SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly period ended June 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 July 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 June 30, 2003 and December 31, 2002		1

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

Condensed Consolidated Statements of Cash Flows for the six months ended June 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		18

Item 4. Controls and Procedures		18

PART II. OTHER INFORMATION		19

SIGNATURES		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)

	June 30, 2003			December 31, 2002
Assets
Current assets:
Cash and cash equivalents	$	59,965		$	3,087
Accounts receivable, net		11,531			11,537
Receivable from sale of Canadian subsidiaries		31,939			—
Assets of discontinued operations		—			72,300
Current portion of deferred taxes		740			—
Other current assets		1,150			1,107

Total current assets		105,325			88,031

Property, plant and equipment:
Oil and gas properties, at cost, full cost method, net of accumulated depreciation, depletion, amortization and impairment		51,573			48,761
Deferred income taxes		4,738			22,066
Other assets, net		2,919			2,723

Total assets	$	164,555		$	161,581

Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable	$	7,393		$	7,367
Accrued liabilities		2,350			2,758
Current income tax payable		319			—
Liabilities of discontinued operations		—			22,111

Total current liabilities		10,062			32,236

Long-term debt		—			28,750

Dismantlement obligation		5,119			—

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, 12,655,046 and 12,645,309 shares outstanding as of June 30, 2003 and December 31, 2002, respectively		130			130
Additional paid-in capital		112,364			111,905
Retained earnings (accumulated deficit)		39,757			(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		149,009			100,595

Total liabilities and shareholders’ equity	$	164,555		$	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 June 30,						For the six months ended June 30,
	2003			2002			2003			2002
Revenues:
Oil and gas	$	9,148		$	7,115		$	18,951		$	13,243
Other		178			57			216			105

		9,326			7,172			19,167			13,348

Expenses:
Production costs		2,467			2,507			4,995			5,091
Depreciation, depletion and amortization		1,768			2,130			3,293			4,450
General and administrative		561			375			1,280			738
Other operating expenses		21			32			55			64

		4,817			5,044			9,623			10,343

Income from operations		4,509			2,128			9,544			3,005

Other income (expenses):
Investment income		211			95			230			106
Interest expense		(81	)		(426	)		(416	)		(850	)
Other income (expenses)		2,918			222			3,134			255

		3,048			(109	)		2,948			(489	)

Income from continuing operations before income taxes and accounting change		7,557			2,019			12,492			2,516

Income tax provision:
Current		(99	)		(10	)		1,651			(27	)
Deferred		2,880			573			2,910			764

		2,781			563			4,561			737

Income from continuing operations before accounting change		4,776			1,456			7,931			1,779
Discontinued operations:
Income from discontinued Canadian operations (net of applicable taxes of nil, $816, $1,530 and $1,248)		—			924			2,113			1,647
Gain on sale of Canadian subsidiaries (net of taxes of $80 and $19,771)		138			—			33,664			—

Income before cumulative effect of a change in accounting principle		4,914			2,380			43,708			3,426
Cumulative effect on prior years of accounting change, less applicable income taxes of $1,743		—			—			(2,969	)		—

Net income	$	4,914		$	2,380		$	40,739		$	3,426

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	$	0.38	$	0.12	$	0.62		$	0.14
Income from discontinued operations		0.01		0.07		2.83			0.13
Cumulative effect of change in accounting principle		—		—		(0.23	)		—

Net income	$	0.39	$	0.19	$	3.22		$	0.27

Net income per common share—diluted
Income from continuing operations	$	0.37	$	0.12	$	0.62		$	0.14
Income from discontinued operations		0.01		0.07		2.80			0.13
Cumulative effect of change in accounting principle		—		—		(0.23	)		—

Net income	$	0.38	$	0.19	$	3.19		$	0.27

Weighted average number of common shares—basic		12,650		12,561		12,649			12,559

Weighted average number of common shares—diluted		12,779		12,685		12,765			12,680

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

PETROCORP INCORPORATED

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	For the six months ended June 30,
	2003			2002
Cash flows from operating activities:
Net income	$	40,739		$	3,426
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		3,293			4,450
Deferred income tax expense		2,910			764
Gain on sale of Canadian subsidiaries		(33,664	)		—
Cumulative effect of change in accounting principal		2,969			—
Translation adjustment to receivable from sale of Canadian subsidiaries		(2,881	)		—
Other		(27	)		64
Changes in operating assets and liabilities:
Accounts receivable		6			1,961
Other current assets		(43	)		290
Accounts payable		26			110
Accrued liabilities		656			697
Income tax payable		319			—
Net change provided by discontinued operations		(105	)		385

