UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

 

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of Registrant as specified in its charter)

 

Delaware		75-2396863
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)
6 Desta Drive, Suite 6500, Midland, Texas		79705-5510
(Address of principal executive offices)		(Zip code)
Registrant’s Telephone Number, including area code: (432) 682-6324
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.     Yes     ý     No     o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).     Yes     ý     No     o

 

There were 10,799,844 shares of Common Stock, $.10 par value, of the registrant outstanding as of May 4, 2005.

 

 

CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004
	Consolidated Statements of Operations for the three months ended March 31, 2005 and 2004
	Consolidated Statement of Stockholders’ Equity for the three months ended March 31, 2005
	Consolidated Statements of Cash Flows for the three months ended March 31, 2005 and 2004
	Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosure About Market Risks
Item 4.	Controls and Procedures
PART II. OTHER INFORMATION
Item 6.	Exhibits
	Signatures

 

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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

 

		March 31, 2005			December 31, 2004
		(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	10,902		$	16,359
Accounts receivable:
Oil and gas sales, net		27,651			25,573
Joint interest and other, net		6,754			4,653
Affiliates		841			553
Inventory		5,569			5,202
Deferred income taxes		648			625
Fair value of derivatives		126			2,333
Prepaids and other		1,670			1,401
		54,161			56,699
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		925,063			909,095
Natural gas gathering and processing systems		17,311			17,286
Other		11,859			11,839
		954,233			938,220
Less accumulated depreciation, depletion and amortization		(542,851		)	(539,860		)
Property and equipment, net		411,382			398,360
OTHER ASSETS		7,172			7,176
		$	472,715		$	462,235
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade		$	42,361		$	51,014
Oil and gas sales		8,666			11,223
Affiliates		2,206			2,954
Current maturities of long-term debt		30			31
Fair value of derivatives		28,119			16,026
Accrued liabilities and other		3,045			3,017
		84,427			84,265
NON-CURRENT LIABILITIES
Long-term debt		183,712			177,519
Deferred income taxes		32,270			36,897
Fair value of derivatives		46,136			28,958
Other		17,351			17,000
		279,469			260,374
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized – 3,000,000 shares; issued and outstanding – none		—			—
Common stock, par value $.10 per share, authorized – 30,000,000 shares; issued and outstanding – 10,795,725 shares in 2005 and 10,787,013 shares in 2004		1,079			1,078
Additional paid-in capital		104,888			104,674
Retained earnings		2,852			11,844
		108,819			117,596
		$	472,715		$	462,235

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share)

 

		Three Months Ended March 31,
		2005			2004
REVENUES
Oil and gas sales		$	61,496		$	36,332
Natural gas services		2,581			2,527
Gain on sales of property and equipment		1,612			5
Total revenues		65,689			38,864
COSTS AND EXPENSES
Production		12,571			6,955
Exploration:
Abandonments and impairments		11,270			4,632
Seismic and other		788			1,925
Natural gas services		2,417			2,352
Depreciation, depletion and amortization		12,292			8,524
Accretion of abandonment obligations		279			175
General and administrative		2,518			3,301
Loss on sales of property and equipment		32			—
Total costs and expenses		42,167			27,864
Operating income		23,522			11,000
OTHER INCOME (EXPENSE)
Interest expense		(2,366		)	(460		)
Change in fair value of derivatives		(35,089		)	(3,093		)
Other		446			(124		)
Total other income (expense)		(37,009		)	(3,677		)
Income (loss) before income taxes		(13,487		)	7,323
Income tax expense (benefit)		(4,495		)	2,510
NET INCOME (LOSS)		$	(8,992	)	$	4,813
Net income (loss) per common share:
Basic:
Income (loss) before extraordinary items		$	(0.83	)	$	0.51
Net income (loss)		$	(0.83	)	$	0.51
Diluted:
Income (loss) before extraordinary items		$	(0.83	)	$	0.50
Net income (loss)		$	(0.83	)	$	0.50
Weighted average common shares outstanding:
Basic		10,792			9,371
Diluted		10,792			9,720

 

The accompanying notes are an integral part of these consolidated financial statements.

