Mesa Energy 10-Q 2012 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended June 30, 2012

or

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

For the Transition Period from _________ to _________

Commission file number: 000-53972

MESA ENERGY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

Delaware	98-0506246
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

5220 Spring Valley Road, Suite 615

Dallas, Texas 75254

(Address of principal executive offices) (zip code)

(972) 490-9595

(Registrant’s telephone number, including area code)

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.    Yesþ   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). Yesþ    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.  See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer¨ Accelerated filer¨ Non-accelerated filer¨ Smaller reporting companyþ

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

As of August 10, 2012, there were 83,302,769 shares of the registrant’s common stock outstanding.

INDEX TO FINANCIAL STATEMENTS

	Page
PART I.  FINANCIAL INFORMATION
Item 1.  Financial Statements	3
Consolidated Balance Sheets (Unaudited) as of June 30, 2012 and December 31, 2011	3
Consolidated Statements of Operations (Unaudited) for the Three and Six Months Ended June 30, 2012 and 2011	5
Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2012 and 2011	6
Notes to Consolidated Financial Statements (Unaudited)	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	24
Item 4. Controls and Procedures	24
PART II.  OTHER INFORMATION
Item 1.  Legal Proceedings	25
Item 1A.  Risk Factors	25
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	25
Item 3.  Defaults Upon Senior Securities	26
Item 4.  Mine Safety Disclosures	26
Item 5.  Other Information	26
Item 6.  Exhibits	26
Signatures	27

PART 1. FINANCIAL INFORMATION

Item 1. Consolidated Interim Financial Statements

MESA ENERGY HOLDINGS, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2012		December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	3,587,611	$	3,182,392
Accounts receivable – oil and gas		1,807,430		2,460,260
Accounts receivable – other		251,592		58,818
Derivative assets, commodity contracts – current		828,524		656,413
Deferred financing costs – current		51,507		51,507
Prepaid expenses		57,832		3,971
TOTAL CURRENT ASSETS		6,584,496		6,413,361
Oil and gas properties, successful efforts accounting:
Proved properties subject to amortization – net		6,765,654		6,742,027
Unproved properties not subject to amortization		500,700		—
Support facilities and equipment – net		2,415,176		2,061,777
Land		48,345		48,345
Oil and gas properties – net		9,729,875		8, 852,149
Office furniture and equipment – net		78,553		31,834
Deferred tax asset – noncurrent		2,826,735		3,088,740
Deferred financing cost – noncurrent, net of accumulated amortization of $313,656 and $287,943, respectively		2,718		28,431
Derivative assets, commodity contracts – noncurrent		32,921		282,537
Deposit on asset retirement obligations		640,000		640,000
Other assets		4,013		5,000
TOTAL ASSETS	$	19,899,311	$	19,342,052

See accompanying notes to these unaudited consolidated financial statements.

3

MESA ENERGY HOLDINGS, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(Continued)

	June 30, 2012		December 31, 2011
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable – trade	$	1,233,955	$	1,518,603
Revenue payable		621,777		796,221
Accrued expenses		274,012		259,808
Accrued expenses – related parties		54,840		54,840
Deferred tax liability – current		303,800		212,781
Notes payable – current		25,632		466,655
TOTAL CURRENT LIABILITIES		2,514,016		3,308,908
Non-current liabilities:
Notes payable – noncurrent		5,303,251		5,162,018
Convertible notes payable, net of discount		50,000		461,740
Derivative liability, convertible debt – noncurrent		11,788		113,083
Asset retirement obligations		3,409,260		3,450,252
TOTAL LIABILITIES		11,288,315		12,496,001
Commitments and contingencies		—		—
Stockholders’ equity:
Preferred stock, par value $0.0001, 10,000,000 shares authorized, -0- shares issued and outstanding		—		—
Common stock, par value $0.0001, 300,000,000 shares authorized, 83,302,769 and 79,531,616 shares issued and outstanding, respectively		8,330		7,953
Additional paid-in capital (deficiency)		609,261		(633,745	)
Retained earnings		7,993,405		7,471,843
TOTAL  STOCKHOLDERS’ EQUITY		8,610,996		6,846,051
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	19,899,311	$	19,342,052

See accompanying notes to these unaudited consolidated financial statements.

4

MESA ENERGY HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
				(Restated)						(Restated)
Revenue	$	3,847,090		$	18,679		$	8,241,902		$	37,088
Operating expenses:
Lease operating expense		1,640,004			—			3,622,968			—
Environmental remediation expense		28,023			—			244,237			—
Exploration cost		43,867			7,802			95,999			25,928
Depletion, depreciation, accretion and impairment expense		435,094			1,779			855,434			3,584
Loss on settlement of asset retirement obligation		—			—			116,394			—
General and administrative expense		847,080			203,811			1,705,803			349,844
Total operating expense		2,994,068			213,392			6,640,835			379,356
Income (loss) from operations		853,022			(194,713	)		1,601,067			(342,268	)
Other income (expense):
Interest income		2,726			—			5,798			—
Interest expense		(96,774	)		(48,028	)		(274,138	)		(297,036	)
Realized gain on commodity contracts		236,599			—			245,992			—
Unrealized gain (loss) on change in derivatives – commodity contracts		766,981			—			(76,300	)		—
Unrealized gain (loss) on change in derivatives  – convertible debt		246,305			(136,404	)		(518,708	)		(136,404	)
Gain on settlement of debt		—			223,736			—			223,736
Loss on extinguishment of debt		—			(17,620	)		—			(17,620	)
Other income		327			—			5,865			—
Total other income (expense)		1,156,164			21,684			(611,491	)		(227,324	)
Net income (loss) before income taxes		2,009,186			(173,029	)		989,576			(569,592	)
Income tax expense		(821,862	)		—			(468,014	)		—
Net income (loss)	$	1,187,324		$	(173,029	)	$	521,562		$	(569,592	)
Net income (loss) per common share:
Basic	$	0.01		$	(0.00	)	$	0.01		$	(0.01	)
Diluted	$	0.01		$	(0.00	)	$	0.01		$	(0.01	)
Weighted average number of common shares outstanding:
Basic		84,364,934			49,079,448			83,140,752			47,229,124
Diluted		86,772,776			49,079,448			84,143,254			47,229,124

See accompanying notes to these unaudited consolidated financial statements.

5

MESA ENERGY HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Six Months Ended June 30,
	2012			2011
				(Restated)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	521,562		$	(569,592	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, accretion and impairment expense		855,434			3,584
Deferred income taxes		353,024			—
Share-based compensation		208,357			83,619
Realized loss on settlement of asset retirement obligation		116,394			—
Amortization of debt discount charged to interest expense		4,279			—
Amortization of deferred financing cost		25,713			117,932
Induced debt conversion expense charged to interest expense		—			111,974
Gain on conversion of accounts payable to common stock		—			(286,042	)
Loss on conversion of notes payable to common stock		—			62,306
Loss on debt extinguishment		—			17,620
Unrealized loss from change in derivative value – commodity derivatives		76,300			136,404
Unrealized loss from change in derivative value – conversion feature		518,708			—
Changes in operating assets and liabilities:
Accounts receivable – oil and gas		652,830			(9,590	)
Accounts receivable – other		(192,774	)		—
Prepaid and other assets		(52,874	)		—
Accounts payable and accrued expenses		(270,236	)		214,679
Revenue payable		(174,444	)		—
Accrued expenses – related party		—			14,646
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		2,642,273			(102,460	)
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisition and development of oil and gas properties		(1,141,274	)		—
Cash paid to settle asset retirement obligation for oil and gas properties		(255,751	)		—
Cash paid for support facilities and equipment		(489,343	)		—
Cash paid for purchase of furniture, fixtures, and equipment		(50,896	)		—
CASH USED IN INVESTING ACTIVITIES		(1,937,264	)		—
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds for the sale of stock		—			40,000
Proceeds from borrowings on debt		11,224			20,000
Proceeds from borrowings on debt – related party		—			72,000
Principal payments on long-term notes payable		(311,014	)		—
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(299,790	)		132,000
NET CHANGE IN CASH		405,219			29,540
CASH AT BEGINNING OF PERIOD		3,182,392			6,096
CASH AT END OF PERIOD	$	3,587,611		$	35,636

See accompanying notes to these unaudited consolidated financial statements.

