Edgar Filing: Armada Oil, Inc.

armadaoil10q033113.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended March 31, 2013

¨ 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: 333-52040

ARMADA OIL, INC.

(Exact name of registrant as specified in its charter)

Nevada		98-0195748
(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. Yes þ 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 þ 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 company þ

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 May 16, 2013, there were 55,250,675 shares of the registrant’s common stock outstanding.

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ARMADA OIL, INC.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION

	Item 1. Consolidated Interim Financial Statements (Unaudited)	3

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	27

	Item 4. Controls and Procedures	27

PART II. OTHER INFORMATION

	Item 1. Legal Proceedings	28

	Item 1A. Risk Factors	28

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	28

	Item 3. Defaults Upon Senior Securities	28

	Item 4. Mine Safety Disclosures	28

	Item 5. Other Information	28

	Item 6. Exhibits	29

	Signatures	30

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PART 1. FINANCIAL INFORMATION

Item 1. Interim Consolidated Financial Statements

ARMADA OIL, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2013		December 31, 2012
ASSETS
Current assets
Cash and cash equivalents	$	4,088,222	$	5,884,649
Accounts receivable – oil and gas		2,000,870		1,593,258
Accounts receivable – other		187,969		280,430
Derivative asset, commodity contracts – current		—		83,298
Deferred financing costs, net – current		22,563		22,563
Deferred tax asset – current		6,025		38,325
Prepaid expenses		154,852		117,678
Assets held for sale		109,466		—
TOTAL CURRENT ASSETS		6,569,967		8,020,201

Oil and gas properties, successful efforts accounting:
Properties subject to amortization, net		8,148,324		9,082,526
Properties not subject to amortization		11,226,909		759,133
Support facilities and equipment, net		1,911,237		2,075,563
Land		48,345		48,345
Net oil and gas properties		21,334,815		11,965,567

Property and equipment, net		231,340		241,627
Deferred financing cost, net – noncurrent		7,521		13,162
Deferred tax asset – noncurrent		10,418,177		3,126,478
Deposit on asset retirement obligations		609,421		609,421
Other assets		173,391		4,013

TOTAL ASSETS	$	39,344,632	$	23,980,469

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable – trade	$	3,455,432	$	1,045,918
Revenue payable		497,697		334,433
Accrued expenses		597,147		753,961
Accrued expenses – related parties		54,893		54,840
Derivative liability, commodity contracts – current		266,870		—
Deferred tax liability – current		163,045		—
Notes payable – current		92,113		90,417
Other current liabilities		34,125		91,000
TOTAL CURRENT LIABILITIES		5,161,322		2,370,569

Notes payable, net – noncurrent		9,539,944		9,195,963
Notes payable – related parties, net – noncurrent		60,801		—
Derivative liability, commodity contracts – noncurrent		243,050		58,519
Deferred tax liability – noncurrent		820,068		678,782
Asset retirement obligations		3,614,773		3,507,798
TOTAL LIABILITIES		19,439,958		15,811,631

Commitments and Contingencies

Stockholders’ equity:
Common stock, par value $0.001, 100,000,000 shares authorized, 54,870,024 and 33,732,191 shares issued and outstanding, respectively		54,870		33,732
Additional paid-in capital		15,030,120		803,974
Retained earnings		4,819,684		7,331,132
TOTAL STOCKHOLDERS’ EQUITY		19,904,674		8,168,838

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	39,344,632	$	23,980,469

See accompanying notes to unaudited consolidated financial statements.

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ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended March 31,
	2013			2012

Revenues	$	3,438,838		$	4,394,812

Operating expenses:
Lease operating expense		1,853,195			1,982,964
Environmental remediation expense		—			216,214
Exploration cost		—			52,132
Dry hole expense		2,585,062			—
Depletion, depreciation, amortization, accretion and impairment		759,768			420,340
(Gain) loss on settlement of asset retirement obligations		(1,328	)		116,394
General and administrative expense		1,023,180			858,723
Total operating expense		6,219,877			3,646,767

Income (loss) from operations		(2,781,039	)		748,045

Other income (expense):
Interest income		3,376			3,072
Interest expense		(198,015	)		(177,364	)
Realized gain on commodity contracts		115,678			9,393
Loss on change in derivative value – commodity contracts		(534,699	)		(843,281	)
Loss on change in derivative value – conversion feature		—			(765,013	)
Other income		6,980			5,538
Total other expense		(606,680	)		(1,767,655	)

Loss before income taxes		(3,387,719	)		(1,019,610	)
Income tax benefit		876,271			353,848
Net loss	$	(2,511,448	)	$	(665,762	)

Net loss per common share:
Basic	$	(0.07	)	$	(0.02	)
Diluted	$	(0.07	)	$	(0.02	)

Weighted average number of common shares outstanding:
Basic		34,985,730			32,766,629
Diluted		34,985,730			32,766,629

See accompanying notes to these unaudited consolidated financial statements.

