Magnum Hunter Resources 10-Q 2009 Q2 Quarterly report

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

x QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

-OR-

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

For the transition period from _______ to _______

Commission file number 001-32997

MAGNUM HUNTER RESOURCES CORPORATION

(Name of registrant as specified in its charter)

Delaware	86-0879278
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

777 Post Oak Boulevard, Suite 910, Houston, Texas 77056

(Address of principal executive offices)

(832) 369-6986

(Issuer’s telephone number)

Indicate by check mark  whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding twelve months, and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act):

Large accelerated filer o	Accelerated filer o
Non-accelerated filer o	Smaller reporting company x
(Do not check if a smaller reporting company)

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

As of August 1, 2009 there were 40,806,872 shares of the registrant’s common stock ($.01 par value) outstanding.

MAGNUM HUNTER RESOURCES CORPORATION

QUARTERLY REPORT ON FORM 10-Q

FOR THE PERIOD ENDED JUNE 30, 2009

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited):	1
Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	1
Consolidated Statements of Operations for the Three Months and Six Months Ended June 30, 2009 and 2008	2
Consolidated Statements of Shareholders’ Equity for the Six Months Ended June 30, 2009	3
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008	4
Notes to Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3. Quantitative and Qualitative Disclosures About Market Risk	20
Item 4T. Controls and Procedures	20
Part II. OTHER INFORMATION	21
Item 6. Exhibits	21
SIGNATURES	22

i

MAGNUM HUNTER RESOURCES CORPORATION

(FORMERLY PETRO RESOURCES CORPORATION)

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
	2009			2008
Assets
Current assets
Cash and cash equivalents	$	677,555		$	6,120,402
Accounts receivable		1,292,404			1,038,973
Prepaids		208,643			75,406
Derivative assets		1,906,186			2,944,997
Total current assets		4,084,788			10,179,778
Property and equipment
Oil and natural gas properties, successful efforts accounting
Unproved		18,199,691			18,562,932
Proved properties, net		31,068,522			27,264,790
Furniture and fixtures, net		134,832			110,499
Total property and equipment		49,403,045			45,938,221
Other assets
Derivative assets		2,423,475			4,338,832
Deferred financing costs, net of amortization of $335,005 and $129,200 respectively		991,975			1,197,780
Deposit		10,257			10,257
Total other assets		3,425,707			5,546,869
Total Assets	$	56,913,540		$	61,664,868
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable	$	569,571		$	2,617,034
Accrued liabilities		304,332			106,592
Revenue payable		76,500			-
Derivative liability		75,011			-
Payable on sale of partnership		640,695			754,255
Note payable		153,034			19,527
Total current liabilities		1,819,143			3,497,408
Revolving credit borrowings		7,500,000			6,500,000
Term loan		15,000,000			15,000,000
Asset retirement obligation		1,683,352			1,589,197
Total liabilities		26,002,495			26,586,605
Shareholders' equity
Preferred stock, $0.01 par value; 10,000,000 shares authorized,
none issued and outstanding.		-			-
Common stock, $0.01 par value; 100,000,000 shares authorized,
40,806,872 and 36,768,172 shares issued and outstanding
as of June 30, 2009 and December 31, 2008 respectively		408,069			367,682
Additional paid in capital		51,983,388			51,311,502
Accumulated deficit		(22,750,689	)		(17,985,830	)
Total shareholders' equity		29,640,768			33,693,354
Noncontrolling interest		1,270,277			1,384,909
Total Equity		30,911,045			35,078,263
Total Liabilities and Shareholders' Equity	$	56,913,540		$	61,664,868

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

1

MAGNUM HUNTER RESOURCES CORPORATION

(FORMERLY PETRO RESOURCES CORPORATION)

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenue
Oil and gas sales	$	2,428,891		$	4,368,442		$	4,245,927		$	7,426,443
Other income		100,000			-			200,000			100,000
Total revenue		2,528,891			4,368,442			4,445,927			7,526,443
Expenses
Lease operating expenses		1,273,205			1,346,708			2,517,767			2,569,106
Exploration		19,201			37,654			113,676			610,164
Depreciation, depletion and accretion		799,335			612,021			2,106,862			1,137,193
General and administrative		1,445,062			894,329			2,191,675			2,187,772
Total expenses		3,536,803			2,890,712			6,929,980			6,504,235
Income (loss) from operations		(1,007,912	)		1,477,730			(2,484,053	)		1,022,208
Other income and (expense)
Interest income		251			63,147			852			139,002
Interest expense		(607,509	)		(590,819	)		(1,178,186	)		(1,105,780	)
Loss on derivative contracts		(1,774,419	)		(2,778,056	)		(1,218,104	)		(3,463,650	)
Net loss		(3,389,589	)		(1,827,998	)		(4,879,491	)		(3,408,220	)
Less: Net loss attributable to noncontrolling interest		(3,987	)		223,165			114,632			349,990
Net loss attributable to Magnum Hunter Resources Corporation		(3,393,576	)		(1,604,833	)		(4,764,859	)		(3,058,230	)
Dividend on Series A Convertible Preferred		-			(277,993	)		-			(458,801	)
Net loss attibutable to common stockholders	$	(3,393,576	)	$	(1,882,826	)	$	(4,764,859	)	$	(3,517,031	)
Earnings per common share
Basic and diluted	$	(0.09	)	$	(0.05	)	$	(0.13	)	$	(0.10	)
Weighted average number of common shares outstanding
Basic and diluted		36,797,771			36,718,186			36,788,129			36,685,504

