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 September 30, 2003

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period to

Commission File Number 0-22650

PETROCORP INCORPORATED

(Exact name of registrant as specified in its charter)

Texas		76-0380430
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

6733 South Yale Tulsa, Oklahoma		74136
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: (918) 491-4500

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 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 x No ¨

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

Indicate the number of shares outstanding of each of the Registrant’s classes of stock, as of October 31, 2003:

Common Stock, $.01 per value		12,688,046
(Title of Class)		(Number of Shares Outstanding)

PETROCORP INCORPORATED

INDEX

				PAGE NO.
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Condensed Consolidated Balance Sheets at September 30, 2003 and December 31, 2002				1

Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2003 and 2002				2

Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2003 and 2002				4

Notes to Condensed Consolidated Financial Statements				5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations				12

Item 3. Quantitative and Qualitative Disclosures about Market Risk				17

Item 4. Controls and Procedures				17

PART II. OTHER INFORMATION				18

SIGNATURES				19

CERTIFICATIONS				20

Certain matters discussed in this report, excluding historical information, include forward-looking statements - statements that discuss the Company’s expected future results based on current and pending business operations. The Company is making these forward-looking statements in reliance on the safe harbor protections provided under the PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.

Forward-looking statements can be identified by words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled” or similar expressions. Although the Company believes these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to numerous assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document. Important risk factors (but not necessarily all important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the Company would include, but in no way be limited by, the Company’s ability to obtain agreements with co-venturers, partners and governments; its ability to engage drilling, construction and other contractors; its ability to obtain economical and timely financing; geological, land, sea or weather conditions; world prices for oil, natural gas and natural gas liquids; adequate and reliable transportation systems; and foreign and United States laws, including tax laws. Additional information about issues that could lead to material changes in performance is contained in the Company’s Form 10-K.

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

PETROCORP INCORPORATED

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share amounts)

(Unaudited)

	September 30, 2003			December 31, 2002
Assets
Current assets:
Cash and cash equivalents	$	90,283		$	3,087
Accounts receivable, net		8,803			11,537
Receivable from sale of Canadian subsidiaries		1,023			—
Assets of discontinued operations		—			72,300
Current portion of deferred taxes		740			—
Other current assets		946			1,107

Total current assets		101,795			88,031

Property, plant and equipment:
Oil and gas properties, at cost, full cost method, net of accumulated depreciation, depletion, amortization and impairment		56,088			48,761
Deferred income taxes		4,650			22,066
Other assets, net		2,788			2,723

Total assets	$	165,321		$	161,581

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	5,300		$	7,367
Accrued liabilities		2,995			2,758
Current income tax payable		831			—
Liabilities of discontinued operations		—			22,111

Total current liabilities		9,126			32,236

Long-term debt		—			28,750

Dismantlement obligation		5,192			—

Other long-term liabilities		365			—

Shareholders’ equity:
Preferred stock, $0.01 par value, 1,000,000 shares authorized, none issued
Common stock, $0.01 par value, 25,000,000 shares authorized, 12,688,046 and 12,645,309 shares outstanding as of September 30, 2003 and December 31, 2002, respectively		130			130
Additional paid-in capital		112,643			111,905
Retained earnings (accumulated deficit)		41,107			(982	)
Accumulated other comprehensive loss		—			(7,746	)
Treasury stock, at cost (354,087 and 305,907 shares, respectively)		(3,242	)		(2,712	)

Total shareholders’ equity		150,638			100,595

Total liabilities and shareholders’ equity	$	165,321		$	161,581

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

PETROCORP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share amounts)

(Unaudited)

	For the three months ended September 30,						For the nine months ended September 30,
	2003			2002			2003			2002
Revenues:
Oil and gas	$	8,577		$	7,126		$	27,528		$	20,369
Other		135			129			351			234

		8,712			7,255			27,879			20,603

Expenses:
Production costs		2,913			2,787			7,908			7,878
Depreciation, depletion and amortization		1,887			1,803			5,180			6,253
General and administrative		719			506			1,999			1,244
Other operating expenses		29			11			84			75

		5,548			5,107			15,171			15,450

Income from operations		3,164			2,148			12,708			5,153

Other income (expenses):
Investment income		238			9			468			115
Interest expense		(74	)		(376	)		(490	)		(1,226	)
Other income (expenses)		(773	)		(247	)		2,361			8

		(609	)		(614	)		2,339			(1,103	)

