, the Company receives an upfront premium
from selling the right for a counter party to buy a specified quantity of oil or
gas production at a fixed price.
Price Collars. Selling a call option and buying a put option creates a
"collar" whereby the Company establishes a floor and ceiling price for a
specified quantity of future production. Buying a call option with a strike
price above the sold call strike price establishes a "3-way collar" that
entitles the Company to capture the benefit of price increases above that call
price.
In 2003, the Company entered into a series of derivative transactions
designed to protect against possible declines in natural gas prices while
enabling the Company to benefit from price increases. At March 31, 2003, the
Company had derivative instruments covering 3.5 million Mmbtu of gas production
for April through November 2003. These instruments established an average floor
price of $4.51 and enable the Company to receive market prices up to an average
cap of $5.78, approximately 26% of any price between $5.78 and $6.28 and 100% of
any price above $6.28. The following table sets forth the Company's oil and
natural gas hedged position at March 31, 2003.
Expected Maturity, 2003 Fair
----------------------------------------------------- Value
2nd Quarter 3rd Quarter 4th Quarter Total ($000)
----------- ----------- ----------- ----- ------
Swaps: $ 37
Volumes (bbl) 15,000 -- -- 15,000
Weighted average price ($/bbl) $ 31.06 $ -- $ -- $ 31.06
Puts / Floors: $ 137
Volumes (Mmbtu) 150,000 460,000 305,000 915,000
Weighted average price ($/Mmbtu) $ 4.25 $ 4.25 $ 4.25 $ 4.25
3-way collars: $ 352
Volumes (MMbtu) 1,060,000 1,075,000 460,000 2,595,000
Weighted average price ($/Mmbtu)
Floor (purchased put option) $ 4.83 $ 4.47 $ 4.40 $ 4.61
Cap 1 (sold call option) $ 5.81 $ 5.76 $ 5.75 $ 5.78
Cap 2 (purchased call option) $ 6.31 $ 6.26 $ 6.25 $ 6.28
In addition to the above, the Company has entered into fixed price sales
contracts covering 0.3 million Mmbtu at an average price of $5.09 for April
through June 2003 and will deliver 4.8 Bcfe for April thru December under the
Production Payment sold in February 2001 at an average price of $4.05 per Mcfe.
During 2001, the Company terminated certain derivative contracts and has
been amortizing the loss accumulated in other comprehensive income into earnings
over the original term of the derivative instruments. During the first three
months of 2003, $0.9 million, net of tax, charged to other comprehensive
9
income ("OCI") was reclassified as a reduction of oil and gas revenues. As of
March 31, 2003, $7.6 million remains in accumulated other comprehensive income
and will be amortized against earnings through August 2005 ($2.7 million during
the remainder of in 2003, $2.9 million in 2004 and $2.0 million in 2005). During
the first quarter of 2003, $0.1 million of unrealized derivative losses were
charged to OCI which will be reclassified against earnings within the current
fiscal year. The ineffective portion of these derivatives was immaterial in the
first quarter of 2003.
7. Supplemental Cash Flow Information
The Company considers all highly liquid debt instruments with a maturity
of three months or less when purchased to be cash equivalents. Interest paid
(net of capitalized interest) for the three months ended March 31, 2003 was $9.8
million. No income tax payments were made during the three-month periods ended
March 31, 2003 and March 31, 2002.
In connection with the adoption of SFAS No. 143, the Company recorded a
non-cash increase to oil and gas properties of $10.2 million, a non-cash
increase in liabilities of $11.1 million and a non-cash charge of $0.9 million
as a cumulative effect of accounting change. Other non-cash additions to oil and
gas properties were $1.1 million with a corresponding decrease in prepaid
drilling.