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ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(2,511,448	)	$	(665,762	)

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization, accretion and impairment		759,768			420,340
Dry hole expense		2,585,062			—
Deferred income taxes		(876,271	)		(353,848	)
Share-based compensation		56,653			86,860
(Gain) loss on settlement of asset retirement obligations		(1,328	)		116,394
Amortization of debt discount charged to interest expense		11,321			675
Amortization of deferred financing costs		5,641			12,854
Realized gain on derivative commodity contracts		(115,678	)		(9,393	)
Unrealized loss on change in derivative value – commodity contracts		534,699			843,281
Gain on change in derivative value – conversion feature		—			765,013
Changes in operating assets and liabilities:
Accounts receivable – oil and gas		(407,612	)		—
Accounts receivable – other		92,461			200,344
Prepaid expenses		(4,612	)		(21,252	)
Accounts payable and accrued expenses		(203,335	)		(249,670	)
Accrued expenses – related party		53			—
Revenue payable		163,264			(39,312	)
CASH PROVIDED BY OPERATING ACTIVITIES		88,638			1,106,524

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisition and development of oil and gas properties		(2,285,325	)		(35,062	)
Cash paid for support facilities and equipment		(20,996	)		(130,039	)
Cash proceeds from settlement of derivative commodity contracts		115,678			9,393
Cash received from acquisition of Armada		31,894			—
Cash paid for property and equipment		(1,136	)		(15,517	)
CASH USED IN INVESTING ACTIVITIES		(2,159,885	)		(171,225	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings on debt, net of financing costs		378,166			11,224
Principal payments on debt		(46,471	)		(304,073	)
Installment payments on software		(56,875	)		—
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		274,820			(292,849	)

NET CHANGE IN CASH		(1,796,427	)		642,450
CASH AT BEGINNING OF PERIOD		5,884,649			3,182,392
CASH AT END OF PERIOD	$	4,088,222		$	3,824,842

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest	$	176,652		$	183,268
Cash paid for income taxes	$	35,500		$	40,000

NON-CASH INVESTING AND FINANCING TRANSACTIONS
Common stock issued for the conversion of notes payable and accrued interest	$	—		$	112,500
Transfer of derivative liability from liability classification to equity classification	$	—		$	298,815
Debt discount related to warrants issued in conjunction with notes payable and notes payable – related parties	$	134,289		$	—
Support facilities & equipment currently held for sale	$	109,466		$	—

See accompanying notes to these unaudited consolidated financial statements.

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ARMADA OIL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Organization

Armada Oil, Inc. (the “Company”, “Armada”, or “we”) was incorporated under the laws of the State of Nevada on November 6, 1998, under the name “e.Deal.net, Inc.” On June 20, 2005, the Company amended its Articles of Incorporation to effect a change of name to International Energy, Inc. On June 27, 2011, the Company amended its Articles of Incorporation to change its name to NDB Energy, Inc. On May 7, 2012, the Company filed a Certificate of Amendment to its Articles of Incorporation to change its name to Armada Oil, Inc.

On March 28, 2013 Armada Oil, Inc. formed a business combination with Mesa Energy Holdings, Inc. (“Mesa”), pursuant to which Armada acquired from Mesa substantially all of the assets of Mesa consisting of all of the issued and outstanding shares of Mesa Energy, Inc. (“MEI”), whose predecessor entity, Mesa Energy, LLC, was formed in April 2003 as an exploration and production company in the oil and gas industry. Although Armada was the legal acquirer, Mesa was the accounting acquirer.

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, Louisiana. Mesa Gulf Coast Operating, LLC (“MGC”) became the operator of all operated properties in Louisiana in October 2011. Mesa Midcontinent, LLC is a qualified operator in the state of Oklahoma and operates our properties in Garfield and Major Counties, Oklahoma. MEI is a qualified operator in the State of New York and operates the Java Field.

