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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, 2005
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 Identification No.)
incorporation or organization)
5555 San Felipe Road, 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 May 3, 2005: 49,816,147.
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(Amounts in thousands, except per share data)
Three Months Ended March 31,
----------------------------
2005 2004
--------- ---------
Oil and natural gas revenue $ 66,282 $ 50,314
Other, net (1,440) 130
--------- ---------
Total revenue and other 64,842 50,444
--------- ---------
Operating costs and expenses
Lease operating expenses 7,516 7,433
Production and other taxes 3,043 2,896
General and administrative expenses 2,773 2,283
Stock compensation 360 342
Accretion of asset retirement obligation 241 257
Depreciation, depletion and amortization 17,777 12,789
--------- ---------
Total operating costs and expenses 31,710 26,000
--------- ---------
Operating income 33,132 24,444
Interest and other income 18 4
Interest expense (3,319) (3,021)
--------- ---------
Income before income taxes 29,831 21,427
Federal and state income tax expense (10,411) (1,982)
--------- ---------
Net income $ 19,420 $ 19,445
========= =========
Earnings per share of common stock - basic $ 0.39 $ 0.40
========= =========
Earnings per share of common stock- diluted $ 0.39 $ 0.39
========= =========
Average shares outstanding for computation
of earnings per share
Basic 49,542 48,646
========= =========
Diluted 50,095 49,427
========= =========
The accompanying notes are an integral part of these financial statements.
1
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Amounts in thousands, except share and per share data)
March 31, December 31,
2005 004
---------- -----------
ASSETS
Current assets
Cash and cash equivalents $ 2,501 $ 6,613
Trade accounts receivable, less allowance for doubtful accounts
of $4,908 in 2005 and $4,880 in 2004 38,073 35,173
Prepaid drilling 1,958 510
Other current assets 2,879 3,549
---------- ----------
Current assets 45,411 45,845
---------- ----------
Property, plant and equipment
Oil and gas properties, full cost method, less
accumulated DD&A - 2005 $1,007,483; 2004 $989,930 436,906 393,217
Other property, plant and equipment, at cost less
accumulated depreciation - 2005 $12,773; 2004 $12,549 7,678 7,788
---------- ----------
Property, plant and equipment, net 444,584 401,005
---------- ----------
Deferred charges and other assets
Deferred taxes 30,576 31,713
Other 13,759 8,745
---------- ----------
Deferred charges and other assets 44,335 40,458
---------- ----------
TOTAL ASSETS $ 534,330 $ 487,308
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 33,214 $ 38,772
Accrued interest 6,238 3,118
Accrued drilling cost 33,097 21,922
Derivative liabilities 23,055 --
Other accrued liabilities 7,487 10,775
---------- ----------
Current liabilities 103,091 74,587
---------- ----------
Deferred credits and other non-current liabilities
Deferred revenue 12,719 17,326
Asset retirement obligation 12,773 12,655
Derivative liabilities 4,385 --
Other 691 691
---------- ----------
Deferred credits and other non-current liabilities 30,568 30,672
---------- ----------
Long-term debt
Credit facility 13,000 --
Senior notes 175,000 175,000
---------- ----------
Long-term debt 188,000 175,000
---------- ----------
Commitments and contingencies
Stockholders' equity
Common stock, par value $0.01 per share, authorized
75,000,000 shares; issued 51,981,077 and 51,395,536, respectively 520 514
Additional paid-in capital 245,932 241,545
Accumulated deficit (8,777) (28,197)
Unearned compensation (2,988) (1,225)
Accumulated other comprehensive loss (17,275) (847)
Less treasury stock, 2,167,096 shares, at cost (4,741) (4,741)
---------- ----------
Total Stockholders' equity 212,671 207,049
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 534,330 $ 487,308
========== ==========
The accompanying notes are an integral part of these financial statements.
2
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in thousands)
For the Three Months Ended
March 31,
--------------------------
2005 2004
--------- ---------
Cash flows from operating activities:
Net income $ 19,420 $ 19,445
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization 17,777 12,789
Amortization of deferred revenue (4,607) (5,827)
Deferred income tax expense 9,983 1,582
Accretion of asset retirement obligation 241 257
Non-cash losses on derivative instruments 2,411 1,135
Stock compensation 360 342
Other non-cash charges and credits, net 767 170
Net changes in assets and liabilities:
Trade accounts receivable (2,928) (265)
Other current assets (222) 831
Accounts payable and accrued liabilities (8,817) 1,605
Accrued interest 3,120 (2,774)
Other, net 567 (689)
--------- ---------
Net cash provided by operating activities 38,072 28,601
--------- ---------
Cash flows from investing activities:
Investment in oil and gas properties (56,141) (32,073)
Proceeds from the sale of oil and gas properties 12 152
Investment in other property, plant and equipment (114) (143)
--------- ---------
Net cash used in investing activities (56,243) (32,064)
--------- ---------
Cash flows from financing activities:
Proceeds from borrowings 13,000 5,000
Other, net 1,059 447
--------- ---------
Net cash proved by financing activities 14,059 5,447
--------- ---------
Increase (decrease) in cash and cash equivalents (4,112) 1,984
Cash and cash equivalents at beginning of year 6,613 2,178
--------- ---------
Cash and cash equivalents at end of year $ 2,501 $ 4,162
========= =========
The accompanying notes are an integral part of these financial statements.
3
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
Accumulated
Additional Other
Common Paid-in Accumulated Unearned Comprehensive
Stock Capital Deficit Compensation Loss
--------- --------- --------- --------- ---------
(Dollars in thousands)
Balance at December 31, 2004 $ 514 $ 241,545 $ (28,197) $ (1,225) $ (847)
Comprehensive income
Net income -- -- 19,420 -- --
Commodity hedges, net of tax -- -- -- -- (16,428)
Comprehensive income
Stock isuances - exercise of warrants 2 798
Stock isuances - exercise of stock options 2 1,003 -- -- --
Stock issuances - benefit plans and
awards of restricted stock 2 2,552 -- (2,089) --
Stock compensation expense -- 34 -- 326 --
--------- --------- --------- --------- ---------
Balance at March 31, 2005 $ 520 $ 245,932 $ (8,777) $ (2,988) $ (17,275)
========= ========= ========= ========= =========
Stock-
Treasury Comprehensive holders
Stock Income Equity
--------- --------- ---------
Balance at December 31, 2004 $ (4,741) $ 207,049
Comprehensive income
Net income -- $ 19,420 19,420
Commodity hedges, net of tax -- (16,428) (16,428)
---------
Comprehensive income $ 2,992
=========
Stock isuances - exercise of warrants 800
Stock isuances - exercise of stock options -- 1,005
Stock issuances - benefit plans and
awards of restricted stock -- 465
Stock compensation expense -- 360
--------- ---------
Balance at March 31, 2005 $ (4,741) $ 212,671
========= =========
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 the "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 for a fair presentation of the interim results. Certain information
and footnote disclosures have been condensed or omitted pursuant to such rules
and regulations. Although the Company believes that the disclosures are adequate
to make the information presented herein 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, 2004. Certain previously
reported amounts have been reclassified to conform with current period
presentations. The results of operations for the three months ended March 31,
2005 are not necessarily indicative of the results that may be expected for the
year ending December 31, 2005.