8. Credit Agreement
On January 14, 2003, the Company amended and restated its credit agreement
("Credit Agreement") with a group of institutional lenders. The Credit
Agreement, which matures on October 3, 2005, provides up to $90.0 million of
borrowing capacity, $40.0 million in the form of a term loan, a $30.0 million
revolving "A" facility and a $20.0 million revolving "B" facility. Borrowing
capacity is subject to monthly borrowing base calculations with respect to the
value of the Company's oil and gas assets. Initial proceeds of $69.3 million
were used primarily to pay off the Company's maturing Senior Note obligations.
The term loan and the revolving "B" facility, which may be prepaid at any time
without penalty, bear interest based on the prime rate, initially equating to
9.0%, and increasing annually. The revolving "A" facility bears, at the
Company's option, an interest rate of LIBOR plus 2.75% to 3.0% or prime plus
0.5% to 0.75%, depending on utilization. On March 31, 2003, $60.5 million was
outstanding under the Credit Agreement and the weighed average interest rate was
7.7%. The revolving "A" facility requires a commitment fee of 0.5% per annum on
the unused availability and carries an early termination penalty of 1.5% in the
first year and 1% in the second year. Financing fees associated with the Credit
Agreementhave been recorded as deferred charges and are being amortized as
interest expense over the life of the Credit Agreement. Certain other fees are
also payable under the Credit Agreementbased on services provided. Substantially
all of the Company's assets are pledged to secure the Credit Agreement.
The Credit Agreement contains various restrictive covenants including
ratios of debt to EBITDA, interest coverage, fixed charge coverage and
liquidity. The Credit Agreement also contains provisions that require the
hedging of a portion of the Company's oil and gas production, payment upon a
change of control, restrictions on the payment of dividends and certain other
restricted payments and places limitations on the incurrence of additional debt,
capital expenditures, the sale of assets, and the repurchase of Senior
Subordinated Notes. Any repayment made on the term loan portion of the facility
will permanently reduce the funds available under the Credit Agreement. The
Credit Agreement also contains cross-default provisions which would result in
the acceleration of payments if the Company defaults on its other debt
instruments.
9. Stock Compensation
As permitted under SFAS No. 123 "Accounting for Stock-Based Compensation",
as amended, the Company has elected to continue to account for stock options
under the provisions of Accounting Principles Board Opinion No. 25 "Accounting
for Stock Issued to Employees." Under this method, the Company records no
compensation expense for stock options granted if the exercise price of those
options
10
is equal to or greater than the market price of the Company's common stock on
the date of grant, unless the awards are subsequently modified. The following
table illustrates the effect on income (loss) available to common stockholders
and earnings (loss) per share if the Company had applied the fair value
recognition provision of SFAS No. 123, as amended, to stock options.
For the Three Months Ended
March 31,
(amounts in thousands except --------------------------
per share data) 2003 2002
- ------------------------------------------------------- -----------
Income (loss) available to common
stockholders, as reported $ 13,593 $ (5,161)
Add: Stock-based compensation expense
included in reported net income 154 316
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards (412) (392)
Pro forma income (loss) available to ---------- ----------
common stockholders $ 13,335 $ (5,237)
========== ==========
Earnings (loss) per share:
Basic - as reported $ 0.36 $ (0.15)
Basic - pro forma $ 0.36 $ (0.15)
Diluted - as reported $ 0.34 $ (0.15)
Diluted - pro forma $ 0.33 $ (0.15)
10. Litigation
Environmental Suits
The Company was a defendant in a lawsuit originally brought by InterCoast
Energy Company and MidAmerican Capital Company ("Plaintiffs") against KCS
Energy, Inc., KCS Medallion Resources, Inc. and Medallion California Properties
Company ("KCS Defendants"), and Kerr-McGee Oil & Gas Onshore LP and Kerr-McGee
Corporation ("Kerr-McGee Defendants") in the 234th Judicial District Court of
Harris County, Texas under Cause Number 1999-45998. The suit sought a
declaratory judgment declaring the rights and obligations of each of the
Plaintiffs, the KCS Defendants and the Kerr-McGee Defendants in connection with
environmental damages and surface restoration on lands located in Los Angeles
County, California which are covered by an Oil & Gas Lease dated June 13, 1935,
from Newhall Land and Farming Company, as Lessor, to Barnsdall Oil Company, as
Lessee (the "RSF Lease") and by an Oil and Gas Lease dated June 6, 1941, from
the Newhall Corporation, as Lessor, to C. G. Willis, as Lessee (the "Ferguson
Lease" and together with the RSF Lease, the "Leases").