Through its wholly owned subsidiary, Armada Oil and Gas, Inc. (“Armada Oil and Gas”), the Company is pursuing projects located in Southern Wyoming. Armada Oil and Gas was incorporated on January 19, 2012. Accordingly, it did not have any operations prior to this time. Armada Oil and Gas holds interests in Carbon County, Wyoming that include leasehold interests in 1,280 acres, and a farmouit agreement with Anadarko Petroleum in the Niobrara play near existing infrastructure, which includes oil and natural gas pipelines, oil refineries and gas processing plants as well as various productive oil and natural gas fields.

The Company’s 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.

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 of America 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 2012, 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.

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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 year-end and the reported amounts of revenues and expenses during the year and the reported amount of proved natural gas and oil reserves. Management bases its estimates on historical experience and various other assumptions that it believes are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from these estimates and changes in these estimates are recorded when known.

Reclassifications

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

Earnings Per Common Share

The Company’s earnings per share are 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 is 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 and convertible debt.

	For the Three Months Ended March 31,
	2013			2012
Numerator:
Net loss available to stockholders	$	(2,511,448	)	$	(665,762	)
Basic net loss allocable to participating securities (1)		—			—
Basic net loss available to stockholders		(2,511,448	)		(665,762	)
Impact of assumed conversions-interest expense, net of income taxes					—
Loss available to stockholders assuming conversion of convertible debentures	$	(2,511,448	)	$	(665,762	)

Denominator:
Weighted average number of common shares – Basic		34,985,730			32,766,629
Effect of dilutive securities (2) :		—			—
Warrants		—			—
Convertible promissory notes		—			—
Weighted average number of common shares – Diluted		34,985,730			32,766,629

Net loss per common share:
Basic	$	(0.07	)	$	(0.02	)
Diluted	$	(0.07	)	$	(0.02	)

(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 three months ended March 31, 2013, convertible debt outstanding representing 0 shares and stock options and warrants representing 2,344,000 and 8,054,787 shares, respectively were antidilutive and, therefore, excluded from the diluted share calculation. For the three months ended March 31, 2012, convertible debt outstanding representing 1,131,405 shares and stock options and warrants representing 947,200 and 2,485,914 shares, respectively, 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.

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Subsequent Events

The Company has evaluated all transactions through the financial statement issuance date for subsequent event disclosure consideration.

NOTE 2 – BUSINESS COMBINATION

On March 28, 2013, Armada completed the acquisition (the “Acquisition”) of substantially all of the assets of Mesa Energy Holdings, Inc. consisting of all of the issued and outstanding shares of MEI pursuant to the terms of the Asset Purchase Agreement and Plan of Reorganization Among Armada Oil, Inc., Mesa Energy Holdings, Inc., and Mesa Energy, Inc. (the “APA”). The Company accounted for the assets, liabilities and ownership interests in accordance with the provisions of ASC 805, Business Combinations for acquisitions occurring in years beginning after December 15, 2008 (formerly SFAS No. 141R, Business Combinations).

Armada acquired MEI, with Mesa continuing as the accounting acquirer and becoming a wholly-owned subsidiary of Armada, in a transaction structured to qualify as a tax-free reorganization. In connection with the Acquisition, Armada issued former security holders of Mesa 33,732,191 shares of common stock, warrants to purchase an aggregate of 200,000 shares of Armada common stock, and options to purchase 1,280,00 shares of the Company’s common stock. These equity instruments have a fair value of $14,056,342 as of the date of the Acquisition.

The Acquisition was accounted for as a “reverse acquisition,” and Mesa was deemed to be the accounting acquirer in the Acquisition. Armada’s assets and liabilities are recorded at their fair value. MEI’s assets and liabilities are carried forward at their historical costs. The financial statements of Mesa are presented as the continuing accounting entity since it is the acquirer for the purpose of applying purchase accounting. The equity section of the balance sheet and earnings per share of Mesa are retroactively restated to reflect the effect of the exchange ratio established in the APA.

The acquisition price was allocated to the assets acquired and liabilities assumed based upon their estimated fair values. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.