2. Income Taxes
There were no state or federal income tax payments made during the three
months ended March 31, 2005. Federal alternative minimum tax payments, or AMT,
of $0.4 million were made during the three months ended March 31, 2004. No state
income tax payments were made during the three months ended March 31, 2004.
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 Company's oil and gas 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 aggregating
approximately $162 million as of December 31, 2004 have remaining lives ranging
from 14 to 18 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 a valuation allowance is required.
In the fourth quarter of 2004, based on the aforementioned analysis and
the Company's belief that the future outlook for continued generation of taxable
income is positive based on existing available information, including current
prices quoted on the New York Mercantile Exchange, the Company reversed the
remainder
5
of the valuation allowance against net deferred income tax assets. Accordingly,
beginning January 1, 2005, the Company resumed recording its book income tax
provision at the statutory corporate income tax rate of 35%. However, the
Company will continue to utilize its net operating loss carryforwards to offset
taxable income and will be subject only to AMT in 2005.
3. Earnings Per Share
Basic earnings per share of common stock is computed by dividing net
income by the weighted average number of common shares outstanding during the
period. Diluted earnings per share of common stock reflects the potential
dilution that could occur if the Company's dilutive outstanding stock options
and warrants were exercised using the average common stock price for the period.
The following table sets forth the computation of basic and diluted earnings per
share:
For the Three Months Ended
March 31,
(amounts in thousands --------------------------
except per share data) 2005 2004
- ---------------------------------------------------- -------- --------
Net income $ 19,420 $ 19,445
-------- --------
Basic earnings per share:
Average shares of common stock outstanding 49,542 48,646
-------- --------
Basic earnings per share $ 0.39 $ 0.40
======== ========
Diluted earnings per share:
Average shares of common stock outstanding 49,542 48,646
Stock options and warrants 553 781
-------- --------
Average diluted shares of common stock outstanding 50,095 49,427
-------- --------
Diluted earnings per share $ 0.39 $ 0.39
======== ========
4. 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 Employee and Directors
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 Transactions Involving Stock Compensation" until
exercised. 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. Stock
compensation was $0.4 million for the three months ended March 31, 2005 compared
to $0.3 million for the three months ended March 31, 2004.
As permitted under Statement of Financial Accounting Standards ("SFAS")
No. 123 "Accounting for Stock-Based Compensation," as amended ("SFAS No. 123"),
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 net income and earnings per share if
the Company had applied the fair value recognition provision of SFAS No. 123.
6
For the Three Months Ended
March 31,
--------------------------
2005 2004
-------- --------
(amounts in thousands except
per share data)
Net income ................................... $ 19,420 $ 19,445
Add: Stock-based compensation expense
included in reported net income ............ 234 342
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards ................................ (477) (554)
-------- --------
Pro forma net income ......................... $ 19,177 $ 19,233
======== ========
Basic earnings per share:
-------- --------
Average shares outstanding ................... 49,542 48,646
-------- --------
Basic - as reported ........................ $ 0.39 $ 0.40
Basic - pro forma .......................... $ 0.39 $ 0.40
Diluted earnings per share:
-------- --------
Average diluted shares outstanding ........... 50,095 49,427
-------- --------
Diluted - as reported ...................... $ 0.39 $ 0.39
Diluted - pro forma ........................ $ 0.38 $ 0.39
5. Deferred Revenue
In February 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, 2005, the Company delivered
1.1 Bcfe and recorded $4.6 million of oil and gas revenue. This compares to
Production Payment deliveries of 1.4 Bcfe and $5.8 million of oil and gas
revenue for the three months ended March 31, 2004. From the sale of the
Production Payment in February 2001 to March 31, 2005, the Company had delivered
40.0 Bcfe, or 93% of the total quantity to be delivered.
6. Derivatives
Oil and natural gas prices have historically been volatile. The Company
has at times utilized derivative contracts, including commodity price swaps,
futures contracts, option contracts and price collars, to manage this price
risk.
Commodity Price Swaps. Commodity price swap agreements require the Company
to make payments to, 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.
7
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.
Commodity Basis Swaps. Commodity basis swap agreements require the Company
to make payments to, or receive payments from, the counter parties based upon
the differential between certain pricing indices and a stated differential
amount.
As of March 31, 2005, we had outstanding derivative instruments covering
14.6 million MMBtu of 2005 natural gas production, 10.2 million MMbtu of 2006
natural gas production, 0.9 million MMbtu of 2007 natural gas production and 0.3
million barrels of 2005 - 2006 oil production. The following table sets forth
information with respect to our open derivative contracts as of March 31, 2005.
Expected Maturity Fair Value as
2005 2006 2007 of March 31,
---------------------------------------------------- -------- ------- 2005
2nd 3rd 4th For the 1st --------------
Quarter Quarter Quarter Total Year Quarter (In thousands)
------- ------- ------- ----- ---- -------
Swaps:
Oil
Volumes (bbl) 100,000 104,000 73,250 277,250 48,000 -- $ (4,264)
Weighted average price ($/bbl) $ 43.39 $ 43.18 $ 40.31 $ 42.50 $ 46.18 --
Natural Gas
Volumes (MMbtu) 4,700,000 4,165,000 3,700,000 12,565,000 8,870,000 900,000 $ (19,701)
Weighted average price ($/MMbtu) $ 6.48 $ 6.82 $ 7.45 6.88 $ 7.13 $ 7.29
Collars:
Natural Gas
Volumes (MMbtu) 455,000 460,000 460,000 1,375,000 450,000 -- $ (1,419)
Weighted average price ($/MMbtu)
Floor $ 5.50 $ 5.50 $ 5.50 $ 5.50 $ 6.75 --
Cap $ 7.61 $ 7.61 $ 7.61 $ 7.61 $ 8.25 --
Sold calls:
Natural Gas
Volumes (MMbtu) -- -- 610,000 610,000 900,000(1) -- $ (2,056)
Weighted average price ($/MMbtu) $ -- -- $ 8.00 $ 8.00 8.00 --
Fair value of derivatives at March 31, 2005. $ (27,440)
- ----------
(1) First quarter only.
8
The fair value of the Company's derivative instruments are reflected as
assets or liabilities in the Company's financial statements as presented in the
following table.