 

4

 

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Unaudited)
(In thousands)

 

		Common Stock					Additional
		No. of Shares		Par Value			Paid-In Capital			Retained Earnings
BALANCE, December 31, 2004		10,787		$	1,078		$	104,674		$	11,844
Net loss and total comprehensive loss		—		—			—			(8,992		)
Issuance of stock through compensation plans		9		1			214			—
BALANCE, March 31, 2005		10,796		$	1,079		$	104,888		$	2,852

 

The accompanying notes are an integral part of these consolidated financial statements.

 

5

 

CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

 

		Three Months Ended March 31,
		2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)		$	(8,992	)	$	4,813
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization		12,292			8,524
Exploration costs		11,270			4,632
Gain on sales of property and equipment		(1,580		)	(5		)
Deferred income taxes		(4,651		)	2,510
Non-cash employee compensation		333			752
Change in fair value of derivatives		31,452			2,945
Settlements on derivatives with financing elements		4,205			—
Accretion of abandonment obligations		279			175
Changes in operating working capital:
Accounts receivable		(4,467		)	1,613
Accounts payable		(10,166		)	(3,544		)
Other		(29		)	(771		)
Net cash provided by operating activities		29,946			21,644
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(38,814		)	(28,604		)
Proceeds from sales of property and equipment		1,694			5
Other		(278		)	137
Net cash used in investing activities		(37,398		)	(28,462		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		6,200			—
Repayments of long-term debt		—			(641		)
Settlements on derivatives with financing elements		(4,205		)	—
Net cash provided by (used in) financing activities		1,995			(641		)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(5,457		)	(7,459		)
CASH AND CASH EQUIVALENTS
Beginning of period		16,359			15,454
End of period		$	10,902		$	7,995
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized		$	2,602		$	421

 

The accompanying notes are an integral part of these consolidated financial statements.

 

6

 

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)

 

1.                                      Nature of Operations

 

Clayton Williams Energy, Inc. (a Delaware corporation) and its subsidiaries (collectively, the “Company” or “CWEI”) is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana and New Mexico.  Approximately 41% of the Company’s outstanding common stock is beneficially owned by its Chairman of the Board and Chief Executive Officer, Clayton W. Williams (“Mr. Williams”).  Oil and gas exploration and production is the only business segment in which the Company operates.

 

Substantially all of the Company’s oil and gas production is sold under short-term contracts which are market-sensitive.  Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

 

2.                                      Presentation

 

The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ materially from those estimates.

 

In the opinion of management, the Company’s unaudited consolidated financial statements as of March 31, 2005 and for the interim periods ended March 31, 2005 and 2004 include all adjustments which are necessary for a fair presentation in accordance with accounting principles generally accepted in the United States.  These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2005.

 

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).  These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s 2004 Form 10-K.

 

3.                                      Recent Accounting Pronouncements

 

In EITF 04-5 the Emerging Issues Task Force (“EITF”) has discussed a proposed framework for addressing when a limited partnership should be consolidated by its general partner.  The proposed framework presumes that a sole general partner in a limited partnership controls the limited partnership.  The presumption of control can be overcome if the limited partners have (a) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (b) substantive participating

 

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rights.  The EITF has tentatively concluded that a general partner lacks control if the limited partners can remove the general partner with a simple majority vote.  We are the general partner of several oil and gas limited partnerships, and are currently evaluating the impact that EITF 04-5 may have on our consolidated financial statements.

 

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 153 “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29” (“SFAS 153”).  SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis.  SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005.  The Company will adopt this statement in the third quarter of 2005, and it is not expected to have a material effect on the financial statements when adopted.

 

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payments” (“SFAS 123R”).  SFAS 123R requires that the cost from all share-based payment transactions, including stock options, be recognized in the financial statements at fair value.  The Company currently uses the intrinsic-value method to account for these share-based payments.  For public companies, SFAS 123R is effective for fiscal years beginning after June 15, 2005.  The Company will adopt the provisions of this statement in the first quarter of 2006 and is currently assessing the effect of SFAS 123R on the financial statements.

