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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, 2004
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, Suite 1200, Houston, Texas 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 12b-2 of the Exchange Act). |X| Yes |_| No
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 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 preceding five years, the registrant did not distribute securities
under its plan of reorganization.
Number of shares of common stock, par value $0.01 per share, outstanding as of
April 30, 2004: 48,889,596
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
Three Months Ended
March 31,
(Amounts in thousands, except -----------------------------
per share data) Unaudited 2004 2003
- -------------------------------------------------------------------------------------------- ------------- --------------
Oil and gas revenue $ 50,314 $ 39,647
Other, net 130 793
- -----------------------------------------------------------------------------------------------------------------------------
Total revenue and other 50,444 40,440
- -----------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses
Lease operating expenses 7,773 6,331
Production taxes 2,556 2,293
General and administrative expenses 2,283 1,800
Stock compensation 342 154
Accretion of asset retirement obligation 257 279
Depreciation, depletion and amortization 12,789 10,642
- -----------------------------------------------------------------------------------------------------------------------------
Total operating costs and expenses 26,000 21,499
- -----------------------------------------------------------------------------------------------------------------------------
Operating income 24,444 18,941
- -----------------------------------------------------------------------------------------------------------------------------
Interest and other income, net 4 27
Interest expense (3,021) (4,614)
- -----------------------------------------------------------------------------------------------------------------------------
Income before income taxes and cumulative effect of accounting change 21,427 14,354
Federal and state income (taxes) benefit (1,982) 482
- -----------------------------------------------------------------------------------------------------------------------------
Net income before cumulative effect of accounting change 19,445 14,836
Cumulative effect of accounting change, net of tax -- (934)
- -----------------------------------------------------------------------------------------------------------------------------
Net income 19,445 13,902
Dividends and accretion of issuance costs on preferred stock -- (309)
- -----------------------------------------------------------------------------------------------------------------------------
Income available to common stockholders $ 19,445 $ 13,593
=============================================================================================================================
Earnings per share of common stock - basic
Before cumulative effect of accounting change $ 0.40 $ 0.38
Cumulative effect of accounting change $ -- $ (0.02)
- -----------------------------------------------------------------------------------------------------------------------------
Earnings per share of common stock - basic $ 0.40 $ 0.36
=============================================================================================================================
Earnings per share of common stock - diluted
Before cumulative effect of accounting change $ 0.39 $ 0.36
Cumulative effect of accounting change $ -- $ (0.02)
- -----------------------------------------------------------------------------------------------------------------------------
Earnings per share of common stock - diluted $ 0.39 $ 0.34
=============================================================================================================================
Average shares outstanding for computation of earnings per share
Basic 48,646 37,436
Diluted 49,427 41,120
=============================================================================================================================
The accompanying notes to the unaudited condensed consolidated financial
statements are an integral part of these financial statements.
1
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, March 31, December 31,
except share and per share data) Unaudited 2004 2003
- -------------------------------------------------------------------------- --------------- --------------
Assets
Current assets
Cash and cash equivalents $ 4,162 $ 2,178
Trade accounts receivable, less allowance
for doubtful accounts-2004 $4,844; 2003 $4,896 24,136 23,911
Prepaid drilling 3,256 1,014
Other current assets 2,875 3,706
- ----------------------------------------------------------------------------------------------------------------------------------
Current assets 34,429 30,809
- ----------------------------------------------------------------------------------------------------------------------------------
Oil and gas properties, full cost method, less accumulated DD&A-2004 $946,127; 2003 $933,572 306,932 283,791
Other property, plant and equipment at cost less accumulated depreciation-2004 $11,832; 2003 $ 11,598 8,123 8,214
- ----------------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net 315,055 292,005
- ----------------------------------------------------------------------------------------------------------------------------------
Deferred charges and other assets
Deferred taxes 18,622 18,818
Other 2,237 1,334
- ----------------------------------------------------------------------------------------------------------------------------------
Deferred charges and other assets 20,859 20,152
- ----------------------------------------------------------------------------------------------------------------------------------
Total Assets $ 370,343 $ 342,966
==================================================================================================================================
Liabilities and stockholders' equity
Current liabilities
Accounts payable $ 30,443 $ 27,834
Accrued interest 2,326 5,100
Accrued drilling cost 15,479 9,596
Other accrued liabilities 8,067 9,071
Derivative liabilites 4,952 --
- ----------------------------------------------------------------------------------------------------------------------------------
Current liabilities 61,267 51,601
- ----------------------------------------------------------------------------------------------------------------------------------
Deferred credits and other non-current liabilities
Deferred revenue 32,869 38,696
Asset retirement obligation 12,181 11,918
Other 702 720
- ----------------------------------------------------------------------------------------------------------------------------------
Deferred credits and other non-current liabilities 45,752 51,334
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt
Credit facility 22,000 17,000
Senior subordinated notes 125,000 125,000
- ----------------------------------------------------------------------------------------------------------------------------------
Long-term debt 147,000 142,000
- ----------------------------------------------------------------------------------------------------------------------------------
Stockholders' equity
Common stock, par value $0.01 per share,
authorized 75,000,000 shares, issued 51,004,711
and 50,532,373, respectively 510 505
Additional paid-in capital 238,829 236,204
Accumulated deficit (109,187) (128,632)
Unearned compensation (1,934) (725)
Accumulated other comprehensive income (7,153) (4,580)
Less treasury stock, 2,167,096 shares, at cost (4,741) (4,741)
- ----------------------------------------------------------------------------------------------------------------------------------
Total stockholders' equity 116,324 98,031
- ----------------------------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity $ 370,343 $ 342,966
==================================================================================================================================
The accompanying notes to the unaudited condensed consolidated financial
statements are an integral part of these financial statements.