March 31, 2005
--------------
(in thousands)
Derivative liabilities-current $ 23,055
Derivative liabilities-non-current 4,385
---------
Fair value of derivatives at March 31, 2005 $ 27,440
=========
In addition to the information set forth in the first table above, the
Company will deliver 2.8 Bcfe during the remainder of 2005 and 0.3 Bcfe in 2006
under the Production Payment and amortize deferred revenue with respect to such
deliveries at a weighted average discounted price of $4.05 per Mcfe.
Reflected in the first table above are natural gas call options covering
1,510,000 MMbtu of natural gas production that were sold for proceeds of $1.2
million. These options do not qualify for hedge accounting treatment under SFAS
No. 133 and therefore realized and all unrealized gains and losses related to
changes in fair value are being reported in Other, net on the Condensed
Statements of Consolidated Income. Unrealized losses associated with these sold
call options were $0.8 million for the three months ended March 31, 2005.
As of March 31, 2005, the Company had approximately $17.3 million of
derivative losses, net of tax, recorded in Accumulated Other Comprehensive
Income (Loss) ("AOCI") which included losses associated with terminated
commodity derivatives and other commodity derivatives. The following table
recaps the balance of AOCI at March 31, 2005 on both a pre-tax and after-tax
basis.
Pre-tax After-tax
--------- ---------
(In thousands)
Terminated commodity derivatives (a) $ (2,269) $ (1,475)
Other commodity derivatives (b) (24,308) (15,800)
--------- ---------
AOCI at March 31, 2005 $ (26,577) $ (17,275)
========= =========
(a) During 2001, the Company terminated certain commodity derivative
instruments and recognized a charge to AOCI. As the original forecasted
transaction occurs, this loss is reclassified as a charge against earnings. The
following table details the activity of these terminated commodity instruments
on both a pre-tax and after-tax basis.
Pre-tax After-tax
--------- ---------
(In thousands)
Balance included in AOCI, December 31, 2004 $ (3,026) $ (1,967)
Reclassified as a charge against earnings 757 492
--------- ---------
Balance included in AOCI, March 31, 2005 $ (2,269) $ (1,475)
========= =========
All of the $1.5 million after-tax loss remaining in AOCI at March 31, 2005
related to the terminated commodity derivatives will be reclassified as a charge
against earnings during the remainder of 2005.
9
(b) The Company also has other commodity derivatives, which were accounted
for as hedges under SFAS No. 133. The following table details the activity of
those commodity derivatives on both a pre-tax and after-tax basis.
Pre-tax After-tax
--------- ---------
(In thousands)
Balance included in AOCI, December 31, 2004 $ 1,723 $ 1,120
Reclassified into earnings (747) (486)
Change in fair market value (25,722) (16,719)
Ineffective portion of hedges 438 285
--------- ---------
Balance included in AOCI, March 31, 2005 $ (24,308) $ (15,800)
========= =========
7. Debt
The following table sets forth information regarding the Company's
outstanding debt.
March 31, December 31,
2005 2004
---------- ------------
(Amounts in thousands)
Bank Credit Facility $ 13,000 $ --
7-1/8% Senior Notes 175,000 175,000
---------- ----------
188,000 175,000
Classified as short-term debt -- --
---------- ----------
Long-term debt $ 188,000 $ 175,000
========== ==========
Bank Credit Facility. On March 31, 2005, the Company amended its bank
credit facility to, among other things, increase the maximum commitment amount
from $100 million to $250 million, extend the maturity date to March 31, 2009,
and permit an additional $125 million of indebtedness for money borrowed. In
connection with the amended bank credit facility, the lenders increased the
borrowing base, which is redetermined semi-annually and may be adjusted based on
the lenders' valuation of the Company's oil and natural gas reserves and other
factors, from $100 million to $185 million. The borrowing base is automatically
reduced by an amount equal to a specified percentage of the net proceeds from
the issuance of any additional indebtedness that is not applied to refinance
existing public indebtedness. As a result of the Senior Notes offering discussed
below, the borrowing base was automatically reduced by $20 million to $165
million.
Effective December 1, 2004, borrowings under the bank credit facility bear
interest, at the Company's option, at an interest rate of LIBOR plus 1.75% to
2.5% or the greater of (1) the Federal Funds Rate plus 0.5% or (2) the Base
Rate, plus 0.0% to 0.75%, depending on utilization. These rates will decrease by
0.5% after the final deliveries are made in connection with the Production
Payment entered into by the Company in 2001 and the lien on the subject property
is released. Also effective December 1, 2004, a commitment fee of 0.35% to 0.5%
per year, depending on utilization, is paid on the unused availability under the
bank credit facility. From November 18, 2003 through November 30, 2004, the
applicable margin for LIBO rate loans was 2.25% to 3.0%, the applicable margin
for base rate loans was 0.5% to 1.25%, depending on utilization and the
commitment fee was 0.5% per year on the unused availability under the credit
facility.
The bank credit facility contains various restrictive covenants, including
minimum levels of liquidity and interest coverage. The bank credit facility also
contains other usual and customary terms and conditions of a conventional
borrowing base facility, including prohibitions on a change of control,
prohibitions on the
10
payment of cash dividends, restrictions on certain other distributions and
restricted payments, and limitations on the incurrence of additional debt and
the sale of assets.
Substantially all of the Company's assets, including the stock of all of
its subsidiaries, are pledged to secure the bank credit facility. Further, each
of the Company's subsidiaries has guaranteed its obligations under the bank
credit facility.
As of March 31, 2005, $13.0 million was outstanding under the bank credit
facility and $172 million of unused borrowing capacity was available for future
financing needs. The Company was in compliance with all covenants under the bank
credit facility as of that date.
Senior Notes. On April 1, 2004, the Company issued $175 million of 7-1/8%
senior notes due April 1, 2012 (the "Senior Notes"). The Senior Notes bear
interest at a rate of 7-1/8% per annum with interest payable semi-annually on
April 1 and October 1. The Company may redeem the Senior Notes at its option, in
whole or in part, at any time on or after April 1, 2008 at a price equal to 100%
of the principal amount plus accrued and unpaid interest, if any, plus a
specified premium which decreases yearly from 3.563% in 2008 to 0% in 2010 and
thereafter. In addition, at any time prior to April 1, 2007, the Company may
redeem up to a maximum of 35% of the aggregate principal amount with the net
cash proceeds of one or more equity offerings at a price equal to 107.125% of
the principal amount, plus accrued and unpaid interest. The Senior Notes are
senior unsecured obligations and rank subordinate in right of payment to all
existing and future secured debt, including secured debt under the Company's
bank credit facility, and will rank equal in right of payment to all existing
and future senior indebtedness.
The Senior Notes (as well as the Additional Notes discussed below) are
jointly and severally and fully and unconditionally guaranteed on a senior
unsecured basis by all of the Company's current subsidiaries. KCS Energy, Inc.,
the issuer of the Senior Notes, has no independent assets or operations apart
from the assets and operations of its subsidiaries.