 

The Financial Accounting Standards Board has proposed FASB Staff Position No. 19-a (“FSP 19-a”), which had a comment deadline of March 7, 2005.  FSP 19-a would amend the present guidance in SFAS 19, paragraphs 31 and 34, regarding when exploratory drilling costs pending determination of proved reserves can be carried as an asset of an oil and gas company that uses the successful efforts accounting method.  Based on the Company’s present understanding of this proposed statement, the adoption of FSP 19-a will not have a significant impact on the Company’s results of operations.  At March 31, 2005 and December 31, 2004, the Company had capitalized $0 and $5.4 million, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves.  Substantially all of the December 31, 2004 capitalized cost was subsequently classified as non-productive.

 

4.                                      Acquisition of Southwest Royalties, Inc.

 

On May 21, 2004, the Company acquired all the outstanding common stock of Southwest Royalties, Inc. (“SWR”) through a merger.  Prior to the acquisition, SWR was a privately-held, Midland-based energy company engaged in oil and gas exploration, production, development and acquisition activities in the United States.  Most of SWR’s properties are located in the Permian Basin of west Texas and southeastern New Mexico.

 

In connection with the acquisition of SWR, the Company paid $57.1 million to holders of SWR common stock and common stock warrants and assumed and refinanced approximately $113.9 million of SWR bank debt at closing.  In addition, the Company incurred approximately $9.4 million of merger-related costs, including (i) the assumption of SWR’s obligations to its officers and employees pursuant to change of control arrangements and (ii) investment banking, legal, accounting and other direct transaction costs related to the acquisition of SWR.

 

The Company has accounted for the acquisition of SWR using the purchase method of accounting for business combinations.  Under this method of accounting, CWEI is deemed to be the acquirer for accounting purposes.  SWR’s assets and liabilities were revalued under the purchase method of accounting and recorded at their estimated fair values.

 

8

 

The following table reflects the unaudited pro forma results of operations for the three months ended March 31, 2004 as though the acquisition of SWR had occurred on January 1, 2004.  The pro forma amounts are not necessarily indicative of the results that may be reported in the future.

 

		Three Months Ended March 31, 2004
		(In thousands, except per share data)
Revenues		$	53,692
Net income (loss) from continuing operations		$	(850	)
Net income (loss) from continuing operations per share:
Basic		$	(.08	)
Diluted		$	(.08	)

 

5.                                      Long-Term Debt

 

Long-term debt consists of the following:

 

		March 31, 2005			December 31, 2004
		(In thousands)
Secured bank credit facilities:
Revolving loan, due May 2007		$	153,700		$	147,500
Senior term loan, due May 2008		30,000			30,000
Other		42			50
		183,742			177,550
Less current maturities		(30		)	(31		)
		$	183,712		$	177,519

 

Aggregate maturities of long-term debt at March 31, 2005 are as follows:  2005 – $30,000; 2006 - $12,000; 2007 - $153,700,000; and 2008 - $30,000,000.

 

Secured Bank Credit Facilities

 

In connection with the acquisition of SWR in May 2004 (see Note 4), the Company entered into new credit facilities with a group of banks that provided for an increase in borrowing capacity under the Company’s existing revolving credit facility and established a new senior term credit facility.  The borrowing base established under the revolving credit facility increased from $95 million to $180 million, and the Company initially borrowed $75 million on the senior term credit facility.  With a portion of the net proceeds from the private placement of common stock in May 2004 (see Note 7), the Company reduced the principal balance on the senior term credit facility to $50 million.  In November 2004, the banks increased the borrowing base under the revolving credit facility to $195 million, and the Company paid down the senior term credit facility to $30 million with proceeds from certain asset sales.

 

The revolving credit facility provides for interest at rates based on the agent bank’s prime rate plus margins ranging from .25% to 1%, or if elected by the Company based on LIBOR plus margins ranging from 1.5% to 2.25%.  The Company also pays a commitment fee on the unused portion of the revolving credit facility.  Initially, the senior term credit facility provided for interest at rates based on the agent bank’s

 

9

 

prime rate plus a margin of 3.5%, or if elected by the Company based on LIBOR plus a margin of 5%.  Until the principal balance on the senior term credit facility was equal to or less than $40 million, the applicable margins increased by .5% per quarter.  Now that the principal balance is $30 million, the prime rate margin is fixed at 2.5%, and the LIBOR margin is fixed at 4%.  Interest and fees are payable at least quarterly.  The effective annual interest rate on the combined credit facility, including bank fees and amortization of debt issue costs, for the three months ended March 31, 2005 was 5.8%.