2
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
Three Months Ended
March 31,
---------------------------------------
(Amounts in thousands) Unaudited 2004 2003
- ------------------------------------------------------------------ ---------------- ----------------
Cash flows from operating activities:
Net income $ 19,445 $ 13,902
Non-cash charges (credits):
Depreciation, depletion and amortization 12,789 10,642
Amortization of deferred revenue (5,827) (8,223)
Non-cash losses on derivative instruments 1,135 1,378
Deferred income taxes expense (benefit) 1,582 (482)
Cumulative effect of accounting change, net of tax -- 934
Asset retirement obligation accretion 257 279
Other non-cash charges and credits, net 512 164
Net changes in assets and liabilities:
Trade accounts receivable (265) (10,752)
Accounts payable and accrued liabilities 1,605 7,585
Accrued interest (2,774) (5,361)
Other current assets 831 (31)
Other, net (689) 48
- ---------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 28,601 10,083
- ---------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Investments in oil and gas properties (32,073) (10,818)
Proceeds from sales of oil and gas properties 152 (157)
Other capital expenditures (143) (225)
- ---------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (32,064) (11,200)
- ---------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Proceeds from borrowings 5,000 69,295
Repayments of debt -- (70,569)
Proceeds from issuance of common stock 1,080 10
Deferred financing costs (633) (2,198)
- ---------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 5,447 (3,462)
- ---------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents 1,984 (4,579)
Cash and cash equivalents at beginning of period 2,178 6,935
- ---------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 4,162 $ 2,356
===============================================================================================================
The accompanying notes to the unaudited condensed consolidated financial
statements are an integral part of these financial statements.
3
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (UNAUDITED)
(Dollars in thousands)
Accumu-
lated
Other
Additional Unearned Compre- Compre-
Common Paid-in Accumulated Compen- hensive Treasury hensive
Stock Capital Deficit sation Income Stock Income Equity
-------- --------- ----------- -------- -------- -------- -------- --------
Balance at December 31, 2003 $ 505 $ 236,204 $(128,632) $ (725) $ (4,580) $ (4,741) $ 98,031
Comprehensive income
Net income -- -- 19,445 -- -- -- $19,445 19,445
Commodity hedges, net of tax -- -- -- -- (2,573) -- (2,573) (2,573)
-------
Comprehensive income $16,872
=======
Stock issuances - exercise of warrants 2 798 -- 800
Stock issuances - costs incurred -- (221) -- -- -- -- (221)
Stock issuances - benefit plans and
awards of restricted stock 3 1,926 -- (1,429) -- -- 500
Stock compensation expense -- 122 -- 220 -- -- 342
-------- --------- --------- -------- -------- -------- --------
Balance at March 31, 2004 $ 510 $ 238,829 $(109,187) $ (1,934) $ (7,153) $ (4,741) $116,324
======== ========= ========= ======== ======== ======== ========
The accompanying notes to the unaudited condensed consolidated financial
statements are an integral part of these financial statements.
4
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. Basis of Presentation
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") for quarterly reports on Form 10-Q and reflect all adjustments which are
of a normal recurring nature and which are, in the opinion of management,
necessary to present 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
KCS Annual Report on Form 10-K for the year ended December 31, 2003. Certain
previously reported amounts have been reclassified to conform with current
period presentations. The results of operations for the three months ended March
31, 2004 are not necessarily indicative of the results that may be expected for
the year ending December 31, 2004.
2. Stock Compensation
The cost of awards of restricted stock, determined as the market value of
the shares as of the date of grant, is expensed ratably over the restricted
period. Stock options issued under the Company's 2001 stock plan within six
months of the cancellation of options in connection with the Company's plan of
reorganization are subject to variable accounting in accordance with Financial
Accounting Standards Board("FASB") Interpretation No. 44, "Accounting for
Certain Transaction Involving Stock Compensation." Under variable accounting for
stock options, the amount of expense recognized during a reporting period is
directly related to the movement in the market price of the Company's common
stock during that period.
As permitted under Statement of Financial Accounting Standards (SFAS") No.
123 "Accounting for Stock-Based Compensation," or SFAS No. 123, 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 does not record any
compensation expense for stock options granted if the exercise price of those
options 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 available to common
stockholders and earnings per share if the Company had applied the fair value
recognition provision of SFAS No. 123, as amended.
5
For the Three Months Ended
March 31,
(amounts in thousands except ---------------------------
per share data) 2004 2003
------------------------------------- ---------- ----------
Income available to common
stockholders, as reported $ 19,445 $ 13,593
Add: Stock-based compensation expense
included in reported net income 342 154
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards (554) (412)
Pro forma income available to ---------- ----------
common stockholders $ 19,232 $ 13,335
========== ==========
Earnings (loss) per share:
Basic - as reported $ 0.40 $ 0.36
Basic - pro forma $ 0.40 $ 0.36
Diluted - as reported $ 0.39 $ 0.34
Diluted - pro forma $ 0.39 $ 0.33
3. Income Taxes
The Company records deferred tax assets and liabilities to account for
temporary differences arising from events that have been recognized in its
financial statements and will result in future taxable or deductible items in
its tax returns. To the extent deferred tax assets exceed deferred tax
liabilities, at least annually and more frequently if events or circumstances
change materially, the Company assesses the realizability of its net deferred
tax assets. A valuation allowance is recognized if, at the time, it is
anticipated that some or all of the net deferred tax assets may not be realized.
In making this assessment, management performs an extensive analysis of
the operations of the Company to determine the sources of future taxable income.
Such an analysis consists of a detailed review of all available data, including
the Company's budget for the ensuing year, forecasts based on current as well as
historical prices, and the independent reservoir engineers' reserve report.
The determination to establish and adjust a valuation allowance requires
significant judgment as the estimates used in preparing budgets, forecasts and
reserve reports are inherently imprecise and subject to substantial revision as
a result of changes in the outlook for prices, production volumes and costs,
among other factors. It is difficult to predict with precision the timing and
amount of taxable income the Company will generate in the future. Accordingly,
while the Company's current net operating loss carryforwards (approximately
$173 million as of December 31, 2003) have remaining lives ranging from 9 to
19 years, with the majority having a life in excess of 15 years, management
examines a much shorter time horizon, usually two to three years, when
projecting estimates of future taxable income and making the determination as to
whether the valuation allowance should be adjusted.