The indenture governing the Senior Notes contains covenants that, among
other things, restrict or limit the ability of the Company and the subsidiary
guarantors to: (i) borrow money; (ii) pay dividends on stock; (iii) purchase or
redeem stock or subordinated indebtedness; (iv) make investments; (v) create
liens; (vi) enter into transactions with affiliates; (vii) sell assets; and
(viii) merge with or into other companies or transfer all or substantially all
of the Company's assets.
In addition, upon the occurrence of a change of control (as defined in the
indenture governing the Senior Notes), the holders of the Senior Notes will have
the right to require the Company to repurchase all or any part of the Senior
Notes at a purchase price equal to 101% of the aggregate principal amount, plus
accrued and unpaid interest, if any.
The Company received $171.1 million in net proceeds from the issuance of
the Senior Notes. Net proceeds of the issuance were used to redeem the aggregate
principal amount of the Company's $125 million 8-7/8% senior subordinated notes
due 2006 (the "Senior Subordinated Notes") together with an early redemption
premium of $3.7 million, to repay the $22 million outstanding under the
Company's bank credit facility, and for general corporate purposes.
The Senior Subordinated Notes were redeemed on May 1, 2004 and the early
redemption premium of $3.7 million was charged against earnings in the second
quarter of 2004. In addition, the Company incurred an
11
additional $0.9 million of interest expense as both the Senior Subordinated
Notes and the Senior Notes were outstanding during the month of April 2004.
Subsequent Event. On April 8, 2005, the Company consummated a private
placement of $100 million aggregate principal amount of 7-1/8% Senior Notes due
2012 (the "Additional Notes"). In connection therewith, the Company entered into
a supplemental indenture that amended the indenture governing the Senior Notes
so that the Additional Notes would form a single class of securities with the
Senior Notes. All other material terms of the original indenture, as described
above, remain the same. The Additional Notes were issued at 100.625% of the face
amount. The net proceeds from the private placement of approximately $98 million
were used to finance the $86.9 million acquisition of oil and gas properties and
related assets located primarily in the Company's North Louisiana-East Texas
core operating area, to repay outstanding borrowings under the bank credit
facility and for general corporate purposes.
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 less than $0.1 million for the three months ended March 31, 2005
compared to $5.7 million for the three months ended March 31, 2004.
9. Comprehensive Income
The following table presents the components of comprehensive income for
the three months ended March 31, 2005 and 2004:
Three Months Ended
March 31,
-----------------------
(Amounts in thousands) 2005 2004
---------------------------- --------- ---------
Net income $ 19,420 $ 19,445
Commodity hedges,
net of tax (16,428) (2,573)
--------- ---------
Comprehensive income $ 2,992 $ 16,872
========= =========
10. Subsequent Event
On April 13, 2005, the Company completed an acquisition of oil and gas
properties and related assets located primarily in the Company's North
Louisiana-East Texas core operating area for $86.9 million. The acquisition
included internally estimated proved reserves of 47 Bcfe associated with 137
producing wells and 81 proved undeveloped drilling locations and additional
acreage with an estimated 185 drilling locations for which no proved reserves
have been assigned. The acquisition was financed with proceeds from the private
placement of 7-1/8% Senior Notes due 2012 described in Note 7 to Condensed
Consolidated Financial Statements.
11. New Accounting Principles
On December 16, 2004, the Financial Accounting Standards Board issued SFAS
No. 123 (Revised 2004) "SFAS 123(R)," "Share-Based Payment," which is a revision
of SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS 123(R)
supersedes APB Opinion No. 25, and amends SFAS Statement No. 95, "Statement of
Cash Flows." Generally, the approach in SFAS 123(R) is similar to the approach
described in SFAS 123. However, SFAS 123(R) requires all share-based payments to
employees, including grants of employee stock options, to be recognized in the
income statement based on their fair values. Pro forma disclosure is no longer
an alternative.
12
The Company plans to adopt SFAS 123(R) on January 1, 2006. The impact of
adoption of SFAS 123(R) on the Company's results of operations cannot be
predicted at this time because it will depend on levels of share-based payments
granted in the future. However, had we adopted Statement 123(R) in prior
periods, the impact of that standard would have approximated the impact of SFAS
123 as described in the table in Note 4 above. SFAS 123(R) will have no impact
on the Company's overall financial position.
13
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
on a consolidated basis.
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, future cash flows and borrowings, pursuit of potential
acquisition opportunities, 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 "may," "will," "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
proved 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, natural disasters, well blowouts, adverse weather
conditions, pipe failure, spills, explosions and other unforeseen
hazards);
o our ability to effectively transport and 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;
14
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 our outstanding indebtedness;
o continued hostilities in the Middle East and other sustained
military campaigns and acts of terrorism or sabotage; and
o if underlying assumptions prove incorrect.
These and other risks are described in greater detail in the section
entitled "Business - Risk Factors" included in our annual report on Form 10-K
for the year ended December 31, 2004. 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 the year ended December 31, 2004, we drilled a record 130 wells, of
which 126 were completed, resulting in a 97% success rate and significantly
increased production and reserves. In 2004, gross production increased 15%, to
40 Bcfe, while net production after production payment delivery obligations that
do not contribute to cash flow from operating activities increased 25% compared
to 2003. Natural gas and oil reserves increased 22% to 328 Bcfe as of December
31, 2004 compared to 268 Bcfe as of December 31, 2003. In total, we added 94.5
Bcfe of proved reserves during 2004, of which 97% was through the drill bit.
Total oil and gas capital expenditures were $166.7 million.
In 2005, we plan to continue to execute our strategies of focusing on
low-risk development and exploitation drilling in our core operating areas and
to commit approximately 15% to 20% of our capital expenditure budget to
moderate-risk, higher-potential exploration prospects primarily in the onshore
Gulf Coast region. We significantly added to our hedged positions during the
first quarter of 2005 and 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 generate 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. Please read Note 6 to our Condensed Consolidated Financial
Statements for more information regarding our hedging activities. We plan to
maintain a conservative capital structure and the financial flexibility to
capitalize on growth opportunities when they become available.
The execution of these strategies was evident in our first quarter
results. During the three months ended March 31, 2005, we drilled 62 wells, of
which 59 were successful, resulting in a 95% success rate. We further
strengthened our financial flexibility during the first quarter of 2005 by
amending our bank credit facility to, among other things, increase the maximum
commitment amount from $100 million to $250 million, extend the maturity date to
March 31, 2009, and permit an additional $125 million of indebtedness for money
borrowed.