Net cash (used) provided by operating activities		14,198			12,147

Cash flows from investing activities:
Additions to oil and gas properties		(6,496	)		(1,967	)
Proceeds received on sale of Canadian subsidiaries (SEE NOTE 3)		80,135			—
Net investing activities of discontinued operations		(1,596	)		(2,371	)
Other		(71	)		—

Net cash used in investing activities		71,972			(4,338	)

Cash flows from financing activities:
Proceeds from long-term debt		—			300
Repayment of long-term debt		(28,750	)		(2,300	)
Other		(71	)		218
Net financing activities of discontinued operations		(471	)		(3,641	)

Net cash used in financing activities		(29,292	)		(5,423	)

Effect of exchange rate changes on cash		—			(58	)

Net increase (decrease) in cash and cash equivalents		56,878			2,328
Cash and cash equivalents at beginning of period		3,087			1,265

Cash and cash equivalents at end of period	$	59,965		$	3,593

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 condensed 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 June 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 June 30,				Six Months Ended June 30,
	2003		2002		2003		2002
Net income, as reported	$	4,914	$	2,380	$	40,739	$	3,426
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		39		133		119		166

Pro forma net income	$	4,875	$	2,247	$	40,620	$	3,260

Earnings per share:
Basic—as reported	$	0.39	$	0.19	$	3.22	$	0.27
Basic—pro forma	$	0.39	$	0.18	$	3.21	$	0.26

Diluted—as reported	$	0.38	$	0.19	$	3.19	$	0.27
Diluted—pro forma	$	0.38	$	0.18	$	3.18	$	0.26

Options to acquire 35,000 shares at an exercise price of $12.65 were granted during the quarter ended June 30, 2003. Thirty-five thousand options, at an exercise price of $9.50 were granted in the corresponding quarter of 2002. These options, when priced under a Black-Scholes option pricing model calculate a “fair value” of $233,000 and $198,000, respectively, as of the grant dates. For the six months ended June 30, 2003 and 2002, the “fair value” of granted options, when priced under a Black-Scholes pricing model was, respectively, $233,000 and $677,000. The Black-Scholes model was developed to price options with terms and conditions significantly different from the terms and conditions of the Company’s options; accordingly, any use for this resultant “fair value” is problematic.

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 six months ended June 30, 2003 and 2002 is as follows (in thousands):

	For the three months ended June 30,				For the six months ended June 30,
	2003		2002		2003		2002
Net income	$	4,914	$	2,380	$	40,739	$	3,426

Derivative hedging gain/(loss) (net of taxes of ($83) and $290)		—		153		—		(445	)
Reclassification of hedging loss to income (net of taxes of $68 and $180)		—		115				283
Reclassification of translation loss to income		—		—		4,939		—
Foreign currency translation gain (loss) (2003 gain covers period from January 1 through March 5)		—		1,993		2,807		1,910

		—		2,261		7,746		1,748

Comprehensive income	$	4,914	$	4,641	$	48,485	$	5,174

As of June 30, 2002, accumulated other comprehensive loss consisted of $730 of derivative gain, net of taxes, and $6,293 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 Canadian $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. The remaining $31.9 million, which is receivable in Canadian dollars, is adjusted using the exchange rate at the end of the period and, accordingly, the second quarter includes an adjustment of $2.9 million. The receivable will be received upon completion of certain tax documentation with the government of Canada. See Note 5 regarding the hedging of foreign currency. 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)		29,058

Net proceeds		109,193

Net assets sold		55,168
Translation loss reclassified from comprehensive income		4,939
Deferred income taxes		15,422

		75,529

Gain on sale of Canadian subsidiaries	$	33,664

(a)

Receivable does not include subsequent translation gain and escrow interest.

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

	Six months ended June 30,
	2003		2002
Net sales	$	5,937	$	11,020

Pre-tax income from discontinued operations	$	3,643	$	2,895
Income tax expense		1,530		1,248

Income from discontinued operations, net of tax	$	2,113	$	1,647

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).

