United States
Securities and Exchange Commission
Washington, D. C. 20549

Form 10-Q

(Mark one)

[ X ] Quarterly Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Quarterly Period Ended June 30, 2003

[ ] Transition Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Transition Period from .......... to ..........

Commission File Number .......... 1-12508

MAGNUM HUNTER RESOURCES, INC.
Exact name of registrant as specified in its charter

Nevada		87-0462881
State or other jurisdiction of incorporation or organization		IRS employer identification No.

600 East Las Colinas Blvd., Suite 1100, Irving, Texas 75039
Address of principal executive offices

(972) 401-0752

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X] No [ ]

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

State the number of shares outstanding of each of the issuer's classes of common equity, as of August 1, 2003: 67,243,038.

PART 1 — FINANCIAL INFORMATION

Item 1. Financial Statements

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)

	June 30, 2003			December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	9,246		$	3,069
Restricted cash		944			682
Accounts receivable - trade, net of allowance of $4,521 and $4,573,
respectively		59,049			53,864
Deposits		978			8,856
Income tax refund receivable		46			9,966
Other current assets		22,932			21,659

Total Current Assets		93,195			98,096

Property, Plant, and Equipment
Oil and gas properties, full cost method
Unproved		179,953			165,676
Proved		1,150,795			1,053,426
Gas processing plants and pipelines		34,073			33,951
Other property		6,966			6,636

Total Property, Plant and Equipment		1,371,787			1,259,689
Accumulated depreciation, depletion, amortization and impairment		(297,623	)		(258,080	)

Net Property, Plant and Equipment		1,074,164			1,001,609

Other Assets
Goodwill		58,463			50,710
Other assets		17,000			19,364

Total Assets	$	1,242,822		$	1,169,779

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Trade payables and accrued liabilities	$	134,944		$	114,079
Accrued interest		9,707			10,327
Due to affiliates		3,423			2,848
Current portion of long-term debt		1,987			1,865

Total Current Liabilities		150,061			129,119

Long-Term Liabilities
Long-term debt, less current maturities		575,998			569,086
Asset retirement obligations		29,670			--
Derivative liabilities, noncurrent		7,759			3,316
Deferred income taxes payable		130,850			118,062
Stockholders' Equity
Preferred stock - $.001 par value; 10,000,000 shares authorized, 216,000
designated as Series A; 80,000 issued and outstanding, liquidation amount $0		1			1
Common Stock - $.002 par value; 100,000,000 shares authorized,
71,730,830 and 71,707,897 shares issued, respectively		144			143
Additional paid-in capital		423,947			423,364
Accumulated other comprehensive loss		(31,095	)		(26,902	)
Accumulated deficit		(8,954	)		(21,114	)
Common stock in deferred compensation plan at cost (34,416 shares)		(192	)		--
Unearned common stock in KSOP, at cost (1,242,868 and 757,246 shares,
respectively)		(7,599	)		(4,888	)

		376,252			370,604
Treasury stock, at cost (4,489,992 and 3,168,013 shares, respectively) .		(27,768	)		(20,408	)

Total Stockholders' Equity		348,484			350,196

Total Liabilities and Stockholders' Equity	$	1,242,822		$	1,169,779

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

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in thousands, except for per share amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Operating Revenues:
Oil and gas sales	$	68,470		$	70,543		$	138,060		$	109,693
Gas gathering, marketing and processing		9,055			4,596			18,440			8,178
Oil field management services		913			1,051			1,992			1,443

Total Operating Revenues		78,438			76,190			158,492			119,314

Operating Costs and Expenses:
Oil and gas production lifting costs		13,498			15,438			26,446			24,386
Production taxes and other costs		7,930			7,922			17,107			12,225
Gas gathering, marketing and processing		6,882			3,466			13,428			6,146
Oil field services		593			543			1,450			819
Depreciation, depletion, amortization and accretion		24,978			23,542			46,502			38,638
Gain on sale of assets		(46	)		--			(140	)		--
General and administrative		3,159			4,223			6,341			6,747

Total Operating Costs and Expenses		56,994			55,134			111,134			88,961

Operating Profit		21,444			21,056			47,358			30,353
Equity in earnings (loss) of affiliate		(525	)		81			(237	)		382
Other income		260			108			378			165
Provision for impairment of investments		--			(621	)		--			(621	)
Costs associated with early retirement of debt		(2,211	)		--			(4,066	)		(1,000	)
Other non-cash hedging adjustments		167			(3,330	)		536			(3,923	)
Interest expense		(12,384	)		(13,670	)		(24,962	)		(21,175	)

Income Before Income Tax		6,751			3,624			19,007			4,181
Deferred income tax (expense) benefit		(2,581	)		(1,373	)		(7,246	)		5,517

Income Before Cumulative Effect of a Change in Accounting
Principle		4,170			2,251			11,761			9,698
Cumulative effect of a change in accounting principle, net
of income tax expense of $244		--			--			399			--

Net Income	$	4,170		$	2,251		$	12,160		$	9,698

Income per Common Share - Basic

Income before cumulative effect of a change in accounting principle	$	0.06		$	0.03		$	0.17		$	0.18
Cumulative effect of a change in accounting principle		--			--			0.01			--

Income per Common Share - Basic	$	0.06		$	0.03		$	0.18		$	0.18

Income per Common Share - Diluted

Income before cumulative effect of a change in accounting principle	$	0.06		$	0.03		$	0.17		$	0.17
Cumulative effect of a change in accounting principle		--			--			0.01			--

Income per Common Share - Diluted	$	0.06		$	0.03		$	0.18		$	0.17

Common Shares Used in Per Share Calculation
Basic		65,937,569			68,490,021			66,321,403			55,207,518

Diluted		66,894,623			69,710,567			67,114,375			56,441,193

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

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
AND OTHER COMPREHENSIVE INCOME
FOR THE SIX MONTHS ENDED JUNE 30, 2003
(Unaudited)
(in thousands)

	Preferred Stock		Common Stock		Treasury Stock			Additional Paid in Capital		Accumulated Deficit			Deferred Compensation			Unearned Shares in KSOP			Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity			Total Comprehensive Income (Loss)
Balance at December 31, 2002	$	1	$	143	$	(20,408	)	$	423,364	$	(21,114	)	$	--		$	(4,888	)	$	(26,902	)	$	350,196



Issuance of 23 shares of common stock pursuant to employee stock option plan				1					74														75


Deferred tax benefit on exercise of employee stock options									29														29

Purchase of 1,340 shares of treasury stock						(7,413	)																(7,413	)

Loan of 486 shares to KSOP																	(2,711	)					(2,711	)

Purchase 53 shares for deferred compensation plan														(295	)								(295	)


Contribution of 18 treasury shares to deferred compensation plan						53			47					(100	)								--

Release 36 shares from deferred compensation plan														203									203

Stock compensation									433														433

Net Income											12,160												12,160		$	12,160


Reclassification adjustment related to derivative contracts																				29,495			29,495			29,495


Change in fair value of outstanding hedge positions																				(33,286	)		(33,286	)		(33,286	)

Amortization of purchased hedge positions																				(402	)		(402	)		(402	)

Balance at June 30, 2003	$	1	$	144	$	(27,768	)	$	423,947	$	(8,954	)	$	(192	)	$	(7,599	)	$	(31,095	)	$	348,484		$	7,967

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

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)


	2003			2002
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income	$	12,160		$	9,698
Adjustments to reconcile net income to cash provided by operating activities:
Cumulative effect of a change in accounting principle		(399	)		--
Depreciation, depletion, amortization and accretion		46,502			38,638
Amortization of financing fees		1,203			920
Imputed interest on debt due to merger		--			108
Costs associated with early retirement of debt		4,066			1,000
Deferred income taxes (benefits)		7,246			(5,517	)
Equity in (income) loss of unconsolidated affiliate		237			(382	)
Gain on sale of assets		(140	)		--
Provision for impairment of investments		--			621
Non-cash hedging adjustments		(536	)		3,923
Stock compensation		433			--
Other		--			(82	)
Changes in certain assets and liabilities, net of the effect of
acquisitions:
Accounts and notes receivable		(5,194	)		(8,989	)
Derivative assets		--			3,600
Refund of income taxes		7,823			300
Deposits and other current assets		6,281			(4,287	)
Accounts payable and accrued liabilities		21,737			(39,014	)

Net Cash Provided by Operating Activities		101,419			537

CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets, net of purchase price adjustments		8,969			1,681
Additions to property and equipment		(97,328	)		(56,197	)
Cash paid in Prize merger net of cash acquired		--			(41,097	)
Increase in note receivable		--			(2,350	)
Decrease in other assets		29			--
Distribution from unconsolidated affiliate		900			--
Investment in unconsolidated affiliate		(600	)		--

Net Cash Used in Investing Activities		(88,030	)		(97,963	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt		248,575			592,183
Redemption of notes payable		(76,897	)		--
Fees paid related to financing activities		(450	)		(11,899	)
Payments of principal on debt and production payment		(167,609	)		(461,383	)
Loan made to stockholder		--			(175	)
Increase in note receivable from affiliate		(225	)		--
Repayment of note receivable from affiliate		--			300
Loan made to KSOP		(2,711	)		(2,683	)
Proceeds from issuance of common stock, net of offering costs		75			592
Purchase of common stock for deferred compensation plan		(295	)		--
Purchase of warrants		--			(98	)
Purchase of treasury stock		(7,413	)		(13,800	)
Increase in restricted cash for payment of notes payable		(262	)		(432	)

Net Cash Provided (Used) By Financing Activities		(7,212	)		102,605

NET INCREASE IN CASH AND CASH EQUIVALENTS		6,177			5,179
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		3,069			2,755

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	9,246		$	7,934

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

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2003
(Unaudited)

NOTE 1 — MANAGEMENT’S REPRESENTATION

In this quarterly report on Form 10-Q, the words “Magnum Hunter,” “company,” “we,” “our,” and “us” refer to Magnum Hunter Resources, Inc. and its consolidated subsidiaries unless otherwise stated or the context otherwise requires. The condensed consolidated balance sheet of Magnum Hunter Resources, Inc. and subsidiaries as of June 30, 2003, the condensed consolidated statements of income for the three and six months ended June 30, 2003 and 2002, the condensed consolidated statement of stockholders’ equity and comprehensive income for the six months ended June 30, 2003, and the condensed consolidated statements of cash flows for the six months ended June 30, 2003 and 2002, are unaudited. In the opinion of management, all necessary adjustments (which include only normal recurring adjustments) have been made to present fairly the financial position at June 30, 2003, results of operations for the three and six month periods, changes in stockholders’ equity and comprehensive income and cash flows for the six month periods.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. It is suggested that these condensed financial statements be read in conjunction with the financial statements and notes thereto included in our December 31, 2002 annual report and on our Form 10-K. The results of operations for the three and six month periods ended June 30, 2003, are not necessarily indicative of the operating results for the full year.

The accompanying condensed consolidated financial statements include the accounts of the company and our subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Certain items have been reclassified to conform with the current presentation.

During the first quarter of 2002, we merged with Prize Energy Corp. (“Prize”), a publicly traded independent oil and gas development and production company. The merger with Prize closed on March 15, 2002, but for operating and financial reporting purposes, was effective as of March 1, 2002.