The Kerr-McGee Defendants, KCS Defendants and Plaintiffs entered into an
Agreed Interlocutory Judgment that contains clarification of the language of the
1990 agreement between predecessors of the KCS Defendants and the Kerr-McGee
Defendants (the "1990 Agreement") under which the Leases were transferred from
Kerr-McGee's predecessor to predecessors of Medallion California Properties
Company ("MCPC"). The Court previously entered the Agreed Interlocutory
Judgment, which essentially disposed of interpretation questions concerning the
1990 Agreement. After entry of the Agreed Interlocutory Judgment, the remaining
issues in the case concerned the interpretation of the 1996 Stock Purchase
Agreement through which certain of the KCS Defendants acquired the stock of
MCPC. Specifically, the remaining issues involved the extent to which Plaintiffs
are obligated to indemnify the KCS Defendants for environmental investigation
costs previously incurred by the KCS Defendants and also for costs of defense
and liability to the KCS Defendants, if any, in the California litigation
described below. By Compromise and Settlement Agreement dated as of October 19,
2001, the Plaintiffs and KCS Defendants agreed: (i) to settle those issues
dealing with the Plaintiffs' obligations to reimburse costs previously incurred
in connection with defense of the California case described below; (ii) to
provide prospectively for the control of defense and settlement and the sharing
of defense costs in the California case described below; and
11
(iii) to defer any disputes concerning the respective liability of Plaintiffs
and KCS Defendants for any individual claims until the extent of such individual
claim liability, after giving effect to indemnification obligations under the
1990 Agreement, is fully and finally determined. The Agreed Interlocutory
Judgment has now been entered as a final judgment.
MCPC is a defendant in a lawsuit filed January 30, 2001, by The Newhall
Land and Farming Company ("Newhall") against MCPC and Kerr-McGee Corporation and
several Kerr-McGee affiliates. The case is currently pending in Los Angeles
County Superior Court under Cause Number BC244203. In the suit, Newhall seeks
damages for alleged environmental contamination and surface restoration on the
lands covered by the RSF Lease and also seeks a declaration that Newhall may
terminate the RSF Lease or alternatively, that it may terminate those portions
of the RSF Lease on which there is currently default under the Lease. MCPC
claims that Newhall is not entitled to lease termination as a remedy and that
Kerr-McGee and InterCoast and MidAmerican owe indemnities to MCPC for defense
and certain potential liability under Newhall's action, all as more particularly
described in the Harris County, Texas litigation described above. Discovery is
ongoing, and the lawsuit is set for trial in May 2003.
Other
The Company and several of its subsidiaries have been named as
co-defendants along with numerous other industry parties in an action brought by
Jack Grynberg on behalf of the Government of the United States. The complaint,
filed under the Federal False Claims Act, alleges underpayment of royalties to
the Government of the United States as a result of alleged mismeasurement of the
volume and wrongful analysis of the heating content of natural gas produced from
federal and Native American lands. The complaint is substantially similar to
other complaints filed by Jack Grynberg on behalf of the Government of the
United States against multiple other industry parties. All of the complaints
have been consolidated in one proceeding. In April 1999, the Government of the
United States filed notice that it had decided not to intervene in these
actions. The Company believes that the allegations in the complaint are without
merit.
The Company is also a party to various other lawsuits and governmental
proceedings, all arising in the ordinary course of business. Although the
outcome of all of the above proceedings cannot be predicted with certainty,
management does not expect such matters to have a material adverse effect,
either singly or in the aggregate, on the financial position or results of
operations of the Company. It is possible, however, that charges could be
required that would be significant to the operating results during a particular
period.