 

The amount of funds available to the Company under the revolving credit facility is the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit.  The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks.  At March 31, 2005, the borrowing base was $195 million, with no monthly commitment reductions.  After taking into account outstanding letters of credit totaling $775,000, the Company had approximately $40.5 million available under the revolving credit facility at March 31, 2005.

 

Principal under the senior term credit facility is due at maturity; however, mandatory prepayments are required when the Company raises funds from capital markets transactions or sales of assets.  Prepayments that reduce the principal balance on the senior term credit facility below $40 million are subject to a 1% fee through May 2005.

 

The loan agreements applicable to the respective credit facilities contain financial covenants that are computed quarterly.  The working capital covenant requires the Company to maintain a ratio of current assets to current liabilities of at least 1 to 1.  Other financial covenants under the credit facilities require the Company to maintain a ratio of indebtedness to cash flow of no more than 3 to 1, and a ratio of reserve value to indebtedness of at least 1.5 to 1.  The computations of current assets, current liabilities, cash flow, indebtedness and reserve value are defined in the respective loan agreements.  The Company was in compliance with all financial and non-financial covenants at March 31, 2005.

 

6.                                      Other Non-Current Liabilities

 

Other non-current liabilities consist of the following:

 

		March 31, 2005			December 31, 2004
		(In thousands)
Abandonment obligations		$	16,524		$	16,147
Other		827			853
		$	17,351		$	17,000

 

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Changes in abandonment obligations for the three months ended March 31, 2005 and 2004 are as follows:

 

		Three Months Ended March 31,
		2005			2004
		(In thousands)
Beginning of period		$	16,147		$	8,849
Additional abandonment obligations from new wells		140			48
Sales or abandonments of properties		(42		)	(18		)
Accretion expense		279			175
End of period		$	16,524		$	9,054

 

7.                                      Common Stock

 

In May 2004, the Company sold 1,380,869 shares of its common stock to certain institutional investors at a price of $23.00 per share in a private placement that raised approximately $31.8 million in gross proceeds.  After the payment of typical transaction expenses, net proceeds of approximately $30 million were used to repay a portion of the bank indebtedness incurred to finance the acquisition of SWR (see Note 4).

 

8.                                      Compensation Plans

 

Executive Stock Compensation Plan

 

The Company has a compensation plan which permits the Company to pay all or part of selected executives’ salaries and bonuses in shares of common stock in lieu of cash.  The Company reserved an aggregate of 500,000 shares of common stock for issuance under this plan.  During the three months ended March 31, 2005, the Company issued 4,515 shares of common stock to Mr. Williams in lieu of net cash compensation aggregating $112,000, which is included in general and administrative expenses in the accompanying consolidated financial statements.  Subsequent to March 31, 2005, the Company issued an additional 1,644 shares to Mr. Williams in lieu of cash compensation aggregating $39,000.

 

Stock-Based Compensation

 

The Company accounts for stock-based compensation utilizing the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB 25”) and related interpretations.  The following pro forma information, as required by Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by Statement of Financial Accounting Standards No. 148 (“SFAS 148”), presents net income and earnings per share information as if the stock options issued since December 31, 1994 were accounted for using the fair value method.  The fair value of stock options issued for each year was estimated at the date of grant using the Black-Scholes option pricing model.  In July 2004, Mr. Williams was granted options to purchase 300,000 shares of common stock at a price of $26.06, which was the market value at the date of grant.

