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 June 30, 2003
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________
Commission file number 001-13781
KCS ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware 22-2889587
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5555 San Felipe Road, Houston, TX 77056
(Address of principal executive offices) (Zip Code)
(713) 877-8006
(Registrant's telephone number, including area code)
NOT APPLICABLE
- --------------------------------------------------------------------------------
(Former name, former address and former fiscal year, if changed since
last report.)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. |X| Yes |_| No
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). |_| Yes |X| 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.
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Common Stock, $0.01 par value: 38,286,414 shares outstanding as of August 12,
2003.
Item 1. Financial Statements.
KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
Three Months Ended Six Months Ended
June 30, June 30,
(Amounts in thousands except ----------------------- -----------------------
per share data) Unaudited 2003 2002 2003 2002
- ----------------------------------------------------------------- -------- -------- -------- --------
Oil and gas revenue $ 38,422 $ 30,808 $ 78,069 $ 60,165
Other revenue, net 4,310 (531) 5,103 (1,064)
- ---------------------------------------------------------------------------------------------------------------------------
Total revenue 42,732 30,277 83,172 59,101
- ---------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses
Lease operating expenses 6,693 6,873 13,024 13,409
Production taxes 1,468 1,632 3,761 2,955
General and administrative expenses 1,862 1,763 3,662 3,890
Stock compensation 257 194 411 510
Accretion of asset retirement obligation 279 -- 558 --
Depreciation, depletion and amortization 11,441 12,031 22,083 25,131
- ---------------------------------------------------------------------------------------------------------------------------
Total operating costs and expenses 22,000 22,493 43,499 45,895
- ---------------------------------------------------------------------------------------------------------------------------
Operating income 20,732 7,784 39,673 13,206
- ---------------------------------------------------------------------------------------------------------------------------
Interest and other income, net 75 9 102 79
Interest expense (4,588) (4,836) (9,202) (9,666)
- ---------------------------------------------------------------------------------------------------------------------------
Income before income taxes and cumulative effect of
accounting change 16,219 2,957 30,573 3,619
Federal and state income (taxes) benefit 11,082 (15,325) 11,564 (14,729)
- ---------------------------------------------------------------------------------------------------------------------------
Net income (loss) before cumulative effect of accounting change 27,301 (12,368) 42,137 (11,110)
Cumulative effect of accounting change, net of tax -- -- (934) (6,166)
- ---------------------------------------------------------------------------------------------------------------------------
Net income (loss) 27,301 (12,368) 41,203 (17,276)
Dividends and accretion of issuance costs on preferred stock (132) (372) (442) (625)
- ---------------------------------------------------------------------------------------------------------------------------
Income (loss) available to common stockholders $ 27,169 $(12,740) $ 40,761 $(17,901)
===========================================================================================================================
Earnings (loss) per share of common stock - basic
Before cumulative effect of accounting change $ 0.71 $ (0.36) $ 1.10 $ (0.34)
Cumulative effect of accounting change $ -- $ -- $ (0.02) $ (0.17)
- ---------------------------------------------------------------------------------------------------------------------------
Earnings (loss) per share of common stock - basic $ 0.71 $ (0.36) $ 1.08 $ (0.51)
===========================================================================================================================
Earnings (loss) per share of common stock - diluted
Before cumulative effect of accounting change $ 0.66 $ (0.36) $ 1.02 $ (0.34)
Cumulative effect of accounting change $ -- $ -- $ (0.02) $ (0.17)
- ---------------------------------------------------------------------------------------------------------------------------
Earnings (loss) per share of common stock - diluted $ 0.66 $ (0.36) $ 1.00 $ (0.51)
===========================================================================================================================
Average shares outstanding for computation of earnings per share
Basic 38,227 35,674 37,833 35,332
Diluted 41,531 35,674 41,295 35,332
===========================================================================================================================
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, June 30, December 31,
except share and per share data) Unaudited 2003 2002
- ----------------------------------------------------------------------- --------- ------------
Assets
Current assets
Cash and cash equivalents $ 2,301 $ 6,935
Trade accounts receivable, less allowance
for doubtful accounts-2003 $4,692; 2002 $4,678 24,169 16,863
Prepaid drilling 5,615 1,362
Other current assets 1,400 2,034
- ------------------------------------------------------------------------------------------------------------
Current assets 33,485 27,194
- ------------------------------------------------------------------------------------------------------------
Oil and gas properties, full cost method, less accumulated
DD&A-2003 $908,368; 2002 $891,124 259,318 231,579
Other property, plant and equipment at cost less accumulated
depreciation; 2003 $10,999; 2002 $10,415 8,423 8,715
- ------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net 267,741 240,294
- ------------------------------------------------------------------------------------------------------------
Deferred charges and other assets
Deferred taxes 11,160 --
Other 3,391 645
- ------------------------------------------------------------------------------------------------------------
Deferred charges and other assets 14,551 645
- ------------------------------------------------------------------------------------------------------------
Total Assets $ 315,777 $ 268,133
============================================================================================================
Liabilities and stockholders' equity (deficit)
Current liabilities
Accounts payable $ 35,479 $ 23,854
Accrued interest 6,288 8,174
Accrued drilling cost 8,913 2,861
Other accrued liabilities 8,649 8,784
- ------------------------------------------------------------------------------------------------------------
Current liabilities 59,329 43,673
- ------------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities
Deferred revenue 51,385 66,582
Asset retirement obligation 11,608 --
Other 929 961
- ------------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities 63,922 67,543
- ------------------------------------------------------------------------------------------------------------
Long-term debt
Credit facility 54,000 500
Senior notes -- 61,274
Senior subordinated notes 125,000 125,000
- ------------------------------------------------------------------------------------------------------------
Long-term debt 179,000 186,774
- ------------------------------------------------------------------------------------------------------------
Commmitments and contingencies
Preferred stock, authorized 5,000,000 shares, issued 30,000 shares
redeemable convertible preferred stock, par value $0.01 per share,
liquidation preference $1,000 per share - 9,388 and
13,288 shares outstanding, respectively 9,116 12,859
- ------------------------------------------------------------------------------------------------------------
Stockholders' equity (deficit)
Common stock, par value $0.01 per share,
authorized 75,000,000 shares, issued 40,419,367
and 38,611,816, respectively 404 386
Additional paid-in capital 172,550 167,335
Accumulated deficit (155,554) (196,315)
Unearned compensation (1,243) (880)
Accumulated other comprehensive income (7,006) (8,501)
Less treasury stock, 2,167,096 shares, at cost (4,741) (4,741)
- ------------------------------------------------------------------------------------------------------------
Total stockholders' equity (deficit) 4,410 (42,716)
- ------------------------------------------------------------------------------------------------------------
Total liabilities and stockholders' equity (deficit) $ 315,777 $ 268,133
============================================================================================================
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
Six Months Ended
June 30,
-----------------------