As of March 31, 2004, the Company estimates an annual effective tax rate
for the year ended December 31, 2004 of approximately 9.3%. The primary item
affecting the Company's annual effective tax rate determination, as compared to
the U.S. corporate statutory rate of 35%, is the anticipated reduction of the
Company's valuation allowance that is currently applied against the deferred tax
asset associated with the Company's net operating losses ("NOLs"). Management
believes that the increased taxable income the Company expects to generate
during 2004, in light of the favorable commodity pricing environment and other
factors, will more likely than not result in the Company's utilization of an
additional portion of its unbenefited NOLs.
Based upon the applicable provisions of SFAS No.109, "Accounting for
Income Taxes", the Company has included the benefit associated with the
realization of its NOLs in its estimated annual effective tax rate because the
realization relates to additional estimated ordinary income in the current year.
The Company estimates that it will make alternative minimum tax payments
of 1-2% of pretax income in 2004.
6
4. 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) to be delivered
over 60 months (the "Production Payment"). Net proceeds from the Production
Payment of approximately $175 million were recorded as deferred revenue on the
Company's balance sheet. Deliveries under the Production Payment are recorded as
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, 2004, the Company delivered 1.4 Bcfe and recorded $5.8
million of oil and gas revenue. This compares to Production Payment deliveries
of 2.0 Bcfe and $8.2 million of oil and gas revenue for the three months ended
March 31, 2003. Since the sale of the Production Payment in February 2001
through March 31, 2004, the Company has delivered 35.1 Bcfe, or 82% of the total
quantity to be delivered.
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) 2004 2003
-------------------------------------------------------------------- -------
Basic earnings per share:
Income available to common stockholders $19,445 $13,593
------- -------
Average shares of common stock outstanding 48,646 37,436
------- -------
Basic earnings per share $ 0.40 $ 0.36
======= =======
Diluted earnings per share:
Income available to common stockholders $19,445 $13,593
Dividends and accretion of issuance costs
on preferred stock -- 309
------- -------
Diluted earnings $19,445 $13,902
------- -------
Average shares of common stock outstanding 48,646 37,436
Assumed conversion of convertible
preferred stock -- 3,566
Dividends on convertible preferred stock -- 66
Stock options and warrants 781 52
------- -------
Average diluted shares of common stock outstanding 49,427 41,120
------- -------
Diluted earnings per share $ 0.39 $ 0.34
======= =======
6. Derivatives
Oil and natural 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.
7
Commodity Price Swaps. Commodity price swap agreements require the Company
to make or entitle it to 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
natural 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 natural 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.
At December 31, 2003, there was $4.9 million remaining in accumulated
other comprehensive income related to certain derivative instruments terminated
in 2001. This amount is being amortized into earnings over the original term of
the derivative instruments, which extends through August 2005 ($2.9 million in
2004 and $2.0 million in 2005).
As of March 31, 2004, the Company had derivative instruments outstanding
covering 9.2 million MMBtu of 2004 natural gas production, 2.7 million MMbtu of
2005 natural gas production and 0.2 million barrels of 2004 oil production with
a fair market value of negative $5.0 million. As of December 31, 2003, the
Company had derivative instruments outstanding covering 8.8 million MMBtu of
2004 natural gas production and 0.1 million barrels of 2004 oil production, with
a fair market value of $0.7 million. The following table sets forth the
Company's oil and natural gas hedge position as of March 31, 2004.
Expected Maturity
------------------------------------------------------------------------------ Fair Value at
2004 2005 March 31,
--------------------------------------------------------------- ----------- 2004
2nd 3rd 4th --------------
Quarter Quarter Quarter Total Total (In thousands)
------- ------- ------- ----- -----
Swaps:
Oil
Volumes (bbl) 91,000 46,000 46,000 183,000 -- $ (634)
Weighted average price ($/bbl) $ 30.65 $ 31.10 $ 30.30 $ 30.68 $ --
Natural Gas
Volumes (MMbtu) 1,970,000 1,380,000 920,000 4,270,000 1,820,000 $ (2,447)
Weighted average price ($/MMbtu) $ 5.34 $ 5.16 $ 5.90 $ 5.40 $ 5.44
Collars:
Natural Gas
Volumes (MMbtu) 910,000 1,840,000 1,840,000 4,590,000 450,000 $ (1,480)
Weighted average price ($/MMbtu)
Floor $ 4.00 $ 4.42 $ 4.00 $ 4.17 $ 5.00
Cap $ 6.81 $ 6.04 $ 7.52 $ 6.79 $ 7.42
Sold calls:
Natural Gas
Volumes (MMbtu) -- -- 305,000 305,000 450,000 $ (391)
Weighted average price ($/MMbtu) -- -- $ 7.10 $ 7.10 $ 7.10
8
In addition to the information set forth in the table above, the Company
will deliver 3.8 Bcfe during the remainder of 2004, 3.9 Bcfe in 2005 and 0.2
Bcfe in 2006 under the Production Payment sold in February 2001 and amortize
deferred revenue at a weighted average price of $4.05 per Mcfe.
The Company realized $2.3 million in net hedging gains in the three months
ended March 31, 2004, excluding the non-cash impact of $1.1 million net hedging
losses due to reclassifications from other income comprehensive Income("OCI) for
contracts terminated prior to January 1, 2004.
As of March 31, 2004, $4.2 million, net of tax associated with contracts
terminated prior to January 1, 2004, remains in OCI and will be amortized as a
non-cash reduction of revenue through 2005 ($2.2 million during the remainder of
2004 and $2.0 million in 2005). As of March 31, 2004, $2.9 million of unrealized
derivative losses, net of tax were charged to OCI and will be reclassified
against earnings when the hedged transaction occurs. At the end of the first
quarter of 2004, the Company sold natural gas call options for proceeds of
$343,525. These options are not being accounted for as hedges under SFAS 133,
therefore all unrealized gains and losses related to changes in fair value and
realized gains and losses are being reported in other, net on the condensed
statements of consolidated income.
7. Subsequent Events
In April 2004, the Company completed a private placement of $175 million
of 7-1/8% Senior Notes due 2012 ("Senior Notes"). Proceeds of this issuance were
used to redeem the $125 million 8-7/8% Senior Subordinated Notes due 2006 and to
repay the $22 million outstanding under the Company's bank credit facility. The
remainder of the proceeds will be used for general corporate purposes.