6

MESA ENERGY HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(Continued)

	For the Six Months Ended June 30,
	2012		2011
			(Restated)
SUPPLEMENTAL DISCLOSURES
Cash paid for interest	$	271,475	$	1,768
Cash paid for income taxes	$	160,993	$	—
NON-CASH INVESTING AND FINANCING TRANSACTIONS
Settlement of derivative liability from conversion of debt	$	620,003	$	—
Common stock issued to settle accounts payable	$	—	$	171,000
Common stock issued for the conversion of notes payable and accrued interest	$	416,019	$	2,040,087
Promissory note exchanged for convertible debt, net of discount	$	—	$	35,276

See accompanying notes to these unaudited consolidated financial statements. 

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Organization

Mesa Energy, Inc. (“MEI”) is a wholly owned subsidiary of Mesa Energy Holdings, Inc. (referred to individually or in conjunction with one or more of its subsidiaries as the “Company”). MEI’s predecessor entity, Mesa Energy, LLC, was formed in April 2003 as an exploration and production company in the oil and gas industry. MEI’s oil and gas operations are conducted through itself and its wholly owned subsidiaries. MEI acquired Tchefuncte Natural Resources, LLC (“TNR”) in July 2011. TNR owns interests in 80 wells and related surface production equipment in five fields located in Plaquemines and Lafourche Parishes in Louisiana. Mesa Gulf Cost Operating, LLC became the operator of all operated properties in Louisiana in October 2011. MEI is a qualified operator in the State of New York and operates the Java Field. Our operating entities have historically employed, and will continue in the future to employ, on an as-needed basis, the services of drilling contractors, other drilling related vendors, field service companies and professional petroleum engineers, geologists and land men as required in connection with future drilling and production operations. See Note 2 for more information on the acquisition of TNR.

Mesa Midcontinent, LLC, (“MMC”) is a wholly owned subsidiary of MEI. MMC owns unproved leasehold acreage in Garfield and Major Counties, Oklahoma. See Note 5 for more information on the acquisition of unproved leasehold acreage.

Basis of Presentation

The accompanying unaudited interim consolidated financial statements have been prepared by the Company in accordance with accounting principles generally accepted in the United States and the rules of the Securities and Exchange Commission (“SEC”) and should be read in conjunction with the audited consolidated financial statements and notes thereto contained in the Company’s latest annual report filed with the SEC on Form 10-K. 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 unaudited interim consolidated financial statements that would substantially duplicate the disclosures contained in the audited consolidated financial statements for fiscal year 2011, as reported in the Form 10-K, have been omitted.

Principles of Consolidation

The consolidated financial statements include the Company’s accounts and those of the Company’s wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expense during each reporting period. Management believes these estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company had cash deposits of $1,543,347 in excess of the FDIC’s current insured limit on interest bearing accounts of $250,000 as of June 30, 2012. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Reclassifications

Certain reclassifications have been made to amounts in prior periods to conform with the current period presentation. All reclassifications have been applied consistently to the periods presented.

8

Earnings (Loss) Per Share

The Company’s earnings per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflects the potential dilution of securities, if any, that could share in the earnings of the Company and are calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options, unvested restricted stock grants, warrants, and convertible debt. The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Numerator:
Net income (loss) available to stockholders	$	1,187,324		$	(173,029	)	$	521,562		$	(569,592	)
Basic net income allocable to participating securities(1)		(21,082	)		—			(10,770	)		—
Basic net income (loss) available to stockholders		1,166,242			(173,029	)		510,792			(569,592	)
Impact of assumed conversions-interest expense, net of income taxes		2,428			—			11,670			—
Income (loss) available to stockholders assuming conversion of convertible debentures	$	1,168,670		$	(173,029	)	$	522,462		$	(569,592	)
Denominator:
Weighted average number of common shares – Basic		84,364,934			49,079,448			83,140,752			47,229,124
Effect of dilutive securities(2) :
Options and warrants		347,826			—			166,667			—
Convertible promissory notes		2,060,016			—			835,835			—
Weighted average number of common shares – Diluted		86,772,776			49,079,448			84,143,254			47,229,124
Net income (loss) per common share:
Basic	$	0.01		$	(0.00	)	$	0.01		$	(0.01	)
Diluted	$	0.01		$	(0.00	)	$	0.01		$	(0.01	)

(1) Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.

(2) For the six months ended June 30, 2012, “out of the money” vested stock options representing 1,578,000 shares and 500,000 “out of the money” vested warrants were antidilutive and excluded from the diluted share calculation. No shares associated with the Company’s convertible promissory notes were excluded from the diluted share calculations. For the six months ended June 30, 2011, convertible debt outstanding representing 7,128,152 shares and stock options representing 848,500 shares were antidilutive and, therefore, excluded from the diluted share calculation.

Recently Issued Accounting Pronouncements

The Company does not expect the adoption of any recently issued accounting pronouncements to have a significant impact on its financial position, results of operations or cash flows.

Subsequent Events

The Company has evaluated all subsequent events from June 30, 2012 through the issuance date of the consolidated financial statements for subsequent event disclosure consideration.

9

NOTE 2 – ACQUISITION OF TCHEFUNCTE NATURAL RESOURCES, LLC.

On July 22, 2011, the Company acquired 100% of the membership interests in Tchefuncte Natural Resources, LLC, which became a wholly-owned subsidiary of the Company. Assets acquired comprise five oil and gas fields in Plaquemines and Lafourche Parishes in Louisiana. In exchange for their members’ interests, the selling members of TNR received an aggregate of 21.2 million shares of the Company’s common stock valued at $2,968,000 based on the closing price of Mesa’s stock on July 22, 2011.

The following unaudited pro forma information assumes the acquisition of TNR occurred as of January 1, 2011. The pro forma results are not necessarily indicative of what actually would have occurred had the acquisition been in effect for the entire period presented.

	For the Three Months Ended		For the Six Months Ended
	June 30, 2011		June 30, 2011
Revenue	$	2,724,395	$	5,466,441
Net income	$	1,408,524	$	2,556,353
Net income per common share – basic	$	0.02	$	0.04
Net income per common share – diluted	$	0.02	$	0.04
Weighted average common shares outstanding –basic		68,009,890		68,024,674
Weighted average common shares outstanding – diluted		74,809,890		78,850,056

NOTE 3 – FAIR VALUE MEASUREMENTS

The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and December 31, 2011.