Subsequent to the Prize merger, we have divested of approximately 83.6 billion cubic feet equivalent of non-strategic proved producing oil and gas reserves for total proceeds of approximately $115 million. Almost all of the properties sold were acquired in the Prize merger, and the proceeds have been used to reduce our overall indebtedness and fund our capital program. These proceeds include the $13.4 million package of non-strategic South Louisiana oil and gas properties which closed June 9, 2003.

Magnum Hunter is a holding company with no significant assets or operations other than our investments in our subsidiaries. The wholly owned subsidiaries of the company, except for Canvasback Energy, Inc. and Redhead Energy, Inc., collectively referred to as Canvasback, are direct guarantors of each of our 10% Senior Notes and 9.6% Senior Notes, and have fully and unconditionally guaranteed these Senior Notes on a joint and several basis. The guarantors comprise all of our direct and indirect subsidiaries (other than Canvasback), and we have presented separate condensed consolidating financial statements and other disclosures concerning each guarantor and Canvasback (See Note 10). Except for Canvasback, there is no restriction on the ability of consolidated or unconsolidated subsidiaries to transfer funds to the company in the form of cash dividends, loans, or advances.

NOTE 2 – NEW ACCOUNTING STANDARDS

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depreciated over the asset’s useful life. See Note 5 for additional information on our asset retirement obligations. Upon adoption of SFAS No. 143, we recorded an addition to oil and gas properties of $25.4 million, an asset retirement obligation of $30.4 million, a reduction of accumulated depletion of $5.6 million, and a pre-tax gain of $643 thousand.

SFAS No. 145 — SFAS No. 145 “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” became effective beginning January 1, 2003. The Statement rescinds, updates, clarifies and simplifies various existing accounting pronouncements. SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. As a result, SFAS No. 145 requires us to reclassify as additional expense, any extraordinary items for debt extinguishment costs which did not meet the criteria as described in APB Opinion No. 30 “Reporting the Results of Operations — Reporting the Effects of Disposal of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions”, as additional expense.

SFAS No. 146 — In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 supercedes EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” Statement 146 is to be applied prospectively to exit or disposal activities initiated after December 31, 2002.

SFAS No. 148 – The FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an Amendment to FASB Statement No. 123,” in December 2002. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123. Effective June 1, 2003, we began expensing the fair market value of stock options newly granted, modified or settled pursuant to SFAS No. 123 “Accounting for Stock-Based Compensation,” and as allowed under the prospective method of SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to SFAS No. 123.” The fair value of each option granted after December 31, 2002 is estimated on the grant date using the Black-Scholes option-pricing model. For the six months ended June 30, 2003, we recorded stock compensation expense of $433 thousand which is reflected in our general and administrative expenses. For options granted prior to January 1, 2003, we continue to use the intrinsic method under APB No. 25, “Accounting for Stock Issued to Employees and Related Interpretations,” whereby no compensation expense is recognized for stock options granted with an exercise price equal to the market value of our stock on the grant date. For additional information on our stock compensation, please see Note 3.

FIN No. 45 – FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees,” was issued in November 2002. This interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. It also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of a guarantee for the obligations the guarantor has undertaken in issuing that guarantee. We adopted this statement in January 2003.

In the past we have provided trade guarantees on behalf of our 30% owned affiliate, NGTS, LLC. In the event that NGTS, LLC is unable to fulfill its obligations with certain vendors, we would be obligated for cash payments of up to $600 thousand to these vendors. We have not recorded these as a liability on our books at June 30, 2003 because we do not expect to have to perform under these guarantees. The last of these guarantees expires in July 2003, and we do not intend to issue any additional guarantees on behalf of NGTS, LLC. Further, we have elected to sell our interest in NGTS, LLC (see Note 11). We have provided no other guarantees on behalf of any unconsolidated entities and do not intend to issue any.

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

In June 2001, FASB issued SFAS No. 141, “Business Combinations,” which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review of impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS No. 141 and 142 clarify that more assets should be distinguished and classified between tangible and intangible. We did not change or reclassify contractual mineral rights included in proved and unproved oil and gas properties on our balance sheet upon adoption of SFAS No. 142. We believe the treatment of such mineral rights as tangible assets under the full cost method of accounting for oil and gas properties is appropriate. An issue has been raised regarding whether these mineral rights should be classified as tangible or intangible assets. If it is determined that reclassification is necessary, we would have reduced our proven properties by $352.7 million, decreased unproved properties by $154.5 million and reported intangible mineral rights related to proved properties of $352.7 million and intangible mineral rights related to unproved properties of $154.5 million at December 31, 2002. At June 30, 2003, we would have reduced our proven properties by $336.4 million, reduced our unproved properties by $165.6 million, and reported intangible mineral rights related to proved properties of $336.4 million and intangible mineral rights related to unproved properties of $165.6 million. These reclassifications represent the cost of acquiring proved and unproved mineral use rights from the effective date of June 30, 2001. The provisions of SFAS No. 141 and SFAS No. 142 impact only the balance sheet and any associated footnote disclosures. Any reclassifications potentially required would not impact our cash flows or statements of income.

NOTE 3 – STOCK BASED COMPENSATION

Beginning June 1, 2003, we began expensing the fair market value of stock options newly granted, modified or settled pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation,” and as allowed under the prospective method of SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to SFAS No. 123.” The fair value of each option granted after December 31, 2002 is estimated on the grant date using the Black-Scholes option-pricing model. For the six months ended June 30, 2003, we recorded stock compensation expense of $433 thousand, which is reflected in our general and administrative expenses. For options granted prior to January 1, 2003, we continue to use the intrinsic method under APB No. 25, “Accounting for Stock Issued to Employees and Related Interpretations,” whereby no compensation expense is recognized for stock options granted with an exercise price equal to the market value of our stock on the grant date.

If we had recorded stock option expense under the fair value provisions of SFAS No. 123 for all grants, our net income and EPS would have been as shown in the below pro forma tables (in thousands):

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

	Three Months Ended June 30,		Six Months Ended June 30,
	2003	2002	2003	2002
Net income, as reported	$4,170	$2,251	$ 12,160		$9,698
Total Stock-based employee compensation expense
included in reported net income, net of related
tax effects	269	--	269		--

Deduct: Total stock-based employee compensation
determined under fair value-based method for all
awards, net of related tax effects	(991)	(670)	(1,662)		(1,358)

Pro forma net income	$3,448	$1,581	$ 10,767		$ 8,340

Earnings per share:
Basic - as reported	$ 0.06	$ 0.03	$ 0.18		$0.18

Basic - pro forma	$ 0.05	$ 0.02	$ 0.16		$0.15

Diluted - as reported	$ 0.06	$.0.03	$ 0.18		$0.17

Diluted - pro forma	$ 0.05	$ 0.02	$ 0.16		$0.15

NOTE 4 — GOODWILL

In June 2001, SFAS No. 141 “Business Combinations” and SFAS No. 142, “Goodwill and other Intangible Assets” were issued to be effective for fiscal years beginning after December 15, 2001. Under the new rules in these statements, goodwill is no longer amortized, but is subject to annual impairment tests. We completed the first of these tests at December 31, 2002 and found no impairment. Changes to the carrying value of goodwill during the six months ended June 30, 2003 are as follows:

Balance at December 31, 2002	$	50,710
Purchase price adjustments		7,753

Balance at June 30, 2003	$	58,463

Our goodwill results from our merger with Prize, and the purchase price allocation was finalized as of June 30, 2003. The goodwill has been fully allocated to our Exploration and Production segment.

NOTE 5 – ASSET RETIREMENT OBLIGATIONS

SFAS No. 143, “Accounting for Asset Retirement Obligations,” became effective beginning January 1, 2003. SFAS No. 143 requires the recognition of a fair value liability for any retirement obligations associated with long-lived assets in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depreciated over the asset’s useful life. Prior to adopting SFAS No. 143 on January 1, 2003, we accounted for asset retirement obligations in accordance with SFAS No. 19.

Our long-lived assets captured under SFAS No. 143 are developed oil and gas properties, production and distribution facilities, and natural gas processing plants. Our asset retirement obligations include plugging, abandonment, decommission and remediation costs.

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

The following is a reconciliation of the Asset Retirement Obligation Liability at June 30, 2003 (in thousands):


Beginning balance at January 1, 2003	$	--
Cumulative effect adjustment		30,391
Liabilities incurred		545
Liabilities settled		(1,104	)
Liabilities sold		(1,047	)
Accretion expense		1,239
Change in retirement cost estimates		(354	)

Ending balance at June 30, 2003	$	29,670

The following pro forma data summarizes our net income (loss) and net income (loss) per share as if we had adopted SFAS No. 143 on January 1, 2002. The associated pro forma asset retirement obligation was $16.9 million on January 1, 2002 and an additional asset retirement obligation of $12.9 million would have been recorded at March 1, 2002 in conjunction with the Prize acquisition.

	Three Months Ended June 30,		Six Months Ended June 30,
	2003	2002	2003	2002
Net income, as reported	$ 4,170	$ 2,251	$12,160		$ 9,698
Pro forma adjustment to reflect retroactive
adoption of SFAS No. 143, net of related tax effects	--	(34)	(399)		65

Pro forma net income	$ 4,170	$ 2,217	$11,761		$ 9,763

Earnings per share:
Basic - as reported	$ 0.06	$ 0.03	$ 0.18		$ 0.18

Basic - pro forma	$ 0.06	$ 0.03	$ 0.17		$ 0.18

Diluted - as reported	$ 0.06	$ 0.03	$ 0.18		$ 0.17

Diluted - pro forma	$ 0.06	$ 0.03	$ 0.17		$ 0.17

NOTE 6 — EARNINGS PER SHARE INFORMATION

The following is a reconciliation of the basic and diluted earnings per share computations (in thousands, except for per share amounts):

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

	Three Months Ended
	June 30, 2003						June 30, 2002
	Income		Shares		Per Share Amount		Income		Shares		Per Share Amount
Basic EPS
Income available to common stockholders	$	4,170		65,938	$	0.06	$	2,251		68,490	$	0.03

Effect of Dilutive Securities
Warrants		--		--				--		73
Options		--		957				--		1,148

Diluted EPS
Income available to common stockholders and
assumed conversions	$	4,170		66,895	$	0.06	$	2,251		69,711	$	0.03

	Six Months Ended
	June 30, 2003						June 30, 2002
	Income		Shares		Per Share Amount		Income		Shares		Per Share Amount
Basic EPS
Income available to common stockholders	$	12,160		66,321	$	0.18	$	9,698		55,208	$	0.18

Effect of Dilutive Securities
Warrants		--		--				--		69
Options		--		793				--		1,164

Diluted EPS
Income available to common stockholders and
assumed conversions	$	12,160		67,114	$	0.18	$	9,698		56,441	$	0.17

At June 30, 2003, warrants representing 7,873,206 shares of common stock and options representing 6,918,333 shares of common stock were outstanding. At June 30, 2002, warrants representing 12,091,446 shares of common stock and options representing 5,237,634 shares of common stock were outstanding. For the three and six month periods ended June 30, 2003, 7,873,206 shares of stock representing warrants and 3,108,300 shares and 3,119,200 shares of stock representing options, respectively, were excluded from the diluted earnings per share calculations because they were anti-dilutive. For the three and six month periods ended June 30, 2002, 11,446,967 shares of stock representing warrants and 3,300,700 and 3,285,350 shares of stock representing options were excluded from the diluted earnings per share calculations because they were anti-dilutive.