(Dollars in thousands) Unaudited 2003 2002
- --------------------------------------------------------- -------- --------
Cash flows from operating activities:
Net income (loss) $ 41,203 $(17,276)
Non-cash charges (credits):
Depreciation, depletion and amortization 22,083 25,131
Amortization of deferred revenue (15,197) (24,343)
Non-cash derivative losses, net 2,756 2,138
Deferred income taxes (benefit) (11,965) 14,729
Cumulative effect of accounting change 934 6,166
Accretion of asset retirement obligation 558 --
Other non-cash charges and credits, net 917 510
Net changes in assets and liabilities:
Change in trade accounts receivable (7,328) (3,067)
Change in accounts payable and accrued liabilities 11,793 (4,484)
Change in accrued interest payable (1,886) (841)
Other, net (261) 1,262
- -----------------------------------------------------------------------------------------
Net cash provided by (used in) operating activities 43,607 (75)
- -----------------------------------------------------------------------------------------
Cash flows from investing activities:
Investment in oil and gas properties (36,845) (26,201)
Proceeds from sales of oil and gas properties (130) 24,674
Other capital expenditures (292) (34)
- -----------------------------------------------------------------------------------------
Net cash used in investing activities (37,267) (1,561)
- -----------------------------------------------------------------------------------------
Cash flows from financing activities:
Proceeds from borrowings 69,295 10,800
Repayments of debt (77,069) (18,526)
Deferred financing costs and other, net (3,200) --
- -----------------------------------------------------------------------------------------
Net cash used in financing activities (10,974) (7,726)
- -----------------------------------------------------------------------------------------
Decrease in cash and cash equivalents (4,634) (9,362)
Cash and cash equivalents at beginning of period 6,935 22,927
- -----------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 2,301 $ 13,565
=========================================================================================
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
(Amounts in thousands)
Accumulated
Additional Other
Common Paid-in Accumulated Comprehensive
Unaudited Stock Capital Deficit Income
- --------------------------------------------------- ---------- ----------- -------------
Balance at December 31, 2002 $ 386 $167,335 $(196,315) $(8,501)
Comprehensive income
Net income -- -- 41,203 --
Commodity hedges, net of tax -- -- -- 1,495
Comprehensive income
Conversion of redeemable
preferred stock 13 3,887 -- --
Stock issuances - benefit plans and
awards of restricted stock 4 1,127 -- --
Stock compensation expense -- 36 -- --
Dividends and accretion of issuance
costs on preferred stock 1 165 (442) --
------- -------- --------- -------
Balance at June 30, 2003 $ 404 $172,550 $(155,554) $(7,006)
======= ======== ========= =======
Total
Stockholders'
Unearned Treasury Comprehensive (Deficit)
Unaudited Compensation Stock Income Equity
- ------------------------------------------- ------------ -------- ------------- -------------
Balance at December 31, 2002 $ (880) $(4,741) $(42,716)
Comprehensive income
Net income -- -- $ 41,203 41,203
Commodity hedges, net of tax -- -- 1,495 1,495
--------
Comprehensive income $ 42,698
========
Conversion of redeemable
preferred stock -- -- 3,900
Stock issuances - benefit plans and
awards of restricted stock (738) -- 393
Stock compensation expense 375 -- 411
Dividends and accretion of issuance
costs on preferred stock -- -- (276)
------- ------- ---------
Balance at June 30, 2003 $(1,243) $(4,741) $ 4,410
======= ======= =========
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. The condensed consolidated interim financial statements included herein have
been prepared by KCS Energy, Inc. ("KCS" or "Company"), without audit, pursuant
to the rules and regulations of the Securities and Exchange Commission ("SEC")
and reflect all adjustments which are of a normal recurring nature and which are
in the opinion of management, necessary to 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, 2002. Certain previously reported amounts have been reclassified to
conform with current period presentations.
2. New Accounting Principles
Effective January 1, 2003, the Company adopted Financial Accounting Standards
Board Statement No. 143, "Accounting for Asset Retirement Obligations" ("SFAS
No. 143"). SFAS No. 143 requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the periods in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of the
related long-lived asset. The liability is accreted to the fair value at the
time of settlement over the useful life of the asset, and the capitalized cost
is depreciated over the useful life of the related asset. Upon adoption of SFAS
No. 143, the Company's net property, plant and equipment was increased by $10.2
million, an additional asset retirement obligation of $11.1 million (primarily
for plugging and abandonment costs of oil and gas wells) was recorded and a $0.9
million charge, net of tax against net income (or a $0.02 loss per basic and
diluted share) was reported in the first quarter of 2003 as a cumulative effect
of a change in accounting principle. Subsequent to adoption, the effect of the
change in accounting principle in the first six months of 2003 was a immaterial.
Had the provisions of SFAS No. 143 been applied as of January 1, 2002, the
asset retirement obligation would have been $10.1 million. The following table
illustrates the pro forma effect on net loss available to common stockholders
and loss per share if the Company had applied the provisions of SFAS No. 143
during the first half of 2002:
For the For the
Quarter Ended Six Months Ended
(Amounts in thousands, except per share data) June 30, 2002 June 30, 2002
- --------------------------------------------- ------------- ----------------
Loss available to common stockholders
As reported $ (12,740) $ (17,901)
Pro forma (12,865) (18,159)
Loss per share
Basic - as reported $ (0.36) $ (0.51)
Basic - pro forma $ (0.36) $ (0.51)
Diluted - as reported $ (0.36) $ (0.51)
Diluted - pro forma $ (0.36) $ (0.51)
Effective January 1, 2002, the Company began amortizing the capitalized
costs related to oil and gas properties on the unit-of-production basis ("UOP")
using proved oil and gas reserves. Previously, the
5
Company had computed amortization on the basis of future gross revenues ("FGR").
The Company determined that the change to UOP was preferable under accounting
principles generally accepted in the United States, since among other reasons,
it provides a more rational basis for amortization during periods of volatile
commodity prices and also increases consistency with others in the industry. As
a result of this change, the Company recorded a non-cash cumulative effect
charge of $6.2 million, net of tax, (or $0.17 per basic and diluted common
share) in the first quarter of 2002.
In January 2003, the Financial Accounting Standards Board ("FASB") issued
Interpretation No. 46, "Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51." Interpretation No. 46
requires a company to consolidate a variable interest entity ("VIE") if the
company has a variable interest (or combination of variable interests) that is
exposed to a majority of the entity's expected losses if they occur, receives a
majority of the entity's expected residual returns if they occur, or both. In
addition, more extensive disclosure requirements apply to the primary and other
significant variable interest owners of the VIE. This interpretation applies
immediately to VIEs created after January 31, 2003, and to VIEs in which an
enterprise obtains an interest after that date. It is also effective for the
first fiscal year or interim period beginning after June 15, 2003, to VIEs in
which a company holds a variable interest that is acquired before February 1,
2003. The guidance regarding this interpretation is extremely complex and,
although we do not believe we have an interest in a VIE, the Company continues
to assess the impact, if any, this interpretation will have on the Company's
consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." SFAS
No. 150 establishes standards on how the Company classifies and measures certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that the Company classify as liabilities the fair value of
all mandatorily redeemable financial instruments that had previously been
recorded as equity or elsewhere in the consolidated financial statements. This
statement is effective for financial instruments entered into or modified after
May 31, 2003, and is otherwise effective for all existing financial instruments
beginning in the third quarter of 2003. SFAS No. 150 will not have an impact on
the Company's classification of its convertible preferred stock because the
convertible preferred stock is not mandatorily redeemable as defined by SFAS No.
150.
SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and
Intangible Assets", were issued in June 2001 and became effective July 1, 2001
and January 1, 2002, respectively. It is the Company's understanding that the
SEC has questioned other public companies as to whether they properly adopted
the provisions of SFAS No. 141 and SFAS No. 142, with respect to how the costs
of acquiring contractual mineral interests in oil and gas properties should be
classified on the balance sheet. It is also the Company's understanding that the
FASB, the SEC and others are engaged in deliberations on the issue of whether
SFAS No. 141 and SFAS No. 142 require that interests held under oil, gas and
mineral leases or other contractual arrangements be classified as intangible
assets or as oil and gas properties. If such interests were deemed intangible
assets, mineral interests for undeveloped and developed leaseholds would be
classified separately from oil and gas properties on the balance sheet but would
be aggregated with oil and gas properties in the Notes to Consolidated Financial
Statements in accordance with SFAS No. 69, "Disclosures about Oil and Gas
Producing Activities. Historically, the Company has included all oil and gas
leasehold interests as part of oil and gas properties. Because this issue is
being deliberated and is unresolved, the Company continues to include mineral
interests as oil and gas properties on its balance sheet.
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
6
generate in the future. Accordingly, while the Company's current net operating
loss carryforwards have remaining lives ranging from 9 1/2 to 19 1/2 years (with
the majority having a life in excess of 15 years), management looks at 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.
During the second quarter of 2002, uncertainty resulting from relatively
low commodity prices and the January 2003 maturity date for the Company's Senior
Notes led management to establish a valuation allowance against all of the
Company's deferred tax assets. Since that time, the future outlook for taxable
income has improved significantly. The Company successfully negotiated an
amended and restated credit agreement, allowing it to repay the Senior Notes.
Furthermore, oil and natural gas prices have improved significantly and are
expected to remain relatively high for the foreseeable future based on existing
available information, including current prices quoted on the New York
Mercantile Exchange. Therefore, during the second quarter of 2003, the Company
reversed approximately $11 million the valuation allowance related to expected
taxes on future year's taxable income, which is reflected as an income tax
benefit in the condensed statement of consolidated operations.
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) (the "Production
Payment"). Net proceeds from the Production Payment of approximately $175
million were recorded as deferred revenue on the Company's balance sheet. In
accordance with Financial Accounting Standards Board Statement No. 19 "Financial
Accounting and Reporting by Oil and Gas Producing Companies," 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 six months ended June 30, 2003, the Company
delivered 3.7 Bcfe and recorded $15.2 million of oil and gas revenue. Since the
sale of the Production Payment in February 2001 through June 30, 2003, the
Company has delivered 30.6 Bcfe, or 71% of the total quantity to be delivered.
5. Redeemable Convertible Preferred Stock
As a result of conversions of the redeemable convertible preferred stock
issued in 2001, 1.3 million shares of common stock were issued in the six months
ended June 30, 2003.
7
6. Earnings Per Share
The following table sets forth the computation of basic and diluted
earnings per share:
Three months ended Six months ended
June 30, June 30,
(Amounts in thousands, ---------------------- ----------------------
except per share data) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------- ----------------------
Basic earnings (loss) per share:
Income (loss) available to common stockholders $ 27,169 $(12,740) $ 40,761 $(17,901)
---------------------- ----------------------
Average shares of common stock outstanding 38,227 35,674 37,833 35,332
---------------------- ----------------------
Basic earnings (loss) per share $ 0.71 $ (0.36) $ 1.08 $ (0.51)
====================== ======================
Diluted earnings (loss) per share:
Income (loss) available to common stockholders $ 27,169 $(12,740) $ 40,761 $(17,901)
Dividends and accretion of issuance
costs on preferred stock 132 N/A 442 N/A
---------------------- ----------------------
Diluted earnings (loss) $ 27,301 $(12,740) $ 41,203 $(17,901)
---------------------- ----------------------
Average shares of common stock outstanding 38,227 35,674 37,833 35,332
Assumed conversion of convertible
preferred stock 3,129 N/A 3,346 N/A
Stock options and warrants 175 N/A 116 N/A
---------------------- ----------------------
Average diluted shares of common stock outstanding 41,531 35,674 41,295 35,332
---------------------- ----------------------
Diluted earnings (loss) per share $ 0.66 $ (0.36) $ 1.00 $ (0.51)
====================== ======================
Common shares on assumed conversion of convertible preferred stock
amounting to 5.0 million shares for the three months ended June 30, 2002 and 5.1
million shares for the six months ended June 30, 2002 were not included in the
computations of diluted loss per common share nor were assumed conversion of
dividends on convertible preferred stock or stock options and warrants since
they would be anti-dilutive.
7. Derivatives
Oil and gas prices have historically been volatile. The Company has at
times utilized derivative contracts, including swaps, futures contracts, options
and collars to manage this price risk.
Commodity Price Swaps. Commodity price swap agreements require the Company
to make or receive payments from the counterparties 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 counterparty to buy oil or natural gas at a future time
at a fixed price.
Option Contracts. Option contracts provide the right, not the obligation,
to buy or sell a commodity at a fixed price. By buying a "put" option, the
Company is able to set a floor price for a specified quantity of its oil or gas
production. By selling a "call" option, the Company receives an upfront premium
from selling the right for a counterparty to buy a specified quantity of oil or
gas production at a fixed price.
Price Collars. Selling a call option and buying a put option creates a
"collar" whereby the Company establishes a floor and ceiling price for a
specified quantity of future production. Buying a call option with a
8
strike price above the sold call strike price establishes a "3-way collar" that
entitles the Company to capture the benefit of price increases above that call
price.
In 2003, the Company entered into a series of derivative transactions
designed to protect a portion of the Company's oil and gas production against
possible declines in natural gas prices while enabling the Company to benefit
from price increases. At June 30, 2003, the Company had derivative instruments
covering 4.1 million Mmbtu of gas production for July 2003 through March 2004.
These instruments established an average floor price of $4.44 and enable the
Company to receive market prices up to an average cap of $7.04, approximately
20% of any price between $7.04 and $7.54 and 100% of any price above $7.54. The
following table sets forth the Company's oil and natural gas hedged position at
June 30, 2003.
Expected Maturity
-------------------------------------------------------------
2003 2004 Fair
---------------------------------------------- ---------- Value
3nd Quarter 4th Quarter Total 1st Quarter ($000)
----------- ----------- ----- ----------- ------
Swaps: $ (6)
Volumes (bbl) 7,700 -- 7,700 --
Weighted average price ($/bbl) $ 30.00 $ -- $ 30.00 $ --
Puts / Floors: $ 36
Volumes (Mmbtu) 460,000 305,000 765,000 --
Weighted average price ($/Mmbtu) $ 4.25 $ 4.25 $ 4.25 $ --
3-way collars: $ 252
Volumes (MMbtu) 1,075,000 1,380,000 2,595,000 910,000
Weighted average price ($/Mmbtu)
Floor (purchased put option) $ 4.47 $ 4.47 $ 4.47 $ 4.50
Cap 1 (sold call option) $ 5.76 $ 7.08 $ 6.50 $ 8.50
Cap 2 (purchased call option) $ 6.26 $ 7.58 $ 7.00 $ 9.00
In addition to the above, the Company has entered into fixed price sales
contracts covering 0.2 million Mmbtu at an average price of $5.30 for July
through August 2003 and will deliver 3.1 Bcfe for July through December 2003,
5.2 Bcfe in 2004, 3.9 Bcfe in 2005 and 0.3 Bcfe in 2006 under the Production
Payment sold in February 2001 at an average price of $4.05 per Mcfe. The fixed
price sales contracts are normal sales pursuant to SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities". Accordingly, the Company has
designated and accounted for these contracts under the accrual method.