	June 30, 2012
	Carrying Value		Fair Value Measurement
			Level 1		Level 2		Level 3
Derivative assets – commodity contracts	$	861,445	$	—	$	861,445	$	—
Derivative liability – convertible debt		11,788		—		—		11,788

	December 31, 2011
	Carrying Value		Fair Value Measurement
			Level 1		Level 2		Level 3
Derivative assets – commodity contracts	$	938,950	$	—	$	938,950	$	—
Derivative liability – convertible debt		113,083		—		—		113,083

The Company did not identify any other assets or liabilities that are required to be presented on the consolidated balance sheet at fair value. Additional information regarding our derivative instruments can be found in Note 4 – Commodity Derivative Instruments and Note 6 – Debt.

10

NOTE 4 – COMMODITY DERIVATIVE INSTRUMENTS

The Company has commodity derivative instruments for which it determined the fair value using period-end closing oil and gas prices, interest rates and volatility factors for the periods under each contract as of June 30, 2012. The details of the derivative instruments are summarized below: 

Costless Gas Collar

		Average
Production Period	Total Volume	Floor/Ceiling		Fair Value
Jul 2012-Dec 2012(1)	264,000 MMBtu		$2.50 / $3.50	$	(21,560	)
Jan 2013-Dec 2013(1)	230,000 MMBtu		$2.50 / $4.50	$	(35,666	)

Gas Fixed Price Swaps

		Average
Production Period	Total Volume	Fixed Price		Fair Value
Jan 2013-Jul 2013(2)	70,000 MMBtu		$4.00	$	52,437

Oil Fixed Price Swaps

		Average
Production Period	Total Volume	Fixed Price		Fair Value
Jul 2012-Dec 2012 (3)	6,000 Bbls	$	100.30	$	84,655
Jul 2012-Dec 2012	21,000 Bbls	$	114.50	$	696,750
Jan 2013-Jul 2013	18,900 Bbls	$	114.90	$	54,924

Oil Basis Swap

Production Period	Total Volume	Basis Price		Fair Value
Jul 2012-Sep 2012	3,000 Bbls	$	20.00	$	29,904

(1)	Costless gas collar entered into on June 26, 2012.
(2)	Fixed price swap is the remaining put of July 25, 2011 costless gas collar unwound on June 26, 2012.
(3)	Crude oil swap entered into on January 6, 2012.

The Company elected not to apply hedge accounting to these derivatives. At June 30, 2012, the Company recognized a short term derivative asset of $828,524 and a long-term derivative asset of $32,921, with the $766,981 increase in fair value reported in other income (expense) as unrealized gain on derivative instruments for the three months ended June 30, 2012 and a $76,300 decrease in fair value reported in other income (expense) as an unrealized loss on derivative instruments for the six months ended June 30, 2012. Net realized gains of $236,599 and $245,992 from settlements of these derivatives have been reported in other income (expense) as realized gain on commodity contracts during the three and six months ended June 30, 2012, respectively.

On July 19, 2012, we added positions to our hedging program. See Note 10 – Subsequent Events.

The Company also has a derivative liability associated with the value of the conversion features of its convertible debt which is discussed more fully in Note 6 - Debt.

NOTE 5 – PROPERTY, PLANT AND EQUIPMENT

Oil and Gas Properties

All of the Company’s oil and gas properties at June 30, 2012 were located in the United States.

11

The carrying values of the Company’s oil and gas properties by field, net of depletion and impairment, at June 30, 2012 and December 31, 2011 were:

	June 30,		December 31,
Property	2012		2011
Lake Hermitage Field	$	2,907,322	$	2,494,003
Valentine Field		1,459,117		1,668,172
La Rose Field		1,400,927		1,528,908
Bay Batiste Field		998,288		1,035,944
Manila Village Field		—		—
Java Field		—		—
Turkey Creek Field		500,700		—
Total	$	7,266,354	$	6,727,027

Net oil and gas properties at June 30, 2012 were:

Year Incurred	Acquisition Costs		Exploration and Development Costs		Dry Hole Costs			Disposition of Assets			Depletion, Amortization, and Impairment			Total
2010 and prior	$	754,878	$	2,947,554	$	(466,066	)	$	(2,090,383	)	$	(1,145,983	)	$	—
2011		7,334,184		621,053		—			—			(1,213,210	)		6,742,027
2012		500,700		640,574		—			—			(616,947	)		524,327
Total	$	8,589,762	$	4,209,181	$	(466,066	)	$	(2,090,383	)	$	(2,976,140	)	$	7,266,354

During the six months ended June 30, 2012, the Company began a leasing and acreage acquisition program in Major and Garfield Counties, Oklahoma, spending $500,700 on 1,395 net mineral acres, with the intent of initiating a drilling program in the Mississippian Limestone no later than the 1^st quarter of 2013. The Company refers to its acreage position in Major and Garfield Counties, Oklahoma, as the Turkey Creek Field. Also during the six months ended June 30, 2012, the Company recompleted three wells in the Lake Hermitage Field and expended $640,574 in development activities in the field.

During the six months ended June 30, 2012, the Company plugged and abandoned two wells, the Southdown 2D and the LLDSB #7, retiring their costs comprising, solely, asset retirement costs for the Southdown 2D well and asset retirement costs and intangible drilling costs for the LLDSB #7. Costs of the LLDSB #7 well were retired after an unsuccessful attempt to convert it to a salt water disposal well resulted in an oil spill for which the Company incurred $244,237 of environmental remediation expense in addition to the expense of plugging and abandoning the well and recognized a loss on the settlement of the asset retirement obligation of $116,394. See Note 7 – Asset Retirement Obligations for more discussion on the impact of the retirement of these two wells on their asset retirement obligations.

Support Facilities and Equipment

The Company’s support facilities and equipment serve its oil and gas production activities. The following table details these properties and equipment, together with their estimated useful lives:

		June 30,			December 31,
	Years	2012			2011
Tank batteries	7	$	993,611		$	646,214
Production equipment	7		1,076,945			950,000
Field offices	20		267,089			267,089
Crew boat	7		57,835			57,835
Asset retirement cost	7		256,364			256,363
			2,651,844			2,177,501
Accumulated depreciation			(236,668	)		(100,724	)
Total support facilities and equipment, net		$	2,415,176		$	2,076,777

12

Office Furniture, Equipment, and Leasehold Improvements

		June 30,			December 31,
	Years	2012			2011
Office equipment and purchased software	3	$	33,303		$	16,388
Furniture and fixtures	10		43,421			18,299
Leasehold improvements	3		8,859			—
			85,583			34,687
Accumulated depreciation			(7,030	)		(2,853	)
Total property and equipment, net		$	78,553		$	31,834

Support facilities and equipment and office furniture, equipment, and leasehold improvements are depreciated using the straight line method over their estimated useful lives.

NOTE 6 – DEBT

Convertible Promissory Notes

The Company had $50,000 and $461,740 of convertible promissory notes outstanding at June 30, 2012 and December 31, 2011, net of unamortized debt discount of $0 and $4,279, respectively. During the six months ended June 30, 2012, convertible notes totaling $416,019 were converted into 3,328,153 common shares of the Company at $0.125 per share. On May 11, 2011, pursuant to the Omnibus Waiver and Modification Agreements provided by the three remaining holders, the convertible debt holders agreed to extend the maturity date of their outstanding note balances to July 31, 2013, amend the conversion price of $0.25 to $0.125 per share and subordinate their lien on the assets of the Company to F & M Bank in conjunction with the Company entering into the Credit Facility in order to acquire TNR. Management determined that the reduction of the conversion price created an embedded derivative with a $0 fair value on May 11, 2011. The fair value of the embedded derivative at June 30, 2012 and December 31, 2011 was $11,788 and $113,083, respectively.