15
In connection with the amended facility, the lenders increased the borrowing
base, which is redetermined semi-annually and may be adjusted based on the
lenders' valuation of the Company's oil and natural gas reserves and other
factors, from $100 million to $185 million. The borrowing base is automatically
reduced by an amount equal to a specified percentage of the net proceeds from
the issuance of any additional indebtedness that is not applied to refinance
existing public indebtedness. As a result of the private placement of Senior
Notes discussed below, the borrowing base was automatically reduced by $20
million to $165 million. Following the private placement, there were no amounts
outstanding under the bank credit facility and $165 million of unused borrowing
capacity was available for future financing needs.
On April 13, 2005, we completed an acquisition of oil and gas properties
and related assets located primarily in our North Louisiana - East Texas core
operating area for $86.9 million. The acquisition included internally estimated
proved reserves of 47 Bcfe associated with 137 producing wells and 81 proved
undeveloped drilling locations and additional acreage with an estimated 185
drilling locations for which no proved reserves have been assigned. The
acquisition is consistent with our strategy of focus on core areas and growth
through drilling.
On April 8, 2005, we completed a private placement of $100 million aggregate
principal amount of 7-1/8% Senior Notes due 2012. The net proceeds from the
private placement of approximately $98 million were used to finance the
acquisition discussed above, to repay outstanding borrowings under our bank
credit facility and for general corporate purposes. Please read Note 7 to
Condensed Consolidated Financial Statements.
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. In 2005, we plan to drill 90 to 115 wells in
this region, approximately half of which are planned in the Elm Grove Field
which is our largest field. We will also pursue drilling in the Sawyer Canyon,
Joaquin, Terryville and Talihina fields and have budgeted $20 million to
commence development of the recently acquired properties discussed above. For
the three months ended March 31, 2005, we drilled 39 wells in this region, of
which 38 were completed, resulting in a 97% success rate.
In the Gulf Coast region, we concentrate our drilling programs primarily in
onshore 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 40 to 50 wells in this region in 2005, approximately
three-fourths of which will be exploratory. The 2005 drilling program will be
concentrated in O'Connor Ranch, La Reforma, Coquat and Austin fields and the
West Mission Valley area. For the three months ended March 31, 2005, we drilled
23 wells, of which 21 were completed, resulting in a 91% success rate.
Results of Operations
Income before income taxes for the three months ended March 31, 2005
increased 39%, to $29.8 million, compared to $21.4 million for the three months
ended March 31, 2004. This increase was primarily attributable to an 18%
increase in daily natural gas and oil production (25% increase in daily net
production contributing to cash flow from operating activities) and a 12%
increase in natural gas and oil prices, partially offset by $1.4 million of
non-cash losses associated with derivative instruments included in other, net
and higher depreciation, depletion and amortization expense ("DD&A"). Income tax
expense for the three months ended March 31, 2005 was $10.4 million compared to
$2.0 million for the three months ended March 31, 2004 reflecting the increase
in our effective income tax rate to 35% in the 2005 three-month period compared
to 9.3% for the three months ended March 31, 2004. Please read Note 2 to
Condensed Consolidated Financial Statements for more information regarding our
income taxes. Net income for the three months ended March
16
31, 2005 was $19.4 million, or $0.39 per basic and diluted share, compared to
$19.4 million, or $0.40 per basic share and $0.39 per diluted share, for the
three months ended March 31, 2004.
Three Months Ended
March 31,
-----------------------
2005 2004
--------- ---------
Production: (a)
Natural gas (MMcf) .................... 9,483 7,867
Oil (Mbbl) ............................ 202 193
Natural gas liquids (Mbbl) ............ 46 58
--------- ---------
Total (MMcfe) ..................... 10,971 9,370
Dedicated to Production Payment ....... (1,109) (1,413)
--------- ---------
Net Production .................... 9,862 7,957
Revenue ($000's):
Natural gas ........................... $ 57,483 $ 44,113
Oil ................................... 7,684 5,224
Natural gas liquids ................... 1,115 977
--------- ---------
Total ............................. $ 66,282 $ 50,314
========= =========
Average Price:
Natural gas (per Mcf) ................. $ 6.06 $ 5.61
Oil (per bbl) ......................... 38.13 27.10
Natural gas liquids (per bbl) ......... 24.07 16.96
Total (per Mcfe) (b) .............. $ 6.04 $ 5.37
Production cost ($000's)
Lease operating expense ............. $ 7,516 $ 7,433
Production and other taxes .......... 3,043 2,896
--------- ---------
Total ............................. $ 10,559 $ 10,329
========= =========
Average production cost (per Mcfe):
Lease operating expense ............... $ 0.69 $ 0.79
Production and other taxes ............ 0.28 0.31
--------- ---------
Total ............................. $ 0.96 $ 1.10
========= =========
- ----------
(a) Includes delivery obligations dedicated to the Production Payment.
Production includes 1,109 MMcfe for the three months ended March 31, 2005
compared to 1,413 MMcfe for the three months ended March 31, 2004 dedicated to
the Production Payment. Please read Note 5 to our Condensed Consolidated
Financial Statements for more information on the Production Payment.
(b) The average realized prices reported above include the non-cash effects of
volumes delivered under the Production Payment as well as the unwinding of
various derivative contracts terminated in 2001. These items do not generate
cash to fund our operations. Excluding these items, the average realized price
per Mcfe was $6.34 for the three months ended March 31, 2005 compared to $5.73
for the three months ended March 31, 2004.
Natural gas revenue
For the three months ended March 31, 2005, natural gas revenue increased
$13.4 million, to $57.5 million, compared to $44.1 million for the same period
in 2004 due to a 21% increase in production and an 8% increase in average
realized prices. The production increase was due to our successful drilling
program.
17
Oil and natural gas liquids revenue
For the three months ended March 31, 2005, oil and natural gas liquids
revenue increased $2.6 million, to $8.8 million, compared to $6.2 million for
the same period in 2004 due to a 44% increase in average realized prices.
Other, net
For the three months ended March 31, 2005, Other, net was a cost of $1.4
million compared to other net revenue of $0.1 million for the three months ended
March 31, 2004. The net cost in the current year three-month period consists of
$1.7 million of non-cash losses associated with derivative instruments,
partially offset by $0.3 million in realized derivative gains. Of the non-cash
derivative losses, $0.9 million relates to a call option we sold in February
2005 for $1.2 million whereby the counter party purchased the right to call 1.5
million MMbtu of our November 2005 through March 2006 production at $8.00 per
MMbtu. Because this derivative instrument does not qualify for hedge accounting
treatment pursuant to Statement of Financial Accounting Standards ("SFAS") No.
133 "Accounting for Derivative Instruments and Hedging Activities", the change
in its fair value is recorded to other, net each period until settlement. Of the
other $0.8 million of non-cash derivative losses for the three months ended
March 31, 2005, $0.4 million relates to the "ineffective" component of our
derivatives that do qualify for hedge accounting treatment pursuant to SFAS No.
133 and $0.4 million relates to derivatives that have not been designated as
hedges.