				Per Share Amounts
	Income		Shares	Income (Loss) from Continuing Operations			Income from Discontinued Operations		Cumulative Effect of Accounting Change		Net Income
Three months ended June 30, 2003
Basic EPS:
Net income	$	4,914	12,650	$	0.38		$	0.01	$	—	$	0.39
Effect of dilutive securities:
Options		—	129		(0.01	)		—		—		(0.01	)

Diluted EPS:
Net income	$	4,914	12,779	$	0.37		$	0.01	$	—	$	0.38

Three months ended June 30, 2002
Basic EPS:
Net income	$	2,380	12,561	$	0.12		$	0.07	$	—	$	0.19
Effect of dilutive securities:
Options		—	124		—			—		—		—

Diluted EPS:
Net income	$	2,380	12,685	$	0.12		$	0.07	$	—	$	0.19

				Per Share Amounts
	Income		Shares	Income (Loss) from Continuing Operations		Income from Discontinued Operations			Cumulative Effect of Accounting Change			Net Income
Six months ended June 30, 2003
Basic EPS:
Net income	$	40,739	12,649	$	0.62	$	2.83		$	(0.23	)	$	3.22
Effect of dilutive securities:
Options		—	116		—		(0.03	)		—			(0.03	)

Diluted EPS:
Net income	$	40,739	12,765	$	0.62	$	2.80		$	(0.23	)	$	3.19

Six months ended June 30, 2002
Basic EPS:
Net income	$	3,426	12,559	$	0.14	$	0.13		$	—		$	0.27
Effect of dilutive securities:
Options		—	121		—		—			—			—

Diluted EPS:
Net income	$	3,426	12,680	$	0.14	$	0.13		$	—		$	0.27

The net income per share amounts do not include the effect of potentially dilutive securities of 35,000 and 405,610 for the three months ended June 30, 2003 and 2002, respectively, and 35,000 and 405,610 for the six months ended June 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 six months ended June 30, 2002 increased oil and gas revenues by $204,000 and $306,000, 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. At June 30, 2003, the fair value of these collars was a liability of $126,000, which was included in accrued liabilities and other expenses. In July, the Company exchanged, at no cost, the collar for a new collar with the nominal Canadian amount of $42 million extended to October 16, 2003.

NOTE 6—PROPERTY, PLANT AND EQUIPMENT:

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

	2003			2002
Oil and gas properties:
Proved	$	232,986		$	225,414
Unproved		233			233

		233,219			225,647
Gas gathering facilities		1,698			1,698

		234,917			227,345

Less—accumulated depreciation, depletion, amortization and impairment		(183,344	)		(178,584	)

	$	51,573		$	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 June 30, 2003, there were no loans outstanding under this facility.

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 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 in June 2001 and became effective for the Company on July 1, 2001, and January 1, 2002, respectively. The majority of the oil and natural gas industry did not change its accounting and disclosures for mineral interest use rights (leasehold acquisition costs) upon the implementation of FAS 141 and 142. However, an interpretation of FAS 141 and 142 is being deliberated by the Securities and Exchange Commission (SEC), Financial Accounting Standards Board (FASB) and others as to whether mineral interest use rights in oil and natural gas properties are intangible assets. Under this interpretation mineral interest use rights for both undeveloped and developed leaseholds would be classified as an asset separate from oil and natural gas properties as intangible assets. The classification as an intangible asset would not affect how these items are accounted for under the full cost method of accounting with respect to the calculation of depreciation, depletion and amortization or the calculation of the ceiling test of oil and natural gas properties. The amounts at December 31, 2002 and June 30, 2003 that would be classified as “intangible undeveloped leasehold” or “intangible developed leasehold” if the Company applied the interpretation currently being deliberated is insignificant. The portion of developed leasehold that would be reclassified represents the costs of developed leaseholds acquired or transferred to the full cost pool subsequent to June 30, 2001, the effective date of FAS 141.

Additionally, FAS 142 requires that certain disclosures be made for all intangible assets. The Company has not made the disclosures set forth under FAS 142 related to the use rights of mineral interests. The Company has continued to make the disclosures required by Statement of Financial Accounting Standards No. 69 “Disclosures about Oil and Gas Producing Activities” (FAS 69). We will continue to classify use rights of mineral interests in oil and gas properties until further guidance is provided that might result from the deliberations described above.

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 first and second quarter of 2003, nor would it have had a material impact in the first and second quarter of 2002 assuming an adoption of this accounting standard on a proforma basis. Accretion expense for the six months ended June 30, 2003 was $148,000 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 dates would be insignificant.

In July 2002, the FASB issued FAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which is effective for exit or disposal activities initiated after December 31, 2002. The adoption of FAS No. 146 did not materially affect the Company’s current financial position or results of operations.

In November 2002, the FASB issued FASB Interpretation (“FIN”) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantee of Indebtedness of Others. FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN 45’s provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The guarantor’s previous application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. The Company is not a guarantor under any significant guarantees and thus the adoption of this interpretation did not have a significant effect on the Company’s financial position or results of operations.