12
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
The following is a discussion and analysis of our financial condition and
results of operations and should be read in conjunction with the condensed
consolidated financial statements (including the notes thereto) included
elsewhere in this Form 10-Q.
Forward-Looking Statements
The information discussed in this quarterlyreport on Form 10-Q includes
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
as amended. All statements, other than statements of historical facts, included
herein concerning, among other things, planned capital expenditures, increases
in oil and gas production, the number of anticipated wells to be drilled after
the date hereof, the Company's financial position, business strategy and other
plans and objectives for future operations, are forward-looking statements.
These forward-looking statements are identified by their use of terms and
phrases such as "expect," "estimate," "project," "plan," "believe,"
"achievable," "anticipate" and similar terms and phrases. Although the Company
believes that the expectations reflected in such forward-looking statements are
reasonable, they do involve certain assumptions, risks and uncertainties, and
the Company can give no assurance that such expectations will prove to be
correct. The Company's actual results could differ materially from those
anticipated in these forward-looking statements as a result of certain factors,
including:
- the timing and success of the Company's drilling activities;
- the volatility of prices and supply and demand for oil and gas;
- the numerous uncertainties inherent in estimating quantities of oil
and gas reserves and actual future production rates and associated
costs;
- the usual hazards associated with the oil and gas industry
(including blowouts, cratering, pipe failure, spills, explosions and
other unforeseen hazards);
- changes in regulatory requirements; or
- if underlying assumptions prove incorrect.
These and other risks are described in greater detail in "Oil and Gas Risk
Factors" included in the Company's Annual Report on Form 10-K for the year ended
December 31, 2002.
All forward-looking statements attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by such factors.
Other than required under the securities laws, the Company does not assume a
duty to update these forward looking statements.
General
Our main objective in 2002 was to position the Company to meet the Senior
Note obligations due January 15, 2003. In order to meet this objective, we
curtailed our drilling and overall capital expenditure programs and sold certain
non-core assets. These actions positioned us to reduce debt and negotiate the
financing necessary to pay off the remaining portion of the maturing Senior
Notes during a difficult period in the capital markets. Although the asset sales
and curtailed drilling and capital expenditure programs resulted in lower
production and reserves in 2002, we exited the year in a stronger financial
position, with increased financial flexibility, a focused asset base in our core
areas, and a quality multi-year drilling prospect inventory.
On January 14, 2003, we completed the arrangements necessary to amend and
restate our existing credit agreement with a group of institutional lenders. The
amended facility provides $90.0 million of borrowing capacity, $40.0 million in
the form of a term loan and $50.0 million in revolving facilities, and
13
matures on October 3, 2005. Initial proceeds of $69.3 million were used
primarily to pay off the balance of the maturing Senior Note obligations,
leaving $20.7 million of available borrowing capacity under the facility.
With the completion of the financing, implementation of a cost reduction
program and a hedging program designed to protect against possible declines in
natural gas prices while enabling us to benefit from price increases, we believe
that the Company is positioned to capitalize on the current strong natural gas
price environment, to focus on developing our prospect inventory to grow
reserves and production in our core areas and to further reduce debt.
Prices for oil and natural gas are subject to wide fluctuations in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond our control. These factors include political conditions in the Middle
East and elsewhere, domestic and foreign supply of oil and natural gas, the
level of industrial and consumer demand, weather conditions and overall economic
conditions.
Results of Operations
Income before cumulative effect of an accounting change for the three
months ended March 31, 2003 was $14.8 million, or $0.38 per basic share ($0.36
per diluted share) compared to $1.3 million, or $0.03 per basic and diluted
share for the three months ended March 31, 2002. This increase was primarily
attributable to substantially higher natural gas and oil prices partially offset
by decreased oil and gas production, due largely to the sale of certain non-core
properties in 2002.