Lease operating expenses
For the three months ended March 31, 2005, lease operating expenses
("LOE") increased $0.1 million, to $7.5 million, compared to $7.4 million for
the three months ended March 31, 2004. On a per unit of production basis, LOE
was $0.69 per Mcfe for the three months ended March 31, 2005 compared to $0.79
per Mcfe for the three months ended March 31, 2004. The decrease in the per unit
cost reflects higher production rates and efficiencies realized in certain of
our larger fields where significant production increases have been achieved.
Production and other taxes
For the three months ended March 31, 2005, production and other taxes
increased $0.1 million, to $3.0 million, compared to $2.9 million for the three
months ended March 31, 2004. The 2005 three-month period includes a $1.1 million
production tax refund due to the Company as a result of lower production tax
rates on certain qualified wells in Texas. On a per unit of production basis,
production and other taxes were $0.28 per Mcfe for the three months ended March
31, 2005 compared to $0.31 per Mcfe for the three months ended March 31, 2004.
Excluding the impact of the production tax refund, production and other taxes
were $0.37 per Mcfe for the three months ended March 31, 2005 reflecting higher
oil and gas revenues and higher ad valorem taxes due to the higher value of our
oil and gas properties.
General and administrative expenses
For the three months ended March 31, 2005, general and administrative
expenses ("G&A") increased $0.5 million, to $2.8 million, compared to $2.3
million for the three months ended March 31, 2004. The increase was primarily
attributable to increased costs to comply with corporate governance initiatives
mandated by the Sarbanes-Oxley Act of 2002 and the New York Stock Exchange and
higher payroll costs. On a per unit of production basis, G&A was $0.25 per Mcfe
for the three months ended March 31, 2005 compared to $0.24 per Mcfe for the
three months ended March 31, 2004.
Depreciation, depletion and amortization
We amortize our oil and gas properties using the unit-of-production method
based on proved reserves.
18
For the three months ended March 31, 2005, DD&A increased $5.0 million, to $17.8
million ($1.62 per Mcfe), compared to $12.8 million ($1.36 per Mcfe) for the
three months ended March 31, 2004. The increase in the 2005 three-month period
reflects increased natural gas and oil production and higher costs. The
increased costs reflect, among other things, our decision to pursue certain
projects with higher finding and development costs that provide attractive
margins at current oil and gas prices.
Interest expense
For the three months ended March 31, 2005, interest expense was $3.3
million compared to $3.0 million for the three months ended March 31, 2004 due
to higher average outstanding borrowings to fund our expanded drilling program,
partially offset by lower interest rates.
Income taxes
Income tax expense for the three months ended March 31, 2005 was $10.4
million compared to $2.0 million for the three months ended March 31, 2004 as
our effective income tax rate during the 2005 three-month period was 35%
following the reversal of the remaining portion of our valuation allowance
against net deferred income tax assets at the end of 2004. For the three months
ended March 31, 2004, our effective income tax rate was 9.3%. We have
significant net operating loss carryforwards to offset taxable income in 2005
and beyond and anticipate that we will pay only alternative minimum tax ("AMT")
in 2005 of approximately 1% to 2% of our pre-tax income. Please read Note 2 to
our Condensed Consolidated Financial Statements for more information regarding
our income taxes.
Liquidity and Capital Resources
Our primary cash requirements are for the exploration, development and
acquisition of oil and gas properties, operating expenses and debt service. We
expect to fund our drilling activities primarily with internally generated cash
flow and to have sufficient capital resources available to allow us the
flexibility to be opportunistic with our drilling program and to fund larger
acquisitions and working capital requirements. We believe this approach allows
us to maintain an appropriate capital structure that allows us to increase our
oil and gas reserves and to reduce debt per Mcfe.
On March 31, 2005, we further strengthened our financial flexibility by
amending our bank credit facility to, among other things, increase the maximum
commitment amount under the bank credit facility from $100 million to $250
million, extend the maturity date to March 31, 2009, and permit an additional
$125 million of indebtedness for money borrowed. In connection with the amended
facility, the lenders increased the borrowing base, which is redetermined
semi-annually and may be adjusted based on the lenders' valuation of our oil and
gas reserves and other factors, from $100 million to $185 million. The borrowing
base is automatically reduced by an amount equal to a specified percentage of
the net proceeds from the issuance of any additional indebtedness that is not
applied to refinance existing public indebtedness. As of March 31, 2005, $13.0
million was outstanding under the bank credit facility and $172 million of
unused borrowing capacity was available for future financing needs. As a result
of the $100 million private placement of senior notes completed in April 2005
(discussed below), the borrowing base was automatically reduced by $20 million
to $165 million. Following the private placement of senior notes, there were no
amounts outstanding under the bank credit facility and $165 million of unused
borrowing capacity was available for future financing needs.
On April 13, 2005, we completed an acquisition of oil and gas properties
and related assets located primarily in our North Louisiana - East Texas core
operating area for $86.9 million. The acquisition included internally estimated
proved reserves of 47 Bcfe associated with 137 producing wells and 81 proved
undeveloped drilling locations and additional acreage with an estimated 185
drilling locations for which no proved reserves have been assigned. The
acquisition is consistent with our strategy of focus on core areas and growth
through drilling.
On April 8, 2005, we completed a private placement of $100 million
19
aggregate principal amount of 7-1/8% Senior Notes due 2012. The net proceeds of
approximately $98 million were used to finance the acquisition and for general
corporate purposes.
In 2005, we have budgeted $190 million for capital investments in natural
gas and oil properties, excluding the cost of acquisitions, and anticipate
drilling at least 150 wells. We expect to fund our 2005 exploration and
development activities primarily through internally generated cash flows. The
amount and allocation of our capital investment program is subject to change
based on operational developments, commodity prices, service costs, acquisitions
and numerous other factors. Generally, acquisitions are not included on our base
capital budget.
Our net working capital position at March 31, 2005 was a deficit of $57.7
million. On that date, we had $172.0 million of unused availability under our
bank credit facility. Working capital deficits are not unusual in our industry.
We, like many other oil and gas companies, typically maintain relatively low
cash reserves and use any excess cash to fund our capital expenditure program or
pay down borrowings under our bank credit facility. The March 31, 2005 working
capital deficit was somewhat higher than usual due mainly to the high level of
accrued drilling costs ($33.1 million) as a result of our accelerated drilling
program and the fair value of derivatives associated with our hedging program
($23.1 million liability).
We believe that cash on hand, net cash generated from operations and
unused committed borrowing capacity under our bank credit facility will be
adequate to fund our capital budget and satisfy our short-term liquidity needs.
In the future, 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
For the three months ended March 31, 2005, net cash provided by operating
activities increased 33% to $38.1 million compared to $28.6 million for the
three months ended March 31, 2004. The increase during the 2005 three-month
period was primarily due to the increase in net production and higher natural
gas and oil prices.