On December 31, 2002, the FASB issued FAS No. 148, Accounting for Stock-Based Compensation—Transition

and Disclosure—an amendment of FAS 123, Accounting For Stock-Based Compensation. FAS 148 does not change the provisions of FAS 123 that permit entities to continue to apply the intrinsic value method of APB 25, Accounting for Stock Issued to Employees. FAS 148 does require certain new disclosures in both annual and interim financial statements. The required disclosures have been included in Note 1 of the Company’s financial statements.

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 thought 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 on (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 position and 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 June 30, 2003, the Company had purchased 354,087 shares at a cost of $3,242,000.

NOTE 10—SUBSEQUENT EVENT:

On July 1, 2003, the Company announced that it has entered into a letter of intent to be acquired by Unit Corporation (“Unit”) for approximately $190 million, comprised of 2 million shares of Unit common stock and the remainder in cash. The sales price is subject to normal adjustments for transaction of this type. The transaction is subject to execution of a definitive agreement and all necessary consents, including PetroCorp shareholder approval.

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, except as follows:

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 June 30,				For the six months ended June 20,
	2003		2002		2003		2002
Production:
Oil (MBbls)		102		121		216		246
Gas (MMcf)		1,185		1,319		2,123		2,786
Total gas equivalents (MMcfe)		1,797		2,045		3,419		4,262

Average sales prices:
Oil (per Bbl)	$	28.00	$	24.15	$	30.56	$	22.00
Gas (per Mcf)		5.31		3.17		5.82		2.81

Selected data per Mcfe:
Average sales price	$	5.09	$	3.48	$	5.54	$	3.11
Production costs		1.37		1.23		1.46		1.19
General and administrative expenses		0.31		0.18		0.37		0.17
Oil and gas depreciation, depletion and amortization		0.96		1.03		0.94		1.03

Results of Operations

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

Revenues. Total revenues increased 30% to $9.3 million in the second quarter of 2003 compared to $7.2 million in the second quarter of 2002, primarily due to commodity price increases. The Company’s natural gas production decreased 10% to 1,185 MMcf from 1,319 MMcf and oil production decreased 16% to 102 MBbls from 121 MBbls, resulting in the Company’s overall equivalent production decreasing 12% to 1,797 MMcfe from 2,045 MMcfe. The decrease in oil and gas production reflects the impact of the October 2002 sale of Alabama properties and plant, along with normal production declines.

The Company’s average natural gas price increased 67% to $5.31 per Mcf in the second quarter of 2003 from $3.17 per Mcf in the corresponding quarter in 2002. The Company’s average oil price increased 16% to $28.00 per barrel in the second quarter of 2003 from $24.15 per barrel in 2002. Of the $2,033,000 increase in oil and gas sales in the second quarter of 2003, approximately $2.5 million and $0.4 million, respectively, were attributable to increased average gas pricing and oil pricing, and these were partially offset by a $0.9 million of decreased oil and gas production.

Production Costs. Production costs decreased overall 2% to $2.5 million in the second quarter of 2003, while production costs per Mcfe increased to $1.37 per Mcfe in the second quarter of 2003, compared to $1.23 in the corresponding prior year period. This resulted from production volume decreases, both from normal production declines and the October 2002 sale of Alabama properties and plant, being almost fully offset by higher production taxes due to higher commodity prices.

Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 17% to $1.8 million in the second quarter of 2003. The composite oil and gas DD&A rate decreased 7% to $0.96 per Mcfe from $1.03 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 50% to $561,000 in the second quarter of 2003 from $375,000 in the second quarter of 2002 due to higher legal costs associated with ongoing litigation 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 81% to $81,000 in the second quarter of 2003 from $426,000 in the prior year quarter, reflecting pay down of outstanding debt. All debt was paid off March 6, 2003.

Other Income. Other income increased to $2,918,000 in the second quarter of 2003 from $222,000 in the corresponding period of 2002 primarily due to a $2,881,000 translation adjustment on the receivable from sale of Canadian subsidiaries.

Income Taxes. The Company recorded a $2,781,000 income tax expense with an effective tax rate of 37% on a pre-tax income of $7,557,000 in the second quarter of 2003. This compares to an income tax expense of $563,000 with an effective tax rate of 28% on pre-tax income of $2,019,000 in the second quarter of 2002. Effective tax rates differ from statutory rates primarily due to statutory depletion in the United States.