 

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The SFAS 123 pro forma information for the three months ended March 31, 2005 and 2004 is as follows:

 

		Three Months Ended March 31,
		2005			2004
		(In thousands, except per share)
Net income (loss), as reported		$	(8,992	)	$	4,813
Add: Stock-based employee compensation expense (credit) included in net income, net of tax		77			375
Net income (loss), pro forma		$	(8,915	)	$	5,188
Basic:
Net income (loss) per common share, as reported		$	(.83	)	$	.51
Net income (loss) per common share, pro forma		$	(.83	)	$	.55
Diluted:
Net income (loss) per common share, as reported		$	(.83	)	$	.50
Net income (loss) per common share, pro forma		$	(.83	)	$	.53

 

In accordance with the issuance of Financial Accounting Standards Board Interpretation No. 44 (“FIN 44”) to APB 25, the Company changed the classification of 233,141 stock options repriced in April 1999 from fixed stock options to variable stock options.  The Company is required to recognize compensation expense on the repriced options to the extent that the quoted market value of the Company’s common stock at the end of each period after July 1, 2000 exceeds the amended option price ($5.50 per share), except that options vested as of July 1, 2000 must recognize compensation expense only to the extent that the quoted market value exceeds the market value on that date ($31.94 per share).  As the repriced options are exercised, the cumulative amount of accrued compensation expense will be credited to additional paid-in capital.  Since this provision is based on changes in the quoted market value of the Company’s common stock, the Company’s future results of operations may be subject to significant volatility.  Accrued compensation expense at March 31, 2005 and December 31, 2004 is classified as a current liability in the accompanying consolidated balance sheet and is comprised of the following activity for the years then ended.

 

		March 31, 2005			December 31, 2004
		(In thousands)
Beginning of period		$	685		$	958
Compensation expense (credit)		118			(245		)
Amounts reclassified to additional paid-in capital for options exercised during the period		—			(28		)
End of period		$	803		$	685

 

After-Payout Working Interest Incentive Plans

 

In September 2002, the Compensation Committee of the Board of Directors adopted an incentive plan for officers, key employees and consultants, excluding Mr. Williams, who promote the Company’s drilling and acquisition programs.  Management’s objective in adopting this plan is to further align the interests of the participants with those of the Company by granting the participants an after-payout working interest in the production developed, directly or indirectly, by the participants.  The plan provides for the creation of a series of limited partnerships to which the Company, as general partner, contributes a portion of its working interest in wells drilled within certain areas, and the key employee and consultants,

 

12

 

as limited partners, contribute cash.  The Company pays all costs and receives all revenues until payout of its costs, plus interest.  At payout, the limited partners receive 99% of all subsequent revenues and pay 99% of all subsequent expenses attributable to the partnerships’ interests.

 

From 3% to 5% of the Company’s working interests in substantially all wells drilled by the Company subsequent to October 2002 are subject to this arrangement.  The Company consolidates its proportionate share of partnership assets, liabilities, revenues, expenses and oil and gas reserves in its consolidated financial statements.  In April 2004, one of the partnerships achieved payout, and the Company’s interest in the partnership was reduced to 1%.  Aggregate cash distributions of $67,000 were paid to the limited partners of this partnership during the three months ended March 31, 2005.

 

9.                                      Derivatives

 

Commodity Derivatives

 

From time to time, the Company utilizes commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for its oil and gas production.  When using swaps to hedge oil and natural gas production, the Company receives a fixed price for the respective commodity and pays a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty.  When purchasing floors, the Company receives a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity.  If the market price is greater than the put strike price, no payments are due from either party.  Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price).  If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price.  If the market price is between the call and the put strike prices, no payments are due from either party.

 

The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to March 31, 2005.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

 

Floors:

 

		Gas					Oil
		MMBtu		Floor			Bbls		Floor
Production Period:
2nd Quarter 2005		1,820,000		$	4.50		118,300		$	28.00
2nd Quarter 2005		1,820,000		$	5.00
3rd Quarter 2005		1,840,000		$	4.50		119,600		$	28.00
4th Quarter 2005		1,840,000		$	4.50		119,600		$	28.00
		7,320,000					357,500

 

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Collars:

 

		Gas								Oil
		MMBtu (a)		Floor			Ceiling			Bbls		Floor			Ceiling
Production Period:
2nd Quarter 2005		630,000		$	4.00		$	5.23		168,000		$	23.00		$	25.41
3rd Quarter 2005		607,000		$	4.00		$	5.23		165,000		$	23.00		$	25.41
4th Quarter 2005		588,000		$	4.00		$	5.23		162,000		$	23.00		$	25.41
2006		2,024,000		$	4.00		$	5.21		613,000		$	23.00		$	25.32
2007		1,831,000		$	4.00		$	5.18		562,000		$	23.00		$	25.20
2008		1,279,000		$	4.00		$	5.15		392,000		$	23.00		$	25.07
		6,959,000								2,062,000

 

(a)                                            One MMBtu equals one Mcf at a Btu factor of 1,000.