Cash used in investing activities
For the three months ended March 31, 2005, net cash used in investing
activities was $56.2 million compared to $32.1 million during the same period in
2004. Substantially all of the net cash used in investing activities for the
three months ended March 31, 2005 and 2004 was invested in oil and gas
properties.
Capital expenditures for the three months ended March 31, 2005 were $61.4
million, including $48.6 million used for development activities, $12.6 million
for lease acquisitions, seismic surveys and exploratory drilling, $0.1 million
in capitalized asset retirement obligation and $0.1 million for other assets.
These amounts include costs that were incurred and accrued as of March 31, 2005
but are not reflected in the net cash used in investing activities above until
payment is made.
Capital expenditures for the three months ended March 31, 2004 were $36.0
million, including $31.0 million used for development activities, $4.7 million
for lease acquisitions, seismic surveys and exploratory drilling, $0.1 million
in capitalized asset retirement obligation and $0.2 million for other assets.
These amounts include costs that were incurred and accrued as of March 31, 2004
but are not reflected in the net cash used in investing activities above until
payment is made.
20
Cash from financing activities
For the three months ended March 31, 2005, net cash provided by financing
activities was $14.1 million, of which $13.0 million was proceeds from
borrowings under our bank credit facility, and $1.1 million was from proceeds
from the exercise of stock options and warrants. For the three months ended
March 31, 2004, proceeds from borrowings was $5.0 million and $0.4 million was
primarily from the exercise of stock options.
Contractual Cash Obligations
As of March 31, 2005, there have been no material changes outside the
ordinary course of our business to the items listed in the Contractual Cash
Obligations table included in our annual report on Form 10-K for the year ended
December 31, 2004.
The following table summarizes our future contractual cash obligations
related to long-term debt after taking into account the issuance on April 8,
2005 of the additional $100 million aggregate principal amount of 7-1/8% senior
notes due 2012 as described above and as further described in Note 7 to our
Condensed Consolidated Financial Statements (in thousands).
Payments due by period
----------------------
Less Than 1-3 3-5 More Than
Total 1 Year Years Years 5 Years
-----------------------------------------------------------------------
Long-term debt $275,000 -- -- -- $275,000
New Accounting Principles
On December 16, 2004, the Financial Accounting Standards Board issued SFAS
No. 123 (Revised 2004) "SFAS 123(R)," "Share-Based Payment," which is a revision
of SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS 123(R)
supersedes APB Opinion No. 25, and amends SFAS Statement No. 95, "Statement of
Cash Flows." Generally, the approach in SFAS 123(R) is similar to the approach
described in SFAS 123. However, SFAS 123(R) requires all share-based payments to
employees, including grants of employee stock options, to be recognized in the
income statement based on their fair values. Pro forma disclosure is no longer
an alternative.
We plan to adopt SFAS 123 (R) on January 1, 2006. The impact of adoption
of SFAS 123(R) on our results of operations cannot be predicted at this time
because it will depend on levels of share-based payments granted in the future.
However, had we adopted Statement 123(R) in prior periods, the impact of that
standard would have approximated the impact of SFAS 123 as described in the
table in Note 4 to Condensed Consolidated Financial Statements. SFAS 123(R) will
have no impact on our overall financial position.
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." Please
read "Management's Discussion and Analysis of Financial Condition and Results of
Operations - 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
21
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. 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. Please read Note 6 to our Condensed Consolidated Financial Statements
for more information on our derivative contracts.
As of March 31, 2005, we had outstanding derivative instruments covering
14.6 million MMBtu of 2005 natural gas production, 10.2 million MMbtu of 2006
natural gas production, 0.9 million MMbtu of 2007 natural gas production and 0.3
million barrels of 2005 and 2006 oil production. The following table sets forth
information with respect to our open derivative contracts as of March 31, 2005.
Expected Maturity
------------------------------------------------------------------------------- Fair Value as
2005 2006 2007 of March 31,
---------------------------------------------------- -------- ------- 2005
2nd 3rd 4th For the 1st --------------
Quarter Quarter Quarter Total Year Quarter (In thousands)
------- ------- ------- ----- ---- -------
Swaps:
Oil
Volumes (bbl) 100,000 104,000 73,250 277,250 48,000 -- $ (4,264)
Weighted average price ($/bbl) $ 43.39 $ 43.18 $ 40.31 $ 42.50 $ 46.18 --
Natural Gas
Volumes (MMbtu) 4,700,000 4,165,000 3,700,000 12,565,000 8,870,000 900,000 $ (19,701)
Weighted average price ($/MMbtu) $ 6.48 $ 6.82 $ 7.45 6.88 $ 7.13 $ 7.29
Collars:
Natural Gas
Volumes (MMbtu) 455,000 460,000 460,000 1,375,000 450,000 -- $ (1,419)
Weighted average price ($/MMbtu)
Floor $ 5.50 $ 5.50 $ 5.50 $ 5.50 $ 6.75 --
Cap $ 7.61 $ 7.61 $ 7.61 $ 7.61 $ 8.25 --
Sold calls:
Natural Gas
Volumes (MMbtu) -- -- 610,000 610,000 900,000(1) -- $ (2,056)
Weighted average price ($/MMbtu) $ -- -- $ 8.00 $ 8.00 8.00 --
Fair value of derivatives at March 31, 2005. $ (27,440)
- ----------
(1) First quarter only.
In addition to the information set forth in the table above, we will
deliver 2.8 Bcfe during the remainder of 2005 and 0.3 Bcfe in 2006 under the
Production Payment and amortize deferred revenue at a weighted average price of
$4.05 per Mcfe.
Reflected in the table above are natural gas call options covering
1,510,000 MMbtu of natural gas production that were sold for proceeds of $1.2
million. These options do not qualify for hedge accounting treatment under SFAS
No. 133 and 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. Unrealized losses associated with
these sold call options were $0.8 million for the three months ended March 31,
2005.
22
Commodity Price Swaps. Commodity price swap agreements require us to make
payments to, 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.
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.
Commodity Basis Swaps. Commodity basis swap agreements require the Company
to make payments to, or receive payments from, the counter parties based upon
the differential between certain pricing indices and a stated differential
amount.
Interest Rate Risk
We use fixed and variable rate long-term debt to finance our capital
spending program and for general corporate purposes. Our 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 $175.0
million at 7-1/8% as of March 31, 2005 and December 31, 2004 and $125.0 million
at 8-7/8% on March 31, 2004. Our variable rate debt and weighted average
interest rate was $13.0 million at 5.6% on March 31, 2005 and we did not have
any outstanding variable rate debt as of December 31, 2004. Our variable rate
debt and weighted average interest rate was $22.0 million at 3.5% as of March
31, 2004.