Income from continuing operations before income taxes and accounting change		2,555			1,534			15,047			4,050

Income tax provision:
Current		653			14			2,304			(13	)
Deferred		215			661			3,125			1,425

		868			675			5,429			1,412

Income from continuing operations before accounting change		1,687			859			9,618			2,638
Discontinued operations:
Income from discontinued Canadian operations (net of applicable taxes of nil, $780, $1,530 and $2,028)		—			1,314			2,113			2,961
Gain on sale of Canadian subsidiaries (net of taxes (benefit) of ($198) and $19,573)		(337	)		—			33,327			—

Income before cumulative effect of a change in accounting principle		1,350			2,173			45,058			5,599
Cumulative effect on prior years of accounting change, less applicable income taxes of $1,743		—			—			(2,969	)		—

Net income	$	1,350		$	2,173		$	42,089		$	5,599

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

PETROCORP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share amounts)

(Unaudited)

(continued)

Net income per common share - basic:
Income from continuing operations	$	0.13		$	0.07	$	0.75		$	0.21
Income from discontinued operations		(0.02	)		0.10		2.80			0.24
Cumulative effect of change in accounting principle		—			—		(0.23	)		—

Net income	$	0.11		$	0.17	$	3.32		$	0.45

Net income per common share - diluted:
Income from continuing operations	$	0.13		$	0.07	$	0.75		$	0.21
Income from discontinued operations		(0.02	)		0.10		2.77			0.23
Cumulative effect of change in accounting principle		—			—		(0.23	)		—

Net income	$	0.11		$	0.17	$	3.29		$	0.44

Weighted average number of common shares - basic		12,684			12,570		12,661			12,563

Weighted average number of common shares - diluted		12,847			12,653		12,796			12,670

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

PETROCORP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	For the nine months ended September 30,
	2003			2002
Cash flows from operating activities:
Net income	$	42,089		$	5,599
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		5,180			6,253
Deferred income tax expense		3,125			1,425
Gain on sale of Canadian subsidiaries		(33,327	)		—
Cumulative effect of change in accounting principle		2,969			—
Other		244			97
Changes in operating assets and liabilities:
Accounts receivable		2,734			(3,050	)
Other current assets		161			310
Accounts payable		(2,067	)		3,145
Accrued liabilities		392			2,573
Income tax payable		831			—
Net cash provided (used) by discontinued operations		(355	)		4,792

Net cash provided by operating activities		21,976			21,144

Cash flows from investing activities:
Additions to oil and gas properties		(11,952	)		(3,615	)
Proceeds received on sale of Canadian subsidiaries (SEE NOTE 3)		107,635			—
Net investing activities of discontinued operations		(1,596	)		(3,763	)
Other		146			—

Net cash provided by (used in) investing activities		94,233			(7,378	)

Cash flows from financing activities:
Proceeds from long-term debt		—			800
Repayment of long-term debt		(28,750	)		(4,300	)
Other		208			314
Net financing activities of discontinued operations		(471	)		(7,789	)

Net cash used in financing activities		(29,013	)		(10,975	)

Effect of exchange rate changes on cash		—			(112	)

Net increase (decrease) in cash and cash equivalents		87,196			2,679
Cash and cash equivalents at beginning of period		3,087			1,265

Cash and cash equivalents at end of period	$	90,283		$	3,944

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

PETROCORP INCORPORATED

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 - BASIS OF PRESENTATION:

The unaudited consolidated financial statements of PetroCorp Incorporated (the “Company” or “PetroCorp”) have been prepared in accordance with generally accepted accounting principles for interim financial information and with instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments, consisting of normal and recurring adjustments necessary for a fair presentation, have been included. For further information, refer to the consolidated financial statements and footnotes thereto for the year ended December 31, 2002, included in the Company’s 2002 Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Interim period results are not necessarily indicative of results of operations or cash flows for a full-year period.