The Senior Notes are unsecured senior obligations that rank equally in
right of payment with all of the Company's existing and future senior
indebtedness. The notes will rank effectively junior to the Company's secured
indebtedness to the extent of the collateral, including secured indebtedness
under the Company's bank credit facility. The notes will mature in 2012 and
cannot be called by the Company for four years after issuance.
On May 1, 2004, the Company redeemed the $125 million 8-7/8% Senior
Subordinated Notes due 2006. Pursuant to the indenture, the Company paid an
early redemption premium of 2.958%, or $3.7 million, which will be charged
against earnings in the second quarter of 2004.
8. Supplemental Cash Flow Information
The Company considers all highly liquid financial instruments with a
maturity of three months or less when purchased to be cash equivalents. Interest
payments were $5.7 million for the three months ended March 31, 2004 compared to
$9.8 million for the three months ended March 31, 2003. Income tax payments were
$0.4 million for the three months ended March 31, 2004. No income tax payments
were made during the three months ended March 31, 2003.
In connection with the adoption of SFAS No. 143 in 2003, 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.
Additions to oil and gas properties for the three months ended March 31,
2004 were $35.8 million. Of this amount, $32.1 million were cash expenditures
and are reflected as investments in oil and gas properties on the Condensed
Statements of Consolidated Cash Flows. The remaining $3.7 million was made up of
increased accrued drilling costs of $5.9 million, partially offset by increased
drilling prepayments of $2.2 million.
Additions to oil and gas properties for the three months ended March 31,
2003 were $11.9 million. Of this amount, $10.8 million were cash expenditures
and are reflected as investments in oil and gas properties on the Condensed
Statements of Consolidated Cash Flows. The remaining $1.1 million reflects the
decrease in (use of) drilling prepayments.
9
9. Comprehensive Income
The following table presents the components of comprehensive income for
the three months ended March 31, 2004 and 2003:
Three Months Ended
March 31,
-----------------------
(Amounts in thousands) 2004 2003
- ----------------------------------------- -------- --------
Net income $ 19,445 $ 13,902
Commodity hedges,
net of tax (2,573) 795
-------- --------
Comprehensive income $ 16,872 $ 14,697
======== ========
10. New Accounting Principles
SFAS No. 141, "Business Combinations," and SFAS No.142, "Goodwill and
Intangible Assets," were issued by the FASB in June 2001 and became effective
for the Company on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141
requires all business combinations initiated after June 30, 2001 to be accounted
for using the purchase method. Additionally, SFAS No. 141 requires companies to
disaggregate and report separately from goodwill certain intangible assets. SFAS
No. 142 establishes new guidelines for accounting for goodwill and other
intangible assets. Under SFAS No. 142, goodwill and certain other intangible
assets are not amortized, but rather are reviewed annually for impairment.
An issue had arisen for companies engaged in the oil and gas exploration
and production industry regarding whether mineral rights held under lease were
intangible assets. In March 2004, the Emerging Issues Task Force (EITF) reached
a consensus on Issue No. 04-2 "Whether Mineral Rights are Tangible or Intangible
Assets and Related Issues," that mineral rights for mining companies are
tangible assets. At the request of the EITF, the FASB issued a staff position,
which amends SFAS No. 141 and SFAS No. 142 to conform to the EITF's consensus.
Based on this guidance, the Company will continue to classify its oil and
natural gas mineral rights held under lease and other contractual rights
representing the right to extract such reserves as tangible oil and gas
properties.
In March 2004, the FASB issued an exposure draft that would amend SFAS No.
123 "Accounting for Stock Based Compensation" and SFAS No. 95 "Statement of Cash
Flows." This exposure draft was issued to improve existing accounting rules and
to provide more complete, higher quality information for investors on employee
stock compensation matters. The comment period for the exposure draft ends June
30, 2004. The exposure draft covers a wide range of equity-based arrangements
including stock options. Under the FASB's proposal, share-based payments to
employees, including stock options, would be treated the same as other forms of
compensation by recognizing the related costs in the income statement. The
expense of the award would generally be measured at fair value at the grant
date. The Company is evaluating the effects that could result should this
exposure draft be ratified.
10
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 our unaudited
condensed consolidated financial statements and related notes included elsewhere
in this quarterly report on Form 10-Q. Unless the context otherwise requires,
the terms "KCS," "we," "our," or "us" refer to KCS Energy, Inc. and
subsidiaries.
Forward-Looking Statements
The information discussed in this quarterly report 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 natural gas production, the number of anticipated wells to be drilled
in the future, our 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 we believe that the
expectations reflected in any forward-looking statements are reasonable, they do
involve certain assumptions, risks and uncertainties. Our actual results could
differ materially from those anticipated in these forward-looking statements as
a result of certain factors, including:
o the timing and success of our drilling activities;
o the volatility of prices and supply of, and demand for, oil and
natural gas;
o the numerous uncertainties inherent in estimating quantities of oil
and natural gas reserves and actual future production rates and
associated costs;
o our ability to successfully identify, execute or effectively
integrate future acquisitions;
o the usual hazards associated with the oil and gas industry
(including fires, well blowouts, pipe failure, spills, explosions
and other unforeseen hazards);
o our ability to effectively market our oil and natural gas;
o the results of our hedging transactions;
o the availability of rigs, equipment, supplies and personnel;
o our ability to acquire or discover additional reserves;
o our ability to satisfy future capital requirements;
o changes in regulatory requirements;
o the credit risks associated with our customers;
o economic and competitive conditions;
o our ability to retain key members of senior management and key
employees;
o uninsured judgments or a rise in insurance premiums;
o continued hostilities in the Middle East and other sustained
military campaigns and acts of terrorism or sabotage; and
11
o if underlying assumptions prove incorrect.
These and other risks are described in greater detail in "Business - Risk
Factors" included in our annual report on Form 10-K for the year ended December
31, 2003. All forward-looking statements attributable to us or persons acting on
our behalf are expressly qualified in their entirety by these factors. Other
than as required under the securities laws, we do not assume a duty to update
these forward-looking statements, whether as a result of new information,
subsequent events or circumstances, changes in expectations or otherwise.