Changes in the fair value of embedded derivative instruments for the six months ended June 30, 2012 and the year ended December 31, 2011 were as follows:

	January 1, 2012 Derivative Liability		Conversions and Change in Derivative Liability for Remaining Convertible Debt			Unrealized (Gain) or Loss		June 30, 2012 Derivative Liability
Derivative conversion feature	$	113,083	$	(620,003	)	$	518,708	$	11,788

	January 1, 2011 Derivative Liability		Conversions and Change in Derivative Liability for Remaining Convertible Debt		Unrealized (Gain) or Loss		December 31, 2011 Derivative Liability
Derivative conversion feature	$	—	$	—	$	113,083	$	113,083

13

The fair value of the derivative conversion feature is estimated using the following principal assumptions for the binomial valuation model on the date of initial valuation:

Date	Probability of instrument issuance at a price lower than the conversion price			Probable prices at which instruments will be issued
December 2011		10	%		$0.12- $0.08
June 2012		10	%		$0.12- $0.08
Thereafter		10	%		$0.12- $0.08

	June 30, 2012			December 31, 2011
Common stock issuable upon conversion		400,000			3,400,000
Market price of common stock on measurement date	$	0.14		$	0.14
Conversion price	$	0.12		$	0.12
Conversion period in years		1.08			1.58
Expected volatility		163.91	%		163.11	%
Expected dividend yield		—	%		—	%
Risk free interest rate		0.50	%		0.74	%

Credit Facility and Notes Payable

The Company’s notes payable were as follows:

	June 30,			December 31,
	2012			2011
Credit Facility	$	5,195,963		$	5,495,963
Term notes		132,920			132,710
Notes payable outstanding		5,328,883			5,628,673
Less:  Current maturities		(25,632	)		(466,655	)
Notes payable – noncurrent	$	5,303,251		$	5,162,018

On July 22, 2011, MEI entered into a $25 million senior secured revolving line of credit (“Credit Facility") with F&M Bank and Trust Company (“F&M Bank”) that matures on July 22, 2013. Loans made under this credit facility are secured by TNR’s proved producing reserves (“PDP”) as well as guarantees provided by the Company, MEI, and the Company’s other wholly-owned subsidiaries. The Company is required to make monthly interest payments on the Credit Facility based on a variable interest rate. The interest rate is the F&M Bank Base Rate plus 1% subject to a floor of 5.75%. Interest is currently accruing at 5.75%. A 2.00% annual fee is applicable to letters of credit drawn under the Credit Facility.

The borrowing base is subject to two scheduled redeterminations each year. F&M Bank completed its first scheduled redetermination pursuant to the Credit Facility and increased the Company’s borrowing base from $10,500,000 to $13,500,000 in April 2012. The redetermination eliminated the Company’s obligation to make the remaining $150,000 Monthly Commitment Reduction payment required prior to the redetermination. Reporting requirements, loan covenants and events of default are customary for this type of Credit Facility. The Company was in compliance with all of the debt covenants as of June 30, 2012.

14

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the six months ended June 30, 2012 and for the year ended December 31, 2011. 

	2012			2011
Beginning asset retirement obligation	$	3,450,252		$	80,217
Obligation assumed from acquisition of TNR		—			3,262,160
Accretion expense		98,365			112,311
Sale of property		—			(4,436	)
Settlement of asset retirement obligation		(139,357	)		—
Ending asset retirement obligation	$	3,409,260		$	3,450,252

Through the second quarter of 2012 we plugged and abandoned two wells, the Southdown 2D and the LLDSB #7 recognizing a loss on settlement of asset retirement obligation of $116,394. See Note 5 – Property, Plant, and Equipment for more discussion on the LLDSB #7 well as regards the events leading up to the environmental remediation expense we incurred, not included in plugging and abandonment costs, which resulted in our plugging and abandoning this well.

NOTE 8 – INCOME TAXES

As of June 30, 2012, the Company has U.S. net operating loss carry forwards of approximately $4.2 million which begin to expire in 2028. The Company also has tax credit carry forwards of approximately $35,000 in alternative minimum tax credits which do not expire.

We recognize the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. We have not taken a tax position that, if challenged, would have a material effect on the consolidated financial statements or the effective tax rate for the six months ended June 30, 2012.

NOTE 9 – STOCKHOLDERS’ EQUITY

The Company is authorized to issue 300 million shares of common stock with a $0.0001 par value per share and 10 million shares of preferred stock with a $0.0001 par value per share. At June 30, 2012 and December 31, 2011, the Company had 83,302,769 and 79,531,616 shares issued and outstanding, respectively. No preferred stock has been issued by the Company.

Stock Options 

Options to purchase 530,000 shares of common stock were granted in 2012 with an estimated fair value of $88,001. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the six months ended June 30, 2012:

Weighted average grant date fair value	$	0.19
Weighted average grant date		April 30, 2012
Weighted average risk-free interest rate		0.51	%
Expected life (in years)		5
Weighted average volatility		145.35	%
Expected dividends	$	—

15

The following table summarizes the Company’s employee stock option activity for the six months ended June 30, 2012:

	Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
Outstanding at December 31, 2011		2,228,000	$	0.20
Granted		530,000		0.19
Exercised		—		—
Cancelled/Expired		—		—
Outstanding at June 30, 2012		2,758,000		0.20		3.4  years	$	—
Exercisable at June 30, 2012		2,275,000	$	0.20		3.1  years	$	—

Compensation expense related to stock options of $82,998 and $73,194 was recognized for the six months ended June 30, 2012 and 2011, respectively. At June 30, 2012, the Company had $93,840 of unrecognized compensation expense related to outstanding unvested stock options, which will be fully recognized over the next 1.75 years. No stock options have been exercised.

Restricted Stock

The following table summarizes the Company’s employee restricted stock activity, including activity for awards not granted under the 2009 Plan, for the six months ended June 30, 2012:

	Shares			Weighted Average Grant Price
Unvested Restricted Shares at December 31, 2011		1,941,000		$	0.15
Granted		—			—
Vested and issued		(443,000	)		0.15
Cancelled/Expired		—			—
Unvested Restricted Shares at June 30, 2012		1,498,000		$	0.15

At June 30, 2012, the Company had $192,600 of unrecognized compensation expense related to outstanding restricted stock granted to employees, which is expected to be recognized over the next 1.25 years. Compensation expense related to restricted stock grants of $79,936 and $10,425 was recognized in the first six months of 2012 and 2011, respectively.

Warrants

On June 15, 2012, the Company terminated the consulting agreement previously entered into with Cynergy Advisors, LLC on March 7, 2012, in consideration for which the Company issued 500,000 cashless warrants which vested immediately and are exercisable at $1 per share. Each warrant entitles the holder to one share of the Company’s common stock in the event of exercise. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for warrants issued during the six months ended June 30, 2012:

Grant date fair value	$	45,423
Grant date		June 26, 2012
Weighted average risk-free interest rate		0.73	%
Expected life (in years)		5
Weighted average volatility		136.27	%
Expected dividends	$	—

16

The following table summarizes the Company’s warrant activity for the six months ended June 30, 2012:

	Warrants		Exercise Price		Remaining Contractual Life	Aggregate Intrinsic Value
Outstanding at December 31, 2011		—	$	—
Granted		500,000		1.00
Exercised		—		—
Cancelled/Expired		—		—
Outstanding at June 30, 2012		500,000		1.00	5  years	$	—
Exercisable at June 30, 2012		500,000	$	1.00	5  years	$	—

Share-based compensation expense related to the warrants of $45,423 was recognized for the six months ended June 30, 2012. At June 30, 2012, the Company had $0 of unrecognized share-based expense related to outstanding warrants. No warrants have been exercised.