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

2

MAGNUM HUNTER RESOURCES CORPORATION

(FORMERLY PETRO RESOURCES CORPORATION)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30,
	2009			2008
Cash flows from operating activities
Net loss	$	(4,879,491	)	$	(3,408,220	)
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation, and accretion		2,106,862			1,137,193
Amortization included in interest expense		205,805			795,143
Dry hole costs		30,339			465,439
Issuance of common stock and stock options for services		712,273			891,317
Unrealized loss on derivative contracts		3,029,178			2,251,397
Changes in operating assets and liabilities:
Accounts receivable and accrued revenue		(253,431	)		(670,253	)
Prepaid expenses		(133,237	)		(134,247	)
Accounts payable		161,708			(452,910	)
Revenue payable		76,500			-
Accrued expenses		197,740			(102,009	)
Net cash provided by operating activities		1,254,246			772,850
Cash flows from investing activities
Capital expenditures		(7,830,600	)		(6,249,307	)
Purchase of floor		-			(363,175	)
Investment in partnership		-			(533,280	)
Cash used in investing activities		(7,830,600	)		(7,145,762	)
Cash flows from financing activities
Proceeds from loan		1,217,336			3,614,968
Principal payment on loan		(83,829	)		(2,170,358	)
Net cash provided by financing activities		1,133,507			1,444,610
Net decrease in cash and cash equivalents		(5,442,847	)		(4,928,302	)
Cash and cash equivalents, beginning of period		6,120,402			15,399,547
Cash and cash equivalents, end of period	$	677,555		$	10,471,245
Supplemental disclosure of cash flow information
Cash paid for interest	$	972,381		$	774,967
Cash paid for federal income taxes		-			-
Non-cash transactions
Preferred stock dividend paid in preferred shares	$	-		$	458,801
Capitalized interest in oil and gas properties	$	-		$	1,610,718
Property and equipment included in accounts payable	$	-		$	1,026,541

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

3

MAGNUM HUNTER RESOURCES CORPORATION

(FORMERLY PETRO RESOURCES CORPORATION)

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(Unaudited)

	Common Stock				Additional								Total
	Number				Paid-in		Accumulated			Noncontrolling			Shareholders'
	of Shares		Amount		Capital		Deficit			Interest			Equity
Balance, December 31, 2008		36,768,172	$	367,682	$	51,311,502	$	(17,985,830	)	$	1,384,909		$	35,078,263
Restricted stock issued to employees and directors		4,038,700		40,387		167,645								208,032
Stock options to employees and directors						504,241								504,241
Net loss								(4,764,859	)		(114,632	)		(4,879,491	)
Balance, June 30, 2009		40,806,872	$	408,069	$	51,983,388	$	(22,750,689	)	$	1,270,277		$	30,911,045

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

4

MAGNUM HUNTER RESOURCES CORPORATION

(FORMERLY PETRO RESOURCES CORPORATION)

Notes to Consolidated Financial Statements

(Unaudited)

Note 1—Basis of Presentation

The accompanying unaudited interim financial statements of Magnum Hunter Resources Corporation (the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America and the  rules of the Securities and Exchange Commission, and should be read in conjunction with the audited financial statements and notes thereto contained in the Company’s annual report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 31, 2009. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and the results of operations for the interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. Notes to the consolidated financial statements which would substantially duplicate the disclosure contained in the audited consolidated financial statements as reported in the 2008 annual report on Form 10-K have been omitted.

Effective January 1, 2009, the Company implemented Statement of Financial Accounting Standards (“SFAS”) No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment to ARB No. 51, (“SFAS 160”). This standard changed the accounting for and reporting of minority interest (now called noncontrolling interest) in the unaudited consolidated financial statements. The adoption of SFAS 160 has resulted in the reclassification of amounts previously attributable to noncontrolling interest to a separate component of stockholders’ equity on the accompanying unaudited consolidated balance sheets. Additionally, net loss attributable to noncontrolling interest is shown separately from net loss in the unaudited consolidated statements of operations.

Certain prior period balances have been reclassified to conform to the current period presentation. 

Note 2 – New Accounting Pronouncements

Effective this quarter, the Company implemented SFAS No. 165, Subsequent Events (“SFAS 165”). This standard establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. The adoption of SFAS 165 did not impact the Company’s financial position or results of operations. The Company evaluated all events or transactions that occurred after June 30, 2009 up through August 14, 2009, the date the Company issued these financial statements.  During this period, the Company did not have any material recognizable subsequent events. However, the Company did have nonrecognizable subsequent events as disclosed in Footnote 9.

In April 2009, the FASB issued FASB Staff Position (FSP) No. SFAS 107-1 and Accounting Principles Board (APB) 28-1, Interim Disclosures about Fair Value of Financial Instruments, (FAS 107-1) to amend SFAS No. 107, Disclosures about Fair Value of Financial Instruments and APB 28, Interim Financial Reporting.  SFAS 107-1 changes the reporting requirements on certain fair value disclosures of financial instruments to include interim reporting periods. The Company adopted FAS 107-1 in the second quarter of 2009. There was no impact on the Company’s operating results, financial position or cash flows; however additional disclosures were added for the Company’s fair value of financial instruments. See Note 3 “Fair Value of Financial Instruments” for more details.

Note 3 - Fair Value of Financial Instruments

The Company has adopted the provisions of SFAS No. 157, Fair Value measurements, for all its financial instruments. SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

● Level 1 — Quoted prices (unadjusted) for identical assets or liabilities in active markets

● Level 2 — Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable

● Level 3 — Significant inputs to the valuation model are unobservable

5

The following describes the valuation methodologies we used to measure financial instruments at fair value. 

Derivative Instruments

The follow table provides a summary of the fair value of our derivative liabilities measured on a recurring basis under SFAS 157:

Fair value measurements on a recurring basis June 30, 2009
	Level 1		Level 2		Level 3
Assets
Commodity derivatives	$	-	$	4,329,661	$	-
Liabilities
Commodity derivatives	$	-	$	75,011	$	-

Fair value measurements on a recurring basis December 31, 2008
	Level 1		Level 2		Level 3
Assets
Commodity derivatives	$	-	$	7,283,829	$	-
Liabilities
Commodity derivatives	$	-	$	-	$	-

At June 30, 2009 and December 31, 2008, the Company had commodity derivative financial instruments in place that are accounted for under SFAS 133. The Company does not apply hedge accounting as allowed by SFAS 133, therefore, the changes in fair value subsequent to the initial measurement are recorded in income. The estimated fair value amounts of the Company’s derivative instruments have been determined at discrete points in time based on relevant market information which resulted in the Company classifying such derivatives as Level 2. Although the Company’s derivative instruments are valued using public indexes, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange.

As of June 30, 2009 and December 31, 2008, the Company’s derivative contracts were with major financial institutions with investment grade credit ratings which are believed to have a minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance.