NOTE 7 — DEBT

Notes payable and long-term debt at June 30, 2003 and December 31, 2002 consisted of the following:

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

	6/30/2003		12/31/2002
Long-Term Debt:
Bank debt under revolving credit agreements due
May 2, 2006	$	212,975	$	125,000
Term note payable due May 31, 2005, non-recourse		932		7,000
Production payment liability, non-recourse		50		114
Capital lease obligations		8,494		9,371
10% Senior unsecured notes, due June 1, 2007		55,534		129,466
9.6% Senior unsecured notes, due March 15, 2012		300,000		300,000

		577,985		570,951
Less: Current portion of capital lease obligations		1,987		1,865

Total Long-Term Debt	$	575,998	$	569,086

On January 27, 2003, we redeemed $30 million in principal of our 10% Senior Notes at a redemption price of 105% of par. We paid the holders of the redeemed Notes $31.5 million plus accrued and unpaid interest of $467 thousand. Of the $30 million redeemed, Canvasback received $2.3 million. On June 2, 2003, we redeemed an additional $50 million in principal of our 10% Senior Notes at a redemption price of 103.333% of par. We paid the holders of the redeemed Notes $51.7 million including accrued and unpaid interest of $14 thousand. Of the $50 million redeemed during the second quarter, Canvasback received $3.7 million.

We amended our Senior Bank Credit Facility (the “Facility”) on May 2, 2003. The amended Facility provides for a borrowing base increase of $50 million to $300 million, up from $250 million previously. Additionally, the expiration date of the Facility was extended to May 2, 2006. We used the increased borrowing capacity to fund the June 2, 2003 Note redemption.

We amended our term note payable (the “Term Loan”) on July 2, 2003. The amended Term Loan allows for additional advances of up to $5 million for the purpose of additional Note repurchases. The maturity date was also extended to May 31, 2005.

NOTE 8 — HEDGING

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as extended by SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June 2000), was effective beginning January 2001. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recognition of derivatives in the balance sheet and the measurement of those instruments at fair value.

We were obligated to nine crude oil derivatives, thirteen natural gas derivatives, and two interest rate derivatives on June 30, 2003. All outstanding derivatives qualify for cash flow hedge accounting treatment as defined within SFAS No. 133, which requires derivative assets and liabilities to be recorded at their fair value on the balance sheet with an offset to other comprehensive income. Hedge ineffectiveness on cash-flow hedges is recorded in earnings.

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

At June 30, 2003, the fair value of the company’s derivatives were as follows (in thousands):

Derivative Liabilities
Natural gas collars	$	37,658
Natural gas swaps		3,854
Crude oil collars		3,670
Crude oil swaps		1,784
Interest rate swaps		392

Total derivative liabilities	$	47,358

Of the $47.4 million derivative liability, $39.6 million is included in trade payables and accrued liabilities on our condensed consolidated balance sheet at June 30, 2003.

For the three and six month periods ended June 30, 2003, the statement of operations includes a non-cash hedging ineffectiveness loss of $157 thousand and $112 thousand, respectively, related to the crude oil and natural gas derivatives. Additionally, during this similar period, our statement of operations includes a non-cash gain of $324 thousand and $648 thousand, respectively, related to the amortization of hedge contracts acquired in the Prize merger. The remaining amortization amounts relating to hedge contracts acquired in the Prize merger that will be reclassified into the operations statement in years 2003 and 2004 are a $0.6 million gain and $0.8 million gain, respectively. It is estimated at this time that $26.6 million of other comprehensive loss will be reclassified into the income statement during the next 12 months.

On May 1, 2003, we closed out 20,000 Mmbtu/d of natural gas collar hedges for the period June through December 2003. In closing these contracts, we locked in a $5.7 million loss which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months of June through December 2003. At June 30, 2003, the remaining balance was $5.0 million.

NOTE 9 – SEGMENT DATA

We have three reportable segments. The Exploration and Production segment is engaged in exploratory and developmental drilling and acquisition, production, and sale of crude oil, condensate, and natural gas. The Gas Gathering, Marketing and Processing segment is engaged in the gathering and compression of natural gas from the wellhead, the purchase and resale of natural gas which it gathers, and the processing of natural gas liquids. The Oil Field Services segment is engaged in the managing and operation of producing oil and gas properties for interest owners.

Our reportable segments are strategic business units that offer different products and services. They are managed separately because each business requires different technology and marketing strategies. The Exploration and Production segment has six geographic areas that are aggregated. The Gas Gathering, Marketing and Processing segment includes the activities of the three gathering systems and four natural gas liquids processing plants in four geographic areas that are aggregated. The Oil Field Services segment has six geographic areas that are aggregated. The reason for aggregating the segments, in each case, is due to the similarity in nature of the products, the production processes, the type of customers, the method of distribution, and the regulatory environments.

The accounting policies of the segments are the same as those for the company as a whole. We evaluate performance based on profit or loss from operations before income taxes. The accounting for intersegment sales and transfers is done as if the sales or transfers were to third parties, that is, at current market prices.

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

Segment data for the periods ended June 30, 2003 and 2002 follows (in thousands):

Three Months Ended June 30, 2003:	Exploration & Production		Gas Gathering, Marketing & Processing		Oil Field Services		All Other			Elimination			Consolidated
Revenue from external customers	$	68,470	$	9,055	$	913	$	--		$	--		$	78,438
Intersegment revenues		443		5,779		3,371		--			(9,593	)		--
Depreciation, depletion and amortization		24,101		577		149		151						24,978

Segment profit (loss)		22,940		1,595		173		(3,264	)					21,444
Equity in earnings of affiliates								(525	)					(525	)
Interest expense								(12,384	)					(12,384	)
Costs associated with early retirement
of debt								(2,211	)					(2,211	)
Other income (expense)								427						427

Income before income taxes								--					$	6,751
Provision for income tax (expense)								(2,581	)					(2,581	)

Net income													$	4,170

Three Months Ended June 30, 2002:	Exploration & Production		Gas Gathering, Marketing & Processing		Oil Field Services		All Other			Elimination			Consolidated
Revenue from external customers	$	70,543	$	4,596	$	1,051	$	--		$	--		$	76,190
Intersegment revenues				3,477		5,978		--			(9,455	)		--
Depreciation, depletion and amortization		22,518		544		133		347						23,542

Segment profit (loss)		24,665		586		375		(4,570	)					21,056
Equity in earnings of affiliates								81						81
Interest expense								(13,670	)					(13,670	)
Other income (expense)								(3,843	)					(3,843	)

Income before income taxes													$	3,624
Provision for income tax (expense)								(1,373	)					(1,373	)

Net income													$	2,251

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

Six Months Ended June 30, 2003:	Exploration & Production		Gas Gathering, Marketing & Processing		Oil Field Services		All Other			Elimination			Consolidated
Revenue from external customers	$	138,060	$	18,440	$	1,992	$	--		$	--		$	158,492
Intersegment revenues		843		12,195		6,856		--			(19,894	)		--
Depreciation, depletion and amortization		44,698		1,153		295		356						46,502

Segment profit (loss)		49,809		3,858		248		(6,557	)					47,358
Equity in earnings of affiliates								(237	)					(237	)
Interest expense								(24,962	)					(24,962	)
Costs associated with early retirement
of debt								(4,066	)					(4,066	)
Other income (expense)								914						914

Income before income taxes													$	19,007
Provision for income tax benefit								(7,246	)					(7,246	)
Cumulative effect of a change in
accounting principle								399						399

Net income													$	12,160

Six Months Ended June 30, 2002:	Exploration & Production		Gas Gathering, Marketing & Processing		Oil Field Services		All Other			Elimination			Consolidated
Revenue from external customers	$	109,693	$	8,178	$	1,443	$	--		$	--		$	119,314
Intersegment revenues				5,960		6,395		--			(12,355	)		--
Depreciation, depletion and amortization		37,060		914		238		426						38,638

Segment profit (loss)		36,022		1,118		386		(7,173	)					30,353
Equity in earnings of affiliates								382						382
Interest expense								(21,175	)					(21,175	)
Costs associated with early retirement
of debt								(1,000	)					(1,000	)
Other income (expense)								(4,379	)					(4,379	)

Income before income taxes													$	4,181
Provision for income tax benefit								5,517						5,517

Net income													$	9,698

NOTE 10 – CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

The company and its wholly-owned subsidiaries, except Canvasback, are direct guarantors of our 10% Senior Notes and 9.6% Senior Notes and have fully and unconditionally guaranteed the Notes on a joint and several basis. In addition to not being a guarantor of the company’s 10% Senior Notes and 9.6% Senior Notes, Canvasback cannot be included in determining compliance with certain financial covenants under the company’s credit agreements. We have concluded that separate financial statements related to the guarantors are not included because management has determined that they are not material to investors. Condensed consolidating financial information for Magnum Hunter Resources, Inc. and subsidiaries as of June 30, 2003 and December 31, 2002, and for the three and six month periods ended June 30, 2003 and 2002, was as follows:

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

Magnum Hunter Resources, Inc. and Subsidiaries Condensed Consolidating Balance Sheets

As of June 30, 2003
Amounts in Thousands	Magnum Hunter Resources, Inc. and Guarantor Subs		Canvasback Energy, Inc. (Non Guarantor)		Eliminations			Magnum Hunter Resources, Inc. Consolidated
ASSETS
Current assets	$	108,989	$	5,777	$	(21,571	)	$	93,195
Property and equipment
(using full cost accounting)		1,066,510		7,654		--			1,074,164
Investment in subsidiaries
(equity method)		17,164		--		(17,164	)		--
Investment in Parent		--		38,593		(38,593	)		--
Other assets		74,897		566		--			75,463

Total assets	$	1,267,560	$	52,590	$	(77,328	)	$	1,242,822

LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities	$	150,031	$	21,601	$	(21,571	)	$	150,061
Long-term liabilities		734,918		13,825		(4,466	)		744,277
Stockholders' equity		382,611		17,164		(51,291	)		348,484

Total liabilities and stockholders' equity	$	1,267,560	$	52,590	$	(77,328	)	$	1,242,822

As of December 31, 2002
Amounts in Thousands	Magnum Hunter Resources, Inc. and Guarantor-Subs		Canvasback Energy, Inc. (Non Guarantor)		Eliminations			Magnum Hunter Resources, Inc. Consolidated
ASSETS
Current assets	$	110,584	$	4,036	$	(16,524	)	$	98,096
Property and equipment
(using full cost accounting)		994,766		6,843		--			1,001,609
Investment in subsidiaries
(equity method)		15,650		--		(15,650	)		--
Investment in Parent		--		39,563		(39,563	)		--
Other assets		69,345		729		--			70,074

Total assets	$	1,190,345	$	51,171	$	(71,737	)	$	1,169,779

LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities	$	129,092	$	16,551	$	(16,524	)	$	129,119
Long-term liabilities		682,028		18,970		(10,534	)		690,464
Stockholders' equity		379,225		15,650		(44,679	)		350,196

Total liabilities and stockholders' equity	$	1,190,345	$	51,171	$	(71,737	)	$	1,169,779

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

Magnum Hunter Resources, Inc. and Subsidiaries Condensed Consolidating Statement of Operations

For the Three Months Ended June 30, 2003
Amounts in Thousands	Magnum Hunter Resources, Inc. and Guarantor-Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Revenues	$	76,722		$	1,716		$	--		$	78,438
Expenses		71,626			61			--			71,687