Overview
In 2004, we plan to continue to execute the strategies that were
successful for us in 2003. Our focus will be on low-risk development and
exploitation drilling in our core operating areas and to commit about 12-15% of
our capital expenditure budget to moderate-risk, higher-potential exploration
prospects in the onshore Gulf Coast region. We intend to stay focused on natural
gas, which we believe offers more upside potential than oil or liquids. We plan
to maintain a conservative capital structure and continue to reduce debt per
Mcfe by increasing our oil and gas reserve base. We will continue our
disciplined hedging program designed to protect against price declines while
participating to a large extent in future price increases. In this way, we
endeavor to ensure that we protect a sufficient level of cash flow to carry out
a capital expenditure program sufficient to at least replace our expected
production and still benefit if prices rise. We have initially budgeted $105
million for our 2004 capital expenditure program and plan to drill more than 100
wells. During the first quarter of 2004, we spent $35.8 million and drilled 37
wells. We believe that this program will be funded primarily through cash flow.
We may increase the budget based on the success of our drilling program and
available cash flow.
In the Mid-Continent region, we concentrate our drilling programs
primarily in north Louisiana, east Texas, Oklahoma (Anadarko and Arkoma basins)
and west Texas. Our Mid-Continent operations provide us with a solid base for
production and reserve growth. We plan to continue to exploit areas within the
various basins that require low-risk exploitation wells for additional reservoir
drainage. Our exploitation wells are generally step-out and extension type wells
with moderate reserve potential. We have a multi-year inventory of locations in
the Mid-Continent region and plan to increase the level of drilling in our Elm
Grove, Talihina and Joaquin fields and to continue the development program in
our Sawyer Canyon Field in 2004. During the first quarter of 2004, we drilled 31
wells in this region with a success rate of 100%.
In the Gulf Coast region, we concentrate our drilling programs primarily
in south Texas. We also have working interests in several minor non-operated
offshore and Mississippi salt basin properties. We conduct development programs
and pursue moderate-risk, higher potential exploration drilling programs in this
region. Our Gulf Coast operations have numerous exploration prospects that are
expected to provide us additional growth. We anticipate drilling 20-26 wells in
this region in 2004, approximately half of which will be exploratory. During the
first quarter of 2004, we drilled one exploratory and five development wells in
this region with a success rate of 100%.
Results of Operations
Income before income taxes and cumulative effect of accounting change for
the three months ended March 31, 2004 was $21.4 million compared to $14.4
million for the three months ended March 31, 2003. This increase was primarily
attributable to a 24% increase in natural gas and oil production as a result of
our successful drilling program, slightly higher average realized prices as a
result of less production dedicated to production payment obligations and
substantially lower interest costs, partially offset by higher operating
expenses. During the three months ended March 31, 2004, we recorded
income tax expense of $2.0 million
12
compared to an income tax benefit of $0.5 million for the three months ended
March 31, 2003. During the three months ended March 31, 2003, we recorded a
cumulative effect of accounting change of $0.9 million, or $0.02 per basic and
diluted share, as a result of the adoption of Financial Accounting Standards
Board Statement No. 143, "Accounting for Asset Retirement Obligations" ("SFAS
No. 143"). Income available to common stockholders for the three months ended
March 31, 2004 increase 43% to $19.4 million, or $0.40 per basic share and $0.39
per diluted share, compared to $13.6 million, or $0.36 per basic share and $0.34
per diluted share, for the three months ended March 31, 2003.
The following table sets forth: (i) our gross natural gas and oil
production, (ii) production net of our obligations under a production payment
(net production), (iii) average prices received for the production and (iv)
associated revenue for the three months ended March 31, 2004 and 2003.
Three Months Ended
March 31,
-----------------------
2004 2003
-------- --------
Production: (a)
Natural Gas (MMcf) 7,867 5,975
Oil (Mbbl) 193 215
Natural Gas Liquids (Mbbl) 58 48
-------- --------
Total (MMcfe) 9,370 7,552
Dedicated to Production Payment (1,413) (2,018)
-------- --------
Net Production (MMcfe) 7,957 5,534
Average Price:
Natural Gas (per Mcf) $ 5.61 $ 5.51
Oil (per bbl) 27.10 27.48
Natural Gas Liquids (per bbl) 16.96 17.27
Total (per Mcfe) (b) 5.37 5.25
Revenue ($000's):
Natural Gas $ 44,113 $ 32,911
Oil 5,224 5,911
Natural Gas Liquids 977 825
-------- --------
Total $ 50,314 $ 39,647
======== ========
- ----------
(a) Production includes 1,413 and 2,018 MMcfe for the three months ended
March 31, 2004 and 2003, respectively, dedicated to a production payment
transaction whereby in February 2001 we sold 43.1 Bcfe (38.3 Bcf of natural gas
and 797 Mbbl of oil) to be delivered over 60 months (the "Production Payment").
Please read Note 4 to our Condensed Consolidated Financial Statements
(Unaudited).
(b) Excluding the non-cash effects of volumes delivered under the
Production Payment sold in February 2001 and terminated derivative contracts
associated with the acquisition of Medallion California Properties Company and
related entities, our total average realized price per Mcfe was $5.73 and $6.07
for the three months ended March 31, 2004 and 2003, respectively.
13
Natural gas revenue
For the three months ended March 31, 2004, natural gas revenue increased
$11.2 million to $44.1 compared to $32.9 million for the same period in 2003 due
to a 32% increase in production and a 2% increase in average realized prices.
The production increase was primarily due to our successful drilling program.
Oil and liquids revenue
For the three months ended March 31, 2004, oil and liquids revenue
decreased $0.5 million to $6.2 million due to a 4% decrease in the average
realized price and a 5% decrease in production. The decrease in production
reflected the natural decline of our oil and liquids properties as our drilling
program over the last two years has been focused almost entirely on natural gas
prospects.
Other, net
Other revenue was $0.1 million for the three months ended March 31, 2004
compared to $0.8 million for the three months ended March 31, 2003. The decrease
was primarily attributable to lower marketing and transportation income
incidental to our oil and gas operations.