During 2001, the Company terminated certain derivative contracts that were
in place at the companies acquired in the 1996 acquisition known as the
"Medallion Acquisition" and has been amortizing the loss accumulated in other
comprehensive income ("OCI") into earnings over the original term of the
derivative instruments. During the first six months of 2003, $1.8 million, net
of tax, charged to OCI was reclassified as a reduction of oil and gas revenues.
As of June 30, 2003, $6.7 million, net of tax, remains in accumulated other
comprehensive income and will be amortized against earnings through 2005 ($1.8
million during the remainder of 2003, $2.9 million in 2004 and $2.0 million in
2005). During the first six months of 2003, $0.3 million, net of tax, of
unrealized derivative losses were charged to OCI which will be reclassified
against earnings within the current fiscal year. The ineffective portion of
these derivatives was immaterial in the first half of 2003.
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
paid (net of capitalized interest) for the six months ended June 30, 2003 was
$10.5 million. An income tax payment of $0.4 million was made in the six-month
period ended June 30, 2003 while no income tax was paid in the six-month period
ended June 30, 2002.
9
In connection with the adoption of SFAS No. 143, the Company recorded a
non-cash increase to oil and gas properties of $10.2 million, a non-cash
increase in liabilities of $11.1 million and a non-cash charge of $0.9 million
as a cumulative effect of accounting change. During the six months ended June
30, 2003 non-cash additions to oil and gas properties as a result of recognizing
asset retirement obligations for new wells under SFAS No. 143 was $0.3 million.
Other non-cash additions to oil and gas properties netted to $1.8 million with
increases in accrued drilling costs offset by increased prepaid drilling costs.
9. Credit Agreement
On January 14, 2003, the Company amended and restated its credit agreement
(the "Credit Agreement") with a group of institutional lenders. The Credit
Agreement, which matures on October 3, 2005, provides up to $90.0 million of
borrowing capacity, $40.0 million in the form of a term loan, a $30.0 million
revolving "A" facility and a $20.0 million revolving "B" facility. Borrowing
capacity is subject to monthly borrowing base calculations with respect to the
value of the Company's oil and gas assets. Initial proceeds of $69.3 million
were used primarily to pay off the Company's maturing Senior Note obligations.
The term loan and the revolving "B" facility, which may be prepaid at any time
without penalty, bear interest based on the prime rate, initially equating to
9.0%, and increasing annually. The revolving "A" facility bears, at the
Company's option, an interest rate of LIBOR plus 2.75% to 3.0% or prime plus
0.5% to 0.75%, depending on utilization. On June 30, 2003, $54.0 million was
outstanding under the Credit Agreement, the weighed average interest rate was
7.8% and $34.0 million was available for additional Company borrowings. The
revolving "A" facility requires a commitment fee of 0.5% per annum on the unused
availability and carries an early termination penalty of 1.5% in the first year
and 1% in the second year. Financing fees associated with the Credit Agreement
have been recorded as deferred charges and are being amortized as interest
expense over the life of the Credit Agreement. Certain other fees are also
payable under the Credit Agreement based on services provided. Substantially all
of the Company's assets are pledged to secure the Credit Agreement.
The Credit Agreement contains various restrictive covenants including
ratios of debt to EBITDA, interest coverage, fixed charge coverage and
liquidity. The Credit Agreement also contains provisions that require the
hedging of a portion of the Company's oil and gas production, payment upon a
change of control, restrictions on the payment of dividends and certain other
restricted payments and places limitations on the incurrence of additional debt,
capital expenditures, the sale of assets, and the repurchase of Senior
Subordinated Notes. Any repayment made on the term loan portion of the facility
will permanently reduce the funds available under the Credit Agreement. The
Credit Agreement also contains cross-default provisions, which would result in
the acceleration of payments if the Company defaults on its other debt
instruments.
10. Stock Compensation
As permitted under 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 records no 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
(loss) available to common stockholders and earnings (loss) per share if the
Company had applied the fair value recognition provision of SFAS No. 123 to
stock options.
10
For the Three Months Ended For the Six Months Ended
June 30, June 30,
(Amounts in thousands, except --------------------------- ---------------------------
per share data) 2003 2002 2003 2002
- -------------------------------------- ---------- ---------- ---------- ----------
Income (loss) available to common
stockholders, as reported $ 27,169 $ (12,740) $ 40,761 $ (17,901)
Add: Stock-based compensation expense
included in reported net income 257 194 411 510
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for
all awards (532) (512) (943) (904)
---------- ---------- ---------- ----------
Pro forma income (loss) available to
common stockholders $ 26,894 $ (13,058) $ 40,229 $ (18,295)
========== ========== ========== ==========
Earnings (loss) per share:
Basic - as reported $ 0.71 $ (0.36) $ 1.08 $ (0.51)
Basic - pro forma $ 0.70 $ (0.37) $ 1.06 $ (0.52)
Diluted - as reported $ 0.66 $ (0.36) $ 1.00 $ (0.51)
Diluted - pro forma $ 0.65 $ (0.37) $ 0.98 $ (0.52)
11. Litigation
Environmental Suits
The Company was a defendant in a lawsuit originally brought by InterCoast
Energy Company and MidAmerican Capital Company ("Plaintiffs") against KCS
Energy, Inc., KCS Medallion Resources, Inc. and Medallion California Properties
Company ("KCS Defendants"), and Kerr-McGee Oil & Gas Onshore LP and Kerr-McGee
Corporation ("Kerr-McGee Defendants") in the 234th Judicial District Court of
Harris County, Texas under Cause Number 1999-45998. The suit sought a
declaratory judgment declaring the rights and obligations of each of the
Plaintiffs, the KCS Defendants and the Kerr-McGee Defendants in connection with
environmental damages and surface restoration on lands located in Los Angeles
County, California which are covered by an Oil & Gas Lease dated June 13, 1935,
from Newhall Land and Farming Company, as Lessor, to Barnsdall Oil Company, as
Lessee (the "RSF Lease") and by an Oil and Gas Lease dated June 6, 1941, from
the Newhall Corporation, as Lessor, to C. G. Willis, as Lessee (the "Ferguson
Lease" and together with the RSF Lease, the "Leases").