Income before equity in net earnings of subsidiary		5,096			1,655			--			6,751
Equity in net earnings of subsidiary		1,028			--			(1,028	)		--

Income before income taxes		6,124			1,655			(1,028	)		6,751
Income tax expense		(1,954	)		(627	)		--			(2,581	)

Net income	$	4,170		$	1,028		$	(1,028	)	$	4,170

For the Three Months Ended June 30, 2002
Amounts in Thousands	Magnum Hunter Resources, Inc. and Guarantor-Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Revenues	$	75,783		$	407		$	--		$	76,190
Expenses		72,497			69			--			72,566

Income before equity in net earnings of subsidiary		3,286			338			--			3,624
Equity in net earnings of subsidiary		210			--			(210	)		--

Income before income taxes		3,496			338			(210	)		3,624
Income tax expense		(1,245	)		(128	)		--			(1,373	)

Net income	$	2,251		$	210		$	(210	)	$	2,251

For the Six Months Ended June 30, 2003
Amounts in Thousands	Magnum Hunter Resources, Inc. and Guarantor-Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Revenues	$	155,602		$	2,890		$	--		$	158,492
Expenses		139,031			454			--			139,485

Income before equity in net earnings of subsidiary		16,571			2,436			--			19,007
Equity in net earnings of subsidiary		1,513			--			(1,513	)		--

Income before income taxes		18,084			2,436			(1,513	)		19,007
Income tax expense		(6,323	)		(923	)		--			(7,246	)

Net income		11,761			1,513			(1,513	)		11,761
Cumulative effect of a change in accounting
principle		399			--			--			399

Net income	$	12,160		$	1,513		$	(1,513	)	$	12,160

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

Magnum Hunter Resources, Inc. and Subsidiaries Condensed Consolidating Statement of Operations

For the Six Months Ended June 30, 2002
Amounts in Thousands	Magnum Hunter Resources, Inc. and Guarantor-Subs		Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Revenues	$	118,645	$	669		$	--		$	119,314
Expenses		114,871		262			--			115,133

Income before equity in net earnings of subsidiary		3,774		407			--			4,181
Equity in net earnings of subsidiary		253		--			(253	)		--

Income before income taxes		4,027		407			(253	)		4,181
Income tax benefit (expense)		5,671		(154	)		--			5,517

Net income	$	9,698	$	253		$	(253	)	$	9,698

Magnum Hunter Resources, Inc. and Subsidiaries Condensed Consolidating Statements of Cash Flows

For the Six Months Ended June 30, 2003
Amounts in Thousands	Magnum Hunter Resources, Inc. and Guarantor-Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Cash flow from operating activities	$	93,713		$	7,908		$	(202	)	$	101,419
Cash flow from investing activities		(86,574	)		(486	)		(970	)		(88,030	)
Cash flow from financing activities		(1,829	)		(6,555	)		1,172			(7,212	)

Net increase in cash		5,310			867			--			6,177
Cash at beginning of period		2,540			529			--			3,069

Cash at end of period	$	7,850		$	1,396		$	--		$	9,246

For the Six Months Ended June 30, 2002
Amounts in Thousands	Magnum Hunter Resources, Inc. and Guarantor-Subs			Canvasback Energy, Inc. (Non Guarantor)			Eliminations			Magnum Hunter Resources, Inc. Consolidated
Cash flow from operating activities	$	(8,133	)	$	8,670		$	--		$	537
Cash flow from investing activities		(96,036	)		(14,261	)		12,334			(97,963	)
Cash flow from financing activities		109,360			5,579			(12,334	)		102,605

Net increase (decrease) in cash		5,191			(12	)		--			5,179
Cash at beginning of period		730			2,025			--			2,755

Cash at end of period	$	5,921		$	2,013		$	--		$	7,934

NOTE 11 – SUBSEQUENT EVENT

On July 29, 2003, we exercised our option to sell our 30% interest in NGTS, LLC. We have reduced the carrying value of our investment and equity in earnings of affiliate by approximately $719 thousand at June 30, 2003, to state our investment at its estimated realizable value.

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

Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes associated with them contained in our Form 10-K for the year ended December 31, 2002. This discussion should not be construed to imply that the results discussed herein will necessarily continue into the future or that any conclusion reached herein will necessarily be indicative of actual operating results in the future. Such discussion represents only the best present assessment by our management.

There have been no changes to our critical accounting policies for the six month period ended June 30, 2003 except for accounting for asset retirement obligations, accounting for gains and losses from extinguishment of debt, and accounting for stock-based compensation. SFAS No. 143, “Accounting for Asset Retirement Obligations,” became effective for us beginning January 1, 2003. SFAS No. 143 requires the recognition of a fair value liability for any retirement obligations associated with long-lived assets. The offset to any liability recorded is added to the recorded asset, and the additional amount is depreciated over the same period as the long-lived asset for which the retirement obligation is established. SFAS No. 145, “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” was effective for us beginning January 1, 2003. SFAS No. 145 requires us to classify gains and losses from debt extinguishment as additional interest expense. In June 2003, we began expensing stock-based compensation expense pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation,” as allowed under the prospective method of SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to SFAS No. 123.” Under these statements, all stock options granted, modified or settled after December 31, 2002 will be expensed based on their fair values determined by the Black-Scholes option-pricing model. For a discussion of our other critical accounting policies, refer to our Form 10-K for the period ended December 31, 2002.

During the first quarter of 2002, we merged with Prize Energy Corp. (“Prize”), an independent oil and gas development and production company based in Grapevine, Texas. The merger with Prize closed on March 15, 2002, but for operating and financial reporting purposes, was effective as of March 1, 2002. As such, the results for the three and six month periods ended June 30, 2002 include three months and four months of operating contributions from Prize, respectively.

Throughout this document, we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section of this document for an explanation of these types of assertions.

Our results of operations have been significantly affected by our past success in acquiring oil and gas properties at the bottom of the commodity price cycles and our ability to maintain or increase oil and natural gas production through our exploration and exploitation activities. Fluctuations in oil and gas prices have also significantly affected the results of operations.

The following table sets forth certain information with respect to our oil and gas operations and our gas gathering, marketing and processing operations:

	Three Months Ended June 30,					Six Months Ended June 30,
Exploration and Production Operations	2003			2002		2003			2002
Reported Production:
Oil (Mbbls)		1,000			1,132		1,956			1,802
Gas (MMcf)		12,522			13,431		23,844			22,499
Oil and Gas (Mmcfe)		18,519			20,223		35,582			33,312
Equivalent Daily Rate (Mmcfe/day)		203.5			222.2		196.6			184.0
Average Sale Prices (after hedging)
Oil (per Bbl)	$	26.35		$	24.40	$	26.85		$	23.15
Gas (per Mcf)		3.37			3.20		3.59			3.02
Oil and Gas (per Mcfe)		3.70			3.49		3.88			3.29
Effect of hedging activities (per Mcfe)		(0.91	)		--		(1.31	)		0.17
Lease Operating Expense (per Mcfe)
Lifting costs	$	0.73		$	0.76	$	0.74		$	0.73
Production tax and other costs		0.43			0.39		0.48			0.37
Gross margin (per Mcfe)	$	2.54		$	2.34	$	2.66		$	2.19

Gas Gathering, Marketing and Processing Operations

Throughput Volumes (Mcf per day)
Gathering		16,369			15,207		15,944			15,232
Processing		26,816			21,277		24,803			19,588
Gross margin (in thousands)	$	2,173		$	1,130	$	5,012		$	2,032
Gathering (per Mcf throughput)	$	0.06		$	0.11	$	0.12		$	0.12
Processing (per Mcf throughput)	$	0.84		$	0.48	$	1.03		$	0.44

Period to Period Comparison

For the Three Months Ended June 30, 2003 and 2002

We reported net income of $4.2 million for the three months ended June 30, 2003, as compared to net income of $2.3 million for the same period in 2002, an increase of 83%. Total operating revenues increased 3% to $78.4 million in 2003 from $76.2 million in 2002. Operating profit increased 2% to $21.4 million in 2003 from $21.1 million in 2002, and net income before income tax increased 89% to $6.8 million in 2003 from $3.6 million in 2002. The growth in operating revenues and operating profit was predominately generated by our gathering, marketing, and processing segment. This was offset by small declines in operating revenues and operating profit recorded in our exploration and production and oil field services segments due to non-strategic divestitures. The growth in pretax income was caused by a $167 thousand non-cash hedging adjustment gain in the 2003 period versus a $3.3 million loss recorded in the 2002 period, a valuation adjustment loss of $621 thousand recorded in the 2002 period versus none in the 2003 period, and a $2.2 million cost associated with early retirement of debt in the 2003 period versus none in the 2002 period. We recorded an 86% increase in deferred income tax expense of $2.6 million for the three months in 2003 versus $1.4 million for the same period in 2002, due to the increase in pre-tax income. Basic and diluted earnings per share were $0.06 in the 2003 period versus basic and diluted earnings per share of $0.03 in the 2002 period, a gain of 100%. The increase in net income was the primary factor causing the increase in basic and diluted earnings per share. Common shares used in the basic and diluted earnings per share calculation declined by 4% in the 2003 period compared to the 2002 period, principally due to our stock repurchase program.

Exploration and Production Operations:

For the three months ended June 30, 2003, we reported oil production of approximately one million barrels and gas production of 12.5 billion cubic feet, which represents a decrease of 12% in oil produced and a decrease of 7% in gas produced from the comparable period in 2002. Our reported equivalent daily rate of production, on a million cubic feet per day basis (Mmcfe/day), decreased 8% to 203.5 Mmcfe/day in the 2003 period from 222.2 Mmcfe/day

in the 2002 period. These decreases were primarily the result of the sale of non-strategic oil and gas properties which were initiated after the Prize acquisition which closed in March 2002. These non-strategic property sales continued into June 2003. The impact of these property sales on reported production was a decrease of 32.4 Mmcfe/day in the 2003 period compared to the similar 2002 period.

Oil revenues decreased 5% to $26.3 million in the second quarter of 2003 compared to $27.6 million for the same period in 2002. The oil price received, after hedging effects, was $26.35 per Bbl in the 2003 period compared to $24.40 per Bbl in the 2002 period, an increase of 8%. Gas revenues decreased 2% to $42.1 million in the second quarter of 2003 versus $42.9 million for the same period in 2002. The gas price received, after hedging effects, was $3.37 per Mcf in 2003 compared to $3.20 per Mcf for the same period in 2002, an increase of 5%. Total oil and gas revenues decreased 3% to $68.5 million in 2003 from $70.5 million in 2002. The decline in oil and gas revenues is attributable to the production loss as a result of the sale of non-strategic oil and gas properties.