 

The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to March 31, 2005.

 

Interest Swaps:

 

		Principal Balance			Libor Rates
Period:
April 1, 2005 to November 1, 2005		$	60,000,000		2.97	%
November 1, 2005 to November 1, 2006		$	55,000,000		4.29	%
November 1, 2006 to November 1, 2007		$	50,000,000		5.19	%
November 1, 2007 to November 1, 2008		$	45,000,000		5.73	%

 

Accounting For Derivatives

 

The Company accounts for its derivatives in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.  The Company did not designate any of its currently open commodity or interest rate derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in the Company’s statements of operations.

 

Pursuant to SFAS 133, as amended by SFAS 149, the derivative instruments assumed in connection with the SWR acquisition (see Note 4) are deemed to contain a significant financing element, and all cash flows associated with the settlement of these positions are reported as a financing activity in the consolidated statements of cash flows.

 

10.                               Financial Instruments

 

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments.  Indebtedness under the secured bank credit facility was estimated to have a fair value approximating the carrying amount since the stated interest rate is generally market sensitive.  Abandonment obligations are carried at net present value which approximates their fair value since the discount rate is based on the Company’s credit-adjusted, risk-free rate.  The fair value of other noncurrent liabilities approximate their carrying value.

 

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The fair values of derivatives as of March 31, 2005 and December 31, 2004 are set forth below.  The associated carrying values at these dates are equal to their estimated fair values.

 

		March 31, 2005			December 31, 2004
		(In thousands)
Assets (liabilities):
Commodity derivatives		$	(73,613	)	$	(41,162	)
Interest rate derivatives		(490		)	(1,489		)
Net assets (liabilities)		$	(74,103	)	$	(42,651	)

 

11.                               Income Taxes

 

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities.  Significant components of net deferred tax liabilities at March 31, 2005 and December 31, 2004 are as follows:

 

		March 31, 2005					December 31, 2004
		(In thousands)
Deferred tax assets:
Net operating loss carryforwards		$			5,481		$	7,915
Accrued stock-based compensation		281					240
Fair value of derivatives		25,938					14,930
Credits related to alternative minimum tax		328					279
Depletion carryforwards		3,321					3,209
Other		5,149					5,058
		40,498					31,631
Deferred tax liabilities:
Property and equipment		(72,120				)	(67,903				)
Net deferred tax liabilities		$		(31,622		)	$		(36,272		)
Components of net deferred tax assets (liabilities):
Current assets		$		648			$		625
Non-current liabilities		(32,270				)	(36,897				)
		$	(31,622			)	$			(36,272	)

 

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For the three months ended March 31, 2005 and 2004, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:

 

		Three Months Ended March 31,
		2005			2004
		(In thousands)
Income tax expense (benefit) at statutory rate of 35%		$	(4,720	)	$	2,563
Tax depletion in excess of basis		(112		)	(53		)
State income taxes		337			—
Income tax expense (benefit)		$	(4,495	)	$	2,510
Current		$	156		$	—
Deferred		(4,651		)	2,510
Income tax expense (benefit)		$	(4,495	)	$	2,510

 

The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 8).  Employee stock options that are classified as fixed stock options under APB 25 do not result in a charge against book income when the option price is equal to or greater than the market price at date of grant.  Therefore, any tax benefit from the exercise of fixed stock options results in a permanent difference, which is recorded to additional paid-in capital when the tax benefit is realized.

 

In connection with the SWR merger, the Company acquired $29.3 million of tax loss carryforwards that are subject to Section 382 limitations from a prior change in control that occurred in April 2002 and from the change in control that occurred in connection with the Company’s acquisition of SWR in May 2004.  The Company has completed a review of the facts surrounding these changes in control and presently believes that it will be able to utilize all of SWR’s tax loss carryforwards.