Assets acquired:
Cash	$	31,894
Prepaid assets		33,061
Other current assets		168,879
Total current assets		233,834

Oil and gas properties		10,467,776
Deferred tax asset		6,088,855
Total assets acquired		16,790,465

Liabilities assumed:
Accounts payable and accrued liabilities		2,146,663
Note payable, net of discount of $103,001		197,197
Asset retirement obligations		65,263
Total liabilities assumed		2,409,123

Net assets acquired	$	14,381,342

Consideration paid:
Equity instruments issued at their fair value	$	14,381,342

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Pro forma results of operations for the three month periods ended March 31, 2013 and 2012, as though this acquisition had taken place at the beginning of each period, are as follows. 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.

	Three Months Ended March 31,
	2013			2012
Revenues	$	3,545,644		$	4,433,294
Net loss	$	(4,077,126	)	$	(827,272	)
Loss per share:
Basic and diluted	$	(0.07	)	$	(0.02	)
Weighted average shares outstanding
Basic		55,142,344			43,859,112
Diluted		55,142,344			43,859,112

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 March 31, 2013 and December 31, 2012.

	March 31, 2013
	Carrying Value			Fair Value Measurement
				Level 1		Level 2			Level 3

Derivative asset – commodity contracts	$	95,506		$	—	$	95,506		$	—
Derivative liability – commodity contracts		(605,426	)		—		(605,426	)		—

	December 31, 2012
	Carrying Value			Fair Value Measurement
				Level 1		Level 2			Level 3

Derivative assets – commodity contracts	$	83,298		$	—	$	83,298		$	—
Derivative liability – commodity contracts	$	(58,519	)	$	—	$	(58,519	)	$	—

The Company did not identify any other assets and liabilities that are required to be presented on the consolidated balance sheet at fair value.

NOTE 4 – COMMODITY DERIVATIVE INSTRUMENTS

The Company engages in price risk management activities from time to time, through utilizing derivative instruments consisting of swaps, floors and collars, to attempt to reduce the Company’s exposure to changes in commodity prices. None of the Company’s derivatives is designated as a cash flow hedge. Changes in fair value of derivative instruments which are not designated as cash flow hedges are recorded in other income (expense) as realized and unrealized (gain) loss on commodity derivatives.

While the use of these arrangements may limit the Company's ability to benefit from increases in the price of oil and natural gas, it is also intended to reduce the Company's potential exposure to significant price declines. These derivative transactions are generally placed with major financial institutions that the Company believes are financially stable; however, there can be no assurance of the foregoing.

The Company has commodity derivative instruments with a single counterparty 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 March 31, 2013 and 2012.

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The details of the commodity derivatives, at March 31, 2013, are summarized below:

Costless Gas Collar

		Weighted
		Average
Production Period	Total Volumes	Floor/Ceiling				Fair Value
Apr 2013-Dec 2013 (1)	185,000 MMBtu	$	2.50	/	4.50	$	(138,804	)
Jan 2014-Oct 2014 (5)	130,000 MMBtu	$	3.75	/	4.25		(23,894	)
Nov 2014-Dec 2014 (5)	26,000 MMBtu	$	3.75	/	4.50		(8,516	)

Gas Fixed Price Swaps

		Average
Production Period	Total Volume	Fixed Price		Fair Value
Apr 2013-Jul 2013 (2)	40,000 MMBtu	$	4.00	$	6,318

Oil Fixed Price Swaps

		Average
Production Period	Total Volumes	Fixed Price		Fair Value
Apr 2013-Jul 2013 (3)	10,800 Bbls	$	114.90	$	52,340
Jan 2014-Dec 2014 (5)	60,000 Bbls	$	95.75		(272,328	)
Jan 2015-Mar 2015 (5)	11,049 Bbls	$	92.50		(49,315	)

Average Price Oil Collar

		Average
Production Period (7)	Total Volume	Floor / Ceiling				Fair Value
Apr 2013-Jun 2013 (4)	12,354 Bbls	$	80	/	100	$	(14,454	)
Jul 2013-Dec 2013 (4)	40,908 Bbls	$	80	/	100	$	(98,111	)