On April 1, 2004, we issued $175.0 million aggregate principal amount of
7-1/8% senior notes due April 1, 2012. Please read Note 7 to our Condensed
Consolidated Financial Statements for more information on the senior notes. The
table below presents our debt obligations and related average interest rates
expected by maturity date as of March 31, 2005 (dollars in millions).
As of March 31, 2005
-----------------------------------------------------------------------------
Expected Maturity Date
------------------------------------------------------ Fair
2005 2006 2007 2008 2009 Thereafter Total Value
------ ------ ------ ------ ------ ---------- --------- ---------
Long-term debt
Fixed rate -- -- -- -- -- $ 175.0 $ 175.0 $ 176.1
Average interest rate -- -- -- -- -- 7.125% 7.125% --
Variable rate -- -- -- -- -- $ 13.0 $ 13.0 $ 13.0
Average interest rate -- -- -- -- -- 5.560% 5.560% --
Item 4. Controls and Procedures.
23
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.
24
PART II - OTHER INFORMATION
Item 5. Other Information.
On March 2, 2005, the compensation committee of our board of directors approved
the performance objectives for 2005 under our Annual Performance Incentive Award
Plan. A description of our Annual Performance Incentive Award Plan and the 2005
performance objectives are included in Exhibit 10.1 to this quarterly report on
Form 10-Q and such description is incorporated herein by reference.
Item 6. Exhibits.
*#2.1 Purchase and Sale Agreement among Devon Energy Production
Company, L.P., Devon Louisiana Corporation and KCS Resources,
Inc. dated February 22, 2005 (incorporated by reference to
Exhibit 2.1 to Form 8-K (File No. 001-13781) filed with the
SEC on April 19, 2005).
*4.1 First Supplemental Indenture, dated as of April 8, 2005, to
Indenture dated as of April 1, 2004, among KCS Resources,
Inc., Medallion California Properties Company, KCS Energy
Services, Inc, Proliq, Inc. and U.S. Bank National
Association, as trustee (incorporated by reference to Exhibit
4.1 to Form 8-K (File No. 001-13781) filed with the SEC on
April 11, 2005).
+10.1 KCS Energy, Inc. Annual Performance Incentive Award Plan.
+10.2 Summary of Executive Compensation Arrangements for Named
Executive Officers for 2005.
*10.3 Registration Rights Agreement, dated April 8, 2005, among KCS
Energy, Inc., KCS Resources, Inc., Medallion California
Properties Company, KCS Energy Services, Inc., Proliq, Inc.,
Credit Suisse First Boston LLC, J.P. Morgan Securities Inc.,
Harris Nesbitt Corp., BNP Paribas Securities Corp. and
Greenwich Capital Markets, Inc. (incorporated by reference to
Exhibit 10.2 to Form 8-K (File No. 001-13781) filed with the
SEC on April 11, 2005).
*10.4 Fourth Amendment to Second Amended and Restated Credit
Agreement, dated and effective as of March 31, 2005, by and
among KCS Energy, Inc., each of the Lenders party thereto,
Bank of Montreal, as Agent and Collateral Agent, BNP Paribas,
as Co-Documentation Agent, The Royal Bank of Scotland, as Co-
Documentation Agent, and JPMorgan Chase Bank, N.A., as
Syndication Agent (incorporated by reference to Exhibit 10.1
to Form 8-K (File No. 001-13781) filed with the SEC on April
5, 2005).
25
+31.1 Rule 13a-14(a)/15d-14(a) Certification of James W. Christmas,
Chief Executive Officer.
+31.2 Rule 13a-14(a)/15d-14(a) Certification of Joseph T. Leary,
Chief Financial Officer.
+32.1 Section 1350 Certification of James W. Christmas, Chief
Executive Officer.
+32.2 Section 1350 Certification of Joseph T. Leary, Chief Financial
Officer.
- ----------
+ Filed herewith.
* Incorporated by reference.
# Pursuant to Item 601(b)(2) of Regulation S-K, KCS Energy agrees to furnish
supplementally a copy of any omitted schedule to the Commission upon
request.
26
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, 2005 /s/ Frederick Dwyer
----------------------------------------------
Frederick Dwyer
Vice President, Controller and Secretary
(Signing on behalf of the registrant and
as Principal Accounting Officer)
27
EXHIBIT INDEX
Exhibit
No. Description
------- -----------
*#2.1 Purchase and Sale Agreement among Devon Energy Production
Company, L.P., Devon Louisiana Corporation and KCS Resources,
Inc. dated February 22, 2005. (incorporated by reference to
Exhibit 2.1 to Form 8-K (File No. 001-13781) filed with the
SEC on April 19, 2005).
*4.1 First Supplemental Indenture, dated as of April 8, 2005, to
Indenture dated as of April 1, 2004, among KCS Resources,
Inc., Medallion California Properties Company, KCS Energy
Services, Inc, Proliq, Inc. and U.S. Bank National
Association, as trustee (incorporated by reference to Exhibit
4.1 to Form 8-K (File No. 001-13781) filed with the SEC on
April 11, 2005).
+10.1 KCS Energy, Inc. Annual Performance Incentive Award Plan.
+10.2 Summary of Executive Compensation Arrangements for Named
Executive Officers for 2005.
*10.3 Registration Rights Agreement, dated April 8, 2005, among KCS
Energy, Inc., KCS Resources, Inc., Medallion California
Properties Company, KCS Energy Services, Inc., Proliq, Inc.,
Credit Suisse First Boston LLC, J.P. Morgan Securities Inc.,
Harris Nesbitt Corp., BNP Paribas Securities Corp. and
Greenwich Capital Markets, Inc. (incorporated by reference to
Exhibit 10.2 to Form 8-K (File No. 001-13781) filed with the
SEC on April 11, 2005).
*10.4 Fourth Amendment to Second Amended and Restated Credit
Agreement, dated and effective as of March 31, 2005, by and
among KCS Energy, Inc., each of the Lenders party thereto,
Bank of Montreal, as Agent and Collateral Agent, BNP Paribas,
as Co-Documentation Agent, The Royal Bank of Scotland, as Co-
Documentation Agent, and JPMorgan Chase Bank, N.A., as
Syndication Agent (incorporated by reference to Exhibit 10.1
to Form 8-K (File No. 001-13781) filed with the SEC on April
5, 2005).
+31.1 Rule 13a-14(a)/15d-14(a) Certification of James W. Christmas,
Chief Executive Officer.
+31.2 Rule 13a-14(a)/15d-14(a) Certification of Joseph T. Leary,
Chief Financial Officer.
+32.1 Section 1350 Certification of James W. Christmas, Chief
Executive Officer.
+32.2 Section 1350 Certification of Joseph T. Leary, Chief Financial
Officer.
- ----------
+ Filed herewith.
* Incorporated by reference.
# Pursuant to Item 601(b)(2) of Regulation S-K, KCS Energy agrees to furnish
supplementally a copy of any omitted schedule to the Commission upon
request.