The Kerr-McGee Defendants, KCS Defendants and Plaintiffs entered into an
Agreed Interlocutory Judgment that contains clarification of the language of the
1990 agreement between predecessors of the KCS Defendants and the Kerr-McGee
Defendants (the "1990 Agreement") under which the Leases were transferred from
Kerr-McGee's predecessor to predecessors of Medallion California Properties
Company ("MCPC"). The Court previously entered the Agreed Interlocutory
Judgment, which essentially disposed of interpretation questions concerning the
1990 Agreement. After entry of the Agreed Interlocutory Judgment, the remaining
issues in the case concerned the interpretation of the 1996 Stock Purchase
Agreement through which certain of the KCS Defendants acquired the stock of
MCPC. Specifically, the remaining issues involved the extent to which Plaintiffs
are obligated to indemnify the KCS Defendants for environmental investigation
costs previously incurred by the KCS Defendants and also for costs of defense
and liability to the KCS Defendants, if any, in the California litigation
described below. By Compromise and Settlement Agreement dated as of October 19,
2001, the Plaintiffs and KCS Defendants agreed: (i) to settle those issues
dealing with the Plaintiffs' obligations to reimburse costs previously incurred
in connection with defense of the California case described below; (ii) to
provide prospectively for the control of defense and settlement and the sharing
of
11
defense costs in the California case described below; and (iii) to defer any
disputes concerning the respective liability of Plaintiffs and KCS Defendants
for any individual claims until the extent of such individual claim liability,
after giving effect to indemnification obligations under the 1990 Agreement, is
fully and finally determined. The Agreed Interlocutory Judgment has now been
entered as a final judgment.
MCPC is a defendant in a lawsuit filed January 30, 2001, by The Newhall
Land and Farming Company ("Newhall") against MCPC and Kerr-McGee Corporation and
several Kerr-McGee affiliates. The case is currently pending in Los Angeles
County Superior Court under Cause Number BC244203. In the suit, Newhall seeks
damages for alleged environmental contamination and surface restoration on the
lands covered by the RSF Lease and also seeks a declaration that Newhall may
terminate the RSF Lease or alternatively, that it may terminate those portions
of the RSF Lease on which there is currently default under the Lease. MCPC
claims that Newhall is not entitled to lease termination as a remedy and that
Kerr-McGee and InterCoast and MidAmerican owe indemnities to MCPC for defense
and certain potential liability under Newhall's action, all as more particularly
described in the Harris County, Texas litigation described above. The lawsuit
was set for trial in May, 2003. On the eve of trial, the parties agreed to
engage in settlement negotiations under the Court's supervision. Tentative
settlement terms were agreed to at the end of May, but definitive settlement
documents have not been agreed to and negotiations are continuing. The Company
is unable to predict the outcome of the settlement negotiations.
Other
The Company and several of its subsidiaries have been named as
co-defendants along with numerous other industry parties in an action brought by
Jack Grynberg on behalf of the Government of the United States. The complaint,
filed under the Federal False Claims Act, alleges underpayment of royalties to
the Government of the United States as a result of alleged mismeasurement of the
volume and wrongful analysis of the heating content of natural gas produced from
federal and Native American lands. The complaint is substantially similar to
other complaints filed by Jack Grynberg on behalf of the Government of the
United States against multiple other industry parties. All of the complaints
have been consolidated in one proceeding. In April 1999, the Government of the
United States filed notice that it had decided not to intervene in these
actions. The Company believes that the allegations in the complaint are without
merit.
The Company is also a party to various other lawsuits and governmental
proceedings, all arising in the ordinary course of business. Although the
outcome of all of the above proceedings cannot be predicted with certainty,
management does not expect such matters to have a material adverse effect,
either singly or in the aggregate, on the financial position or results of
operations of the Company. It is possible, however, that charges could be
required that would be significant to the operating results during a particular
period.
12. Comprehensive Income
The following table presents the components of comprehensive income (loss)
for the three months and six months ended June 30, 2003 and 2002.
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
(Amounts in thousands) 2003 2002 2003 2002
- ---------------------- ---- ---- ---- ----
Net income (loss) $ 27,301 $(12,368) $ 41,203 $(17,276)
Commodity hedges,
net of tax 700 1,776 1,495 1,673
-------- -------- -------- --------
Comprehensive income (loss) $ 28,001 $(10,592) $ 42,698 $(15,603)
======== ======== ======== ========
12
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
The following is a discussion and analysis of our financial condition and
results of operations and should be read in conjunction with the unaudited
condensed consolidated financial statements (including the notes thereto)
included elsewhere in this Form 10-Q.
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 fact, included
herein concerning, among other things, planned capital expenditures, increases
in oil and gas production, the number of anticipated wells to be drilled after
the date hereof, the Company's financial position, business strategy and other
plans and objectives for future operations, are forward-looking statements.
These forward-looking statements are identified by their use of terms and
phrases such as "expect," "estimate," "project," "plan," "believe,"
"achievable," "anticipate" and similar terms and phrases. Although the Company
believes that the expectations reflected in such forward-looking statements are
reasonable, they do involve certain assumptions, risks and uncertainties, and
the Company can give no assurance that such expectations will prove to be
correct. The Company's actual results could differ materially from those
anticipated in these forward-looking statements as a result of certain factors,
including:
- the timing and success of the Company's drilling activities;
- the volatility of prices and supply of and demand for oil and gas;
- the numerous uncertainties inherent in estimating quantities of oil
and gas reserves and actual future production rates and associated
costs;
- the usual hazards associated with the oil and gas industry
(including blowouts, cratering, pipe failure, spills, explosions and
other unforeseen hazards);
- changes in regulatory requirements; or
- if underlying assumptions prove incorrect.
These and other risks are described in greater detail in "Oil and Gas Risk
Factors" included in the Company's Annual Report on Form 10-K for the year ended
December 31, 2002.
All forward-looking statements attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by such factors.
Other than required under the securities laws, the Company does not assume a
duty to update these forward-looking statements.
General
Our main objective in 2002 was to position the Company to meet the Senior
Note obligations due January 15, 2003. In order to meet this objective, we
curtailed our drilling and overall capital expenditure programs and sold certain
non-core assets. These actions positioned us to reduce debt and negotiate the
financing necessary to pay off the remaining portion of the maturing Senior
Notes during a difficult period in the capital markets. Although the asset sales
and curtailed drilling and capital expenditure programs resulted in lower
production and reserves in 2002, we exited the year in a stronger financial
position, with increased financial flexibility, a focused asset base in our core
areas, and a quality multi-year drilling prospect inventory.
On January 14, 2003, we completed the arrangements necessary to amend and
restate our existing credit agreement with a group of institutional lenders. The
amended facility provides $90.0 million of borrowing capacity, $40.0 million in
the form of a term loan and $50.0 million in the form of revolving
13
facilities, and matures on October 3, 2005. Initial proceeds of $69.3 million
were used primarily to pay off the balance of the maturing Senior Note
obligations, leaving $20.7 million of available borrowing capacity under the
facility.
With the completion of the financing, we accelerated our drilling program
in the first half of 2003 resulting in increased production and reserves. We
believe that the Company is positioned to capitalize on the current strong
natural gas price environment, to focus on developing our prospect inventory to
grow reserves and production in our core areas and to further reduce debt per
MCFE.
Prices for oil and natural gas are subject to wide fluctuations in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond our control. These factors include political conditions in the Middle
East and elsewhere, domestic and foreign supply of oil and natural gas, the
level of industrial and consumer demand, weather conditions and overall economic
conditions. Demand for natural gas and oil is seasonal, principally related to
weather conditions and access to pipeline transportation.
Results of Operations
Income before income taxes for the three months ended June 30, 2003 was
$16.2 million compared to $3.0 million for the three months ended June 30, 2002.