Oil Basis Swap

Production Period	Total Volume	Basis Price		Fair Value
Apr 2013 (6)	6,800 Bbls	$	16.40	$	6,187
May 2013 (6)	6,800 Bbls	$	14.50	$	9,856
Jun 2013 (6)	6,800 Bbls	$	12.90	$	10,804
Jul 2013 (6)	6,800 Bbls	$	11.75	$	9,101
Aug 2013 (6)	6,800 Bbls	$	10.65	$	5,567
Sep 2013 (6)	6,800 Bbls	$	9.75	$	1,628
Oct 2013 (6)	6,800 Bbls	$	9.05	$	1,017
Nov 2013 (6)	6,800 Bbls	$	8.45	$	(2,236	)
Dec 2013 (6)	6,800 Bbls	$	7.95	$	(5,080	)

	(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.
	(4)	Average price collar entered into on July 19, 2012.
	(5)	Costless gas collar and oil fixed price swap entered into on March 8, 2013.
	(6)	Oil basis swap entered into on February 8, 2013.
	(7)	On March 8, 2013, the Company unwound the crude oil average price collar for the January 2014 through July 2014 settlements periods. Volumes unwound were 39,424 bbls with a fixed price of $100 per bbl. The Company incurred a loss of $8,144 in unwinding these positions.

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At March 31, 2013, the Company recognized a short-term derivative liability of $266,870 and a long-term derivative liability of $243,050, with the change in fair value of $534,699 from December 31, 2012, reflected in unrealized loss on derivative instruments. Realized gains of $115,678 from settlements of these derivatives have been reported in other income as realized gain on commodity contracts.

The details of the commodity derivatives at March 31, 2012, are summarized below:

Costless Gas Collars

Weighted

Average

Production Period

Total Volumes

Floor/Ceiling

Fair Value

Apr 2012-Jul 2013

180,000 MMBtu

4.00

5.75

214,383

Oil Fixed Price Swaps

		Average
Production Period	Total Volumes	Fixed Price		Fair Value
Apr 2012-Dec 2012 (1)	9,000 Bbls	$	100.30	$	(38,014	)
Apr 2012-Dec 2012	31,500 Bbls	$	114,50	$	(162,211	)
Jan 2013-Jul 2013	18,900 Bbls	$	114.90	$	55,714

Oil Basis Swap

Production Period		Total Volume		Basis Price				Fair Value
Apr 2012-Dec 2012		6,000 Bbls		$	20.00			$	25,797

(3)

Crude oil swap entered into on January 6, 2012.

At March 31, 2012, the Company recognized a short term derivative asset of $18,821 and a long-term derivative asset of $76,848, with the $843,281 decrease in fair value from December 31, 2011 reported in other income (expense) as unrealized loss on derivative instruments for the three months ended March 31, 2012. Realized gains of $9,393 from settlements of these derivatives were reported in other income as realized gain on commodity contracts.

NOTE 5 – PROPERTY AND EQUIPMENT

Oil and Gas Properties

The Company’s oil and gas properties at March 31, 2013 are located in the United States of America.

The carrying values of the Company’s oil and gas properties, net of depletion and impairment, at March 31, 2013 and December 31, 2012 were:

	March 31,		December 31,
Property	2013		2012

Lake Hermitage Field	$	3,792,126	$	3,568,957
Valentine Field		1,867,036		1,995,406
La Rose Field		1,367,192		1,435,549
Bay Batiste Field		1,029,326		1,050,390
Turkey Creek Field		851,777		1,791,357
Bear Creek Prospect		5,691,837		—
Overland Trail Prospect		4,775,939		—
Total	$	19,375,233	$	9,841,659

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Net oil and gas properties at March 31, 2013 were:

Year Incurred	Acquisition Costs		Exploration and Development Costs		Dry Hole Costs			Disposition of Assets			Depletion, Amortization, and Impairment			Total

2011 and prior	$	8,089,062	$	3,553,607	$	(466,066	)	$	(2,090,383	)	$	(2,359,193	)	$	6,727,027
2012		759,133		3,807,248		—			—			(1,451,749	)		3,114,632
2013		10,467,776		2,269,632		—			—			(3,203,834	)		9,533,574
Total	$	19,315,971	$	9,630,487	$	(466,066	)	$	(2,090,383	)	$	(7,014,776	)	$	19,375,233

Lake Hermitage Field – Plaquemines Parish, Louisiana

In the three months ended March 31, 2013, the Company spent $635,017 on development of the Lake Hermitage field which included expenditures of $79,196 on the LLDSB #3, $76,123 on the LLDSB #4/4D, and $427,962 on the LLDSB #10 wells.