The estimated fair value of short-term financial instruments, including cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Senior Credit Agreement approximates carrying value because the facility’s interest rate approximates current market rates.

6

Note 4 —Derivative Financial Instruments

We entered into commodity derivative financial instruments intended to hedge our exposure to market fluctuations of oil and natural gas prices. As of June 30, 2009, we had commodity swaps for the following oil volumes:

	Barrels per quarter		Barrels per day		Price per barrel
2009
Third quarter		8,400		91	$	72.55
Fourth quarter		8,400		91	$	72.55
2010
First quarter		14,825		165	$	93.50
Second quarter		15,000		165	$	105.45
Third quarter		15,000		163	$	105.45
Fourth quarter		15,000		163	$	105.45
2011
First quarter		13,500		150	$	105.45
Second quarter		13,500		148	$	105.45
Third quarter		13,500		147	$	105.45
Fourth quarter		13,500		147	$	105.45

As of June 30, 2009, the fair value of the above commodity swaps amounted to $3,096,630.

On June 5, 2008, the Company purchased a floor at $110 per barrel for 100 bbls per day for the calendar year 2009 for a price of $363,175.  As of June 30, 2009 the fair value of the floor was $825,122.

On October 6, 2008, the Company purchased a floor at $7.75 per MCF for 20,000 MCF per month for the calendar year 2009 for a price of $200,400. As of June 30, 2009 the fair value of the floor was $332,898.

During six months ended June 30, 2009, the Company incurred a net loss of $1,218,104 related to derivative contracts. Included in this loss was $1,811,074 of realized gains related to settled contracts, and $3,029,178 of unrealized losses related to unsettled contracts. Unrealized gain and losses are based on the changes in the fair value of derivative instruments covering positions beyond June 30, 2009.

Note 5 – Noncontrolling Interest

The following table reconciles equity attributable to noncontrolling interest:

	Noncontrolling Interest
Noncontrolling interest at December 31, 2008	$	1,384,909
Loss attributable to noncontrolling interest		(114,632	)
Noncontrolling interest at June 30, 2009	$	1,270,277

Note 6 – Note payable

On April 10, 2009, the Company signed a promissory note with a finance company for $217,336 to finance its various insurance policies. The interest rate on the note is 4.75% with payments of $22,210 per month beginning May 1, 2009 and the final payment due February 1, 2009. The note is secured by the insurance policies.

7

Note 7 – Long-term debt

Long-term debt at June 30, 2009 and December 31, 2008 consist of the following:

			June 30,		December 31,
	Interest rate		2009		2008
Revolving credit borrowings		2.68% - 5.25%		7,500,000		6,500,000
Term loan		8.07% - 10.00%		15,000,000		15,000,000
			$	22,500,000	$	21,500,000

On April 16, 2009, the Company borrowed an additional $1,000,000 against its revolving credit facility.

The revolving credit borrowings bear interest, at the Company's option, at either a fluctuating base rate or a rate equal to LIBOR plus, in each case, a margin determined based on the Company's utilization of the borrowing base.  The term loan bears interest, at the Company's option, at a fluctuating base rate plus 6.50% per annum or a rate equal to LIBOR plus 7.50% per annum.  If an event of default occurs and is continuing, the lenders may increase the interest rate then in effect by an additional 2% per annum.

The above loans contain covenants that, among others things, restrict the ability of the Company to, with certain exceptions: (1) incur indebtedness; (2) grant liens; (3) acquire other companies or assets; (4) dispose of all or substantially all of its assets or enter into mergers, consolidations or similar transactions; (5) make restricted payments; (6) enter into transactions with affiliates; and (7) make capital expenditures.  The Company is also required to satisfy certain financial covenants, as amended on March 19, 2009, which included maintaining the following (1) a ratio of EBITDAX to Interest Expense of not less than 2.0:1.0 for the fiscal quarters ending March 31, 2009 and June 30, 2009; 2.25:1.0 for the fiscal quarters ending September 30, 2009 and December 31, 2009 and 2.5:1.0 for all fiscal quarters ending thereafter ; (2) a ratio of Total Reserve Value to Debt of not less than 1.75:1.0 as of any date of determination; (3) a ratio of  Net Debt to EBITDAX of not more than (a) 6.5:1.0 for 2009; 6.0:1 for 2010 and 5.0 for all fiscal quarters ending thereafter; and (4) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0:1.0.

PRC Williston LLC, the Company's majority-owned subsidiary ("PRC Williston"), has guaranteed the performance of all of the Company's obligations for the above loans.  Subject to certain permitted liens, the Company's obligations have been secured by the grant of a first priority lien on not less than 80% of the value of the Company's and PRC Williston's existing and to-be-acquired oil and gas properties and the grant of a first priority security interest in related personal property of the Company and PRC Williston. The Company has also granted a first priority security interest in its ownership interest in PRC Williston, subject only to certain permitted liens.

8

Note 8 —Share Based Compensation

On May 22, 2009, the Company granted 2,750,000 stock options to the new Chairman and 1,250,000 stock options to the new Chief Financial Officer. The stock options have an exercise price of $0.37 per share and expire May 22, 2014.  The options vest as follows: (a) Options to purchase 1,000,000 Shares shall vest and first become exercisable subject to and upon the Company’s acquisition of at least $20 million of additional debt capital, equity capital, or oil and gas properties, or any combination thereof, whether in one transaction or in a series of transactions, during the period commencing on the grant date and ending on May 22, 2010. (b) Options to purchase 1,000,000 Shares shall vest and first become exercisable subject to and upon the Common Stock trading at a price of $0.75 per share (as adjusted for splits, combinations and the like) for 20 of any 30 consecutive trading days during the period commencing on the grant date and ending on May 22, 2011. (c) Options to purchase 1,000,000 Shares shall vest and first become exercisable subject to and upon the Common Stock trading at a price of  $1.25 per share (as adjusted for splits, combinations and the like) for 20 of any 30 consecutive trading days during the period commencing on the grant date and ending on May 22, 2012. (d) Options to purchase 1,000,000 Shares shall vest and first become exercisable subject to and upon the Company achieving daily production of 1,400 boe per day during the period commencing on the grant date and ending on May 22, 2011. The term “boe” means barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. These options were valued using the Lattice model which made use of the following primary assumptions:

Expected volatility	189% to 337%
Expected dividend yield	0
Risk free rate	0.49% to 2.23%

The combined fair value of these stock options was determined to be $884,561.