NOTE 10 – SUBSEQUENT EVENTS

Commodity contracts

On July 19, 2012, we added the following positions with a fair value of $36,602 to our commodity derivative hedges:

Average Price Oil Collars

		Average
Production Period	Total Volume	Floor/Ceiling		Fair Value
Sep 2012-Jan 2013	18,900 Bbls	$	80 / $100	$	4,725
Jan 2013-Feb 2013	6,525 Bbls	$	80 / $100	$	1,631
Feb 2013-Aug 2013	24,708 Bbls	$	80 / $100	$	6,177
Aug 2013-Feb 2014	40,908 Bbls	$	80 / $100	$	10,227
Feb 2014-Sep 2014	39,424 Bbls	$	80 / $100	$	9,842

Drilling activities

In July 2012, the Company elected to participate in the drilling and completion of the PPCO #1 sidetrack well in the Valentine Field. The Company has a 15% working interest in the well which is operated by an unaffiliated company.  The operator expects to commence operations in the third quarter of 2012.  The Company advanced $281,061 for tangible and intangible drilling costs, and has agreed to advance an additional $131,175 should the sidetrack merit completion.

17

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

This report contains forward-looking statements. All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q, including without limitation, statements in this Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding our financial position, estimated working capital, business strategy, the plans and objectives of our management for future operations and those statements preceded by, followed by or that otherwise include the words “believe,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions or variations on such expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, our inability to obtain adequate financing, insufficient cash flows and resulting illiquidity, our inability to expand our business, government regulations, lack of diversification, volatility in the price of oil and/or natural gas, increased competition, results of arbitration and litigation, stock volatility and illiquidity, our failure to implement our business plans or strategies and general economic conditions. A description of some of the risks and uncertainties that could cause our actual results to differ materially from those described by the forward-looking statements in this Quarterly Report on Form 10-Q appears in the section captioned “Risk Factors” in our 2011 Annual Report on Form 10-K.

Except as otherwise required by the federal securities laws, we disclaim any obligations or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Quarterly Report on Form 10-Q to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any such statement is based.

Overview

Mesa Energy Holdings, Inc. is a growth-oriented exploration and production (E&P) company with a definitive focus on growing reserves and net asset value per share, primarily through the acquisition and enhancement of high quality producing properties and the development of highly diversified developmental drilling opportunities. We currently own producing oil and natural gas properties in Plaquemines and Lafourche Parishes in Louisiana as well as developmental properties in Major and Garfield Counties, OK and Wyoming County, NY.

The following discussion highlights the principal factors that have affected our financial condition as well as our liquidity and capital resources for the periods described and provides information which management believes is relevant for an assessment and understanding of the statements of financial position, results of operations and cash flows presented herein. This discussion should be read in conjunction with our unaudited financial statements, related notes and the other financial information included elsewhere in this report.

Producing Fields - Plaquemines and Lafourche Parishes, Louisiana

On July 22, 2011, Mesa Energy, Inc., our wholly owned subsidiary (“MEI”), completed the acquisition of Tchefuncte Natural Resources, LLC (“TNR”), a Louisiana operator. Immediately prior to MEI’s closing of the TNR acquisition, TNR completed the acquisition of properties in four fields in south Louisiana from Samson Contour Energy E & P, LLC. TNR, now a wholly owned subsidiary of MEI, owns 100% working interests in the Lake Hermitage Field in Plaquemines Parish, Louisiana along with various working interests in producing properties in four additional fields in Plaquemines and Lafourche Parishes, Louisiana. The total net mineral acreage held by production in the five fields is approximately 7,189 acres.

We believe that by recompleting or otherwise returning several additional shut-in wells to production, continuing to improve operational efficiencies and continued optimization of the gas lift systems, significant increases in production can continue to be achieved in these fields. Two wells were successfully recompleted to uphole zones in the Lake Hermitage Field in the fourth quarter of 2011 with positive results. The recompletion of three additional wells took place in the second quarter of 2012 and a number of additional recompletions are planned or underway, both in the Lake Hermitage Field and in the Valentine Field. All of this activity is being funded out of operating cash flow. These efforts should significantly increase production and proved developed producing (“PDP”) reserves. An extensive geological and engineering evaluation of the Valentine Field has been completed and a number of additional recompletion and/or drilling opportunities have been identified. In addition, we have submitted applications for permits to drill the first of our proved undeveloped (“PUD”) drilling locations in the Lake Hermitage Field and we expect to drill the first of several developmental wells later this year. We are reviewing a number of deep targets with potential for farm out or joint venture with other operators and continue to evaluate additional acquisition opportunities in South Louisiana.

18

Lake Hermitage Field – Plaquemines Parish, Louisiana

The Company owns a 100% working interest in each of the eighteen wells in the Lake Hermitage Field. Current net production is approximately 188 BOE/D (barrels of oil equivalent per day) from seven producing wells and a total of 3,578 mineral acres is held by production in the field. Ten wells are currently shut-in pending evaluation for workover and/or future recompletion in uphole zones. The LLDSB #1 has been permitted for conversion to a salt water disposal well which would reduce expenses and allow us to handle more fluid on a daily basis. An attempt in the first quarter to convert the LLDSB #7 to a salt water disposal well was unsuccessful and it has been plugged and abandoned. There are three processing facilities and tank batteries in the field. The high gravity crude oil produced at Lake Hermitage is transported out of the field by barge.

A significant improvement in efficiency has been achieved in the Lake Hermitage Field by the installation of higher capacity equipment and by optimization of the gas lift system. In addition, during the three months ended June 30, 2012, we recompleted three wells in the Lake Hermitage Field:

The LLDSB #3 was successfully recompleted in the UL-5 Sand at approximately 12,548 feet. It flowed at a rate of 1,972 mcf and 101 barrels of condensate per day at 2,900 psi during a four hour test. The pressures we encountered were considerably higher than expected and the decision was made to shut-in the well and to replace the tubing and down-hole safety and production equipment prior to putting the well on production.

The LLDSB #20 was successfully recompleted in the UL-1 Sand at approximately 10,055 feet. It flowed at a rate of 1,047 mcf per day of gas at 1,175 psi during a four hour test. The well is online but we have reduced the production rate to conserve gas for higher pricing and/or future field maintenance use.

The LLDSB #34 was recompleted in the A79 Sand at approximately 7,760 feet. After encouraging initial results, the well abruptly stopped flowing and is currently being evaluated.

In addition, we have submitted applications for permits to drill the first two of our PUD drilling locations in the Lake Hermitage Field and we expect to drill the first of several developmental wells later this year. 

Bay Batiste Field, Plaquemines Parish, Louisiana

The Company owns an average 61% working interest in seven wells in the Bay Batiste Field. Current net production is approximately 81 BOE/D from one producing well. The other six wells are currently shut-in pending evaluation for future workover or recompletion in uphole zones. Approximately 74 net mineral acres are held by production by the producing well. The salt water disposal well and two production facilities have plenty of excess capacity to handle production from recompleted wells or from third party operators nearby. Access to markets is excellent.