Turkey Creek Field – Garfield and Major Counties, Oklahoma

In the three months ended March 31, 2013, the Company spent $1,608,727 on drilling the Thomas Unit #6H well. The Thomas Unit #6H was not completed due to mechanical issues and has been plugged and abandoned. We charged the drilling costs of $2,585,062 to dry hole expense in the first quarter of 2013.

In the three months ended March 31, 2012, we plugged and abandoned two wells, the Southdown 2D in the Valentine Field and the LLDSB #7 in the Lake Hermitage Field, retiring their costs which comprised 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 we incurred $216,214 of environmental remediation expense in addition to the expense of plugging and abandoning the well.

Bear Creek and Overland Trail Prospects – Carbon County, Wyoming

Pursuant to the Share Exchange Agreement in 2012, Armada assumed a Purchase and Option Agreement between Armada Oil and Gas and TR Energy through which it received leasehold interests in 1,280 acres of land, engineering data, and 2D seismic. At present, the terms of this agreement are in the process of renegotiation.

Armada also assumed a Seismic and Farm Out Option Contract (the “Anadarko Contract”) whereby Anadarko E&P Company, LP, and Anadarko Land Corp, (collectively “Anadarko”) will execute a mineral permit granting the Company the nonexclusive right, until May 1, 2013, to conduct 3D survey operations on and across the contracted acreage in Carbon County, Wyoming. If and when the Company drills and completes a test well capable of production and complies with all other terms of the Anadarko Contract, the Company will receive from Anadarko a lease, with an initial term of three (3) years, which provides for the Company to receive an eighty percent (80%) operated interest; and Anadarko will earn a twenty percent (20%) royalty interest in future production.

Gonzales, Young, and Archer Counties, Texas

Gonzales County. Approximately 300 acres of undeveloped leasehold were acquired in Gonzales County, Texas, in July 2011. The Company will evaluate this acreage to determine if it possesses commercially exploitable quantities of oil and gas reserves.

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Young County. Approximately 200 acres of land and fourteen wells were acquired in July 2011. The Company plans to take over operations and enhance production from the wells.

Archer County. Approximately 140 acres of land and twelve wells were acquired in September 2011. These properties are considered non-core assets, and, as such, the Company plans to sell them.

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:

		March 31,			December 31,
	Years	2013			2012

Tank batteries	7	$	791,021		$	798,043
Production equipment	7		1,012,482			1,001,943
Production Facilities			55,544			55,544
Field offices (1)	20		150,000			267,089
Crew boats	7		74,793			66,313
Construction in progress (not depreciated)			21,070			19,019
Asset retirement cost	7		256,363			256,363
			2,361,273			2,455,314
Accumulated depreciation			(450,036	)		(379,751	)
Total support facilities and equipment, net		$	1,911,237		$	2,075,563

(1)

In the first quarter of 2013 the Company decided to market for sale the Lake Hermitage Camp which was damaged during Hurricane Isaac in August 2012; accordingly, its net book value of $109,467 was transferred from Support Facilities and Equipment to Assets Held for Sale and reclassified as a current asset.

In the three months ended March 31, 2013 and 2012, the Company recognized depreciation expense of $70,285 and $65,213, respectively, on support facilities and equipment.

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Office Furniture, Equipment, and Other

		March 31,			December 31,
	Years	2013			2012

Office equipment, computer equipment, purchased software, and leasehold improvements	3	$	203,972		$	203,972
Furniture and fixtures	10		54,481			53,346
			258,453			257,318
Accumulated depreciation			(27,113	)		(15,691	)
Total property and equipment, net		$	231,340		$	241,627

During the three months ended March 31, 2013 and 2012, the Company recognized depreciation expense of $11,422 and $1,752, respectively, on office furniture, equipment, and other.

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

NOTE 6 – DEBT

Credit Facility and Notes Payable

The Company’s notes payable at March 31, 2013 and December 31, 2012 were as follows:

	March 31,			December 31,
	2013			2012

Credit Facility	$	9,195,963		$	9,195,963
Private placement of debt, net of discount		404,782			—
Term notes		92,113			90,417
Notes payable outstanding		9,692,858			9,286,380
Less: Current maturities		(92,113	)		(90,417	)
Notes payable – noncurrent	$	9,600,745		$	9,195,963

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, under its original terms, was to mature on July 22, 2013. The interest rate is the F&M Bank Base Rate plus 1% subject to a floor of 5.75%, payable monthly. During the year ended December 31, 2012, the maturity was extended to July 22, 2014. At March 31, 2013 and December 31, 2012, the interest rate was 5.75%. A 2.00% annual fee is applicable to letters of credit drawn under the Credit Facility.