Six Months Ended June 30, 2003 Compared to six Months Ended June 30, 2002

Revenues. Total revenues increased 44% to $19.2 million in the first half of 2003 compared to $13.3 million in the first half of 2002, primarily due to commodity price increases. The Company’s natural gas production decreased 24% to 2,123 MMcf from 2,786 MMcf and oil production decreased 12% to 216 MBbls from 246 MBbls, resulting in the Company’s overall equivalent production decreasing 20% to 3,419 MMcfe from 4,262 MMcfe. The decrease in oil and gas production reflects the impact of the October 2002 sale of Alabama properties and plant, along with normal production declines.

The Company’s average natural gas price increased 107% to $5.82 per Mcf in the first half of 2003 from $2.81 per Mcf in the corresponding period of 2002. The Company’s average oil price increased 39% to $30.56 per barrel in the first half of 2003 from $22.00 per barrel in 2002. Of the $5,708,000 increase in oil and gas sales in the first half of 2003, approximately $6.4 million and $1.8 million, respectively, were attributable to increased average gas pricing and oil pricing, and these were partially offset by a $2.5 million of decreased oil and gas production.

Production Costs. Production costs decreased overall 2% to $5.0 million in the first half of 2003, while production costs per Mcfe increased to $1.46 per Mcfe in the first half of 2003, compared to $1.19 in the corresponding prior year period. This resulted from production volume decreases, both from normal production declines and the October 2002 sale of Alabama properties and plant, being almost fully offset by higher production taxes due to higher commodity prices.

Depreciation, Depletion & Amortization (DD&A). Total DD&A decreased 26% to $3.3 million in the first half of 2003. The composite oil and gas DD&A rate decreased 9% to $0.94 per Mcfe from $1.03 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 73% to $1,280,000 in the first half of 2003 from $738,000 in the first half of 2002 due to increased costs related to an increased company stock price and its effect on certain stock options, higher legal costs associated with ongoing litigation 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 51% to $416,000 in the first half of 2003 from $850,000 in the prior year period, reflecting pay down of outstanding debt. All debt was paid off March 6, 2003.

Other Income. Other income increased to $3,134,000 in the first half of 2003 from $255,000 in the corresponding period of 2002. This increase was primarily due to a $2,881,000 translation adjustment in the second quarter on the receivable from sale of Canadian subsidiaries.

Income Taxes. The Company recorded a $4,561,000 income tax expense with an effective tax rate of 37% on a pre-tax income of $12,492,000 in the first half of 2003. This compares to an income tax expense of $737,000 with an effective tax rate of 29% on pre-tax income of $2,516,000 in the first half of 2002. Effective tax rates differ from statutory rates primarily due to statutory depletion in the United States.

Liquidity and Capital Resources

As of June 30, 2003, the Company had working capital of $95.3 million as compared to $55.8 million at December 31, 2002. Net cash provided by operating activities was $14.2 million for the six months ended June 30, 2003 compared to $12.1 million for the corresponding six months of 2002 primarily due to increased oil and gas prices.

The Company’s total capital expenditures were $6.5 million and $2.0 million for the six months ended June 30, 2003 and 2002, respectively, primarily related to exploration and development.

No sales of oil and gas properties occurred in the first six 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 June 30, 2003, the Company had no debt outstanding under the revolver and $25 million available based on the current borrowing base, as defined, subject to certain limitations. 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 quarter. 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 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.

Other

requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. The Company is not a guarantor under any significant guarantees and thus the adoption of this interpretation did not have a significant effect on the Company’s financial position or results of operations.

On December 31, 2002, the FASB issued FAS No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure—an amendment of FAS 123, Accounting For Stock-Based Compensation. FAS 148 does not change the provisions of FAS 123 that permit entities to continue to apply the intrinsic value method of APB 25, Accounting for Stock Issued to Employees. FAS 148 does require certain new disclosures in both annual and interim financial statements. The required disclosures have been included in Note 1 of the Company’s financial statements.

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 six months ended June 30, 2002 increased oil and gas revenues by $204,000 and $306,000 (reclassified from comprehensive income). All oil and gas hedging transactions expired in the fourth quarter of 2002.

Common Stock Repurchases

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

(A) May 29, 2003 Annual shareholders meeting

(1) Election of Lealon L. Sargent, Paul S. Coughlin III, Mark W. Files, and Thomas R. Fuller as directors of the Company

	Number of Votes
		Abstentions and
	For	Against	Broker Non-Votes
Coughlin, Files and Fuller	10,327,731	958	7,556
Sargent	10,323,955	4,734	7,556

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 July 1, 2003 concerning the signing of letter of intent to sell PetroCorp Incorporated to Unit Corporation for cash and stock.

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: August 8, 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