Accounting for Stock-Based Compensation

At September 30, 2003, the Company has a stock-based compensation plan, which is more fully described in Notes 1 and 9 of the Company’s Annual Report on Form 10-K. The Company accounts for this plan under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of FASB Statement No. 123, Accounting for Stock-Based Compensation, (in thousands, except per share amounts):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2003		2002		2003		2002
Net income, as reported	$	1,350	$	2,173	$	42,089	$	5,599
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		58		133		177		299

Pro forma net income	$	1,292	$	2,040	$	41,912	$	5,300

Earnings per share:
Basic - as reported	$	0.11	$	0.17	$	3.32	$	0.45
Basic - pro forma	$	0.10	$	0.16	$	3.31	$	0.42

Diluted - as reported	$	0.11	$	0.17	$	3.29	$	0.44
Diluted - pro forma	$	0.10	$	0.16	$	3.28	$	0.42

NOTE 2 - COMPREHENSIVE INCOME:

The Company follows SFAS No. 130, Reporting Comprehensive Income. This Statement establishes requirements for reporting comprehensive income and its components which includes the Company’s foreign currency translation adjustments. The Company’s comprehensive income for the three and nine months ended September 30, 2003 and 2002 is as follows (in thousands):

	For the three months ended September 30,					For the nine months ended September 30,
	2003		2002			2003		2002
Net income	$	1,350	$	2,173		$	42,089	$	5,599

Derivative hedging gain/(loss) (net of taxes of $266 and ($24))		—		409			—		(36	)
Reclassification of hedging loss to income (net of taxes of $181 and $361)		—		300					583
Reclassification of translation loss to income		—		—			4,939		—
Foreign currency translation gain (loss) (2003 gain covers period from January 1 through March 5)		—		(1,826	)		2,807		84

		—		(1,117	)		7,746		631

Comprehensive income	$	1,350	$	1,056		$	49,835	$	6,230

As of December 31, 2002, accumulated other comprehensive loss consisted of $7,746 of foreign currency translation losses.

NOTE 3 - SALE OF CANADIAN SUBSIDIARIES:

On December 24, 2002, PetroCorp signed an agreement to sell its two Canadian subsidiaries, PCC Energy Inc. and PCC Energy Corp. for C$167.6 million (approximately US$112 million), with an economically effective date of October 1, 2002. This is subject to post closing adjustments for certain working capital items. On March 5, 2003, PetroCorp received approximately 75% of the sale proceeds. Additionally, $27.5 million of the receivable recorded at the time of sale was received in September 2003 upon completion of certain tax documentation with the government of Canada and the remainder is expected to be received in the fourth quarter of 2003. The financial statements reflect the results of the Canadian operations and the sale of Canadian subsidiaries as discontinued operations. Prior year statements of operations have been restated to conform to the current year presentation. The sale was recorded as follows (amounts in thousands):

Cash proceeds received, net of $4,350 Canadian taxes withheld	$	80,135
Receivable recorded (A)		28,523

Net proceeds received		108,658

Net assets sold		55,168
Translation loss reclassified from comprehensive income		4,939
Deferred income taxes		15,224

		75,331

Gain on sale of Canadian subsidiaries	$	33,327

(A)	Receivable does not include subsequent translation gain and escrow interest, which are recorded in other income (expense).

Net sales and income of the discontinued operations are as follows (amounts in thousands):

	Nine months ended September 30,
	2003		2002
Net sales	$	5,937	$	16,275

Pre-tax income from discontinued operations	$	3,643	$	4,988
Income tax expense		1,530		2,028

Income from discontinued operations, net of tax	$	2,113	$	2,960

Assets and liabilities of the discontinued operations were as follows (amounts in thousands):

	March 5, 2003
Cash	$	5,961
Accounts receivable		11,332
Property, plant and equipment		66,205
Other Assets		64
Accounts Payable		(9,388	)
Accrued liabilities		(1,759	)
Deferred tax liability		(17,247	)

	$	55,168

NOTE 4 - EARNINGS PER SHARE:

The following is a reconciliation of the numerators and denominators of the basic and diluted per share computations for the periods presented (in thousands, except per share amounts).

	Income		Shares	Per Share Amounts
	Income		Shares	Income (Loss) from Continuing Operations		Income (Loss) from Discontinued Operations			Cumulative Effect of Accounting Change			Net Income
Three months ended September 30, 2003
Basic EPS:
Net income	$	1,350	12,684	$	0.13	$	(0.02	)	$	—		$	0.11
Effect of dilutive securities:
Options		—	163		—		—			—			—

Diluted EPS:
Net income	$	1,350	12,847	$	0.13	$	(0.02	)	$	—		$	0.11


Three months ended September 30, 2002
Basic EPS:
Net income	$	2,173	12,570	$	0.07	$	0.10		$	—		$	0.17
Effect of dilutive securities:
Options		—	83		—		—			—			—