On May 22, 2009, the Company also granted the new Chairman and the new Chief Financial Officer 2,750,000 and 1,250,000 of Restricted Stock, respectively. The shares of Restricted Stock become vested in the following amounts, at the following times and upon the following conditions, provided that the new employee remains in continuous employment of the Company through and on the applicable vesting date: (a) 1,500,000 Shares shall vest on January 1, 2010. (b) 625,000 Shares shall vest subject to and the Company’s acquisition of at least $20 million of additional debt capital, equity capital, or oil and gas properties, or any combination thereof, whether in one transaction or in a series of transactions, during the period commencing on the grant date and ending on  May 22, 2010.  (c) 625,000 Shares shall vest subject to and upon the Common Stock trading at a price of $0.75 per share (as adjusted for splits, combinations and the like) for 20 of any 30 consecutive trading days during the period commencing on the grant date and ending on May 22, 2011. (d)  625,000 Shares shall vest subject to and upon the Common Stock trading at a price of $1.25 per share (as adjusted for splits, combinations and the like) for 20 of any 30 consecutive trading days during the period commencing on the grant date and ending on May 22, 2012.  (e) 625,000 Shares shall vest subject to and upon the Company’s satisfaction in full of the performance condition set forth in Section 2(d) of the Option Agreement on or before May 22, 2011. The Restricted Stock also shall become vested at such earlier times, if any, as shall be provided in the restricted stock agreement or as shall otherwise be determined by the Compensation Committee in its sole and absolute discretion. Restricted stocks that contain both service and performance conditions were valued using the share price at grant date determined to be $0.35 per share for a total fair value of $962,500. Restricted stocks that contain both service and market conditions were valued using the Lattice model which made use of the following primary assumptions:

Expected volatility	189% to 337%
Expected dividend yield	0
Risk free rate	0.49% to 2.23%

The fair value of these restricted shares was determined to be $287,045.

On June 12, 2009 the Company granted a total of 172,000 stock options to certain employees.  These stock options have an exercise price of $0.69 per share of which 43,000 vested immediately. The remaining 129,000 stock options will be issued and will vest annually on June 12, 2010, 2011 and 2012. The stock options have a five year term expiring on June 12, 2014. The stock options were valued using the Black-Sholes model with the following assumption: $0.69 quoted stock price; $0.69 exercise price; 123.5% volatility; 3.25 year estimated life; zero dividends and a 1.91% discount rate. The fair value of these options was determined to be $88,122.

On June 26, 2009, the Company granted 100,000 stock options each to three existing board members and 130,000 stock options each to two of its existing board members. The stock options have an exercise price of $0.51 per share. The stock options fully vested on June 26, 2009, and have a 10 year term expiring June 26, 2019. The stock options were valued using the Black-Sholes model with the following assumption: $0.51 quoted stock price; $0.51 exercise price; 124.76% volatility; 5 year estimated life; zero dividends; 2.53% discount rate. The fair value of these options was determined to be $241,895.

The Company recognized stock compensation expense of $712,273 and $891,317 for the six months ended June 30, 2009 and 2008 respectively.

9

A summary of stock option activity for the six months ended June 30, 2009 is presented below:

	Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2008	1,035,000		$	3.11
Granted	4,732,000			.40
Exercised, forfeited, or expired	(25,000	)		2.50
Outstanding at June 30, 2009	5,742,000			.88
Exercisable at December 31, 2008	752,500			3.56
Exercisable at June 30, 2009	1,458,000		$	2.18

A summary of the Company’s non-vested options as of June 30, 2009 is presented below.

Non-vested Options	Shares
Non-vested at December 31, 2008		282,500
Granted		4,732,000
Vested		(705,500	)
Forfeited		(25,000)
Non-vested at June 30, 2009		4,284,000

Total unrecognized compensation cost related to the non-vested options amounted to $975,508 and $1,115,880 as of June 30, 2009 and 2008 respectively. The cost at June 30, 2009 is expected to be recognized over a weighted-average period of 1.93 years. The aggregate intrinsic value for options was $1,107,200; and the weighted average remaining contract life was 4.95 years.

A summary of the Company’s non-vested shares as of June 30, 2009 is presented below:

Non-vested Shares	Shares			Price Per Share
Non-vested at December 31, 2008		215,000			2.04
Granted		4,000,000			3.20
Vested		(80,000	)		2.09
Forfeited		(25,000	)		2.50
Non-vested at June 30, 2009		4,110,000			2.82

Total unrecognized compensation cost related to the above non-vested shares amounted to $1,278,946 and $383,557 as of June 30, 2009 and 2008 respectively. The cost at June 30, 2009 is expected to be recognized over a weighted-average period of 2.8 years.

A summary of warrant activity for the six months ended June 30, 2009 is presented below:

	Shares	Weighted- Average Exercise Price
Outstanding at December 31, 2008	6,838,962	$	2.15
Granted	-		-
Exercised, forfeited, or expired	-		-
Outstanding at June 30, 2009	6,838,962	$	2.15
Exercisable at December 31, 2008	6,838,962	$	2.15
Exercisable at June 30, 2009	6,838,962	$	2.15

The aggregate intrinsic value for warrants was $0; and the weighted average remaining contract life was 1.42 years.

Note 9 – Subsequent events

On July 13, 2009 the Company borrowed an additional $4,500,000 against its revolving credit facility.

On July 14, 2009  the Company formed a new subsidiary to purchase Magnum Hunter Resources, LP and the new subsidiary was  merged into the Petro Resources Corporation in order to effect a name change from "Petro Resources Corporation" to ''Magnum Hunter Resources Corporation".

On July 30, 2009, the Company paid $1,241,182 to Eagle Operating as an advance related to the drilling of a new horizontal well located in the Williston Basin in North Dakota.