Larose Field – Lafourche Parish, Louisiana

Various working interests, some of which are non-operated, are owned by us in eight wells in the Larose Field. Current net production is approximately 91 BOE/D from three producing wells and approximately 439 net mineral acres are held by production in the field. Five wells are currently shut-in pending evaluation for future workover or recompletion in uphole zones. The processing facilities and tank batteries are well located and have plenty of excess capacity. Access to pipelines and crude oil markets is excellent.

Valentine Field – Lafourche Parish, Louisiana

The Company owns an average 90% working interest in forty-four wells in the Valentine Field. Current net production is approximately 385 BOE/D from fourteen producing wells and approximately 3,082 net mineral acres are held by production in the field. There are four salt water disposal wells in the field and twenty-six wells are currently shut-in pending evaluation for future workover or recompletion in uphole zones. The processing facilities and tank batteries are strategically located throughout the field and have plenty of excess capacity. A field operations center is centrally located in the field. Access to pipelines and crude oil markets is excellent.

An extensive geological and engineering evaluation of the Valentine Field has been completed and a number of additional recompletion and/or drilling opportunities have been identified. We expect to recomplete the Valentine #2 in the third quarter of 2012 and to pursue additional recompletions in the field later this year. In addition to numerous recompletion and workover opportunities, there is offset developmental drilling potential as well as deep gas potential. All of those potential opportunities are currently being evaluated.

19

SE Manila Village Field – Plaquemines Parish, Louisiana

The Company owns a non-operated working interest in two wells operated by Hilcorp in the Manila Village Field. 16.88 net mineral acres are held by production in the field. The wells are shut-in at this time.

Java Field Natural Gas Development Project – Wyoming County, New York

On August 31, 2009, we acquired the Java Field, a natural gas development project targeting the Marcellus Shale present in the Appalachian basin in Wyoming County in western New York. The acquisition included 19 producing natural gas wells and their associated leases/units, two surface tracts of land totaling approximately 36 acres and two pipeline systems, including a 12.4 mile pipeline and gathering system that serves the existing field as well as a separate 2.5 mile system located northeast of the field. Our average net revenue interest (NRI) in the leases is approximately 78%. Production from the wells is nominal but serves to hold the acreage for future development. In late 2009, we evaluated a number of the existing wells in order to determine the viability of the re-entry of existing wellbores for plug-back and recompletion of the wells in the Marcellus Shale. As a result of this evaluation, we selected the Reisdorf Unit #1 and the Ludwig #1 as our initial targets and these two wells were recompleted in the Marcellus Shale and fracked in May and June of 2010. The initial round of testing and analysis provided a solid foundation of data that strongly supports further development of the Marcellus in western New York. Formation pressures and flow-back rates were much higher than expected providing a clear indication of the potential of the resource. We now believe that shallow horizontal drilling, as is currently being done successfully at this depth in the Fayetteville Shale in northern Arkansas, is ultimately what is needed to maximize the resource.

The State of New York has placed a moratorium on high volume frac stimulation in order to develop new permitting rules. The new permitting rules have not been completed and there can be no assurance when such permitting rules will be issued or what restrictions such permits might impose on producers. Accordingly, we are unable to continue with our development plans in New York for the time being. Unless the moratorium is removed and new permitting rules provide for the economic development of these properties, production on these properties will remain marginally economic. Accordingly, management made a determination to fully impair the properties as of December 31, 2010.

A recent report released by the New York Department of Environmental Conservation proposes to remove the moratorium in all areas of the state other than in the New York City and Syracuse watersheds and to implement new permitting rules for drilling and fracking horizontal wells. Although these measures have yet to be formally adopted, we believe that this report constitutes significant progress and that its final adoption could ultimately allow us to proceed with the next phase of development of the property and the expansion of our acreage position in western New York. 

Mineral Acreage Leasing - Garfield and Major Counties, Oklahoma

During the three months ended June 30, 2012, we began a leasing and acreage acquisition program in Major and Garfield Counties, Oklahoma, spending $500,700 on 1,395 net mineral acres, with the intent of initiating a drilling program in the Mississippian Limestone no later than the 1^st quarter of 2013. We are continuing to actively lease additional acreage in the play and to pursue agreements with operators to acquire acreage that is held by production. Total capital expense required to develop the field will be determined once all acreage is obtained. We refer to our acreage position in Major and Garfield Counties, OK as the Turkey Creek Field.

We believe that Oklahoma is a great place to develop a drilling program. It is relatively close to Dallas, is a very oil friendly state and has good availability of services and a moderate climate. The Mississippian Limestone in Oklahoma is a proven zone that has been drilled vertically in that area for many years so there is substantial well control information available. The emerging horizontal play is mature enough to have a substantial amount of public information available, yet early enough that acreage can still be acquired at moderate prices. This is an opportunity to establish a repeatable drilling program with additional acreage leasing and acquisition opportunities in an area with a high drilling success rate. All in all, we believe this area offers all of the positive attributes that we are looking for.

The Mississippian Limestone in the area of interest is at vertical depths of approximately 7,000’ and is 300’ to 400’ thick. The Woodford Shale, which would be a secondary objective in any well drilled, is immediately below the Mississippian and appears to be oil bearing and is 50 to 100’ thick. Potential reserves in the Mississippian on a per well basis are estimated to be 200,000 to 400,000 barrels per well with recoverable barrels per section estimated to be as much as 2,600,000 BOE. The Woodford zone would increase the potential reserves recoverable. A multi-stage frac is required using acid, fresh water and a simple sand proppant. The Mississippian produces some water, so disposal wells will likely be required. The oil is light, sweet crude with a gravity of 40 to 45 dg.

20

Adjusted EBITDA as a Non-GAAP Performance Measure

In evaluating our business, management believes earnings before interest, taxes, depreciation, depletion, amortization and accretion, unrealized gains and losses on financial instruments, gains and losses on sales of assets and stock-based compensation expense ("Adjusted EBITDA") is a key indicator of financial operating performance and is a measure of our ability to generate cash for operational activities and future capital expenditures. Adjusted EBITDA is not a GAAP measure of performance. We use this non-GAAP measure primarily to compare our performance with other companies in our industry and as a measure of our current liquidity. We believe that this measure may also be useful to investors for the same purposes and as an indication of our ability to generate cash flow at a level that can sustain or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for income from operations, or cash flow from operations determined under GAAP, or any other measure for determining operating performance that is calculated in accordance with GAAP. In addition, because Adjusted EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures that may be disclosed by other companies.