The cumulative effect of an accounting change was $0.9 million, or $0.02
per basic and diluted share for the current year three-month period as a result
of the adoption of Financial Accounting Standards Board Statement No. 143,
"Accounting for Asset Retirement Obligations" ("SFAS No. 143"). For the three
months ended March 31, 2002, the cumulative effect of accounting change was $6.2
million, or $0.18 per basic and diluted share which reflected the change from
the future gross revenue method of accounting for the amortization of
capitalized costs related to oil and gas properties to the unit-of-production
method. See Note 2 to Condensed Consolidated Financial Statements for more
information regarding these accounting changes.
Income available to common stockholders for the three-months ended March
31, 2003 was $13.6 million, or $0.36 per basic share ($0.34 per diluted share),
compared to a loss of $5.2 million, or $0.15 per basic and diluted share for the
same period in 2002.
14
Three Months Ended
March 31,
-------------------
2003 2002
-------- --------
Production: (a)
Gas (MMcf) 5,975 8,312
Oil (Mbbl) 215 269
Liquids (Mbbl) 48 71
Summary (MMcfe):
Working interest 7,552 9,469
VPP -- 879
-------- --------
Total 7,552 10,348
Average Price: (b)
Gas (per Mcf) $ 5.51 $ 2.88
Oil (per bbl) 27.48 17.70
Liquids (per bbl) 17.27 9.03
Total (per Mcfe) 5.25 2.84
Revenue:
Gas $ 32,911 $ 23,964
Oil 5,911 4,753
Liquids 825 640
-------- --------
Total $ 39,647 $ 29,357
======== ========
Notes:
(a)
Production includes 2,018 and 3,234 MMcfe for the three months ended in 2003 and
2002 respectively, dedicated to the Production Payment sold in February 2001.
See Note 3 to Condensed Consolidated Financial Statements.
(b)
Includes the effects of hedging and the Production Payment sold in February
2001. See Notes 3 and 6 to Condensed Consolidated Financial Statements.
Gas revenue
For the three months ended March 31, 2003, gas revenue increased $8.9
million to $32.9 million due to a 91% increase in average realized natural gas
prices offset by 28% decrease in production. The production decline was
primarily due to the sale of oil and gas properties in 2002 and the expiration
of certain VPPs.
Oil and liquids revenue
For the three months ended March 31, 2003, oil and liquids revenue
increased $1.3 million to $6.7 million due to a 61% increase in the weighted
average price offset by a 23% decrease in production. The decrease in production
in current year period was primarily due to the sale of oil and gas properties
in 2002 and the natural declines of producing properties.
Other revenue, net
Other revenue was $0.8 million for the three months ended March 31, 2003
compared to a net cost of $0.5 million for the same period a year ago. The
increase was primarily attributable to increased marketing and transportation
revenue incidental to our oil and gas operations.
15
Lease operating expenses
Lease operating expenses decreased $0.2 million to $6.3 million for the
three months ended March 31, 2003 compared to the same period in 2002. Continued
focus on operating efficiency along with the sale of certain properties
contributed to the current year reductions. This was partially offset by
increased workover activity on oil and gas wells during the first quarter of
2003.
Production taxes
Production taxes, which are generally based on a percentage of revenue
(excluding VPP revenue) increased $1.0 million to $2.3 million for the three
months ended March 31, 2002 compared to the same period in 2002, due to higher
oil and gas revenue associated with higher average realized prices.
General and administrative expenses
General and administrative expenses for the three months ended March 31,
2003 were $1.8 million compared to $2.1 million for the same period a year ago
primarily due to lower labor costs associated with a reduced work force.
Stock compensation
Stock compensation was $0.2 million for the three-month period ended March
31, 2003 compared to $0.3 million for the same period a year ago. The slight
decrease is associated with our reduction in work force. These amounts reflect
the non-cash amortization of restricted stock grants issued to employees under
the Company's 2001 Employees and Directors Stock Plan.