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ITEM 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Industry terms used in this report are defined in the Glossary of Oil and Natural Gas Terms located at the end of this Item

In this report we make, and from time to time we otherwise make, written and oral statements regarding our business and prospects, such as projections of future performance, statements of management’s plans and objectives, forecasts of market trends, and other matters that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements containing the words or phrases “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimates,” “projects,” “believes,” “expects,” “anticipates,” “intends,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions identify forward-looking statements, which may appear in documents, reports, filings with the Securities and Exchange Commission, news releases, written or oral presentations made by our officers or other representatives to analysts, stockholders, investors, news organizations and others, and discussions with management and other of our representatives. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

Our future results, including results related to forward-looking statements, involve a number of risks and uncertainties. No assurance can be given that the results reflected in any forward-looking statements will be achieved. Any forward-looking statement speaks only as of the date on which such statement is made. Our forward-looking statements are based upon assumptions that are sometimes based upon estimates, data, communications and other information from operators, government agencies and other sources that may be subject to revision. Except as required by law, we do not undertake any obligation to update or keep current either (i) any forward-looking statement to reflect events or circumstances arising after the date of such statement, or (ii) the important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or which are reflected from time to time in any forward-looking statement.

There are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors, are included in our filings with the SEC, including the risk factors set forth of our annual report on Form 10-K for our 2008 fiscal year filed with the SEC on March 31, 2009.

General

Magnum Hunter Resources Corporation and subsidiaries (“Magnum Hunter”) is a Houston, Texas based independent exploration and production company engaged in the acquisition and development of producing properties, secondary enhanced oil recovery projects and production of oil and natural gas in the United States.

We develop and produce low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth. We currently own interests in approximately 286,282 gross (50,611 net) leasehold acres, of which 261,147 gross (43,281 net) acres are classified as undeveloped acreage.

In 2007, we acquired oil and gas producing assets in the Williston Basin area of North Dakota and added mineral acreage in the Permian Basin located in West Texas. In 2008, we participated in new prospects located in southwest Louisiana as well as in east Texas.  During 2009, the Company began to operate several of our projects with the intention of operating a much larger portion of our projects in the future. In May 2009, Messrs. Gary C. Evans and Ronald D. Ormand joined the Company as Chairman of the Board and Executive Vice President and Chief Financial Officer, respectively.

As of June 30, 2009, we held interests in approximately 238 producing wells in Texas, Louisiana and North Dakota.  Our current drilling inventory includes prospects located in Texas, Louisiana, New Mexico, North Dakota and Kentucky.

We recognize the value of hedging oil and gas production through both derivative and physical contracts to help stabilize future cash flow. During the second and third quarters of 2008, we entered into three separate hedging agreements. In June 2008, we purchased put options for crude oil at a price of $110 per bbl for 100 bbls per day of production during 2009. The cost of these crude oil put options was $363,175. We also entered into swap agreements in September covering 207,400 barrels of crude oil at a price of $105 per bbl for the period of October 2008 to December 2011. We incurred no cost in entering into these swap agreements. In addition to crude oil hedges, we hedged natural gas production in October 2008. We purchased natural gas put options at a strike price of $7.75 per mcf for 658 mcf per day (240,000 total mcf) of production during 2009. The cost of these natural gas put options was $200,400.

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As of June 30, 2009, our total proved reserves were 3,726 mboe, a gain of 608,000 Boe from year end 2008 of 3,118 mboe. This gain in proved reserves was primarily the result of gains from North Dakota proved reserves of 402 mboe. The total June 30, 2009 mid-year 2009 proved reserves is comprised of 2,910 mbbls of crude oil and NGLs and 816 mboe of natural gas. All mid-year reserve estimations were calculated internally by Magnum Hunter Resources engineering personnel.

Our executive offices are located at 777 Post Oak Blvd., Suite 910, Houston, Texas 77056, and our telephone number is (832) 369-6986.  Our web site is www.magnumhunterresources.com.  Additional information which may be obtained through our web site does not constitute part of this quarterly report on Form 10-Q.  A copy of this quarterly report on Form 10-Q is located at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549.  Information on the operation of the SEC’s Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330.  The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.gov.

Results of Operations

For the three months ended June 30, 2009 compared to the three months ended June 30, 2008

The Company’s net production increased by 20,426 boe from 48,798 boe to 69,224 boe for the quarter ended June 30, 2009. Production during this period included 36,882 barrels of oil, 127,778 mcf of natural gas, and 11,046 barrels of natural gas liquids for a barrel-equivalent total of 67,100 boe compared to 30,670 barrels of oil, 75,637 mcf of natural gas, and 5,522 barrels of natural gas liquids for a barrel-equivalent total of 48,798 boe for the quarter ended June 30, 2008.

For the quarter ended June 30, 2009, the average daily production was approximately 761 boe per day compared to average daily production of 536 boe per day for the quarter ended June 30, 2008.

 The Company's realized commodity prices for the quarter ended June 30, 2009 were approximately $51.19 per barrel of oil, $2.55 per mcf of natural gas, and $19.44 per barrel of natural gas liquids compared to $113.58 per barrel of oil, $7.91 per mcf of natural gas, and $51.95 per barrel of natural gas liquids for the comparable prior year period.

Revenue for the quarter ended June 30, 2009 consisted $2,428,891 of oil and gas sales compared to oil and gas sales of $4,368,442 for the quarter ended June 30, 2008. The decrease in revenue from oil and gas sales was due primarily to significantly lower commodity prices.

Lease operating expenses for the quarter ended June 30, 2009 totaled $1,273,205 compared to lease operating expenses of $1,346,708 for the prior year comparable period. While lease operating expenses have not come off as quickly as the drop in commodity prices in the initial months of 2009, the industry has begun to see a retreat in these costs reflecting the current market conditions.

Exploration costs for the quarter ended June 30, 2009 were $19,201 compared to $37,654 for the quarter ended June 30, 2008. Exploration costs represent our drilling costs associated with dry holes and the carrying costs of properties. The decrease in exploration costs is the result of fewer dry hole expenses due to our curtailment of exploratory drilling.

We incurred no expenses related to the impairment of oil and gas properties in the quarters ended June 30, 2009 or 2008. Impairment expenses represent the write-down of previously capitalized expenses for productive wells. We take an impairment charge for a productive well when there is an indication that we may not receive production payments equal to the net capitalized costs. No wells needed to be written down in either quarter.