Lease operating expenses
Lease operating expenses increased $1.5 million to $7.8 million for the
three months ended March 31, 2004 compared to the three months ended March 31,
2003. The increase is attributable to the increase in the number of producing
wells as a result of our expanded drilling program, higher salt water disposal
costs associated with our properties, higher ad valorem taxes and increased
workover activity.
Production taxes
Production taxes, which are generally based on a percentage of revenue,
increased $0.3 million to $2.6 million for the three months ended March 31, 2004
compared to the three months ended March 31, 2003, due to higher oil and gas
revenue.
General and administrative expenses
General and administrative expenses for the three months ended March 31,
2004 increased $0.5 million to $2.3 million compared to the three months ended
March 31, 2003. The increase is primarily attributable to higher workforce costs
as a result of our expanded drilling program.
Stock compensation
Stock compensation reflects the non-cash expense associated with stock
options issued in 2001 that are subject to variable accounting in accordance
with FASB Interpretation No. 44, "Accounting for Certain Transactions Involving
Stock Compensation", or FIN 44, and the non-cash expense associated with the
amortization of restricted stock grants. Under variable accounting for stock
options, the amount of expense recognized during a reporting period is directly
related to the movement in the market price of our common stock during that
period. Stock compensation was $0.3 million for the three-month period ended
March 31, 2004 compared to $0.2 million for the three months ended March 31,
2003.
Depreciation, depletion and amortization
We amortize our oil and gas properties using the unit-of-production method
based on proved reserves. For the three months ended March 31, 2004,
depreciation, depletion and amortization ("DD&A") increased $2.2 million to
$12.8 million compared to $10.6 million for the three months ended March 31,
2003. The increase reflects the higher production associated with our expanded
drilling program.
14
Interest expense
Interest expense for the three months ended March 31, 2004 was $3.0
million compared to $4.6 million for the three months ended March 31, 2003. The
decrease reflects lower amounts of outstanding debt and lower borrowing costs
associated with our amended and restated bank credit facility.
Income Taxes
The income tax provision for the three months ended March 31, 2004 was
$2.0 million, compared to an income tax benefit of $0.5 million for the three
months ended March 31, 2003.
As of March 31, 2004, we estimated an annual effective tax rate for the
year ended December 31, 2004 of approximately 9.3%. The primary item affecting
our annual effective tax rate determination, as compared to the U.S. corporate
statutory rate of 35%, is the anticipated reduction of our valuation allowance
that is currently applied against the deferred tax asset associated with our net
operating losses ("NOLs"). We believe that the increased taxable income expected
to be generated during 2004, in light of the favorable commodity pricing
environment and other factors, will more likely than not result in the
utilization of an additional portion of our unbenefited NOLs.
Based upon the applicable provisions of SFAS No.109, "Accounting for
Income Taxes", we included the benefit associated with the realization of our
NOLs in the estimated annual effective tax rate because the realization relates
to additional estimated ordinary income in the current year.
We also believe that if the current pricing environment continues, the
valuation allowance on our deferred tax assets for NOL's may be further reduced.
We estimate that we will make alternative minimum tax payments of 1-2% of
pretax income in 2004.
Liquidity and Capital Resources
Our liquidity and capital resources improved significantly during 2003. In
January 2003, we amended and restated our bank credit facility to increase our
borrowing availability and paid off the maturing senior note obligations. We
also accelerated our drilling program, resulting in increased production and oil
and natural gas reserves. The increase in production coupled with a strong
natural gas and oil price environment resulted in a substantial increase in cash
flow.
We took several major steps during 2003 to further strengthen our
financial condition, lower interest costs and provide increased financial
flexibility. The balance of our outstanding Series A Convertible Preferred Stock
was converted into shares of our common stock. This conversion simplified our
overall capital structure and eliminated the 5% dividend obligation associated
with the preferred stock. In the first quarter, we paid off our maturing senior
note obligations. In the fourth quarter of 2003, we amended and restated our
bank credit facility, which increased our revolving credit capacity to $100
million and significantly reduced our borrowing costs. We also completed a
public offering of 6.9 million shares of our common stock. We used the net
proceeds of approximately $52 million to repay a portion of the borrowings under
our bank credit facility and to accelerate our drilling program in certain core
areas. Our successful drilling program, along with strong oil and natural gas
prices and proceeds from our public common stock offering, allowed us to reduce
debt during 2003 from $186.8 million, or $0.95 per Mcfe of reserves, at the
beginning of the year to $142.0 million, or $0.53 per Mcfe of reserves, at the
end of the year.
In April 2004, we completed a private placement of $175 million of 7-1/8%
Senior Notes due 2012. Proceeds of this issuance were used to redeem the $125
million 8-7/8% Senior Subordinated Notes due 2006 and to repay the $22 million
outstanding under our bank credit facility. The remainder of the proceeds will
be used for general corporate purposes. On May 1, 2004, we redeemed the $125
million 8-7/8% Senior Subordinated Notes due 2006. Pursuant to the indenture, we
paid an early redemption premium of 2.958%, or $3.7 million, which will be
charged against earnings in the second quarter of 2004.
15
With the completion of the steps outlined above, we believe that we are
positioned to capitalize on the current strong natural gas and oil price
environment, to focus on developing our multi-year prospect inventory, to
increase reserves and production in our core areas and to further reduce debt
per Mcfe.
Our primary cash requirements are for exploration, development and
acquisition of oil and gas properties, operating expenses and debt service.
For 2004, we have budgeted $105 million for capital investments in natural
gas and oil properties and anticipate drilling over 100 wells. During the first
quarter of 2004, we spent $35.8 million and drilled 37 wells. We believe that
this program will be funded primarily through cash flow. We may increase the
budget based on the success of our drilling program and available cash flow.
After the issuance of the $175 million 7-1/8% Senior Notes discussed
above, we had approximately $22 million of cash on hand and $100 million of
unused committed borrowing capacity under our bank credit facility available for
future financing needs. We may also utilize various financing sources available
to us, including the issuance of debt or equity securities under our shelf
registration statement or through private placements. Our ability to complete
future debt and equity offerings and the timing of these offerings will depend
upon various factors including prevailing market conditions, interest rates and
our financial condition.