Depreciation, depletion and amortization
For the three months ended March 31, 2003, depreciation, depletion and
amortization ("DD&A") decreased $2.2 million to $10.9 million compared to $13.1
million for the same period in 2002. The decrease reflects reduced production
and a lower depletion base primarily as a result of the non-core property sales
in 2002.
Interest expense
Interest expense for the three months ended March 31, 2003 was $4.6
million compared to $4.8 million for the same period a year ago. The decrease
reflects the trend of lowering outstanding debt and, to a lesser extent, lower
interest rates on our new credit facility.
Income Taxes
Income tax benefits were $0.5 million for the three months ended March 31,
2003 compared to $0.6 million for the same period a year ago and are related to
the continued amortization of terminated derivative contracts from accumulated
other comprehensive income into earnings.
We continue to maintain a valuation allowance against 100% of net deferred
tax assets, since at this time, it is difficult to project the necessary levels
of future taxable income with sufficient certainty, considering the significant
volatility in natural gas and oil prices and that the current higher price
environment has existed for only a short period. We will continue to assess the
valuation allowance, and to the extent it is determined that such allowance is
no longer required, the tax benefit of the remaining net deferred tax assets
will be recognized in the future.
Liquidity and Capital Resources
Our main objective in 2002 was to position the Company to meet the Senior
Note obligations due January 15, 2003. In order to meet this objective, we
curtailed our drilling and overall capital expenditure programs and sold certain
non-core assets. These actions positioned us to reduce debt and negotiate the
financing necessary to pay off the remaining portion of the maturing Senior
Notes during a difficult period in the capital markets. Although the asset sales
and curtailed drilling and capital expenditure programs
16
resulted in lower production and reserves in 2002, we exited the year in a
stronger financial position, with increased financial flexibility, a focused
asset base in our core areas, and a quality multi-year drilling prospect
inventory.
On January 14, 2003, we completed the arrangements necessary to amend and
restate our existing credit agreement ("Credit Agreement") with a group of
institutional lenders. Initial proceeds of $69.3 million were used primarily to
pay off the balance of the maturing Senior Note obligations. On March 31, 2003,
$60.5 million was outstanding under the Credit Agreement and the weighed average
interest rate was 7.7%.
With the completion of the financing, implementation of a cost reduction
program and a hedging program designed to protect against possible declines in
natural gas prices while enabling us to benefit from price increases, we believe
that the Company is positioned to capitalize on the current strong natural gas
price environment, to focus on developing our prospect inventory to grow
reserves and production in our core areas and to further reduce debt.
Cash flow from operating activities
Net cash provided by operating activities for the three months ended March
31, 2003 was $10.1 million compared to net cash used in operating activities of
$10.4 million during the same period in 2002. The improvement in our cash flow
in 2003 was primarily due to higher realized oil and natural gas prices. The net
changes in trade accounts receivable and in accounts payable and accrued
liabilities also reflect the higher natural gas and oil price environment in
2003 and the timing of cash receipts and disbursements.
Investing activities
Capital expenditures for the three months ended March 31, 2003 were $11.9
million of which $11.0 million was for development activities, $0.8 million was
for lease acquisitions, seismic surveys and exploratory drilling and $0.1
million was for the acquisition of proved reserves.
Capital expenditures for the three months ended March 31, 2002 were $15.6
million of which $10.9 million was for development activities, $4.6 million for
lease acquisitions, seismic surveys and exploratory drilling and $0.1 million
for other assets.
New Accounting Principles
Effective January 1, 2003, the Company adopted SFAS No. 143 which requires
entities to record the fair value of a liability for legal obligations
associated with the retirement obligations of tangible long-lived assets in the
periods in which it is incurred. When the liability is initially recorded, the
entity increases the carrying amount of the related long-lived asset. The
liability is accreted to the fair value at the time of settlement over the
useful life of the asset, and the capitalized cost is depreciated over the
useful life of the related asset. Upon adoption of SFAS No. 143, the Company's
net property, plant and equipment was increased by $10.2 million, an additional
asset retirement obligation of $11.1 million was recorded and a $0.9 million
charge, net of tax against net income (or a $0.02 loss per basic and diluted
share) was reported in the first quarter of 2003 as a cumulative effect of a
change in accounting principle. Subsequent to adoption, the effect of the change
in accounting principles was inmaterial.