The following is a reconciliation of our net income in accordance with GAAP to our Adjusted EBITDA for the three and six month periods ending June 30, 2012 and 2011:

	For the Three Months  Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012		2011
Net loss	$	1,187,324		$	(173,029	)	$	521,562	$	(569,592	)
Adjustments:
Interest (income) expense, net		94,048			48,028			268,340		297,036
Depreciation, depletion and accretion expense		435,094			1,779			855,434		3,584
Gain on settlement of debt		—			(223,736	)		—		(223,736	)
Loss on extinguishment of debt		—			17,620			—		17,620
Share-based compensation expense		121,497			43,804			208,357		83,619
Unrealized (gain) loss on change in derivatives – commodity contracts		(766,981	)		—			76,300		—
Unrealized (gain) loss on change in derivatives  – convertible debt		(246,305	)		136,404			518,708		136,404
Income tax expense		821,862			—			468,014		—
Adjusted EBITDA	$	1,646,539		$	(149,130	)	$	2,916,715	$	(255,065	)

Results of Operations

Quarter Ended June 30, 2012 Compared to Quarter Ended June 30, 2011

Revenue

Revenue from sales of oil and natural gas were $3,847,090 for the three months ended June 30, 2012 as compared to $18,679 for the three months ended June 30, 2011. This increase in revenues reflects additional sales volumes from producing wells acquired in the TNR acquisition and stimulation efforts in the wells acquired. Revenues are predominantly generated from oil sales of $3,328,104, which is 87% of revenue, compared to natural gas sales of $518,986, which is 13% of revenue. The average price of oil in the second quarter of 2012 was $109.86/Bbl. Prior to the TNR acquisition, the we had no oil production or sales. Oil sales volumes during the second quarter of 2012 were 328 Bbls per day. The increase in volumes is also attributable to the addition of producing properties resulting from our acquisition of TNR. Average natural gas prices decreased by $2.17/Mcf to $2.34/Mcf in the second quarter of 2012 from an average price of $4.51/Mcf in the second quarter of 2011.Natural gas sales volumes increased during the second quarter of 2012 to 2,436 Mcf per day from 250 Mcf per day during the second quarter of 2011. Included in revenue is a small volume of natural gas liquids (“NGL”) which we did not have in the second quarter of 2011.

21

Operating expenses

· Lease operating expense. Production expense increased to $1,640,004 in the three months ended June 30, 2012 from $0 in the three months ended June 30, 2011. Higher expense in the second quarter of 2012 as compared to the second quarter of 2011 is the result of the addition of TNR operations. Lease operating expense for the three months ended June 30, 2012 was $17.94 per BOE.

· Environmental remediation expense. Environmental remediation expense for the three months ended June 30, 2012 was $28,023 as compared to $0 for the three months ended June 30, 2011, due to an oil spill which occurred while attempting to convert the LLDSB #7 well, to a salt water disposal well.

· Exploration expense. Exploration expense increased to $43,867 during the three months ended June 30, 2012 from $7,802 during the three months ended June 30, 2011. This was primarily due to prospecting costs incurred by us in Oklahoma.

· General and administrative expense. General and administrative expense increased to $847,080 for the three months ended June 30, 2012 from $203,811 for the three months ended June 30, 2011. The increase is primarily the result of additional payroll and administrative burdens due to the TNR acquisition and non-cash share-based compensation cost of $121,497.

· Depreciation, depletion, accretion, and impairment expense. The increase in depreciation, depletion, accretion, and impairment expense to $435,094 for the three months ended June 30, 2012 from $1,779 for the three months ended June 30, 2011 reflects the additional volumes of oil and gas produced from wells obtained in the TNR acquisition. Additional depreciation of production support facilities and equipment obtained in the TNR acquisition and accretion of asset retirement obligations associated with those properties and equipment added to the increase from the three months ended June 30, 2011.

Operating income. In the three months ended June 30, 2012, we recognized operating income of $853,022 compared to an operating loss of $194,713 in the three months ended June 30, 2011.

Interest expense. Interest expense increased to $96,774 for the three months ended June 30, 2012, from $48,028 for the three months ended June 30, 2011. The increase was related primarily to additional interest and other related fees and expenses paid to F&M Bank in the second quarter of 2012. The F&M Bank Credit Facility wasn’t acquired until after the second quarter of 2011.

Unrealized gains on changes in derivative value. The unrealized gains on change in derivatives – commodity contracts for the three months ended June 30, 2012 was $766,981 compared to an unrealized loss of $0 for the three months ended June 30, 2011. Unrealized gains in the second quarter of 2012 were primarily the result of changes in oil prices relative to the fixed oil prices in our swap derivatives. The unrealized gain on change in derivatives – convertible debt for the three months ended June 30, 2012 was $246,305 compared to an unrealized loss of and $136,404 for the three months ended June 30, 2011, respectively. The unrealized gain associated with the convertible debt derivative represents the change in the fair value of the liability for issuing shares with a market value higher than the strike price upon conversion of convertible debt into common stock.

Realized gain on changes in derivatives – commodity contracts. Cash settlements from hedging sales of oil and gas production were $236,599 for the three months ended June 30, 2012 as compared to $0 in the three months ended June 30, 2011. The increase is attributable to our hedging program, implemented in accordance with covenants associated with our credit facility with F&M Bank. We had no hedging program in the second quarter of 2011.

Income tax expense. Income tax expense for the three months ended June 30, 2012 increased to $821,862 from $0 in the three months ended June 30, 2011.

Net income. Net income for the three months ended June 30, 2012 was $1,187,324 ($0.01 per basic and diluted share). Net loss for the three months ended June 30, 2011 was $173,029 ($0.00 per basic and diluted share). The increase in earnings is primarily due to the acquisition of TNR.

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

Revenue

Revenue from sales of oil and natural gas were $8,241,902 for the six months ended June 30, 2012 as compared to $37,088 for the six months ended June 30, 2011. This increase in revenues reflects additional sales volumes from producing wells acquired in the TNR Acquisition and stimulation efforts in the wells acquired. Revenues are predominantly generated from oil sales of $7,143,283, which is 87% of revenue, compared to natural gas sales of $1,098,619, which is 13% of revenue. The average price of oil in the first six months of 2012 was $111.64/Bbl. Prior to the TNR acquisition, we had no oil production or sales. Oil sales volumes during the first six months of 2012 were 350 Bbls per day. The increase in volumes is attributable to the addition of producing properties resulting from our acquisition of TNR. Average natural gas prices decreased $1.86/Mcf to $2.58/Mcf in the second quarter of 2012 from an average price of $4.44/Mcf in the second quarter of 2011. Natural gas sales volumes increased during the first six months of 2012 to 2,351 Mcf per day from 1,001 Mcf per day during the first six months of 2011. Included in revenue is a small volume of NGL which we did not have in the second half of 2011.

22

Operating expenses

· Lease operating expense. Production expense increased to $3,622,968 in the six months ended June 30, 2012 from $0 in the six months ended June 30, 2011. Higher expense in the second quarter of 2012 as compared to the second quarter of 2011is the result of the addition of TNR operations. Lease operating expense for the six months ended June 30, 2012 was $20.02 per BOE.

· Environmental remediation expense. Environmental remediation expense for the six months ended June 30, 2012 was $244,237 as compared to $0 for the six months ended June 30, 2011 was incurred in connection with an oil spill which occurred while attempting to convert the LLDSB #7 well to a salt water disposal well. As a result of the spill and additional complications, the conversion of the well was unsuccessful and the well was plugged and abandoned.

· Exploration expense. Exploration expense increased to $95,999 during the six months ended June 30, 2012 from $25,928 during the six months ended June 30, 2011. This was primarily due to prospecting costs incurred by us in Oklahoma.

· General and administrative expense. General and administrative expense increased to $1,705,803 for the six months ended June 30, 2012 from $349,844 for the first six months of 2011. The increase is primarily the result of additional payroll and administrative burdens due to the TNR acquisition and non-cash stock-based compensation cost of $208,357.

· Depreciation, depletion, accretion, and impairment expense. The increase in depreciation, depletion, accretion, and impairment expense to $855,434 for the six months ended June 30, 2012 from $3,584 for the six months ended June 30, 2011 reflects the additional volumes of oil and gas produced from wells obtained in the TNR acquisition. Additional depreciation of production support facilities and equipment obtained in the TNR acquisition and accretion of asset retirement obligations associated with those properties and equipment added to the increase from the first six months of 2011.