Diluted EPS:
Net income	$	2,173	12,653	$	0.07	$	0.10		$	—		$	0.17


	Income		Shares	Per Share Amounts
	Income		Shares	Income (Loss) from Continuing Operations		Income from Discontinued Operations			Cumulative Effect of Accounting Change			Net Income
Nine months ended September 30, 2003
Basic EPS:
Net income	$	42,089	12,661	$	0.75	$	2.80		$	(0.23	)	$	3.32
Effect of dilutive securities:
Options		—	135		—		(0.03	)		—			(0.03	)

Diluted EPS:
Net income	$	42,089	12,796	$	0.75	$	2.77		$	(0.23	)	$	3.29


Nine months ended September 30, 2002
Basic EPS:
Net income	$	5,599	12,563	$	0.21	$	0.24		$	—		$	0.45
Effect of dilutive securities:
Options		—	107		—		(0.01	)		—			(0.01	)

Diluted EPS:
Net income	$	5,599	12,670	$	0.21	$	0.23		$	—		$	0.44

The net income per share amounts do not include the effect of potentially dilutive securities of nil and 306,000 for the three months ended September 30, 2003 and 2002, respectively, and nil and 306,000 for the nine months ended September 30, 2003 and 2002, respectively, as the impact of these outstanding options was antidilutive.

NOTE 5 - HEDGING ACTIVITIES:

To reduce the impact of fluctuations in the market prices of oil and natural gas, the Company periodically utilizes hedging strategies such as collars or swaps to hedge the price of a portion of its future oil and natural gas production. Results of these hedging transactions are reflected in oil and natural gas sales in the month of hedged production.

No oil or natural gas hedges were outstanding during 2003. Hedging transactions for the three and nine months ended September 30, 2002 increased oil and gas revenues by $417,000 and $723,000, respectively, (reclassified from comprehensive income). All oil and gas hedging transactions expired in the fourth quarter of 2002.

The Company offsets any gain or loss on the swaps and collars contracts with the realized prices for its production. While the swaps and collars reduce the Company’s exposure to declines in the market price of natural gas and oil, this also limits the Company’s gains from increases in the market price.

In June, 2003 the Company entered into a costless collar foreign currency exchange transaction with a nominal amount of Canadian $42 million and a settlement date of August 8, 2003. In July, the Company exchanged, at no cost, the collar for a new collar with the nominal Canadian amount extended to October 16, 2003. At September 30, 2003, the fair value of these collars was a liability of $413,000, which was included in accrued liabilities. The decrease in fair value during the three and nine months ended September 30, 2003 of $277,000 and $413,000, respectively, is included in other income (expense).

NOTE 6 - PROPERTY, PLANT AND EQUIPMENT:

Investments in property, plant and equipment were as follows at September 30, 2003 and December 31, 2002 (amounts in thousands):

	2003			2002
Oil and gas properties:
Proved	$	241,227		$	225,414
Unproved		55			233

		241,282			225,647
Gas gathering facilities		1,698			1,698

		242,980			227,345
Less - accumulated depreciation, depletion, amortization and impairment		(186,892	)		(178,584	)

	$	56,088		$	48,761

As more fully described in the Company’s Form 10-K, PetroCorp utilizes the full cost method of accounting for costs related to its oil and natural gas properties. Under this method, capitalized costs are subject to a ceiling test, evaluated each quarter, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties. A decline in oil and gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future write-down of capitalized costs and a non-cash charge against future earnings.

NOTE 7 - LONG-TERM DEBT:

In July 2000, the Company entered into a $75 million revolving credit agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of Nova Scotia. The agreement was amended in August 2002 to extend its term, increase the borrowing base, and partially change the lenders. The amended term of the facility is through May 1, 2004 and the amended borrowing base was set at $70 million. In March 2003, and in conjunction with the sale of Canadian subsidiaries described in Note 3, the Company amended its revolving credit agreement to adjust the borrowing base to $25 million, allocated entirely to United States borrowing. The Canadian lenders were released from the agreement. All outstanding debt was paid off with proceeds from the sale. Effective April 28, 2003 the other lenders to the revolving credit agreement assigned their interests to the Bank of Oklahoma, N.A.