The Credit Facility provided financing for the 2011 acquisition of TNR, working capital for field enhancements, and general corporate purposes. The Credit Facility was originally subject to an initial borrowing base of $10,500,000 which was fully utilized by the Company with the completion of the acquisition of TNR. The Company obtained letters of credit in the amount of $4,704,037 that were provided to the State of Louisiana to secure asset retirement obligations associated with the properties. $5,693,106 was funded to MEI to complete the transaction, provide working capital for field enhancements and for general corporate purposes. In addition, MEI paid a $102,857 loan origination fee which is being amortized over the life of the loan. The borrowing base is subject to two scheduled redeterminations each year. Loans made under this credit facility are secured by TNR’s proved developed producing reserves (“PDP”) as well as guarantees provided by the Company, MEI, and the Company’s other wholly-owned subsidiaries. Monthly Commitment Reductions were initially set at $150,000 beginning November 22, 2011, and continuing until the first redetermination on or about April 1, 2012. At the first redetermination, the Company was relieved of its obligation to make Monthly Commitment Reductions, and its borrowing base was increased from $10,500,000 to $13,500,000. Future principal reduction requirements, if any, will be determined concurrently with each semi-annual redetermination. In September 2012, F&M performed a second redetermination and increased the Company’s borrowing base from $13,500,000 to $14,500,000. In addition, the term of the note was extended from July 22, 2013 to July 22, 2014. In December 2012, the Company drew an additional $4 million from its Credit Facility, resulting in an outstanding principal balance of $9,195,963.

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At inception of the Credit Facility, deferred financing costs of $102,877 were incurred. At March 31, 2013, and December 31, 2012, $5,641 and $44,214, respectively, of amortized deferred financing costs had been recognized as interest expense. At March 31, 2013, $30,084 of deferred financing costs remained to be amortized.

The Company was in compliance with all of the debt covenants as of March 31, 2013 and December 31, 2012.

The Credit Facility requires that 50% of the projected production from the acquired properties be hedged for 24 months at $100 per barrel or above. The Company entered into various commodity derivate contracts with a single counterparty. For more information see Note 4 – Commodity Derivative Instruments

For the three months ended March 31, 2013 and 2012, the Company recognized interest expense of $179,842 and $130,376, respectively, on the Credit Facility.

Private Placement of Notes

On March 20, 2013 the Company offered a private placement of debt pursuant to the provisions of Section 4(2), Section 4(6) and/or Regulation D under the Securities Act of 1933, as amended (the “Private Placement”). Pursuant to the Private Placement the Company offered $300,000 minimum and $4 million maximum of Series A Senior Unsecured Notes carrying an interest rate of 9.625% per annum, payable quarterly, with a maturity date of May 30, 2014 (the “Notes”). Under the terms of the offering, Series D Warrants for common shares were issued at closing. The number of warrants to be issued is to be calculated by dividing the face value of each subscriber’s note by $0.75, and each warrant will be exercisable at $0.75 per share beginning September 1, 2013. At March 31, 2013, the Company had received subscriptions for $630,000 of Notes and recorded 840,000 of warrants to subscribers. The fair value of the warrants, determined as their relative fair value to the notes, calculated using a Black Scholes model, of $241,083 was recorded as discount on the Notes to be amortized to interest expense using an effective interest rate. Assumptions used in determining the fair values of the warrants were as follows:

	2013
Weighted average grant date fair value	$	0.54
Weighted average grant date	March 24, 2013
Discount rate		0.77	%
Expected life (in years)		4.9
Weighted average volatility		205.74	%
Expected dividends	$	—

Of the Notes, $100,000 was subscribed by James J. Cerna, Jr., who is the President and a Director of the Company. $39,199 of debt discount is associated with this note, and warrants exercisable, as described above, for 133,333 shares were issued.

At March 31, 2013, the Company recognized interest expense of $490 on the face value of the notes, and amortization of the debt discount resulted in the recognition of $11,321 as interest expense. Prior to the acquisition of Mesa on March 27, 2013, $198 of interest expense on the notes and $4,544 of debt discount amortization were recognized as interest expense, and were allocated to the purchase price of the Acquisition on March 28, 2013. $225,218 of debt discount remains to be amortized at March 31, 2013.