Effective January 1, 2002, KCS began amortizing the capitalized costs
related to oil and gas properties on the unit-of-production basis ("UOP") using
proved oil and gas reserves. Previously, KCS had computed amortization on the
basis of future gross revenue ("FGR"). The Company determined that the change to
UOP was preferable under accounting principles generally accepted in the United
States, since among other reasons, it provides a more rational basis for
amortization during periods of volatile commodity prices and also increases
consistency with others in the industry. As a result of this change, the Company
recorded a non-cash cumulative effect charge of $6.2 million, net of tax, (or
$0.17 per basic and diluted common share) in the first quarter of 2002.
17
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Derivative Instruments. The Company's major market risk exposure is to oil
and gas prices, which have historically been volatile. Realized prices are
primarily driven by the prevailing worldwide price for crude oil and regional
spot prices for natural gas production. The Company has utilized, and may
continue to utilize, derivative contracts, including swaps, futures contracts,
options and collars to manage this price risk. See Note 6 to Condensed
Consolidated Financial Statements. While these derivative contracts are
structured to reduce the Company's exposure to decreases in the price associated
with the underlying commodity, they also limit the benefit the Company might
otherwise receive from any price increases.
At March 31, 2003, the Company had derivative instruments covering 3.5
million Mmbtu of gas production for April through November 2003. These
instruments established an average floor price of $4.51 and enable the Company
to receive market prices up to an average cap of $5.78, approximately 26% of any
price between $5.78 and $6.28 and 100% of any price above $6.28. The following
table sets forth the Company's oil and natural gas hedged position at March 31,
2003.
Expected Maturity, 2003 Fair
----------------------------------------------------- Value
2nd Quarter 3rd Quarter 4th Quarter Total ($000)
----------- ----------- ----------- ----- ------
Swaps: $ 37
Volumes (bbl) 15,000 -- -- 15,000
Weighted average price ($/bbl) $ 31.06 $ -- $ -- $ 31.06
Puts / Floors: $ 137
Volumes (Mmbtu) 150,000 460,000 305,000 915,000
Weighted average price ($/Mmbtu) $ 4.25 $ 4.25 $ 4.25 $ 4.25
3-way collars: $ 352
Volumes (MMbtu) 1,060,000 1,075,000 460,000 2,595,000
Weighted average price ($/Mmbtu)
Floor (purchased put option) $ 4.83 $ 4.47 $ 4.40 $ 4.61
Cap 1 (sold call option) $ 5.81 $ 5.76 $ 5.75 $ 5.78
Cap 2 (purchased call option) $ 6.31 $ 6.26 $ 6.25 $ 6.28
In addition to the above, the Company has entered into fixed price sales
contracts covering 0.3 million Mmbtu at an average price of $5.09 for April
through June 2003 and will deliver 4.8 Bcfe for April thru December under the
Production Payment sold in February 2001 at an average price of $4.05 per Mcfe
as described in Note 3 to Condensed Consolidated Financial Statements.
Interest Rate Risk. The Company uses fixed and variable rate long-term
debt to finance its capital spending program and for general corporate purposes.
These variable rate debt instruments expose the Company to market risk related
to changes in interest rates. The Company's fixed rate debt and the associated
weighted average interest rate was $125.0 million at 8.9% on March 31, 2003 and
$198.9 million at 9.7% on March 31, 2002. The Company's variable rate debt and
weighted average interest rate was $60.5 million at 7.7% on March 31, 2003 and
$10.8 million at 3.9% on March 31, 2002.
18
Item 4. Controls and Procedures.
(a) Evaluation of disclosure controls and procedures.