Borrowings can be funded by either Eurodollar loans or Base Rate loans. The interest rate on the borrowings is equal to an interest rate spread plus either the Eurodollar rate or the Base Rate. The interest rate spread is determined from a sliding scale based on the Company’s borrowing base percentage utilization in effect from time to time. The

spread ranges from 1.25 to 2.25 on Eurodollar loans and .25 to 1.25 on Base Rate loans. At September 30, 2003, there were no loans outstanding under this facility and $22 million (net of outstanding letters of credit of $3 million) was available for borrowing.

The revolving credit agreement prohibits the declaration and payment of dividends on the common stock of the Company. Also, the debt agreement requires the Company to maintain a minimum current ratio, a minimum tangible net worth, and a minimum interest coverage ratio. The Company obtained waivers of certain covenants relating to the sale of some of its Alabama properties and the sale of the Canadian operations.

NOTE 8 - RECENT ACCOUNTING PRONOUNCEMENTS:

Statement of Financial Accounting Standards No. 141, Business Combinations (FAS 141), and Statement of Financial Accounting Standards No. 142, Goodwill and Intangible Assets (FAS 142), were issued by the Financial Accounting Standards Board (FASB) in June 2001 and became effective for the Company on July 1, 2001, and January 1, 2002, respectively. FAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, FAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. FAS 142 establishes new guidelines for accounting and goodwill and other intangible assets. Under FAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on the Company’s balance sheets. In addition, the disclosures required by FAS 141 and 142 relative to intangibles would be included in the notes to financial statements. Historically, the Company has included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after FAS 141 and 142 became effective.

As applied to companies that have adopted full cost accounting for oil and gas activities, this interpretation of FAS 141 and 142, as described above, would only affect the Company’s balance sheet classification of proved oil and gas leaseholds acquired after June 30, 2001 and our unproved oil and gas leaseholds. The Company’s results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with full cost accounting rules.

At September 30, 2003, the Company had no undeveloped leasehold that would be classified on our balance sheet as “intangible undeveloped leasehold” and developed leaseholds of an estimated $1.4 million that would be classified as “intangible developed leasehold” if the Company applied the interpretation currently being considered. The Company will continue to classify oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.

In June 2001, the FASB issued FAS No. 143, Accounting for Asset Retirement Obligations. FAS 143 is effective for fiscal years beginning after June 15, 2002 (January 1, 2003 for the Company) and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for depleted wells) in the period in which the liability is incurred (at the time the wells are drilled). The effect of the adoption of this standard on the Company’s results of operations and financial condition was an unaudited increase in liabilities of approximately $5 million; an unaudited net increase in property, plant and equipment of approximately $259 thousand; and an unaudited after tax charge to income for the cumulative effect of adopting the new standard of approximately $3 million and a deferred tax asset of approximately $1.7 million. The new standard had no material impact on income before the cumulative effect of adoption in the nine months ended September 30, 2003, nor would it have had a material impact in the 2002 periods assuming an adoption of this accounting standard on a proforma basis on January 1, 2002. Accretion expense for the nine months ended September 30, 2003 was $221,000 and other changes to the dismantlement obligation were minimal for the same period. If FAS No. 143 had been applied retroactively, the effect would be an unaudited increase to liabilities of $2.4 million, $2.5 million and $5.4 million at December 31, 1999, 2000 and 2001. The impact on results of operations for those periods would be insignificant.

On January 17, 2003, the FASB issued FIN 46, Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51. The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities “VIE”) and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. The adoption of this standard had no impact on the financial position or results of operations of the Company.

In April 2003, the FASB issued FAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This Statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement is effective for contracts entered into or modified after June 30, 2003. The Company does not expect that adoption of this statement will have a significant effect on financial condition or results of operations.

In May 2003, the FASB issued FAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This Statement establishes standards to classify and measure certain financial instruments with characteristics of both liabilities and equity. It requires the classification of financial instruments within its scope as a liability (or asset in some circumstances). Based on financial instruments currently held by the Company, it does not expect that adoption of this statement will have a significant effect on financial condition and results of operations.

NOTE 9 - COMMON STOCK REPURCHASES:

On September 14, 2001, the Board of Directors authorized the purchase of up to 1,000,000 shares of the Company’s common stock. On March 5, 2003, the Board of Directors increased the number of shares authorized for purchase up to 25% of the outstanding shares of the Company. Through September 30, 2003, 354,087 shares have been purchased at a cost of $3,242,000.