Our expenses for depreciation, depletion, and accretion for the quarter ended June 30, 2009 totaled $799,335 compared to $612,021 for the same period in the prior year. This was due to our increased production as well as an increase in depletion rates.

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General and administrative expenses for the quarter ended June 30, 2009 totaled $1,445,062 compared to general and administrative expenses of $894,329 for the prior year period. General and administrative expenses for the quarters ended June 30, 2009 and June 30, 2008 included expenses of $519,498 and $296,682, respectively, for new common stock grants for compensation and common stock options granted under our Stock Incentive Plan. Without giving effect to expenses for common shares and stock options, our general and administrative expenses for the quarters ended June 30, 2009 and June 30, 2008 were $925,564 and $597,647, respectively. The increase in general and administrative expenses (other than expenses for options and common shares) between reporting periods was due to the increased number of employees and additional office space in conjunction with the expansion of the Company's operations.

We incurred a net loss from operations of $1,500,084 for the quarter ended June 30, 2009 compared to net income from operations of $1,477,730 during the same period in the prior year.   The increase in net loss is due to lower revenue because of lower commodity prices and higher depletion because of increased production.

During the quarter ended June 30, 2009, interest expense totaled $607,509, compared to $590,819 for the quarter ended June 30, 2008.  The increase in interest expense was principally due to decreased capitalization of interest and a LIBOR floor of 2.5% being placed on our long term debt that did not exist in the 2008 period.

Beginning in March 2007, we entered into commodity derivative financial instruments for purposes of hedging our exposure to market fluctuations of oil prices.  During the quarter ended June 30, 2009, we incurred a loss on derivative contracts of $1,774,419 compared to a loss of $2,778,056 for the comparable period in 2008. Our loss on derivative contracts include both $756,342 in gains on the actual settlement of certain derivative financial instruments during the quarter ended June 30, 2009 and the unrealized loss of $2,530,761 based on the changes in the fair value of derivative instruments covering positions beyond June 30, 2009.

We incurred a net loss attributable to common shareholders of $3,393,576 ($.10 per share) during the quarter ended June 30, 2009, compared to a net loss of $1,882,826 ($.05 per share) to common shareholders for the same period in 2008.  The increase in net loss was primarily the result of a decrease in commodity prices leading to lower revenue and an increase in depletion due to higher production rates.

For the six months ended June 30, 2009 compared to the six months ended June 30, 2008

The Company’s net production for the six months ended June 30, 2009 included 70,251 barrels of oil, 249,651 mcf of natural gas, and 23,147 barrels of natural gas liquids for a barrel-equivalent total of 135,007 boe. This compared to 60,857 barrels of oil, 122,523 mcf of natural gas, and 9,557 barrels of natural gas liquids for a barrel-equivalent total of 90,834 boe for the six months ended June 30, 2008.

For the six months ended June 30, 2009, the average daily production was approximately 746 boe per day compared to average daily production of 499 boe per day for the six months ended June 30, 2008.

The Company's realized commodity prices for the six months ended June 30, 2009 were $42.95 per barrel of oil, $2.89 per mcf of natural gas, and $21.95 per barrel of natural gas liquids compared to $99.87 per barrel of oil, $7.09 per mcf of natural gas, and $50.31 per barrel of natural gas liquids for the comparable prior year period.

Revenues for the six months ended June 30, 2009 totaled $4,445,927 compared to revenues of $7,526,443 for the six months ended June 30, 2008. Revenue for the six months ended June 30, 2009 consisted $4,245,927 of oil and gas sales compared to oil and gas sales of $7,426,443 for the six months ended June 30, 2008. The decrease in revenue from oil and gas sales was due primarily to a decrease in commodity prices partially offset by increased production due to our successful secondary enhanced oil recovery operations in North Dakota and our drilling results in Crockett County, Texas.

Lease operating expenses for the six months ended June 30, 2009 totaled $2,517,767 compared to lease operating expenses of $2,569,106 for the prior year comparable period. The slight decrease in lease operating expenses is due primarily to the fact that operating expenses are beginning to come down as commodity prices decrease.

Exploration costs for the six months ended June 30, 2009 were $113,676 compared to $610,164 for the six months ended June 30, 2008. Exploration costs represent our drilling costs associated with dry holes and the carrying costs of properties. The decrease in exploration costs is the result of fewer dry hole expense due to our curtailment of  exploratory drilling.

We incurred no expenses related to the impairment of oil and gas properties in the six months ended June 30, 2009 as well as during the prior year comparable period. Impairment expenses represent the write-down of previously capitalized expenses for productive wells. We take an impairment charge for a productive well when there is an indication that we may not receive production payments equal to the net capitalized costs.

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Our expenses for depreciation, depletion, and accretion for the six months ended June 30, 2009 totaled $2,106,862, compared to $1,137,193 for the same period in the prior year. This was due to our increased production as well as an increase in depletion rates.

General and administrative expenses for the six months ended June 30, 2009 totaled $2,191,675 compared to general and administrative expenses of $2,187,772 for the prior year period. General and administrative expenses for the six months ended June 30, 2009 and June 30, 2008 included expenses of $712,273 and $891,317, respectively, for new common stock grants for compensation and common stock options granted under our Stock Incentive Plan. Without giving effect to expenses for common shares and stock options, our general and administrative expenses for the six months ended June 30, 2009 and June 30, 2008 were $1,479,402 and $1,296,455, respectively. The increase in general and administrative expenses (other than expenses for options and common shares) between reporting periods was due to the increased number of employees and additional office space in conjunction with the expansion of the Company's operations.

We realized a loss from operations of $2,484,053 for the six months ended June 30, 2009 compared to net income from operations of $1,022,208 during the same period in the prior year.   The decrease is due to lower revenue because of lower commodity prices and higher depletion because of increased production.

During the six months ended June 30, 2009, interest expense totaled $1,178,186, compared to $1,105,780 for the six months ended June 30, 2008.  The increase in interest expense was principally due to decreased capitalization of interest and a LIBOR floor of 2.5% being placed on our long term debt that did not exist in the 2008 period.