This increase was primarily attributable to higher natural gas and oil prices
and the $4.7 million sale of emission reduction credits, partially offset by
decreased oil and gas production due largely to the sale of certain non-core
properties in 2002. Income tax benefit for the three months ended June 30, 2003
was $11.1 million compared to income tax expense of $15.3 million for the same
period a year ago due to changes in our valuation allowance against net deferred
tax assets (see Note 3 to Condensed Consolidated Financial Statements). Income
available to common stockholders for the three months ended June 30, 2003 was
$27.2 million, or $0.71 per share ($0.66 per diluted share), compared to a loss
of $12.7 million, or $0.36 per basic and diluted share for the three months
ended June 30, 2002.
Income before income taxes and cumulative effect of accounting change for
the six months ended June 30, 2003 was $30.6 million, compared to $3.6 million
for the six months ended June 30, 2002. This increase was primarily attributable
to higher natural gas and oil prices and the sale of emission reduction credits,
partially offset by decreased oil and gas production due largely to the sale of
certain non-core properties in 2002. Income tax benefit for the six months ended
June 30, 2003 was $11.6 million compared to income tax expense of $14.7 million
for the same period in 2002 due to changes in our valuation allowance against
net deferred tax assets (see Note 3 to Condensed Consolidated Financial
Statements). The cumulative effect of an accounting change was $0.9 million, or
$0.02 per basic and diluted share for the six months ended June 30, 2003 as a
result of the adoption of Financial Accounting Standards Board Statement No.
143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). For the six
months ended June 30, 2002, the cumulative effect of accounting change was $6.2
million, or $0.17 per basic and diluted share which reflected the change from
the future gross revenue method of accounting for the amortization of
capitalized costs related to oil and gas properties to the unit-of-production
method. See Note 2 to Condensed Consolidated Financial Statements for more
information regarding these accounting changes. Income available to common
stockholders for the six months ended June 30, 2003 was $40.8 million, or $1.08
per share ($1.00 per diluted share), compared to a loss of $17.9 million, or
$0.51 per basic and diluted share, for the six months ended June 30, 2002.
The following table provides our volume and average prices for the three
and six month periods ended June 30, 2003 and 2002.
14
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
2003 2002 2003 2002
------- ------- ------- -------
Production: (a)
Gas (MMcf) 6,758 7,576 12,733 15,888
Oil (Mbbl) 213 260 428 528
Liquids (Mbbl) 58 71 105 142
Summary (MMcfe):
Working interest 8,381 8,912 15,933 18,382
VPP -- 646 -- 1,525
------- ------- ------- -------
Total 8,381 9,558 15,933 19,907
======= ======= ======= =======
Average Price: (b)
Gas (per Mcf) $ 4.81 $ 3.27 $ 5.14 $ 3.07
Oil (per bbl) 23.97 20.45 25.73 19.05
Liquids (per bbl) 14.15 10.10 15.56 9.56
Total (per Mcfe) 4.58 3.22 4.90 3.02
Oil and Gas Revenue:
Gas $32,504 $24,784 $65,415 $48,749
Oil 5,103 5,309 11,014 10,062
Liquids 815 715 1,640 1,354
------- ------- ------- -------
Total $38,422 $30,808 $78,069 $60,165
======= ======= ======= =======
Notes:
(a) Production includes 1,702 and 3,720 Mmcfe, respectively, for the three and
six months ended June 30, 2003 compared to 2,809 and 6,043 Mmcfe,
respectively, for the three and six months ended June 30, 2002, dedicated
to the Production Payment sold in February 2001. See Note 4 to Condensed
Consolidated Financial Statements.
(b) Includes the effects of the Production Payment sold in February 2001 and
hedging activities. See notes 4 and 7 to Condensed Consolidated Financial
Statements.
Gas revenue
For the three months ended June 30, 2003, gas revenue increased $7.7
million, to $32.5 million, from $24.8 million for the same period in 2002 due to
a 47% increase in average realized natural gas prices offset by an 11% decrease
in production. For the six months ended June 30, 2003, gas revenue increased
$16.7 million, to $65.4 million, from $48.7 million for the same period in 2002
due to a 67% increase in average realized gas prices offset by a 20% decrease in
production. The production decline in both periods was due to the sale of oil
and gas properties in 2002 and the expiration of certain VPPs.
Gas production in the second quarter of 2003 increased 13% to 6.8 bcf
compared to 6.0 bcf in the first quarter of 2003 reflecting our successful
drilling program.
15
Oil and liquids revenue
For the three months ended June 30, 2003, oil and liquids revenue
decreased $0.1 million, to $5.9 million, from $6.0 million for the same period
in 2002, due to a 20% increase in the weighted average price offset by lower
production. For the six months ended June 30, 2003, oil and liquids revenue
increased $1.3 million, to $12.7 million, from $11.4 million for the same period
in 2002 due to a 39% increase in the weighted average price offset by a 20%
decrease in production. The decrease in production in 2003 was primarily due to
the sale of oil and gas properties in 2002 and the natural declines of producing
properties.
Other revenue, net
Other revenue was $4.3 million for the three months ended June 30, 2003
compared to a net cost of $0.5 million for the same period a year ago. The
increase in other revenue was primarily related to the sale of emission
reduction credits. For the six months ended June 30, 2003, other revenue was
$5.1 million compared to a net cost of $1.1 million for the six months ended
June 30, 2003. The net cost in 2002 was primarily attributable to marketing and
transportation activities incidental to our oil and gas operations.
Lease operating expenses
Lease operating expenses decreased $0.2 million, to $6.7 million for the
three months ended June 30, 2003, from $6.9 million for the same period in 2002.
For the six months ended June 30, 2003, lease operating expense decreased $0.4
million, to $13.0 million, from $13.4 million for the same period in 2002.
Continued focus on operating efficiency along with the sale of certain
properties contributed to the current year reductions, partially offset by
increased workover activity on oil and gas wells during 2003.
Production taxes
Production taxes, which are generally based on a percentage of revenue
(excluding VPP revenue) decreased $0.1 million, to $1.5 million for the three
months ended June 30, 2003, from $1.6 million for the same period in 2002, as
the impact of higher oil and gas revenue was offset by $0.2 million of
production tax refunds and slightly lower production tax rates. For the six
months ended June 30, 2003, production taxes increased $0.8 million, to $3.8
million, from $3.0 million for the same period in 2002, primarily due to higher
oil and gas revenue associated with higher average realized prices.
General and administrative expenses
General and administrative ("G&A") expenses for the three months ended
June 30, 2003 were $1.9 million compared to $1.8 million for the same period in
2002. The increase was primarily due to higher incentive compensation expense
resulting from improved operating results. For the six months ended June 30,
2003, G&A expenses were $3.7 million compared to $3.9 million for the same
period in 2002. The decrease was primarily due to lower labor costs associated
with a reduced work force, partially offset by higher incentive compensation
expense resulting from improved operating results.
Stock compensation
Stock compensation reflects the non-cash amortization of restricted stock
grants and the "in the money" component of 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". For the
six-month period ended June 30, 2003, stock compensation was $0.4 million
compared to $0.5 million for the same period in 2002. The slight decrease was
associated with our reduction in work force.