NOTE 10 - SALE OF COMPANY:

On August 14, 2003, the Company announced that it had entered into a definitive agreement to be acquired by Unit Corporation. The agreement is subject to approval by the Company’s shareholders and other customary closing conditions and is expected to close in the fourth quarter of 2003 or early in 2004. If the merger is completed, the Company’s shareholders will be entitled to receive, for each share owned, a minimum of $13.37 in cash at the closing, plus up to $0.50 per share in the form of cash distributions from an escrow account set up to settle or satisfy certain of the Company’s contingent tax and litigation liabilities.

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

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in the Company’s 2002 Annual Report on form 10-K.

General

The Company’s principal line of business is the production and sale of its oil and natural gas reserves located in North America. Results of operations are dependent upon the quantity of production and the price obtained for such production. Prices received by the Company for the sale of its oil and natural gas have fluctuated significantly from period to period. Such fluctuations affect the Company’s ability to maintain or increase its production from existing oil and gas properties and to explore, develop or acquire new properties.

The following table reflects certain operating data for the periods presented:

	For the three months ended September 30,				For the nine months ended September 30,
	2003		2002		2003		2002
Production:
Oil (MBbls)		99		121		315		367
Gas (MMcf)		1,108		1,184		3,231		3,970
Total gas equivalents (MMcfe)		1,702		1,910		5,121		6,172

Average sales prices:
Oil (per Bbl)	$	29.47	$	26.55	$	30.23	$	23.47
Gas (per Mcf)		5.11		3.31		5.57		2.96

Selected data per Mcfe:
Average sales price	$	5.04	$	3.73	$	5.38	$	3.30
Production costs		1.71		1.46		1.54		1.28
General and administrative expenses		0.42		0.26		0.39		0.20
Oil and gas depreciation, depletion and amortization		1.09		0.93		0.99		1.00

Results of Operations

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002

Revenues. Total revenues increased 20% to $8.7 million in the third quarter of 2003 compared to $7.3 million in the third quarter of 2002, primarily due to commodity price increases. The Company’s natural gas production decreased 6% to 1,108 MMcf from 1,184 MMcf and oil production decreased 18% to 99 MBbls from 121 MBbls, resulting in the Company’s overall equivalent production decreasing 11% to 1,702 MMcfe from 1,910 MMcfe. The decrease in oil and gas production reflects the impact of the October 2002 sale of the Alabama properties and plant, along with normal production declines.

The Company’s average natural gas price increased 54% to $5.11 per Mcf in the third quarter of 2003 from $3.31 per Mcf in the corresponding quarter in 2002. The Company’s average oil price increased 11% to $29.47 per barrel in the third quarter of 2003 from $26.55 per barrel in 2002. Of the $1,451,000 increase in oil and gas sales in the third quarter of 2003, approximately $2.0 million and $0.3 million, respectively, were attributable to increased average gas pricing and oil pricing, and these were partially offset by $0.8 million of decreased oil and gas production.

Production Costs. Production costs increased overall 5% to $2.9 million in the third quarter of 2003, while production costs per Mcfe increased to $1.71 per Mcfe in the third quarter of 2003, compared to $1.46 in the corresponding prior year period. This resulted from the effects of higher commodity price on production taxes (a component of production costs) and approximately $220 thousand more non-recurring well expenses in the quarter ended September 30, 2003.

Depreciation, Depletion & Amortization (DD&A). Total DD&A increased 5% to $1.9 million in the third quarter of 2003. The composite oil and gas DD&A rate increased 17% to $1.09 per Mcfe from $0.93 per Mcfe. The increase in the composite rate is due to substantial drilling and completion costs incurred in the third quarter, partially offset by the impact of adopting FASB Statement 143 (see Note 8 to the financial statements).

General and Administrative Expenses. General and administrative expenses increased 42% to $719,000 in the third quarter of 2003 from $506,000 in the third quarter of 2002 due to increased costs related to an increased company stock price and its related effect on certain stock options, higher legal costs associated with general corporate matters and with ongoing litigation related to the Mackie lawsuit, more fully described in footnote 13 of the financial statements in Form 10-K for the period ending December 31, 2002, and the full cost of certain expenses which previously had been partially absorbed by the Canadian operation now shown as discontinued operations (see Note 3).

Interest Expense. Interest expense decreased 73% to $74,000 in the third quarter of 2003 from $276,000 in the prior year quarter, reflecting the pay down of outstanding debt. Although all debt was paid off March 6, 2003, the Company continues to amortize the loan facility origination cost since the facility remains open for Company use.