From time to time, we enter into various commodity hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices which provides a basic level of cash flow to fund capital expenditures. During the 2003 period, hedging decreased the average price we received for oil by $1.75 per Bbl and decreased the average price we received for gas by $1.20 per Mcf. During the second quarter of 2003, we had approximately 60.0 MMcf/day of gas hedged through fixed price swaps with a weighted average price of $3.01 per MMbtu and approximately 40.0 MMcf/day of gas hedged through cost-less collars with a weighted average floor price of $3.06 per MMbtu and a weighted average ceiling price of $4.30 per MMbtu. Approximately 73% of second quarter 2003 natural gas production was hedged. On the crude side, we had approximately 1,000 Bbls/day hedged through fixed price swaps with a weighted average price of $21.25 per barrel and approximately 6,000 Bbls/day hedged through cost-less collars with a weighted average floor price of $23.00 per Bbl and a weighted average ceiling price of $27.00 per Bbl. Approximately 64% of second quarter 2003 crude oil production was hedged. For the remainder of 2003, we have approximately 10.0 MMcf/day hedged through fixed price swaps with a weighted average price of $3.65 per MMbtu and approximately 70.0 MMcf/day hedged through cost-less collars with a weighted average floor price of $2.82 and a weighted average ceiling price of $3.78. In addition, for the remainder of 2003, we have hedged 1,000 Bbls/day of crude oil production through a fixed price swap with a price of $21.25 per Bbl and 6,000 Bbls/day of crude oil production hedged through cost-less collars with a weighted average floor price of $23.00 per Bbl and a weighted average ceiling price of $27.00 per Bbl.

On May 1, 2003, we closed out 20,000 Mmbtu/day of natural gas collar hedges for the period June through December 2003. In closing these contracts, we locked in a $5.7 million loss which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months of June through December 2003. At June 30, 2003, the remaining balance was $5.0 million.

Lease operating expense consists of lifting costs and production tax as well as other costs. For the 2003 period, lifting costs were $13.5 million versus $15.4 million in the 2002 period, a decrease of 13%. Production taxes and other costs were unchanged at $7.9 million in both the 2003 period and the 2002 period. The decreases in lifting costs were primarily attributable to the sale of non-strategic oil and gas properties and due to lower costs associated with workover and remedial operations in the 2003 period compared to the 2002 period. For the 2003 period, lifting costs, on a unit of production basis, were $0.73 per Mcfe as compared to $0.76 per Mcfe in the 2002 period, a decrease of 4%. Production tax and other costs were $0.43 per Mcfe in the 2003 period compared to $0.39 per Mcfe in the 2002 period, an increase of 10%. The increase in production taxes was caused by an increase in commodity prices received during the 2003 period.

Our gross margin realized from exploration and production operations (oil and gas revenues less lease operating expenses) for the 2003 period was $47.0 million, or $2.54 per Mcfe, compared to $47.2 million, or $2.34 per Mcfe in the 2002 period, an increase of 9% on a per unit of production basis, as a result of a 6% increase in revenue per Mcfe, offset by a 1% increase in lease operating expense per Mcfe.

Depreciation, depletion, amortization and accretion of oil and gas properties was $24.1 million in 2003 versus $22.5 million in 2002. The 2003 period included accretion expense related to asset retirement obligations (due to the adoption of SFAS No. 143) of $601 thousand. On a unit of production basis, depreciation and depletion expense was $1.27 per Mcfe produced in the 2003 period versus $1.11 per Mcfe produced in the 2002 period. This 14% increase in the equivalent unit cost was due primarily to an increase in development costs and shorter reserve life properties associated with our activities in the Gulf of Mexico.

Segment profit for exploration and production operations was $22.9 million for the three months ended June 30, 2003 versus $24.7 million for the same period in 2002, a decrease of 7%, principally due to the increase in depreciation, depletion and accretion expense.

Gathering, Marketing and Processing Operations:

For the three months ended June 30, 2003, our gas gathering system throughput was 16.4 MMcf/day versus 15.2 MMcf/day for the same period in 2002, an increase of 8%, due to increased production from development drilling activities conducted by the company behind the gathering system. Gas processing throughput was 26.8 MMcf/day in 2003 versus 21.3 MMcf/day in 2002, an increase of 26%. This increase is primarily due to increased production from new well hookups behind two of our processing plants and to the shutdown of one processing plant for most of one month in the 2002 period for scheduled maintenance.

Revenues from gas gathering, marketing and processing increased 97% to $9.1 million in 2003 versus $4.6 million in 2002. Operating costs for the gas gathering, marketing and processing segment increased 99% to $6.9 million in 2003 from $3.5 million in 2002. Both the revenues and operating cost increases were the result of increased gas processing throughput and higher commodity prices.

The gross margin realized from gas gathering, marketing and processing for the 2003 period was $2.2 million versus $1.1 million in the 2002 period, an increase of 92%. The gas gathering margin was $0.06 per Mcf gathered in 2003 versus $0.11 per Mcf in 2002 due to lower gas marketing profits. The gas processing margin was $0.84 per Mcf in 2003 compared to $0.48 per Mcf in 2002, due to improved plant processing economics.

Depreciation expense for gas gathering, marketing and processing operations for the 2003 period was $577 thousand versus $544 thousand for the same period in 2002, an increase of 6% due to capital additions.

Segment profit for gas gathering, marketing and processing operations was $1.6 million in the 2003 period versus $586 thousand for the 2002 period, an increase of 172%, principally due to higher throughput and improved processing economics at our natural gas processing plants.

Oil Field Management Services Operations:

Revenues from oil field management services decreased 13% to $913 thousand in the first quarter of 2003 versus $1.1 million in the first quarter of 2002. This decrease is primarily due to a reduction in the operating fees under our operating agreements associated with the sale of non-strategic oil and gas properties subsequent to the Prize merger. Operating costs increased 9% to $593 thousand in 2003 from $543 thousand in 2002, due to higher overhead costs. The gross margin for this segment in 2003 was $320 thousand versus $508 thousand in 2002, a decrease of 37%, due to increased overhead costs. Depreciation expense was $149 thousand in the 2003 period versus $133 thousand in the 2002 period, an increase of 12%, due to capital additions. Segment profit was $173 thousand for the three months in 2003 versus $375 thousand for the same period in 2002.

Other Income and Expenses:

Total depreciation, depletion, amortization and accretion expense was $25.0 million in the 2003 period versus $23.5 million in the similar 2002 period, an increase of 6%. This is primarily the result of the increased depletion and accretion rates in our exploration and production segment.

General and administrative expense for 2003 decreased 25% to $3.2 million from $4.2 million in 2002. The principal reason for this decrease was the costs associated with the Prize merger that were recorded in the 2002 period. We recorded equity in losses of affiliate of $525 thousand in 2003 versus earnings of $81 thousand in 2002. This decrease was mainly due to the reduction of the carrying value of our investment in NGTS by $719 thousand to state it at its realizable value. Other income was $260 thousand for 2003 versus $108 thousand in 2002, caused by an increase in interest income. The company recognized a $167 thousand gain in other non-cash hedging adjustments in 2003 versus a $3.3 million loss in 2002. In the 2003 period, $324 thousand of the hedging gain relates to the amortization of commodity hedge assets acquired in the Prize merger, while a loss of $157 thousand was due to recording hedge ineffectiveness.

We incurred costs associated with the early retirement of debt of $2.2 million in the three months of 2003 versus none in the same period of 2002. The 2003 period costs were associated with the $50 million early redemption of our 10% Senior Notes in June 2003 at 103.333% of par.

Interest expense was $12.4 million for 2003 versus $13.7 million for 2002, as a result of a decrease in our 10.0% Senior Notes outstanding and lower interest rates on our senior bank credit facility. Our weighted average interest rate paid under our senior bank credit facility was 3.4% in the 2003 period versus 3.9% in the 2002 period.

The effective tax rate was 38.2% and 37.9% for the three months ended June 30, 2003 and 2002, respectively. The variance from the statutory rate of 35% was primarily due to state income taxes.

For the Six Months Ended June 30, 2003 and 2002

We reported net income of $12.2 million for the six months ended June 30, 2003, as compared to net income of $9.7 million for the same period in 2002, an increase of 26%. Total operating revenues increased 33% to $158.5 million in 2003 from $119.3 million in 2002. Operating profit increased 56% to $47.4 million in 2003 from $30.4 million in 2002, and net income before income tax increased 352% to $19.0 million in 2003 from $4.2 million in 2002, due primarily to the Prize merger and increases in commodity prices in the 2003 period compared to the 2002 period. We recorded deferred income tax expense of $7.2 million for the first six months of 2003 versus a deferred tax benefit of $5.5 million for the same period in 2002. The 2002 period income tax benefit resulted from the elimination of the $7.1 million valuation allowance that had been carried against deferred tax assets derived from net operating loss carryovers by Magnum Hunter. As a result of the Prize merger, we believe that this tax asset can be fully realized. Additionally, the 2003 period includes the cumulative effect on prior years of a change in accounting principle due to the adoption of SFAS No. 143 relating to asset retirement obligations. The cumulative effect was a gain of $399 thousand, net of income tax expense of $244 thousand, or $0.01 per share, both basic and diluted. Basic and diluted earnings per share were $0.18 in the 2003 period versus basic and diluted earnings per share of $0.18 and $0.17, respectively, in the 2002 period. Basic and diluted shares outstanding increased 20% and 19%, respectively, in the 2003 period primarily as a result of new shares issued in the Prize merger. The change in basic and diluted earnings per share was a result of increased net income reduced by the effect of an increase in total shares outstanding.

Exploration and Production Operations:

For the six months ended June 30, 2003, we reported oil production of approximately two million barrels and gas production of 23.8 billion cubic feet, which represents an increase of 9% in oil produced and an increase of 6% in gas produced from the 1.8 million barrels of oil and 22.5 billion cubic feet of gas reported in the comparable period during 2002. Our reported equivalent daily rate of production on a million cubic feet per day basis (Mmcfe/day) increased 7% to 196.6 Mmcfe/day in the 2003 period from 184.0 Mmcfe/day in the 2002 period. These increases were primarily the result of the merger with Prize and the success of our drilling program offsetting both normal production declines and the sale of non-strategic oil and gas properties subsequent to the Prize merger.

Oil revenues increased 26% to $52.5 million in the first six months of 2003 compared to $41.7 million for the same period in 2002. The oil price received, after hedging effects, was $26.85 per Bbl in the 2003 period compared to $23.15 per Bbl for the same period in 2002, an increase of 16%. Gas revenues increased 26% to $85.5 million in the first six months of 2003 versus $68.0 million for the same period in 2002. The gas price received, after hedging effects, was $3.59 per Mcf in the 2003 period compared to $3.02 per Mcf for the same period in 2002, an increase of 19%.

From time to time we enter into various commodity hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices which provides a base level of cash flow to fund capital expenditures. During the 2003 period, hedging decreased the average price we received for oil by $3.37 per Bbl and decreased the average price we received for gas by $1.68 per Mcf. During the first half of 2003, we had approximately 60.0 MMcf/day of gas hedged through fixed price swaps with a weighted average price of $3.01 per MMbtu and approximately 40.0 MMcf/day of gas hedged through cost-less collars with a weighted average floor price of $3.06 per MMbtu and a weighted average ceiling price of $4.30 per MMbtu. Approximately 76% of the first six months of 2003 natural gas production was hedged. On the crude side, we had approximately 1,000 Bbls/day hedged through fixed price swaps with a weighted average price of $21.25 per barrel and approximately 6,000 Bbls/day

hedged through cost-less collars with a weighted average floor price of $23.00 per Bbl and a weighted average ceiling price of $27.00 per Bbl. Approximately 65% of the first six months of 2003 crude oil production was hedged. For the remainder of 2003, we have approximately 10.0 MMcf/day hedged through fixed price swaps with a weighted average price of $3.65 per MMbtu and approximately 70.0 MMcf/day hedged through cost-less collars with a weighted average floor price of $2.82 and a weighted average ceiling price of $3.78. In addition, for the remainder of 2003, we have hedged 1,000 Bbls/day of crude oil production through a fixed price swap with a price of $21.25 per Bbl and 6,000 Bbls/day of crude oil production through cost-less collars with a weighted average floor price of $23.00 per Bbl and a weighted average ceiling price of $27.00 per Bbl.