Accretion of asset retirement obligation
Accretion of our asset retirement obligation was $0.3 million and $0.6
million for the three month and six month periods ended June 30, 2003,
respectively. Effective January 1, 2003, we adopted Financial
16
Accounting Standards Board Statement No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS No. 143"). See Note 2 to Condensed Consolidated Financial
Statements for more information regarding this accounting change.
Depreciation, depletion and amortization
Depreciation, depletion and amortization ("DD&A") expense for the three
months ended June 30, 2003, decreased $0.6 million, to $11.4 million, from $12.0
million for the same period in 2002. For the six months ended June 30, 2003,
DD&A decreased $3.0 million, to $22.1 million, from $25.1 million for the same
period in 2002. The decreases were primarily attributable to reduced production
as a result of the non-core property sales in 2002.
Interest expense
Interest expense for the three months ended June 30, 2003 was $4.6 million
compared to $4.8 million for the same period in 2002. For the six-month period
ended June 30, 2003, interest expense was $9.2 million compared to $9.7 million
for the same period in 2002. The decrease reflects lowering outstanding debt
and, to a lesser extent, lower interest rates on our Credit Agreement.
Income Taxes
For the six months ended June 30, 2003, income tax benefits were $11.6
million compared to an income tax expense of $14.7 million for the same period
in 2002.
We record deferred tax assets and liabilities to account for temporary
differences arising from events that have been recognized in our financial
statements and will result in future taxable or deductible items in our tax
returns. To the extent our deferred tax assets exceed deferred tax liabilities,
at least annually (and more frequently if events or circumstances change
materially), we assess the realizability of our net deferred tax assets. A
valuation allowance is recognized if, at the time, it is anticipated that some
or all of our net deferred tax assets may not be realized. See Note 3 to
Condensed Consolidated Financial Statements.
During the second quarter of 2002, we increased the valuation allowance on
the Company's deferred tax assets, which are primarily related to tax net
operating loss carryforwards, by $15.9 million, thereby reducing to zero the
carrying amount of net deferred tax assets with a corresponding non-cash charge
to income tax expense. In making that assessment, management considered several
factors, including future projections of taxable income, which reflected
relatively low natural gas and oil prices at that time, and the January 2003
maturity of the Company's Senior Note obligations that required refinancing.
In 2003, we negotiated and amended our credit agreement with a group of
institutional lenders and repaid the remaining Senior Note obligations. In
addition, natural gas and oil prices improved significantly and we generated
significant income in the first half of 2003 thereby utilizing a portion of our
deferred tax assets. As a result of the substantial improvement in our financial
condition and current and projected profitability levels over the next several
years, we reversed $11 million of our valuation allowance related to the tax
effects on future gross taxable income which is reflected as an income tax
benefit in the statement of operations for the second quarter of 2003.
Liquidity and Capital Resources
Our main objective in 2002 was to position the Company to meet the Senior
Note obligations due January 15, 2003. In order to meet this objective, we
curtailed our drilling and overall capital expenditure programs and sold certain
non-core assets. These actions positioned us to reduce debt and negotiate the
financing necessary to pay off the remaining portion of the maturing Senior
Notes during a difficult period in the capital markets. Although the asset sales
and curtailed drilling and capital expenditure programs resulted
17
in lower production and reserves in 2002, we exited the year in a stronger
financial position, with increased financial flexibility, a focused asset base
in our core areas, and a quality multi-year drilling prospect inventory.
On January 14, 2003, we completed the arrangements necessary to amend and
restate our existing credit agreement ("Credit Agreement") with a group of
institutional lenders. Initial proceeds of $69.3 million were used primarily to
pay off the balance of the maturing Senior Note obligations. On June 30, 2003,
$54.0 million was outstanding under the Credit Agreement, the weighted average
interest rate was 7.8% and $34.0 million was available for additional Company
borrowings.
With the completion of the financing, we accelerated our drilling program
in the first half of 2003 resulting in increased production and reserves. We
believe that the Company is positioned to capitalize on the current strong
natural gas price environment, to focus on developing our prospect inventory to
grow reserves and production in our core areas and to further reduce debt per
MCFE.
Cash flow from operating activities
Net cash provided by operating activities for the six months ended June
30, 2003 was $43.6 million compared to net cash used in operating activities of
$0.1 million during the same period in 2002. The improvement in our cash flow in
2003 was primarily due to higher realized oil and natural gas prices and
substantially less production dedicated to repayment of the production payment
discussed in Note 4 to Condensed Consolidated Financial Statements. The net
change in trade accounts receivable reflects the higher natural gas and oil
price environment in 2003 and the timing of cash receipts. The net change in
accounts payable and accrued liabilities was primarily attributable to the
significant increase in our drilling program in the current year.
Investing activities
For the six months ended June 30, 2003, net cash used in investing
activities was $37.3 million of which $36.8 million was invested in oil and gas
properties compared to net cash used in investing activities of $1.6 million for
the same period in 2002. For the 2002 six-month period, the Company invested
$26.2 million on oil and gas properties and sold $24.7 million of non-core
properties. We recently increased our 2003 budget for investments in oil and gas
properties from $55 million to $65 million.
KCS believes that cash on hand, net cash generated from operations and
unused committed borrowing capacity under the Credit Agreement will be adequate
to satisfy its liquidity needs. In the future, the Company may utilize various
financing sources including the issuance of debt or equity securities.
New Accounting Principles
Effective January 1, 2003, we adopted SFAS No. 143 which requires entities
to record the fair value of a liability for legal obligations associated with
the retirement obligations of tangible long-lived assets in the periods in which
it is incurred. When the liability is initially recorded, the entity increases
the carrying amount of the related long-lived asset. The liability is accreted
to the fair value at the time of settlement over the useful life of the asset,
and the capitalized cost is depreciated over the useful life of the related
asset. Upon adoption of SFAS No. 143, our net property, plant and equipment was
increased by $10.2 million, an additional asset retirement obligation of $11.1
million (primarily for plugging and abandonment costs of oil and gas wells) was
recorded and a $0.9 million charge, net of tax against net income (or a $0.02
loss per basic and diluted share) was reported in the first quarter of 2003 as a
cumulative effect of a change in accounting principle. Subsequent to adoption,
the effect of the change in accounting principle in the first six months of 2003
was a charge of $0.3 million, or $0.01 per basic and diluted share.
Effective January 1, 2002, we began amortizing the capitalized costs
related to oil and gas properties on the unit-of-production basis ("UOP") using
proved oil and gas reserves. Previously, we had computed amortization on the
basis of future gross revenue ("FGR"). The Company determined that the change to
UOP was preferable under accounting principles generally accepted in the United
States, since among other reasons, it provides a more rational basis for
amortization during periods of volatile commodity prices and also
18
increases consistency with others in the industry. As a result of this change,
we recorded a non-cash cumulative effect charge of $6.2 million, net of tax, (or
$0.17 per basic and diluted common share) in the first quarter of 2002.