Other Income (Expense). Other income (expense) decreased to ($773,000) in the third quarter of 2003 from ($247,000) in the corresponding period of 2002 primarily due to realized translation losses on the receivable from the sale of Canadian subsidiaries and a $413,000 (loss) mark-to-market adjustment related to the foreign currency hedge.

Income Taxes. The Company recorded a $868,000 income tax expense with an effective tax rate of 34% on a pre-tax income of $2,555,000 in the third quarter of 2003. This compares to an income tax expense of $675,000 with an effective tax rate of 41% on pre-tax income of $1,634,000 in the third quarter of 2002. Effective tax rates differ from statutory rates primarily due to statutory depletion in the United States.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002

Revenues. Total revenues increased 35% to $27.9 million in the first nine months of 2003 compared to $20.6 million in the first nine months of 2002, primarily due to commodity price increases. The Company’s natural gas production decreased 19% to 3,231 MMcf from 3,970 MMcf and oil production decreased 14% to 315 MBbls from 367 MBbls, resulting in the Company’s overall equivalent production decreasing 17% to 5,121 MMcfe from 6,172 MMcfe. The decrease in oil and gas production reflects the impact of the October 2002 sale of the Alabama properties and plant, along with normal production declines.

The Company’s average natural gas price increased 88% to $5.57 per Mcf in the first nine months of 2003 from $2.96 per Mcf in the corresponding period of 2002. The Company’s average oil price increased 29% to $30.23 per barrel in the first nine months of 2003 from $23.47 per barrel in 2002. Of the $7,159,000 increase in oil and gas sales in the first nine months of 2003, approximately $8.5 million and $2.1 million, respectively, were attributable to increased average gas pricing and oil pricing, and these were partially offset by $3.4 million of decreased oil and gas production.

Production Costs. Production costs increased overall less than 1% to $7.9 million in the first nine months of 2003, while production costs per Mcfe increased to $1.54 per Mcfe in the first nine months of 2003, compared to $1.28 in the corresponding prior year period. This resulted from the effects of higher commodity price on production taxes (a component of production costs) and approximately $312 thousand more non-recurring well expenses in the nine months ended September 30, 2003.

Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 17% to $5.2 million in the first nine months of 2003. The composite oil and gas DD&A rate decreased 1% to $0.99 per Mcfe from $1.00 per Mcfe. The decrease in the composite rate results from the impact of adopting FASB Statement 143 (see Note 8 to the financial statements).

General and Administrative Expenses. General and administrative expenses increased 61% to $1,999,000 in the first nine months of 2003 from $1,244,000 in the first nine months of 2002 due to increased costs related to an increased company stock price and its related effect on certain stock options, higher legal costs associated with general corporate matters and with ongoing litigation related to the Mackie lawsuit, more fully described in footnote 13 of the financial statements in Form 10-K for the period ending December 31, 2002, and the full cost of certain expenses which previously had been partially absorbed by the Canadian operation now shown as discontinued operations (see Note 3).

Interest Expense. Interest expense decreased 60% to $490,000 in the first nine months of 2003 from $1,226,000 in the prior year period, reflecting the pay down of outstanding debt. Although all debt was paid off March 6, 2003, the Company continues to amortize the loan facility origination cost since the facility remains open for company use.

Other Income (Expense). Other income (expense) increased to $2,361,000 in the first nine months of 2003 from $8,000 in the corresponding period of 2002. The 2003 balance primarily arose from the impact of translation rate changes on the receivable from the sale of the Canadian subsidiaries, which occurred in the first quarter of 2003.

Income Taxes. The Company recorded a $5,429,000 income tax expense with an effective tax rate of 36% on a pre-tax income of $15,047,000 in the first nine months of 2003. This compares to an income tax expense of $1,412,000 with an effective tax rate of 35% on pre-tax income of $4,050,000 in the first nine months of 2002. Effective tax rates differ from statutory rates primarily due to statutory depletion in the United States.

Liquidity and Capital Resources

As of September 30, 2003, the Company had working capital of $92.7 million as compared to $55.8 million at December 31, 2002. Net cash provided by operating activities was $22.0 million for the nine months ended September 30, 2003 compared to $21.1 million for the corresponding nine months of 2002 primarily due to increased oil and gas prices.

The Company’s total capital expenditures were $13.5 million and $7.4 million for the nine months ended September 30, 2003 and 2002, respectively, primarily related to exploration and development.