On May 1, 2003, we closed out 20,000 Mmbtu/day of natural gas collar hedges for the period of June through December 2003. In closing these contracts, we locked in a $5.7 million loss which will be recognized in earnings with the underlying forecasted commodity sales transactions for the months of June through December 2003. At June 30, 2003, the remaining balance was $5.0 million.

Lease operating expense consists of lifting costs and production tax and other costs. For the 2003 period, lifting costs were $26.4 million versus $24.4 million in the 2002 period, an increase of 8%. Production taxes and other costs were $17.1 million in the 2003 period versus $12.2 million in the 2002 period, an increase of 40%. Both increases were primarily attributable to the Prize merger and increased commodity prices. For the 2003 period, lifting costs, on a unit of production basis, were $0.74 per Mcfe as compared to $0.73 per Mcfe in the 2002 period, an increase of 1%. Production tax and other costs were $0.48 per Mcfe in the 2003 period compared to $0.37 per Mcfe in the 2002 period, an increase of 30%. The increase in production taxes was caused by an increase in commodity prices received during the 2003 period.

Our gross margin realized from exploration and production operations (oil and gas revenues less lease operating expenses) for the first half of 2003 was $94.5 million, or $2.66 per Mcfe, compared to $73.1 million, or $2.19 per Mcfe in the 2002 period, an increase of 21% on a per unit of production basis. This is the result of an 18% increase in revenue per Mcfe, offset by a 11% increase in lease operating expense per Mcfe.

Depreciation, depletion, amortization and accretion of oil and gas properties was $44.7 million in the first half of 2003 versus $37.1 million in 2002. The 2003 period included accretion expense related to asset retirement obligations (due to the adoption of SFAS No. 143) of $1.2 million. On a unit of production basis, depreciation and depletion expense was $1.22 per Mcfe produced in the 2003 period versus $1.11 per Mcfe produced in the 2002 period. This 10% increase in the equivalent unit cost was due primarily to an increase in development costs and shorter reserve life properties associated with our activities in the Gulf of Mexico.

Segment profit for exploration and production operations was $49.8 million for the first six months of 2003 versus $36.0 million for the same period in 2002, an increase of 38%, primarily due to properties acquired in the Prize merger.

Gathering, Marketing and Processing Operations:

For the six months ended June 30, 2003, our gas gathering system throughput was 15.9 MMcf/day versus 15.2 MMcf/day for the same period in 2002, an increase of 5%. Gas processing throughput was 24.8 MMcf/day in 2003 versus 19.6 MMcf/day in 2002, an increase of 27%. This increase is primarily due to the acquisition of a 100% owned interest in the Elmore City processing plant as a result of the Prize merger.

Revenues from gas gathering, marketing and processing increased 125% to $18.4 million in 2003 versus $8.2 million in 2002. Operating costs for the gas gathering, marketing and processing segment increased 118% to $13.4 million in 2003 from $6.1 million in 2002. Both the revenues and operating cost increases were the result of increased gas processing throughput and higher commodity prices.

The gross margin realized from gas gathering, marketing and processing operations for the 2003 period was $5.0 million versus $2.0 million in the 2002 period, an increase of 147%. The gas gathering margin was $0.12 per Mcf gathered in both 2003 and in 2002. The gas processing margin increased 134% to $1.03 per Mcf in 2003 compared to $0.44 per Mcf in 2002, due to the addition of the Elmore City plant and improved plant processing economics.

Depreciation expense for gas gathering, marketing and processing operations for the 2003 period was $1.2 million versus $914 thousand for the same period in 2002, an increase of 26% due to the addition of the Elmore City plant which came from the Prize merger.

Segment profit for gas gathering, marketing and processing operations was $3.9 million in the first half of 2003 versus $1.1 million for the 2002 period, an increase of 265%, principally due to assets acquired in the Prize merger and improved natural gas processing economics.

Oil Field Management Services Operations:

Revenues from oil field management services increased 38% to $2.0 million in the 2003 period versus $1.4 million in the 2002 period. This increase is primarily due to an increase in the number of properties operated as a result of the Prize merger. Operating costs increased 77% to $1.5 million in 2003 from $819 thousand in 2002, also due to costs associated with the Prize merger. The gross margin for this segment in 2003 was $542 thousand versus $624 thousand in 2002, a decrease of 13%, due to overhead costs charged. Depreciation expense was $295 thousand in the 2003 period versus $238 thousand in the 2002 period, an increase of 24% due to capital additions. Segment profit was $248 thousand for the 2003 period versus $386 thousand for the same period in 2002.

Other Income and Expenses:

Total depreciation, depletion, amortization and accretion expense was $46.5 million in the 2003 period versus $38.6 million in the 2002 period, an increase of 20% primarily as a result of increased production due to the Prize merger.

General and administrative expense for 2003 decreased 6% to $6.3 million from $6.7 million in 2002. The 2002 period included costs related to the merger with Prize. We recorded equity in losses of affiliate of $237 thousand in 2003 versus earnings of $382 thousand in 2002, mainly due to the reduction of the carrying value of our investment in NGTS by $719 thousand to state it at its realizable value. Other income was $378 thousand for 2003 versus $165 thousand in 2002, caused by an increase in interest income. The company recognized a $536 thousand gain in other non-cash hedging adjustments in 2003 versus a $3.9 million loss in 2002. In the 2003 period, $648 thousand of the hedging gain relates to the amortization of commodity hedge assets acquired in conjunction with the Prize merger, while a loss of $112 thousand was due to recording hedge ineffectiveness.

We incurred costs associated with the early retirement of debt of $4.1 million during the first six months of 2003 versus $1.0 million in the same period of 2002. The 2003 period costs were associated with the $30 million and $50 million redemption of our 10% Senior Notes at 105% of par and 103.333% of par in January and June 2003, respectively. The 2002 period costs were associated with the amendment of our senior bank credit facility in connection with the Prize merger.

Interest expense was $25.0 million for 2003 versus $21.2 million for 2002, an increase of 18%, principally due to the placement of $300 million of 9.6% Senior Notes in March 2002 as a result of the Prize merger. Our weighted average interest rate paid under our senior bank credit facility was reduced to 3.4% in the 2003 period from 4.1% in the 2002 period.

The effective tax rate was 38.1% and (132.0)% for the six months ended June 30, 2003 and 2002, respectively. The variance from the statutory rate of 35% was primarily due to state income taxes in the 2003 period and to the release of the valuation allowance on previously reserved deferred tax assets in the 2002 period.

Liquidity and Capital Resources

CASH FLOW AND WORKING CAPITAL. Net cash provided by operating activities for the six month periods in 2003 and 2002 was $101.4 million and $537 thousand, respectively. The substantial increase in our operating cash flows in 2003 over 2002 was primarily the result of large payments in the first quarter of 2002 on trade payables which had accumulated at year-end as well as current liability balances acquired in the merger with Prize. We also benefited in the 2003 period from the return of $8.9 million in margins we had been required to post on certain commodity hedged positions and another $7.8 million received in net state and federal tax refunds. Our net working capital position at June 30, 2003 was a deficit of $56.7 million. On that date, we had $84.5 million available to be drawn under our $300 million Senior Bank credit facility. A large factor in our working capital deficit at June 30,

2003 is our current derivative liability of $39.6 million, partially offset by current deferred tax assets of $15 million, which we have recorded on our hedged positions for the next twelve months due to continued increases in commodities prices over our hedged prices. If actual commodities prices realized remain higher than our hedged prices on these positions, our resulting higher cash proceeds received on our production will offset any actual amounts paid out related to these liabilities.

INVESTING ACTIVITIES. Net cash used in investing activities was $88 million in the 2003 six month period. We made capital expenditures of $97.3 million under our capital budget during 2003. Our capital expenditures are discussed in further detail below. For 2003, we also received proceeds from the sale of assets of $9 million, net of certain purchase price adjustments related to both 2002 and 2003 divestitures.

In the 2002 six month period, net cash used in investing activities was $98 million. We made cash expenditures of $56.2 million under our capital budget during 2002. Additionally, during 2002, we made a loan of $2.4 million to an affiliate, received proceeds from sale of assets of $1.7 million, and used $41.1 million associated with the Prize merger.

FINANCING ACTIVITIES. Net cash used by financing activities was $7.2 million in the 2003 six month period. We borrowed a total of $248.6 million, of which we repaid $167.6 million. We paid $450 thousand in fees related to the amended Senior Bank credit facility, loaned $2.7 million to the ESOP to purchase shares for the plan, purchased treasury stock for $7.4 million, made a loan to an unconsolidated affiliate of $225 thousand, had an increase in restricted cash of $262 thousand, purchased common stock for our deferred compensation plan of $295 thousand, paid $76.9 million (net of Canvasback redemption) to redeem $80 million in principal of our 10% Notes, and received net proceeds from the issuance of common stock of $75 thousand. Our financing activities are discussed in further detail below.

Net cash provided by financing activities was $102.6 million in the 2002 six month period. We borrowed a total of $592.2 million, including $300 million in new 9.6% Senior Notes during the period. We also repaid borrowings of $461.4 million, including $155.7 million to pay off the previous bank credit facility, $245.8 million to pay off the Prize bank credit facility in connection with the merger, and the remainder to pay off other indebtedness. We paid $11.8 million in fees related to the newly issued 9.6% Senior Notes and the new Senior Bank credit facility (the “Facility”), loaned $2.7 million to the ESOP, purchased treasury stock for $13.8 million, purchased warrants for $98 thousand, and made a loan to a stockholder and executive officer for $175 thousand.

CAPITAL RESOURCES. The following discussion of Magnum Hunter’s capital resources refers to the company and our affiliates. Internally generated cash flow and the borrowing capacity under our Facility are our major sources of liquidity. From time to time, we may also sell non-strategic properties in order to increase liquidity. In addition, we may use other sources of capital, including the issuance of additional debt securities or equity securities, as sources to fund acquisitions or other specific needs. In the past, we have accessed both the public and private capital markets to provide liquidity for specific activities and general corporate purposes.

We amended our Facility in May 2003. The amended Facility provides for total borrowings of $300 million, up $50 million from the prior $250 million borrowing base. Additionally, the expiration date of the Facility was extended to May 2, 2006. The increase in borrowing capacity was used to retire an additional $50 million of our 10% Senior Notes at 103.333% of par plus accrued interest, or approximately $51.7 million on June 2, 2003. At June 30, 2003, we had $84.5 million available under this Facility.

On June 9, 2003, we sold certain oil and gas properties considered to be non-strategic assets for $13.4 million, subject to certain purchase price adjustments.

On March 7, 2002, Canvasback entered into a $10.0 million revolving credit agreement with a financial institution. This loan is collateralized by the 10% Senior Notes Canvasback owns. During 2002, this revolving loan was converted into a $7 million term loan. The proceeds of $6.1 million received by Canvasback as a result of the bond redemptions were used to reduce the outstanding balance to $932 thousand. In July 2003, Canvasback amended its term loan to allow for additional advances of up to $5 million for the purpose of additional repurchases of our 10% Senior Notes. The maturity date was also extended to May 31, 2005.