 

At March 31, 2005, the Company’s cumulative tax loss carryforwards were approximately $15.7 million.  Based upon current commodity prices and production volumes, as well as the availability of tax planning strategies (such as elective capitalization of intangible drilling costs), the Company believes that it is more likely than not that the Company will be able to utilize these tax loss carryforwards before they expire (beginning in 2008).  Accordingly, no valuation allowance exists at March 31, 2005 or December 31, 2004.

 

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Item 2 -       Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2004.

 

Overview

 

We are an oil and gas exploration, development and production company.  Our basic business model is to find oil and gas reserves through exploration activities, develop the discovered reserves, and sell the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and gas reserves and then sell our discovered production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.

 

From time to time, we may also acquire producing properties if we believe the acquired assets offer us the potential for reserve growth through additional developmental or exploratory drilling activities.  The acquisition of SWR in May 2004 provided us with a number of well locations suitable for developmental drilling and also enhanced our ability to conduct exploration activities on or adjacent to some of the acquired properties.

 

We believe that the economic climate in the domestic oil and gas industry continues to be suitable for our business model.  Oil and gas prices have remained strong.  Supply and demand fundamentals continue to suggest that energy prices will remain high for the near term, providing us with the economic incentives necessary for us to assume the risks we face in our search for oil and gas reserves.

 

Finding quality domestic oil and gas reserves through exploration is a significant challenge and involves a high degree of risk.  Although our recent exploration results have improved, our drilling successes in 2002 and 2003 were limited and did not find sufficient reserves to replace our production through exploration activities.  In order to grow our reserve base through our exploration program, we need to continue to improve our drilling success.  We will also continue to look for opportunities to complement our exploration program through the purchase of proved reserves as we did in 2004 with the acquisition of SWR.

 

Key Factors to Consider

 

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the first quarter of 2005 and the outlook for the remainder of 2005.

 

•           Our acquisition of SWR in May 2004 contributed significantly to production and cash flow during the first quarter of 2005.

 

•           We recorded a loss of $35.1 million related to the change in fair value of derivatives during the first quarter of 2005. Cash settlements to counterparties accounted for $3.6 million of this loss, and changes in mark-to-market valuations accounted for $31.5 million.  Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to results of operations.

 

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•           Exploration costs related to abandonments and impairments were $11.3 million during the first quarter of 2005, of which $7.2 million was related to the Catherine Destefano #1 in the Cotton Valley Reef Complex area and $2.5 million in Mississippi primarily related to the Inez West #1.

 

•           Production for the first quarter of 2005, on an Mcfe basis, was up 30% from the first quarter of 2004.  This was due primarily to the acquisition of SWR in May 2004 which contributed approximately 2.5 Bcfe of oil and gas production during the first quarter of 2005 excluding incremental production from wells drilled subsequent to the acquisition.

 

•           We currently plan to spend $128.4 million in 2005 on exploration and development activities, of which approximately 66% relates to exploratory prospects.  We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results.

 

Acquisition of Southwest Royalties, Inc.

 

On May 21, 2004, we acquired all the outstanding common stock of SWR through a merger.  Prior to the acquisition, SWR was a privately-held, Midland-based energy company engaged in oil and gas exploration, development, production and acquisition activities in the United States.  Most of SWR’s properties are located in the Permian Basin of west Texas and southeast New Mexico.  Using reserve guidelines established by the SEC, the SWR acquisition added approximately 170.8 Bcfe to our proved oil and gas reserves on the effective date of the acquisition.

 

Recent Exploration and Developmental Activities

 

South Louisiana

 

The following table sets forth certain information about our exploratory well activities in south Louisiana subsequent to December 31, 2004.

 

Spud Date		Well Name (Prospect)		Working Interest		Current Status
August 2004		McIlhenny #1 (Tabasco)		33	%	Dry
November 2004		Orleans Levee District #1 (American Bay)		45	%	Waiting on production facilities
February 2005		State Lease 18065 #1 (Alabama)		100	%	Completing

 

In February 2005, we plugged and abandoned the McIlhenney #1 (Tabasco), an 18,300-foot exploratory well in Vermillion Parish, resulting in pretax charges of $3.8 million in the fourth quarter of 2004 and $800,000 in the first quarter of 2005.  We are currently constructing production facilities for the Orleans Levee District #1 (American Bay) and expect to begin selling production from this well in the fourth quarter of 2005.