Cash flow provided by operating activities
Net cash provided by operating activities for the three months ended March
31, 2004 was $28.6 million compared to $10.1 million for the three months ended
March 31, 2003. The improvement in our cash flow in 2004 was primarily due to a
44% increase in net production, lower interest expense, and the timing of cash
receipts and disbursements. The net changes in trade accounts receivable and in
accounts payable and accrued liabilities in the prior year three-month period
reflect the higher natural gas and oil price environment in 2003 compared to
2002.
Cash used in investing activities
For the three months ended March 31, 2004 net cash used in investing
activities was $32.1 million, which substantially all was invested in oil and
gas properties compared to net cash used in investing activities of $11.2
million in the same period in 2003, of which $10.8 million was invested in oil
and gas properties.
New Accounting Principles
SFAS No. 141, "Business Combinations," and SFAS No.142, "Goodwill and
Intangible Assets," were issued by the FASB in June 2001 and became effective
for the Company on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141
requires all business combinations initiated after June 30, 2001 to be accounted
for using the purchase method. Additionally, SFAS No. 141 requires companies to
disaggregate and report separately from goodwill certain intangible assets. SFAS
No. 142 establishes new guidelines for accounting for goodwill and other
intangible assets. Under SFAS No. 142, goodwill and certain other intangible
assets are not amortized, but rather are reviewed annually for impairment.
An issue had arisen for companies engaged in the oil and gas exploration
and production industry regarding whether mineral rights held under lease were
intangible assets. In March 2004, the Emerging Issues Task Force (EITF) reached
a consensus on Issue No. 04-2 "Whether Mineral Rights are Tangible or Intangible
Assets and Related Issues," that mineral rights for mining companies are
tangible assets. At the request of the EITF, the FASB issued a staff position,
which amends SFAS No. 141 and SFAS No. 142 to conform to the EITF's consensus.
Based on this guidance, the Company will continue to classify its oil and
natural gas mineral rights held under lease and other contractual rights
representing the right to extract such reserves as tangible oil and gas
properties.
In March 2004, the FASB issued an exposure draft that would amend SFAS No.
123 "Accounting for Stock Based Compensation" and SFAS No. 95 "Statement of Cash
Flows." This exposure draft was issued to improve existing accounting rules and
to provide more complete, higher quality information for investors on employee
stock compensation matters. The comment period for the exposure draft ends June
30, 2004. The exposure draft covers a wide range of equity-based arrangements
including stock options. Under the FASB's proposal, share-based payments to
employees, including stock options, would be treated the same as other forms of
compensation by recognizing the related costs in the income statement. The
expense of the award would generally be measured at fair value at the grant
date. The Company is evaluating the effects that could result should this
exposure draft be ratified.
Item 3. Quantitative and Qualitative Disclosures about Market Risk.,
All information and statements included in this section, other than
historical information and statements, are "forward-looking statements."
Commodity Price Risk
Our major market risk exposure is to oil and natural 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. We have utilized, and may continue to utilize, derivative
contracts, including swaps, futures contracts, options and collars to manage
this price risk. We do not enter into derivative or other financial instruments
for trading or speculative purposes. Effective January 1, 2001, we adopted SFAS
No. 133. While these derivative contracts are structured to reduce our exposure
to decreases in the price associated with the underlying commodity, they also
limit the benefit we might otherwise receive from price increases. We maintain a
system of controls that includes a policy covering authorization, reporting, and
monitoring of derivative activity.
16
As of March 31, 2004, we had derivative instruments outstanding covering
9.2 million MMBtu of 2004 natural gas production, 2.7 million MMbtu of 2005
natural gas production and 0.2 million barrels of 2004 oil production, with a
fair market value of negative $5.0 million. As of December 31, 2003, we had
derivative instruments outstanding covering 8.8 million MMBtu of 2004 natural
gas production and 0.1 million barrels of 2004 oil production, with a fair
market value of $0.7 million. The following table sets forth information with
respect to our oil and natural gas hedge position as of March 31, 2004.
Expected Maturity
------------------------------------------------------------------------------ Fair Value at
2004 2005 March 31,
--------------------------------------------------------------- ----------- 2004
2nd 3rd 4th --------------
Quarter Quarter Quarter Total Total (In thousands)
------- ------- ------- ----- -----
Swaps:
Oil
Volumes (bbl) 91,000 46,000 46,000 183,000 -- $ (634)
Weighted average price ($/bbl) $ 30.65 $ 31.10 $ 30.30 $ 30.68 $ --
Natural Gas
Volumes (MMbtu) 1,970,000 1,380,000 920,000 4,270,000 1,820,000 $ (2,447)
Weighted average price ($/MMbtu) $ 5.34 $ 5.16 $ 5.90 $ 5.40 $ 5.44
Collars:
Natural Gas
Volumes (MMbtu) 910,000 1,840,000 1,840,000 4,590,000 450,000 $ (1,480)
Weighted average price ($/MMbtu)
Floor $ 4.00 $ 4.42 $ 4.00 $ 4.17 $ 5.00
Cap $ 6.81 $ 6.04 $ 7.52 $ 6.79 $ 7.42
Sold calls:
Natural Gas
Volumes (MMbtu) -- -- 305,000 305,000 450,000 $ (391)
Weighted average price ($/MMbtu) -- -- $ 7.10 $ 7.10 $ 7.10
In addition to the information set forth in the table above, we will
deliver 3.8 Bcfe during the remainder of 2004, 3.9 Bcfe in 2005 and 0.2 Bcfe in
2006 under the Production Payment and amortize deferred revenue at a weighted
average price of $4.05 per Mcfe.
We realized $2.3 million in net hedging gains in the three months ended
March 31, 2004, excluding the non-cash impact of $1.1 million net hedging losses
due to reclassifications from other comprehensive income ("OCI") for contracts
terminated prior to January 1, 2004.
As of March 31, 2004, $4.2 million, net of tax associated with contracts
terminated prior to January 1, 2004, remains in OCI and will be amortized as a
non-cash reduction of revenue through 2005 ($2.2 million during the remainder of
2004 and $2.0 million in 2005). As of March 31, 2004, $2.9 million of unrealized
derivative losses, net of tax were charged to OCI and will be reclassified
against earnings when the hedged transaction occurs. At the end of the first
quarter of 2004, we sold natural gas call options for proceeds of $343,525.