Beginning in March 2007, we entered into commodity derivative financial instruments for purposes of hedging our exposure to market fluctuations of oil prices.  During the six months ended June 30, 2009, we incurred a loss on derivative contracts of $1,218,104 compared to a loss of $3,463,650 for the comparable period in 2008. Our loss on derivative contracts include both $1,811,074 in gains on the actual settlement of certain derivative financial instruments during six months ended June 30, 2009 and the unrealized losses related to unsettled swap contracts and the floors of $3,029,178. Unrealized losses are based on the changes in the fair value of derivative instruments covering positions beyond June 30, 2009.

We incurred a net loss attributable to common stockholders of $4,764,859 ($.13 per share) during the six months ended June 30, 2009, compared to a net loss of $3,517,031 ($.10 per share) for the same period in 2008.  The increase in net loss was primarily the result of a decrease in commodity prices leading to lower revenue and an increase in depletion due to higher production rates.

Reserves

Our natural gas and crude oil reserves have been estimated internally as of June 30, 2009 by Magnum Hunter engineering personnel based predominantly on third party prepared engineering reports.  Natural gas and crude oil reserves and the estimates of the present value of future net revenues therefrom, were determined based on then current prices and costs. Since January 1, 2009, we have not filed, nor were we required to file, any reports concerning our oil and gas reserves with any federal authority or agency.

There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserve quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.

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The following table sets forth our estimated proved reserves as of June 30, 2009.

	Proved Reserves
	6/30/2009						12/31/2008
	Developed		Undeveloped		Total		Developed		Undeveloped		Total
Crude Oil & NGL (Bbls)
North Dakota		1,175,834		595,610		1,771,444		880,286		488,683		1,368,969
Cinco Terry		459,412		591,777		1,051,189		476,586		476,383		952,969
Other		32,290		54,890		87,180		37,436		49,879		87,315
Total Oil (Bbls)		1,667,536		1,242,277		2,909,813		1,394,308		1,014,945		2,409,253
Natural Gas (Boe)
North Dakota		108,178		-		108,178		85,143		-		85,143
Cinco Terry		313,591		290,290		603,881		289,274		235,809		525,083
Other		52,650		51,760		104,410		50,500		48,100		98,600
Total Gas (Boe)		474,419		342,050		816,469		424,917		283,909		708,826
Total Proved Reserves (Boe)		2,141,955		1,584,327		3,726,282		1,819,225		1,298,854		3,118,079

Plan of Operations

Magnum Hunter’s plan of operations is to capitalize on market opportunities to acquire leveraged and underperforming producing assets. The Company intends to grow its asset base with a focus on acquiring distressed assets, increasing the percentage of operated assets, increasing exposure to resource plays and unconventional areas and leveraging management’s operating experience. We plan to continue further exploration and development of oil and natural gas prospects that we currently own while concentrating on those with the lowest development and lifting costs. Consistent with our plans is our structuring and staffing of our company towards increased operations of oil and gas properties anywhere in the U.S.

The continued development of our properties and prospects and the pursuit of new opportunities will require that we maintain access to adequate levels of capital.   We strive for an optimal balance between our property portfolio and our capital structure that allows for growth and benefit to our shareholders.   The balancing of capital needs and property holdings will be challenging during times of lower commodity prices, the access to capital markets and the complex global economic picture.

The business of oil and natural gas property acquisition, exploration and development is capital intensive. The level of success attainable by an oil and gas company is directly linked to and limited by the amount of available capital. A principal part of our plan of operations is to raise the additional capital to finance future acquisitions and the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties.  As explained under “Financial Condition and Liquidity” below, based on our present working capital, borrowings and borrowing available under the credit facility and expected cash flow from operations, we believe we have sufficient working capital to fund our operations and expected commitments through at least June 30, 2010.  

We intend to use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental, audit and tax services.  We believe that by limiting our management and employee costs, we are able to better control overall costs and retain flexibility in terms of project management.  

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Financial Condition and Liquidity

The Company’s cash flow from operations increased $481,396 from $722,850 at June 30, 2008 to $1,254,246 at June 30, 2009. This increase was due to increases in accounts payable, revenue payable, accrued expenses and accounts receivable partially offset by decreased revenue due to decreased commodity prices. Our cash used in investing activities increased from $7,145,762 at June 30, 2008 to $7,830,600 at June 30, 2009. This was due to increased investment activity on our Cinco Terry property. Net cash provided by financing activity was $1,133,507 at June 30, 2009 compared to $1,444,610 at June 30, 2008. The Company borrowed less money because it was able to generate funds from results of operations during the period.

As of the date of this report, we estimate our capital budget for fiscal 2009 to be approximately $11.6 million of which, $5.7 million has been expended during the first two quarters of 2009, including:

· Up to $3.8 million to be deployed for drilling in Cinco Terry of which $2.9 million has been expended during the first two quarters of 2009.

· Approximately $1.0 million for drilling and completion operations in the Surprise Prospect that has been expended during the first two quarters of 2009.

· Approximately $300,000 to be used for new drilling and salt water disposal facilities in the East Chalkley Prospect and Leblanc Prospect.

· Approximately $4.5 million to drill new production wells and maintain secondary recovery efforts in North Dakota of which $400,000 has been committed to date.

· Approximately $2.0 million to be used in connection with other prospect areas including $1.4 million deployed in the first two quarters of 2009.

As of June 30, 2009, we had total assets of $56,913,540 and working capital of $2,265,645.  In addition, we have $65.0 million in credit facilities, of which $15.0 million was outstanding on the Second Lien Term Loan Agreement and $7.5 million was outstanding on the Credit Agreement as of June 30, 2009. We have currently drawn down the remaining credit available under the current borrowing base of $12 million. The borrowing base under our current credit facilities will be re-determined based on mid-year reserves. Based on our present working capital and current rate of cash flow from operations, we believe that we have available to us sufficient working capital to fund our operations and expected commitments for exploration and development through at least June 30, 2010.  However, in the event we receive calls for capital greater than, or generate cash flow from operations less than, we expect, we may require additional working capital to fund our operations and expected commitments for exploration and development prior to June 30, 2010.  