 

Permian Basin

 

Subsequent to December 31, 2004, we have drilled 11 gross (10.3 net) operated wells in various fields in the Permian Basin, all of which were completed as producers.  Most of these wells contributed favorably to our first quarter 2005 production.  In addition, we are currently conducting drilling or completing operations on 4 gross (3.2 net) wells in this area.

 

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Cotton Valley/Knowles

 

During the first quarter of 2005, we abandoned the Catherine Destefano #1, a 14,600-foot exploratory well in Robertson County, Texas targeting the Knowles formation, resulting in a pretax charge of $7.2 million.

 

Supplemental Information

 

The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-Q with data that is not readily available from those statements.

 

		Three Months Ended March 31,
		2005			2004
Oil and Gas Production Data:
Gas (MMcf)		4,761			4,177
Oil (MBbls)		619			375
Natural gas liquids (MBbls)		66			69
Total (MMcfe)		8,871			6,841
Average Realized Prices(1):
Gas ($/Mcf)		$	6.22		$	5.17
Oil ($/Bbl)		$	47.83		$	34.04
Natural gas liquids ($/Bbl):		$	27.50		$	24.57
Average Daily Production:
Natural Gas (Mcf):
Permian Basin		16,156			1,866
Louisiana		15,272			10,739
Austin Chalk (Trend)		2,558			3,669
Cotton Valley Reef Complex		18,014			28,119
Other		900			1,508
Total		52,900			45,901
Oil (Bbls):
Permian Basin		3,332			940
Louisiana		1,474			738
Austin Chalk (Trend)		2,033			2,393
Other		39			50
Total		6,878			4,121
Natural Gas Liquids (Bbls):
Permian Basin		233			186
Austin Chalk (Trend)		337			371
Other		163			201
Total		733			758

 

(continued)

 

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		Three Months Ended March 31,
		2005			2004
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana		$	1,272		$	3,596
Cotton Valley Reef Complex		7,246			—
Nevada, Arizona, California and Utah		—			585
Mississippi		2,464			—
Permian Basin		288			—
Other		—			451
Total		11,270			4,632
Seismic and other		788			1,925
Total exploration costs		$	12,058		$	6,557
Oil and Gas Costs ($/Mcfe Produced):
Production costs		$	1.42		$	1.02
Oil and gas depletion		$	1.30		$	1.14
Net Wells Drilled(2):
Exploratory Wells		3.3			2.1
Developmental Wells		8.9			5.5

 

(1)                          The Company did not designate any of its 2005 or 2004 derivatives as cash flow hedges under Statement of Financial Accounting Standards No. 133, as amended.  All changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income/expense in the Company’s statements of operations and are excluded from the computation of average realized prices from oil and gas sales.  During the quarter ended March 31, 2005 and 2004, we realized net losses on derivative contracts as follows:  Oil - $4.2 million and $149,000, respectively;  Gas - $ 700,000 gain in 2005.

 

(2)                          Excludes wells being drilled or completed at the end of each period.

 

Operating Results – Three-Month Periods

 

The following discussion compares our results for the three months ended March 31, 2005 to the comparative period in 2004.  Unless otherwise indicated, references to 2005 and 2004 within this section refer to the respective quarterly period.

 

Oil and gas operating results

 

Oil and gas sales in 2005 increased 69% from 2004 due primarily to higher product prices and an increase in oil and gas production on an Mcfe basis.  Oil and gas sales increased $25.2 million, of which price variances accounted for a $13.9 million increase and production variances accounted for a $11.3 million increase.

 

Production in 2005 (on an Mcfe basis) was 30% higher than 2004.  We increased our oil production in 2005 primarily through the acquisition of SWR in May 2004 and production from new wells in Louisiana.  Our gas production increased 14% in 2005 from 2004 due primarily to additional gas production from the SWR acquisition and production from new wells in Louisiana, offset in part by normal production declines in the Cotton Valley Reef Complex area.

 

20