On May 1, 2002, our Board of Directors announced an expansion of our existing stock repurchase program originally established in June 2001. The company or our affiliates were authorized to repurchase up to two million

shares of our common stock. On October 17, 2002, our Board of Directors approved a new three million share repurchase program. Approximately 4.2 million shares have been purchased through June 30, 2003 under these programs, and approximately 818 thousand shares remain available for repurchase.

On a semi-annual basis, our borrowing base under our Facility is redetermined by the financial institutions who have committed to the company based on their review of our proved oil and gas reserves and other assets. If the outstanding senior bank debt exceeds the redetermined borrowing base, the company must repay the excess. The next redetermination date will have an effective date of June 30, 2003 and will be completed no later than November 10, 2003. We do not anticipate a downward redetermination.

Our internally generated cash flow, results of operations, and financing for our operations are substantially dependent on oil and gas prices. To the extent that oil and gas prices decline, our earnings and cash flows may be adversely affected in spite of our commodity hedging activities. We believe that our cash flow from operations, existing working capital and availability under our Facility will be sufficient to meet interest payments and to fund the capital expenditure budget for the year 2003.

CAPITAL EXPENDITURES. During the 2003 six month period, our total capital expenditures were $97.3 million. Our management intentionally “front end” loaded the 2003 budget in an effort to capture low service costs and high commodity prices. Exploration activities accounted for $14.3 million, development activities accounted for $70.2 million, unproved property acquisitions accounted for $11.1 million, proved property acquisitions accounted for $1.4 million, and additions to other assets accounted for $402 thousand of the capital expenditures. We participated in the drilling of 60 wells during the 2003 period, of which 55 were deemed commercial, for a 92% overall success rate. Of the 60 wells drilled, 12 were exploratory wells, of which 7 were successful, and 48 were development wells, all of which were successful. As of June 30, 2003, we had total unproved oil and gas property costs of $180 million.

For calendar year 2003, we have budgeted approximately $115 million for exploration and development activities. We are not contractually obligated to proceed with any of our material budgeted capital expenditures. The amount and allocation of future capital expenditures will depend on a number of factors that are not entirely within our control or ability to forecast, including drilling results, oilfield service costs, and changes in oil and gas prices. As a result, actual capital expenditures may vary significantly from current expectations. In the normal course of business, we review opportunities for the possible acquisition of oil and gas reserves and activities related thereto. When potential acquisition opportunities are deemed consistent with our growth strategy, bids or offers in amounts and with terms acceptable to us may be submitted. It is uncertain whether any such bids or offers which may be submitted by us from time to time, will be acceptable to the sellers. In the event of a future significant acquisition, utilizing cash, we may require additional financing in connection therewith.

FORWARD-LOOKING STATEMENTS. This Form 10-Q and the information incorporated by reference contain statements that constitute “forward-looking statements” within the meaning Section 27A of the Securities Act and Section 21E of the Securities Exchange Act. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs, or current expectations, including the plans, beliefs, and expectations of our officers and directors.

When considering any forward-looking statement, one should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks and other risk factors as described in our Annual Report on Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to Magnum Hunter Resources, Inc. are expressly qualified in their entirety by this cautionary statement.

Inflation and Changes in Prices

During the 2003 period, we experienced substantial increases in the price for both oil and gas compared to the same period in the previous year. The results of operations and cash flow of the company have been, and will continue to be, affected by the volatility in oil and gas prices. Should the company experience a significant increase in oil and gas prices that is sustained over a prolonged period, we would expect that there would also be a corresponding increase in oil and gas finding costs, lease acquisition costs, and operating expenses. Periodically, the company enters into futures, options, and swap contracts to reduce the effects of fluctuations in crude oil and gas prices. At inception, commodity hedge positions may not exceed 75% of the natural gas and 90% of the crude oil forecasted current (18 months) commodity production. For non-current (greater than 18 months) commodity production, at inception, commodity hedge positions for natural gas and crude oil may not exceed 75%. A portion of our oil and natural gas production will be subject to price fluctuations unless we enter into additional hedging transactions. For the remainder of 2003, we have approximately 60% of our combined crude oil and natural gas production hedged.

We market oil and gas for our own account, which exposes us to the attendant commodities risk. A significant portion of our gas production is currently sold to a 30% owned affiliate, NGTS, LLC, or end-users either on the spot market on a month-to-month basis at prevailing spot market prices, or under long-term contracts based on current spot market prices. We have elected to sell our interest in NGTS, LLC. Our ability to market our natural gas will not be impacted. We normally sell our oil under month-to-month contracts to a variety of purchasers.

Hedging

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as extended by SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June 2000), was effective for the company beginning January 2001. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recognition of derivatives in the balance sheet and the measurement of those instruments at fair value.

At June 30, 2003, the fair value of the company’s derivatives was as follows (in thousands):

Derivative Liabilities
Natural gas collars	$	37,658
Natural gas swaps		3,854
Crude oil collars		3,670
Crude oil swaps		1,784
Interest rate swaps		392

Total derivative liabilities	$	47,358

Of the $47.4 million derivative liability, $39.6 million is included in trade payables and accrued liabilities on our condensed consolidated balance sheet at June 30, 2003.

For the three and six month periods ended June 30, 2003, the statement of operations includes a non-cash hedging ineffectiveness loss of $157 thousand and $112 thousand, respectively, related to the crude oil and natural gas derivatives and a non-cash gain of $324 thousand and $648 thousand, respectively, related to the amortization of hedge contracts acquired in the Prize merger. The remaining amortization amounts relating to hedge contracts acquired in the Prize merger that will be reclassified into the operations statement in years 2003 and 2004 are a $0.6 million gain and $0.8 million gain, respectively. It is estimated at this time that $26.6 million of other comprehensive loss will be reclassified into the income statement during the next 12 months.

New Accounting Standards

SFAS No. 143 — SFAS No. 143, “Accounting for Asset Retirement Obligations,” became effective beginning January 1, 2003. SFAS No. 143 requires the recognition of a fair value liability for any retirement obligation associated with long-lived assets in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depreciated over the asset’s useful life. Upon adoption of SFAS No. 143, we recorded an addition to oil and gas properties of $25.4 million, an asset retirement obligation of $30.4 million, a reduction of accumulated depletion of $5.6 million, and a pre-tax gain of $643 thousand.

SFAS No. 145 — SFAS No. 145, “Recission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” became effective beginning January 1, 2003. The Statement rescinds, updates, clarifies and simplifies various existing accounting pronouncements. SFAS No. 145 rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt,” which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. As a result, SFAS No. 145 requires us to reclassify as additional expense extraordinary items for debt extinguishment costs which did not meet the criteria as described in APB Opinion No. 30 “Reporting the Results of Operations — Reporting the Effects of Disposal of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions.”

SFAS No. 148 – The FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an Amendment to FASB Statement No. 123,” in December 2002. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation and amends the disclosure requirements of SFAS No. 123. Beginning June 1, 2003, we began expensing the fair market value of stock options newly granted, modified or settled pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation,” and as allowed under the prospective method of SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to SFAS No. 123.” The fair value of each option granted after December 31, 2002 is estimated on the grant date using the Black-Scholes option-pricing model. For the six months ended June 30, 2003, we recorded stock compensation expense of $433 thousand which is reflected in our general and administrative expenses. For options granted prior to January 1, 2003, we continue to use the intrinsic method under APB No. 25, “Accounting for Stock Issued to Employees and Related Interpretations,” whereby no compensation expense is recognized for stock options granted with an exercise price equal to the market value of our stock on the grant date.

If we had recorded stock option expense under the fair value provisions of SFAS No. 123 for all grants, our net income and EPS would have been as shown in the below pro forma tables (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2002			2003			2002
Net income, as reported	$	4,170		$	2,251		$	12,160		$	9,698
Total Stock-based employee compensation expense
included in reported net income, net of related
tax effects		269			--			269			--

Deduct: Total stock-based employee compensation
determined under fair value-based method for all
awards, net of related tax effects		(991	)		(670	)		(1,662	)		(1,358	)

Pro forma net income	$	3,448		$	1,581		$	10,767		$	8,340

Earnings per share:
Basic - as reported	$	0.06		$	0.03		$	0.18		$	0.18

Basic - pro forma	$	0.05		$	0.02		$	0.16		$	0.15

Diluted - as reported	$	0.06		$	0.03		$	0.18		$	0.17

Diluted - pro forma	$	0.05		$	0.02		$	0.16		$	0.15

In the past we have provided trade guarantees on behalf of our 30% owned affiliate, NGTS, LLC. In the event that NGTS, LLC is unable to fulfill its obligations with certain vendors, we would be obligated for cash payments of up to $600 thousand to these vendors. We have not recorded these as a liability on our books at June 30, 2003 because we do not expect to have to perform under these guarantees. The last of these guarantees expires in July 2003, and we do not intend to issue any additional guarantees on behalf of NGTS, LLC. On July 29, 2003, we exercised our option to sell our 30% interest in NGTS, LLC. We have provided no other guarantees on behalf of any unconsolidated entities and do not intend to issue any.

Item 3. Qualitative and Quantitative Disclosure About Market Risk

Our operations are exposed to market risks primarily as a result of changes in commodity prices and interest rates. We do not use derivative financial instruments for speculative or trading purposes.

Commodity Price Swaps and Options

We produce, purchase, and sell crude oil, natural gas, condensate, and natural gas liquids. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces and conditions. We have previously engaged in oil and gas hedging activities and intend to continue to consider various hedging arrangements to realize commodity prices which we consider favorable. The company engages in hedging contracts for a portion of its oil and gas production through various contracts (“Swap Agreements”). The primary objective of these activities is to protect against significant decreases in price during the term of the hedge.

The Swap Agreements provide for separate contracts tied to the New York Mercantile Exchange (“NYMEX”) light sweet crude oil and Henry Hub natural gas, and the Inside FERC natural gas index price posting (“Index”). We have contracts which contain specific contracted prices (“Swaps”) that are settled monthly based on the differences between the contract prices and the specified Index prices for each month applied to the related contract volumes. To the extent the Index exceeds the contract price, we pay the spread, and to the extent the contract price exceeds the Index price, we receive the spread. In addition, we have combined option contracts which have agreed upon price floors and ceilings (“Costless collars”). To the extent the Index price exceeds the contract ceiling, we pay the spread between the ceiling and the Index price applied to the related contract volumes. To the extent the contract floor exceeds the Index, we receive the spread between the contract floor and the Index price applied to the related contract volumes.

To the extent we receive the spread between the contract price and the Index price applied to related contract volumes, we have a credit risk in the event of nonperformance of the counterparty to the agreement. We do not anticipate any material impact to our results of operations as a result of nonperformance by such parties.

We are contractually obligated to a counter-party to provide a margin deposit in the form of cash or bank letter of credit should the aggregate fair value of hedge contracts held with the counter-party exceed a predetermined value. Margins posted at June 30, 2003 totaled $400 thousand.

The following is a summary of the company’s open commodity hedge contracts as of June 30, 2003:

Commodity	Type	Volume/Day	Duration	Weighted Average Price
Natural Gas	Swap	10,000 MMBTU	Jul 03 - Dec 03	$3.65
Natural Gas	Collar	70,000 MMBTU	Jul 03 - Dec 03	$2.82 - $3.78
Natural Gas	Collar	55,000 MMBTU	Jan 04 - Dec 04	$3.64 - $4.93
Crude Oil	Swap	1,000 BBL	Jul 03 - Dec 03	$21.25
Crude Oil	Collar	6,000 BBL	Jul 03 - Dec 03	$23.00 - $27.00
Crude Oil	Collar	3,000 BBL	Jan 04 - Dec 04	$23.00 - $27.33

Based on future market prices at June 30, 2003, the fair value of open commodity hedging contracts was a liability of $47.0 million. If future market prices were to increase 10% from those in effect at June 30, 2003, the fair value of open contracts would be a liability of $85.5 million. If future market prices were to decline 10% from those in effect at June 30, 2003, the fair value of the open contracts would be a liability of $24.4 million.