The term disclosure controls and procedures is defined in Rules 13a-14(c)
and 15d-14(c) of the Securities Exchange Act of 1934. These rules refer to the
controls and other procedures of a company that are designed to ensure that
information required to be disclosed by a company in the reports that it files
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission's rules and
forms. Furthermore, we have designed our disclosure controls and procedures to
ensure that information that we are required to disclose in our report is
accumulated and communicated to management (including our Chief Executive
Officer and Principal Financial Officer) in a manner that permits timely
decisions to be made regarding required disclosure.
Our Chief Executive Officer and our Principal Financial Officer have
evaluated the effectiveness of our disclosure controls and procedures as of a
date within 90 days prior to the date of the filing of this quarterlyreport, and
they have concluded that such disclosure controls and procedures were effective
at ensuring that they were alerted in a timely manner as to all material
information that we are required to include in our reports with the Securities
and Exchange Commission.
(b) Changes in internal controls.
We maintain a system of internal accounting controls that is designed to
provide reasonable assurance that our books and records accurately reflect our
transactions and that our established policies and procedures are followed.
Since the date of the evaluation of our disclosure controls and procedures by
our Chief Executive Officer and Principal Financial Officer, there have been no
significant changes to our internal controls or in other factors that could
significantly affect our internal controls subsequent to the date of the most
recent evaluation.
19
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
Reference is made to Note 10 to Condensed Consolidated Financial
Statements included herein.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
3.1 Restated Certificate of Incorporation of KCS Energy, Inc.
(filed as Exhibit (3) i to the Annual Report on Form 10-K as
filed with the SEC on April 2, 2001 and incorporated by
reference herein.
3.2 Restated By-Laws of KCS Energy, Inc. (filed as Exhibit (3) ii
to the Annual Report on Form 10-K as filed with the SEC on
April 2, 2001 and incorporated by reference herein.
10.1 Amended and Restated Credit Agreement by and among KCS Energy,
Inc., the lenders from time to time hereto, Foothill Capital
Corporation, as collateral and administrative agent, and
Highbridge/ Zwirn Special Opportunities Fund, L.P., as lead
arranger (filed as Exhibit (10) vii to the Annual Report on
Form 10-K as filed with the SEC on March 31, 2003 and
incorporated by reference herein.
99.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes- Oxley Act of
2002 filed here with.
99.2 Certification of Frederick Dwyer, Principal Financial Officer,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes- Oxley Act of 2002 filed here
with.
(b) Reports on Form 8-K.
On January 21, 2003, the Company filed a report on Form 8-K under
Item 5, Other Events reporting that the Company had completed its
previously announced financing and that it paid off the balance of
its maturing Senior Notes obligations.
SIGNATURES
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 thereunto duly authorized.
KCS ENERGY, INC.
May 14, 2003 By: /S/ FREDERICK DWYER
------------------------------------
Frederick Dwyer
Vice President, Controller
and Secretary
20
Exhibit Index
Exhibit
No. Description
------ -----------
3.1 Restated Certificate of Incorporation of KCS Energy, Inc. (filed
as Exhibit (3) i to the Annual Report on Form 10-K as filed with
the SEC on April 2, 2001 and incorporated by reference herein.
3.2 Restated B-Laws of KCS Energy, Inc. (filed as Exhibit (3) ii to
the Annual Report on Form 10-K as filed with the SEC on April 2,
2001 and incorporated by reference herein.
10.1 Amended and Restated Credit Agreement by and among KCS Energy,
Inc., the lenders from time to time hereto, Foothill Capital
Corporation, as collateral and administrative agent, and
Highbridge/ Zwirn Special Opportunities Fund, L.P., as lead
arranger (filed as Exhibit (10) vii to the Annual Report on Form
10-K as filed with the SEC on March 31, 2003 and incorporated by
reference herein.
99.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes- Oxley Act of
2002.
99.2 Certification of Frederick Dwyer, Principal Financial Officer,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes- Oxley Act of 2002.
21