We may seek to obtain additional working capital through the sale of our securities and, subject to the successful deployment of our cash on hand, we will endeavor to obtain additional capital through bank lines of credit, private equity investors, hedge funds and project financing.  However, other than our existing credit facilities, we have no agreements or understandings with any third parties at this time for our receipt of additional working capital and we have no history of generating significant cash from existing oil and gas operations.  Further, as described below, under the terms of our existing credit facilities, we are prohibited from incurring any additional debt from third parties.  Our ability to obtain additional working capital through bank lines of credit, private equity investors, hedge funds and project financing may be subject to the repayment of our credit facilities.  Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms.  If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price may be materially adversely affected.

CIT Credit Facility

On September 9, 2008, we entered into a $50.0 million Credit Agreement (the "Credit Agreement") with CIT Capital USA Inc., as administrative agent for the lenders, and a $15.0 million Second Lien Term Loan Agreement (the "Second Lien Term Loan Agreement") with CIT Capital USA Inc., as administrative agent for the lenders.

The Credit Agreement provides for a $50.0 million first lien revolving credit facility, with an initial borrowing base availability of $17.0 million. The maturity date of the Credit Agreement is September 9, 2011. Borrowings under the Credit Agreement bear interest, at our option, at either a fluctuating base rate or a rate equal to LIBOR plus, in each case, a margin determined based on our utilization of the borrowing base.

The Credit Agreement was amended on March 19, 2009. The amended terms include the adjustment of negative covenants, the addition of a LIBOR floor of 2.5%, a fifty basis point increase to the margin and a reduction of the borrowing base to $12.0 million from $17.0 million.

The Second Lien Term Loan Agreement provides for a $15 million second lien term loan facility. The maturity date of the Second Lien Term Loan Agreement is September 9, 2012. Borrowings under the Second Lien Term Loan Agreement bear interest, at our option, at either a fluctuating base rate plus 6.50% per annum or a rate equal to LIBOR plus 7.50% per annum.

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PRC Williston LLC, our subsidiary, has guaranteed the performance of all of our obligations under the Credit Agreement, the Second Lien Term Loan Agreement and related agreements pursuant to a Guaranty and Collateral Agreement and a Second Lien Guaranty and Collateral Agreement each dated as of September 9, 2008. Subject to certain permitted liens, our obligations have been secured by the grant of a first priority lien on no less than 80% of the value of our and PRC Williston's existing and to-be-acquired oil and gas properties and the grant of a first priority security interest in related personal property of ours and PRC Williston. We also granted a first priority security interest in our ownership interest in PRC Williston, subject only to certain permitted liens.

As of June 30, 2009, we had drawn $22.5 million on the CIT facility, of which $15.0 million was drawn on the Second Lien Term Loan Agreement and $7.5 million was drawn on the Credit Agreement. Subsequent to June 30, 2009 and in light of CIT Capital USA Inc.’s recent financial situation, we have drawn down the $4.5 million remaining under the current borrowing base on the Credit Agreement that is maintained as cash in a financial institution.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet financing arrangements. 

Glossary of Oil and Natural Gas Terms

The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.

bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

bcf. Billion cubic feet of natural gas.

boe. Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

boe/d. boe per day.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Hydrocarbons which are in the gaseous state under reservoir conditions and which become liquid when temperature or pressure is reduced. A mixture of pentanes and higher hydrocarbons.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Drilling locations. Total gross locations specifically quantified by management to be included in the Company’s multi-year drilling activities on existing acreage. The Company’s actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

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Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. An identifiable layer of rocks named after its geographical location and dominant rock type.

Lease. A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.

Leasehold. Mineral rights leased in a certain area to form a project area.

mbbls. Thousand barrels of crude oil or other liquid hydrocarbons.

mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids

mcf. Thousand cubic feet of natural gas.

mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

mmbbls. Million barrels of crude oil or other liquid hydrocarbons.

mmboe. Million barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

mmbtu. Million British Thermal Units.

mmcf. Million cubic feet of natural gas.

Net acres, net wells, or net reserves. The sum of the fractional working interest owned in gross acres, gross wells, or gross reserves, as the case may be.

ngl. Natural gas liquids, or liquid hydrocarbons found in association with natural gas.

Overriding royalty interest. Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working interest the operator owns. This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no obligation or responsibility for developing and operating the property. The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues (PV-10). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such a general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

PV-10. Pre–tax present value of estimated future net revenues discounted at 10%.

Production. Natural resources, such as oil or gas, taken out of the ground.

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Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i)   Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii)   Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii)   Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilscnite , and other such sources.

Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves he attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Probable Reserves. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

Possible Reserves. Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

Productive well. A well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

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Project. A targeted development area where it is probable that commercial gas can be produced from new wells.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Recompletion. The process of re-entering an existing well bore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reserves. Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible nature gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.

Shut-in. A well that has been capped (having the valves locked shut) for an undetermined amount of time. This could be for additional testing, could be to wait for pipeline or processing facility, or a number of other reasons.

Standardized measure. The present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful. A well is determined to be successful if it is producing oil or natural gas, or awaiting hookup, but not abandoned or plugged.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Water flood. A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil and enhance hydrocarbon recovery.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Not applicable.

ITEM 4(T).       CONTROLS AND PROCEDURES

Our chairman and chief financial officer have reviewed and continue to evaluate the effectiveness of our controls and procedures over financial reporting and disclosure (as defined in the Securities Exchange Act of 1934 (“Exchange Act”) Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this quarterly report. The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our chairman and chief financial officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating our controls and procedures over financial reporting and disclosure, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and our management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

An evaluation was performed under the supervision and with the participation of our management, including our chairman and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2009. Based on that evaluation, our management, including our chairman and chief financial officer, has concluded that our disclosure controls and procedures were effective as of June 30, 2009.

Changes in Internal Control. We made no changes to our internal control over financial reporting during the quarter ended June 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 6.    EXHIBITS

Exhibit No.	Description	Method of Filing
31.1	Certification of Chairman Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934	Filed herewith
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934	Filed herewith
32	Certification of Chairman and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350	Filed herewith

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SIGNATURES

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

	MAGNUM HUNTER RESOURCES CORPORATION
Date: August 14, 2009		/s/ Gary C. Evans
		Gary C. Evans,
		Chairman

Date: August 14, 2009	/s/ Ronald D. Ormand
	Ronald D. Ormand,
	Chief Financial Officer

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