These options are not being accounted for as hedges under SFAS 133, therefore
all unrealized gains and losses related to changes in fair value and realized
gains and losses are being reported in other, net on the condensed statements of
consolidated income.
Commodity Price Swaps. Commodity price swap agreements require us to make
or entitle us to 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.
17
Futures Contracts. Oil or natural gas futures contracts require us 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, we are
able to set a floor price for a specified quantity of our oil or natural gas
production. By selling a "call" option, we receive an upfront premium from
selling the right for a counter party to buy a specified quantity of oil or
natural gas production at a fixed price.
Price Collars. Selling a call option and buying a put option creates a
"collar" whereby we establish 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 establishes a "3-way collar" that entitles us to capture the benefit
of price increases above that call price
Interest Rate Risk
We use fixed and variable rate long-term debt to finance our capital
spending program and for general corporate purposes. These variable rate debt
instruments expose us to market risk related to changes in interest rates. Our
fixed rate debt and the associated weighted average interest rate was $125.0
million at 8.9% on March 31, 2004, December 31, 2003 and March 31, 2003. Our
variable rate debt and weighted average interest rate was $22.0 million at 3.5%
on March 31, 2004, $17.0 million at 3.6% on December 31, 2003 and $60.5 million
at 7.7% on March 31, 2003.
Item 4. Controls and Procedures.
Evaluation of disclosure controls and procedures. Based on their
evaluation of our disclosure controls and procedures as of the end of the period
covered by this report, our Chief Executive Officer and Chief Financial Officer
have concluded that our disclosure controls and procedures are effective in
ensuring that the information required to be disclosed by us (including our
consolidated subsidiaries) in the reports that we file or submit under the
Securities Exchange Act of 1934, as amended, is recorded, processed, summarized
and reported, within the time periods specified in the Securities and Exchange
Commission's rules and forms.
Changes in internal control over financial reporting. There were no
changes in our internal control over financial reporting that occurred during
our last fiscal quarter that have materially affected, or are reasonably likely
to materially affect, our internal control over financial reporting.
18
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
Note 11 to our Condensed Consolidated Financial Statements (Unaudited)
included in our annual report on Form 10-K for the year ended December
31, 2003 is incorporated herein by reference.
Item 5. Other Events
On May 1, 2004, the Company redeemed the $125 million 8-7/8% Senior
Subordinated Notes due 2006. In connection therewith the Company paid the
principle amount, accrued interest and the required early redemption premium of
2.958%, or $3.7 million.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
4.1 Indenture, dated as of April 1, 2004, among KCS Energy, Inc.,
certain of its subsidiaries and U.S. Bank National
Association. +
4.2 Form of 7-1/8% Senior Note due 2012 (included in Exhibit 4.1).
+
10.1 First Amendment to Second Amended and Restated Credit
Agreement, effective as of February 26, 2004, by and among KCS
Energy, Inc., the lenders from time to time party thereto,
Bank of Montreal, as Agent and Collateral Agent, and BNP
Paribas, as Documentation Agent (incorporated by reference to
Exhibit 10.7 to Form 10-K (File No. 001-13781) filed with the
SEC on March 15, 2004). *
10.2 Registration Rights Agreement, dated April 1, 2004, by and
among KCS Energy, Inc., KCS Resources, Inc., Medallion
California Properties Company, KCS Energy Services, Inc.,
Proliq, Inc., Credit Suisse First Boston LLC, Merill Lynch,
Pierce, Fenner & Smith, Incorporated, Jefferies & Company,
Inc., Harris Nesbitt Corp., Banc One Capital Markets, Inc.,
and BNB Paribas Securities Corp. +
31.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. +
31.2 Certification of Joseph T. Leary, Vice President and Chief
Financial Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. +
32.1 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. +
32.2 Certification of Joseph T. Leary, Chief Financial Officer,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002. +
- --------------------
+Filed herewith
*Incorprated by reference.
(b) Reports on Form 8-K.
On March 15, 2004, we furnished a report on Form 8-K under Item 12,
Results of Operations and Financial Condition, reporting the
issuance of a press release announcing financial and operating
results for the three and twelve months ended December 31, 2003.
On March 18, 2004, we filed a report on Form 8-K under Item 5, Other
Events, announcing the private offering of senior notes. The report
on Form 8-K also furnished information pursuant to Item 9,
Regulation FD Disclosure, disclosing certain information to be
presented to analysts and investors in connection with the senior
notes offering.
19
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.
Date: May 10, 2004 /s/ Frederick Dwyer
---------------------------------
Frederick Dwyer
Vice President, Controller and Secretary
(Signing on behalf of the registrant and
as Principal Accounting Officer)
20
EXHIBIT INDEX
Exhibit
No. Description
------ -----------
4.1 Indenture, dated as of April 1, 2004, among KCS Energy, Inc.,
certain of its subsidiaries and U.S. Bank National
Association. +
4.2 Form of 7-1/8% Senior Note due 2012 (included in Exhibit 4.1).
+
10.1 First Amendment to Second Amended and Restated Credit
Agreement, effective as of February 26, 2004, by and among KCS
Energy, Inc., the lenders from time to time party thereto,
Bank of Montreal, as Agent and Collateral Agent, and BNP
Paribas, as Documentation Agent (incorporated by reference to
Exhibit 10.7 to Form 10-K (File No. 001-13781) filed with the
SEC on March 15, 2004). *
10.2 Registration Rights Agreement, dated April 1, 2004, by and
among KCS Energy, Inc., KCS Resources, Inc., Medallion
California Properties Company, KCS Energy Services, Inc.,
Proliq, Inc., Credit Suisse First Boston LLC, Merill Lynch,
Pierce, Fenner & Smith, Incorporated, Jefferies & Company,
Inc., Harris Nesbitt Corp., Banc One Capital Markets, Inc.,
and BNB Paribas Securities Corp. +
31.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. +
31.2 Certification of Joseph T. Leary, Vice President and Chief
Financial Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002. +
32.1 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. +
32.2 Certification of Joseph T. Leary, Chief Financial Officer,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002. +
- --------------------
+Filed herewith
*Incorprated by reference.