At inception, commodity hedge positions may not exceed 75% of natural gas and 90% of crude oil forecasted current (18 months) commodity production. For non-current (greater than 18 months) commodity production, at inception, commodity hedge positions for natural gas and crude oil may not exceed 75%. Unhedged portions of our natural gas and crude oil production will be subject to market price fluctuations.

Interest Rate Swaps

On August 9, 2001, the company entered into two interest rate swaps in order to shift a portion of its variable rate bank debt to fixed rate debt. The following table reflects the terms of these swaps:

Type	Notional Amount	Termination Date	Pay Rate	Receive Rate
Pay Fixed/Receive Variable	$50,000,000	8/23/03	4.25% Fixed	3 month LIBOR (currently 1.27%)

Based on the set rates at June 30, 2003, the fair value of outstanding contracts to the company was a liability of $392 thousand.

Fixed and Variable Rate Debt. The company uses fixed and variable rate debt to partially finance budgeted expenditures. These agreements expose the company to market risk related to changes in interest rates.

The following table presents the carrying and fair value of the company’s debt along with average interest rates. Fair values are calculated as the net present value of the expected cash flows of the financial instruments, except for the fixed rate Senior Notes, which are valued at their last traded value before June 30, 2003.

Expected Maturity Dates	2003		2004-6		2007		2012		Total		Fair Value
(in thousands)
Variable Rate Debt:
Bank Debt with Recourse (a)	$	--	$	212,975	$	--	$	--	$	212,975	$	212,975
Bank Debt without Recourse (b)	$	--	$	932	$	--	$	--	$	932	$	932
Capital Leases (c)	$	990	$	5,331	$	2,172	$	--	$	8,493	$	8,493
Fixed Rate Debt:
Senior Notes (d)	$	--	$	--	$	55,534	$	--	$	55,534	$	57,478

Senior Notes (e)	$	--	$	--	$	--	$	300,000	$	300,000	$	330,000

Other	$	51	$	--	$	--	$	--	$	51	$	51


			(a)			The average interest rate on the bank debt with recourse is 3.01%.
			(b)			The average interest rate on the bank debt without recourse is 5.89%.
			(c)			The average interest rate on the two capital leases is 4.7%.
			(d)			The interest rate on the senior notes due 2007 is a fixed 10%.
			(e)			The interest rate on the senior notes due 2012 is a fixed 9.6%.

Item 4. Controls and Procedures

Our chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the company’s disclosure controls and procedures [as defined in Rules 240.13a-14 (c) and 15d-14 (c) promulgated under the Securities Exchange Act of 1934] as of a date within ninety days before the filing date of this quarterly report. Based on that review and evaluation, which included inquiries made to certain other employees of the company, the chief executive officer and chief financial officer have concluded that our current disclosure controls and procedures, as designed and implemented, are reasonably adequate to ensure that they are provided with material information relating to the company required to be disclosed in the reports the company files or submits under the Securities Exchange Act of 1934. There have not been any significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation. There were no significant deficiencies or material weaknesses and, therefore, no corrective actions were taken.

PART III – OTHER INFORMATION

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

Number			Description of Exhibit
3.1&4.1			Articles of Incorporation (Incorporated by reference to Registration Statement on Form S-18, File No. 33-30298-D)

3.2&4.2			Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for the year ended December 31, 1990)

3.3&4.3			Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement on Form SB-2, File No. 33-66190)

3.4&4.4			Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement on Form S-3, File No. 333-30453)

3.5&4.5			Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for the year ended December 31, 2001)

3.6&4.6			By-Laws, as Amended (Incorporated by reference to Registration Statement on Form SB-2, File No. 33-66190)

3.7&4.7			Amendment to By-Laws (Incorporated by reference to Registration Statement on Form S-4, File No. 333-76774)

3.8&4.8			Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K dated December 26, 1996, filed January 3, 1997)

3.9&4.9			Amendment to Certificate of Designations for 1996 Series A Convertible Preferred Stock (Incorporated by reference to Registration Statement on Form S-3, File No. 333-30453)

4.10			Form of Warrant Agreement by and between Magnum Hunter Resources, Inc. and American Stock Transfer & Trust Company, as warrant agent (Incorporated by reference to Registration Statement on Form S-3, File No. 333-82552)


4.11			Form of Warrant Agreement by and between Midland Resources, Inc. and Stock Transfer Company of America, Inc., as warrant agent, dated November 1, 1990 (Incorporated by reference to Registration Statement on Form S-3, File No. 333-83376)


4.12			Form of Warrant Agreement by and between Vista Energy Resources, Inc. and American Stock Transfer & Trust Company, as warrant agent, dated October 28, 1998 (Incorporated by reference to Registration Statement on Form S-3, File No. 333-83376)


4.13			Indenture dated May 29, 1997 between Magnum Hunter Resources, the subsidiary guarantors named therein and First Union National Bank of North Carolina, as Trustee (Incorporated by reference to Registration Statement on Form S-4, File No. 333-2290)


4.14			Supplemental Indenture dated January 27, 1999 between Magnum Hunter Resources, the subsidiary guarantors named therein and First Union National Bank of North Carolina, as Trustee (Incorporated by reference to Form 10-K for the fiscal year-end December 31, 1998 filed April 14, 1999)
4.15			Form of 10% Senior Note due 2007 (Incorporated by reference to Registration Statement on Form S-4, File No. 333-2290)

4.16			Indenture, dated March 15, 2002, between Magnum Hunter Resources, Inc., the subsidiary guarantors named therein and Bankers Trust Company, as Trustee (Incorporated by reference to Form 10-K for the year ended December 31, 2001)


4.17			Shareholder Rights Agreement dated as of January 6, 1998 by and between Magnum Hunter Resources, Inc. and Securities Transfer Corporation, as Rights Agent (Incorporated by reference to Form 8-K dated January 7, 1998, filed January 9, 1998)


10.1			Fourth Amended and Restated Credit Agreement, dated March 15, 2002, between Magnum Hunter Resources, Inc. and Bankers Trust Company, et al (Incorporated by reference to Form 10-K for the year ended December 31, 2001)


10.2			Amendment to Fourth Amended and Restated Credit Agreement (Incorporated by reference to Form 10-Q for the period ended June 30, 2002)

10.3			Amendment to Fourth Amended and Restated Credit Agreement (Incorporated by reference to Form 10-Q for the period ended March 31, 2003)

10.4			Employment Agreement for Gary C. Evans (Incorporated by reference to Form 10-K for the fiscal
			year-end December 31, 1999 filed March 30, 2000)
10.5			Employment Agreement for Richard R. Frazier (Incorporated by reference to Form 10-K for the
			fiscal year-end December 31, 1999 filed March 30, 2000)
10.6			Employment Agreement for Chris Tong (Incorporated by reference to Form 10-K for the year ended
			December 31, 2002)
10.7			Employment Agreement for R. Douglas Cronk (Incorporated by reference to Form 10-K for the year
			ended December 31, 2002)
10.8			Employment Agreement for Charles Erwin (Incorporated by reference to Form 10-K for the year ended
			December 31, 2002)
10.9			Purchase and Sale Agreement, dated February 27, 1997 among Burlington Resources Oil and Gas
			Company, Glacier Park Company and Magnum Hunter Production, Inc. (Incorporated by reference to
			Form 8-K, dated April 30, 1997, filed May 12, 1997)
10.10			Purchase and Sale Agreement between Magnum Hunter Resources, Inc., NGTS, et al, dated December
			17, 1997 (Incorporated by reference to Form 8-K, dated December 17, 1997, filed December 29, 1997)
10.11			Purchase and Sale Agreement dated November 25, 1998 between Magnum Hunter Production, Inc. and
			Unocal Oil Company of California (Incorporated by reference to Form 10-K for the fiscal year-end
			December 31, 1998, filed April 14, 1999)
10.12			Agreement of Limited Partnership of Mallard Hunter, L.P., dated May 23, 2000 (Incorporated by
			reference to Form 10-Q/A for the period ended June 30, 2000, filed November 30, 2000)
99.1*			Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002, signed by Gary C. Evans
99.2*			Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002, signed by Chris Tong
99.3*			Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Gary C. Evans
99.4*			Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Chris Tong

*Filed herewith

(b) Reports on Form 8-K

1) Form 8-K, filed April 28, 2003 under Item 9.

SIGNATURE

In accordance with the requirements of the Exchange Act, the Registrant has caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

MAGNUM HUNTER RESOURCES, INC.

By /s/ Gary C. Evans		August 5, 2003
Gary C. Evans Chairman, President and Chief Executive Officer

By /s/ Chris Tong		August 5, 2003
Chris Tong Senior Vice President and Chief Financial Officer

By /s/ Morgan F. Johnston		August 5, 2003
Morgan F. Johnston Senior Vice President, General Counsel and Secretary

By /s/ David S. Krueger		August 5, 2003
David S. Krueger Senior Vice President and Chief Accounting Officer

United States Securities and Exchange Commission Washington, D. C. 20549

Form 10-Q

PART 1 — FINANCIAL INFORMATION

Item 1. Financial Statements

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands of dollars)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited)(in thousands, except for per share amounts)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND OTHER COMPREHENSIVE INCOME FOR THE SIX MONTHS ENDED JUNE 30, 2003 (Unaudited) (in thousands)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (in thousands)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS June 30, 2003 (Unaudited)

NOTE 1 — MANAGEMENT’S REPRESENTATION

NOTE 2 – NEW ACCOUNTING STANDARDS

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

NOTE 3 – STOCK BASED COMPENSATION

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

NOTE 4 — GOODWILL

NOTE 5 – ASSET RETIREMENT OBLIGATIONS

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

NOTE 6 — EARNINGS PER SHARE INFORMATION

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

NOTE 7 — DEBT

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

NOTE 8 — HEDGING

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

NOTE 9 – SEGMENT DATA

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

NOTE 10 – CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

Magnum Hunter Resources, Inc. and Subsidiaries Condensed Consolidating Balance Sheets

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued) June 30, 2003 (Unaudited)

NOTE 11 – SUBSEQUENT EVENT

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

Results of Operations

Period to Period Comparison

For the Three Months Ended June 30, 2003 and 2002

For the Six Months Ended June 30, 2003 and 2002

Liquidity and Capital Resources

Inflation and Changes in Prices

Hedging

New Accounting Standards

Item 3. Qualitative and Quantitative Disclosure About Market Risk

Item 4. Controls and Procedures

PART III – OTHER INFORMATION

Item 6. Exhibits and Reports on Form 8-K

SIGNATURE

MAGNUM HUNTER RESOURCES, INC.

United States
Securities and Exchange Commission
Washington, D. C. 20549

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
(in thousands, except for per share amounts)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
AND OTHER COMPREHENSIVE INCOME
FOR THE SIX MONTHS ENDED JUNE 30, 2003
(Unaudited)
(in thousands)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(in thousands)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 2003
(Unaudited)