No sales of oil and gas properties occurred in the first nine months of either 2003 or 2002. However, as described in Note 3 to the financial statements, the Company sold its Canadian subsidiaries, and the oil and gas properties contained therein, for approximately $112 million, with a closing date of March 5, 2003.

In July 2000, the Company entered into a $75 million revolving credit agreement with the Toronto-Dominion Bank (TD Bank), the agent, and the Bank of Nova Scotia. The amended term of the facility is through May 1, 2004 and the current borrowing base is set at $25 million. Borrowings can be funded by either Eurodollar loans or Base Rate loans. The interest rate on the borrowings is equal to an interest rate spread plus either the Eurodollar rate or the Base Rate. The interest spread is determined from a sliding scale based on the Company’s borrowing base percentage utilization in effect from time to time. The spread ranges from 1.25 to 2.25 on Eurodollar loans and .25 to 1.25 on Base Rate loans. At September 30, 2003, the Company had no debt outstanding under the revolver and $22 million was available based on the current $25 million borrowing base, as defined, subject to certain limitations, reduced by outstanding letters of credit of $3 million. During the first quarter of 2003, the average interest rate under this facility was approximately 4.1% and no debt was outstanding during the second or third quarters. Effective April 28, 2003 the other lenders to the revolving credit agreement assigned their interests to the Bank of Oklahoma, N.A.

The Company has historically funded its capital expenditures, which are discretionary, and working capital requirements with cash flow from operations, debt and equity capital and participation by institutional investors. If the Company does not complete its planned merger with Unit Corp and increases its capital expenditure level in the future or operating cash flow is not as expected, capital expenditures may require additional funding, obtained through borrowings from commercial banks and other institutional sources or by public or private offerings of equity or debt securities.

Common Stock Repurchases

Other

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The Company’s primary sources of market risk are from fluctuations in commodity prices, interest rates and exchange rates.

Commodity Price Risk

The Company produces and sells natural gas, crude oil, condensate and natural gas liquids. As a result, the Company’s financial results can be significantly affected as these commodity prices fluctuate widely in response to changing market forces. The Company has previously utilized hedging transactions to manage its exposure to price fluctuations on its sales of oil and natural gas.

No oil or natural gas hedges were outstanding during 2003. Hedging transactions for the three and nine months ended September 30, 2002 increased oil and gas revenues by $417,000 and $723,000, respectively (reclassified from comprehensive income). All oil and gas hedging transactions expired in the fourth quarter of 2002.

Foreign Currency Risk

In June 2003, the Company entered into a costless collar foreign currency exchange transaction with a nominal amount of Canadian $42 million and a settlement date of August 8, 2003. In July, the company exchanged, at no cost, the collar for a new collar with the nominal Canadian amount extended to October 16, 2003. At September 30, 2003, the fair value of these collars was a liability of $413,000, which was included in accrued liabilities. The decrease in fair value during the three and nine months ended September 30, 2003 of $277,000 and $413,000, respectively, is included in other income (expense).

Item 4. Controls and Procedures

As required by Rule 13a-15(b), PetroCorp management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation as of the end of the period covered by this report, of the effectiveness of the Company’s disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report. As required by Rule 13a-15(d), PetroCorp management, including the Chief Executive Officer and Chief Financial Officer, also conducted an evaluation of the Company’s internal control over financial reporting to determine whether any changes occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Based on that evaluation, there has been no such change during the quarter covered by this report.

PART II. OTHER INFORMATION

Item 1 - Legal Proceedings

Not Applicable

Item 2 - Changes in Securities

Not Applicable

Item 3 - Defaults upon Senior Securities

Not Applicable

Item 4 - Submission of Matters to Vote of Security Holders

Not Applicable

Item 5 - Other Information

Not Applicable

Item 6 -

(a) Exhibits


Exhibit 31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 31.2		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 32		Certification 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

Report dated August 8, 2003 in which PetroCorp Incorporated reported quarterly and year-to-date earnings as of June 30, 2003.

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 duly authorized officer.

		PETROCORP INCORPORATED
		(Registrant)

Date: November 14, 2003		/s/ STEVEN R. BERLIN
		Steven R. Berlin
		Chief Financial Officer and Secretary
		(On behalf of the Registrant and as the
		Principal Financial Officer)

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PETROCORP INC 10-Q