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51." Interpretation No. 46 requires a company to consolidate a variable
interest entity ("VIE") if the company has a variable interest (or combination
of variable interests) that is exposed to a majority of the entity's expected
losses if they occur, receive a majority of the entity's expected residual
returns if they occur, or both. In addition, more extensive disclosure
requirements apply to the primary and other significant variable interest owners
of the VIE. This interpretation applies immediately to VIEs created after
January 31, 2003, and to VIEs in which an enterprise obtains an interest after
that date. It is also effective for the first fiscal year or interim period
beginning after June 15, 2003, to VIEs in which a company holds a variable
interest that is acquired before February 1, 2003. The guidance regarding this
interpretation is extremely complex and, although we do not believe we have an
interest in a VIE, the Company continues to assess the impact, if any, this
interpretation will have on the Company's consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." SFAS
No. 150 establishes standards on how the Company classifies and measures certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that the Company classify as liabilities the fair value of
all mandatorily redeemable financial instruments that had previously been
recorded as equity or elsewhere in the consolidated financial statements. This
statement is effective for financial instruments entered into or modified after
May 31, 2003, and otherwise effective for all existing financial instruments
beginning in the third quarter of 2003. SFAS No. 150 will not have an impact on
the Company's classification of its convertible preferred stock because the
convertible preferred stock is not mandatorily redeemable as defined by SFAS No.
150.
19
Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Derivative Instruments. The Company's major market risk exposure is to oil
and gas prices, which have historically been volatile. Realized prices are
primarily driven by the prevailing worldwide price for crude oil and regional
spot prices for natural gas production. The Company has utilized, and may
continue to utilize, derivative contracts, including swaps, futures contracts,
options and collars to manage this price risk. See Note 7 to Condensed
Consolidated Financial Statements. While these derivative contracts are
structured to reduce the Company's exposure to decreases in the price associated
with the underlying commodity, they also limit the benefit the Company might
otherwise receive from any price increases.
At June 30, 2003, the Company had derivative instruments covering 4.1
million Mmbtu of gas production for July 2003 through March 2004. These
instruments established an average floor price of $4.44 and enable the Company
to receive market prices up to an average cap of $7.04, approximately 20% of any
price between $7.04 and $7.54 and 100% of any price above $7.54. The following
table sets forth the Company's oil and natural gas hedged position at June 30,
2003.
Expected Maturity
-------------------------------------------------------------
2003 2004 Fair
---------------------------------------------- ---------- Value
3nd Quarter 4th Quarter Total 1st Quarter ($000)
----------- ----------- ----- ----------- ------
Swaps: $ (6)
Volumes (bbl) 7,700 -- 7,700 --
Weighted average price ($/bbl) $ 30.00 $ -- $ 30.00 $ --
Puts / Floors: $ 36
Volumes (Mmbtu) 460,000 305,000 765,000 --
Weighted average price ($/Mmbtu) $ 4.25 $ 4.25 $ 4.25 $ --
3-way collars: $ 252
Volumes (MMbtu) 1,075,000 1,380,000 2,445,000 910,000
Weighted average price ($/Mmbtu)
Floor (purchased put option) $ 4.47 $ 4.47 $ 4.47 $ 4.50
Cap 1 (sold call option) $ 5.76 $ 7.08 $ 6.50 $ 8.50
Cap 2 (purchased call option) $ 6.26 $ 7.58 $ 7.00 $ 9.00
In addition to the above, the Company has entered into fixed price sales
contracts covering 0.3 million Mmbtu at an average price of $5.30 for July
through August 2003 and will deliver 3.1 Bcfe for July through December 2003,
5.2 Bcfe in 2004, 3.9 Bcfe in 2005 and 0.3 Bcfe in 2006 under the Production
Payment sold in February 2001 at an average price of $4.05 per Mcfe.
Interest Rate Risk. The Company uses fixed and variable rate long-term
debt to finance its capital spending program and for general corporate purposes.
These variable rate debt instruments expose the Company to market risk related
to changes in interest rates. The Company's fixed rate debt and the associated
weighted average interest rate was $125.0 million at 8.9% on June 30, 2003 and
$195.9 million at 9.6% on June 30, 2002. The Company's variable rate debt and
weighted average interest rate was $54.0 million at 7.8% on June 30, 2003 and
$12.0 million at 4.2% on June 30, 2002.
20
Item 4. Controls and Procedures.
We carried out an evaluation, under the supervision and with the
participation of our management, including our Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the design and operation of our
disclosure controls and procedures, as of the end of the period covered by this
report, pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, our
Chief Executive Officer and Chief Financial Officer concluded that our
disclosure controls and procedures are effective in timely alerting them to
material information relating to us (including our consolidated subsidiaries)
required to be included in our periodic Exchange Act reports. There have been no
changes in our internal control over financial reporting that occurred during
our most recent fiscal quarter that have materially affected, or are likely to
materially affect, our internal control over financial reporting.
21
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
Reference is made to Note 11 to Condensed Consolidated Financial
Statements included herein.
Item 4. Submission of Matters to a Vote of Security Holders.
The Company held its Annual Meeting of Stockholders on May 27, 2003 in
Houston, Texas. All nominated directors were elected and will serve a three-year
term expiring in 2006.
(a) Directors elected at the Annual Meeting:
Votes in Favor Votes Withheld
William N. Hahne 33,750,327 90,140
James L. Bowles 33,750,161 90,306
(b) Directors with terms of office continuing after the Annual Meeting:
Directors with terms expiring in 2004
-------------------------------------
G. Stanton Geary
Robert G. Reynolds
Directors with terms expiring in 2005
-------------------------------------
James W. Christmas
Joel D. Siegel
Christopher A. Viggiano
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
3.1 Amendments to Restated By-Laws of KCS Energy, Inc.
effective April 22, 2003.
10.1 First, Second and Third Amendments to the Amended and
Restated Credit Agreement by and among KCS Energy, Inc.,
the lenders from time to time hereto, Foothill Capital
Corporation, as collateral and administrative agent, and
Highbridge/ Zwirn Special Opportunities Fund, L.P., as
lead arranger.
10.2 Change on Control Agreement between KCS Energy, Inc. and
Joseph T. Leary.
10.3 Change in Control Agreement between KCS Energy, Inc. and
Frederick Dwyer.
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.
(b) Reports on Form 8-K.
The Company furnished a report on Form 8-K on April 4, 2003 under
Item 9 reporting the issuance of a press release announcing the
Company's 2002 fourth quarter and full year operating and financial
results.
The Company furnished a report on Form 8-K on May 13, 2003 under
Item 12, Results of Operations and Financial Condition, reporting
the issuance of a press release announcing the Company's first
quarter 2003 operational and financial results.
22
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.
August 14, 2003 By: /S/ FREDERICK DWYER
------------------------------
Frederick Dwyer
Vice President, Controller
and Secretary
Exhibit Index
Exhibit
No. Description
------ -----------------
3.1 Amendments to Restated By-Laws of KCS Energy, Inc. effective
April 22, 2003.
10.1 First, Second and Third Amendments to the Amended and Restated
Credit Agreement by and among KCS Energy, Inc., the lenders
from time to time hereto, Foothill Capital Corporation, as
collateral and administrative agent, and Highbridge/Zwirn
Special Opportunities Fund, L.P., as lead arranger.
10.2 Change in Control Agreement between KCS Energy, Inc. and
Joseph T. Leary.
10.3 Change in Control Agreement between KCS Energy, Inc. and
Frederick Dwyer.
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.
23