· Loss on settlement of asset retirement obligation. We recognized a loss of $116,394 for the plugging and abandonment of two wells for the six months ended June 30, 2012. We incurred no such loss in the six months ended June 30, 2011.

Operating income. In the six months ended June 30, 2012, we recognized operating income of $1,601,067 compared to an operating loss of $342,268 in the six months ended June 30, 2011.

Interest expense. For the six months ended June 30, 2012 interest expense decreased to $274,138 from $297,036 for the six months ended June 30, 2011. The decrease was the result of 2011 induced debt conversion expenses, not incurred in 2012, charged to interest expense, which was offset by additional interest expense and fees in the first six months of 2012 related to the Credit Facility with F&M Bank. The Credit Facility with F&M Bank was closed subsequent to the end of the second quarter of 2011.

Unrealized losses on changes in derivative value. The unrealized loss on change in derivatives – commodity contracts for the six months ended June 30, 2012 and 2011 was $76,300 and $0, respectively. Unrealized losses in the six months ended June 30, 2012 were primarily the result of changes in oil prices relative to the fixed oil prices in our swap derivatives. Unrealized loss on changes in derivatives – convertible debt for the six months ended June 30, 2012 and 2011 was $518,708 and $136,604, respectively. The unrealized loss associated with the convertible debt derivative represents the change in the fair value of potential liability for issuing shares with a higher market value than the strike price upon conversion of convertible debt into common stock.

Realized gain on changes in derivatives – commodity contracts. Cash settlements from hedging our sales of oil and gas production were $245,992 for the six months ended June 30, 2012 as compared to $0 in the six months ended June 30, 2011. The increase is attributable to our hedging program, implemented in accordance with covenants associated with our credit facility with F&M Bank.

Income tax expense. Income tax expense for the six months ended June 30, 2012 increased to $468,014 from $0 in the six months ended June 30, 2011.

Net income. Our net income for the six months ended June 30, 2012 was $521,562 ($0.01 per basic and diluted share), compared to our net loss of $569,592 ($0.01 per basic and diluted share) for the six months ended June 30, 2011. The increase in net income in the first six months of 2012 compared to 2011 is due primarily to the acquisition of TNR.

23

Liquidity and Capital Resources

Overview

As of June 30, 2012, we had working capital of $4,070,480. As of December 31, 2011, we had working capital of $3,104,453. The increase in the working capital was attributable to:

· Increased revenues from the properties acquired from TNR.

· A reduction in the current portion of long term debt due to the elimination of the requirement that we pay the monthly commitment reduction of our long-term note with F&M Bank upon credit redetermination in the second quarter of 2012 along with the conversion of convertible debt to common stock.

Cash and Accounts Receivable

At June 30, 2012, we had cash and cash equivalents of $3,587,611, compared to $3,182,392 at December 31, 2011. Cash increased by $405,219 due to cash provided by operations of $2,642,273 offset by cash of $2,237,054 used in investing and financing activities, the latter primarily comprising debt repayments.

Liabilities

Accounts payable and accrued expenses decreased to $2,184,584 at June 30, 2012, from $2,629,472 at December 31, 2011, primarily due to a decrease in accounts payable resulting from an increased level of cash flow from operations.

As of June 30, 2012, the outstanding balance of principal on debt was $5,378,883, a net decrease of $711,530 from the outstanding balance of $6,090,413, as of December 31, 2011. The decrease was primarily due to repayment of $300,000 on the F&M Bank credit facility and the conversion of $416,019 of convertible notes to common stock during the quarter ended June 30, 2012.

Cash Flows

For the three months ended June 30, 2012, the net cash provided by operating activities was $2,642,273, which was used to fund our capital expenditures and credit facility repayments for the period. We expect to fund operations and the capital expenditure budget for the next twelve months out of operating cash flow. However, we are actively pursuing additional capital to fund an accelerated drilling program.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Not required under Regulation S-K for “smaller reporting companies.”

Item 4. Controls and Procedures

a) Evaluation of disclosure controls and procedures.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of June 30, 2012. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

24

Based on management’s evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as a result of the material weaknesses described below, as of June 30, 2012, our disclosure controls and procedures are not presently designed at a level to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The material weaknesses, which relate to internal control over financial reporting, that were identified are:

1. As of June 30, 2012, we did not adequately segregate, or mitigate the risks associated with, incompatible functions among personnel to reduce the risk that a potential material misstatement of the financial statements would occur without being prevented or detected. Accordingly, management concluded that this control deficiency constituted a material weakness.

We are committed to improving our accounting and financial reporting functions. As part of this commitment, we are considering the engagement of additional employees and have engaged consultants to assist in the preparation and filing of financial reports.

We will continue to monitor and evaluate the effectiveness of our disclosure controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow.

(b) Changes in internal control over financial reporting.

We have remedied a prior material weakness in our internal control over financial reporting in that, due to full integration of the TNR acquisition into our accounting processes and the engagement of our CFO and accounting consultants with appropriate levels of technical accounting knowledge, experience, and training in the application of U.S. GAAP commensurate with our increased complexity and financial accounting and reporting requirements, we are able to ensure our financial reporting occurs in a timely manner.

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We are currently not a party to any material legal proceedings or claims.

Item 1A. Risk Factors

Not required under Regulation S-K for “smaller reporting companies.”

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On April 9, 2012, Whalehaven Capital Fund, Ltd. elected to convert $200,000 of its Convertible Promissory Note resulting in the issuance of 1,600,000 shares.

On April 16, 2012, Chestnut Ridge Partners, LP elected to convert $62,500 of its Convertible Promissory Note resulting in the issuance of 500,000 shares.

On May 30, 2012, Whalehaven Capital Fund, Ltd. elected to convert $41,019 of its Convertible Promissory Note resulting in the issuance of 328,153 shares.

The above offerings and sales were deemed to be exempt under either rule 506 of Regulation D and Section 4(2) or Rule 902 of Regulation S of the Securities Act of 1933, as amended. No advertising or general solicitation was employed in offering the securities. The offerings and sales were made to a limited number of persons, all of whom were accredited investors or business associates of ours, and transfer was restricted by us in accordance with the requirements of the Securities Act of 1933. In addition to representations by the above-referenced persons, we have made independent determinations that all of the above-referenced persons were accredited or sophisticated investors, and that they were capable of analyzing the merits and risks of their investment, and that they understood the speculative nature of their investment. Except as expressly set forth above, the individuals and entities to which we issued securities as indicated in this section are unaffiliated with us.

25

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit No.	Description
31.01*	Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02*	Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01**	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.02**	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101INS	XBRL Instance Document***
101SCH	XBRL Schema Document***
101CAL	XBRL Calculation Linkbase Document***
101LAB	XBRL Labels Linkbase Document***
101PRE	XBRL Presentation Linkbase Document***
101DEF	XBRL Definition Linkbase Document***
*	Filed herewith.
**	This certification is being furnished and shall not be deemed “filed” with the SEC for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except if and to the extent that the Registrant specifically incorporates it by reference.
***	To be furnished by amendment. The XBRL related information in Exhibit 101 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability of that section and shall not be incorporated by reference into any filing or other document pursuant to the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such filing or document.

26

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	MESA ENERGY HOLDINGS, INC.
Date:  August 14, 2012	By:	/s/ RANDY M. GRIFFIN
		Randy M. Griffin
		Chief Executive Officer (Principal Executive Officer)
Date:  August 14, 2012	By:	/s/ RACHEL L. DILLARD
		Rachel L. Dillard
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

27