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the quarter ended March 31, 2013.

	2013

Beginning asset retirement obligation	$	3,507,798
Obligation assumed from acquisition (1)		65,263
Accretion expense		57,390
Sale of property		—
Settlement of asset retirement obligation		(15,678	)
Ending asset retirement obligation	$	3,614,773

(1)

ARO of properties acquired in business combination

In the first quarter of 2013, the State of Louisiana refunded the deposit made by the Company on the Valentine Sugars #10 well which was plugged and abandoned before it was acquired from TNR on July 22, 2011. As a result, the asset retirement obligation on the well was eliminated.

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In the three months ended March 31, 2013 and 2012, the Company recognized $57,390 and $49,161, respectively, of accretion expense on its asset retirement obligations.

NOTE 8 – INCOME TAXES

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 three months ended March 31, 2013.

As of March 31, 2013, the Company has U.S. net operating loss carry forwards of approximately $10.2 million which begin to expire in 2028.

NOTE 9 – COMMON STOCK

The Company is authorized to issue 100 million shares of common stock with a $0.001 par value per share. At March 31, 2013 and December 31, 2012, the Company had 54,870,024 and 33,732,191 shares issued and outstanding, respectively. The increase of 21,137,833 common shares outstanding is the result of the issuance of 21,094,623 shares valued at $11,602,048 based on the date of grant, in the business combination consummated at March 28, 2013 and the vesting of 43,200 shares valued at $23,760, based on the date of grant, of restricted stock to employees.

All share and per share amounts have been retroactively adjusted to reflect the ratio of the Company’s common stock to holders of shares in Mesa Energy Holdings, Inc., prior to the acquisition.

NOTE 10 – SHARE BASED COMPENSATION

Warrants

On March 20, 2013, under a private placement, Series D Warrants to purchase 840,000 common shares were issued at closing. Each warrant will be exercisable at $0.75 per share beginning September 1, 2013. The fair value of the warrants, determined as their relative fair value to the notes, calculated using a Black Scholes model, of $241,083. Assumptions used in determining the fair values of the warrants were as follows:

	2013
Weighted average grant date fair value	$	0.54
Weighted average grant date	March 24, 2013
Discount rate		0.77	%
Expected life (in years)		4.9
Weighted average volatility		205.74	%
Expected dividends	$	—

The following table summarizes the Company’s warrant activity for the three months ended March 31, 2013:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value

Outstanding at December 31, 2012		200,000	$	2.50	4.5 years	$	—
Granted under Armada acquisition		7,414,787		2.07	4.0 years
Granted		440,000		0.75	4.9 years
Exercised		—		—
Cancelled/Expired		—		—
Outstanding at March 31, 2013		8,054,787	$	2.01	4.1 years	$	—

Exercisable at March 31, 2013		7,214,787	$	2.16	4.0 years	$	—

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Stock Options

Options to purchase 380,000 shares of common stock were granted in 2013 prior to the date of the Acquisition the estimated fair value of options granted in the first quarter was $163,021. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during the three months ended March 31, 2013:

	2013
Weighted average grant date fair value	$	0.39
Weighted average grant date	March 15,2013
Weighted average risk-free interest rate		0.84	%
Expected life (in years)		5
Weighted average volatility		129.24	%
Expected dividends	$	—

The following table summarizes the Company’s stock option activity for the three months ended March 31, 2013:

	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value

Outstanding at December 31, 2012		1,138,800		$	0.49	3.0 years	$	111,715
Granted under Armada acquisition		1,064,000			1.06	7.5 years		100
Granted (1)		280,000			0.33	5.0 years		60,900
Exercised		—			—
Cancelled/Expired		(138,800	)		—
Outstanding at March 31, 2013		2,344,000		$	0.72	5.3 years	$	172,560

Exercisable at March 31, 2013		1,071,600		$	0.55	3.6 years	$	99,385

(1)

Includes 240,000-share restricted stock grant converted to options on March 20, 2013

Compensation expense related to stock options of $45,143 and $38,814 was recognized for the three months ended March 31, 2013 and 2012, respectively. At March 31, 2013, the Company had $504,509 of unrecognized compensation expense related to outstanding unvested stock options, which will be fully recognized over the next 5.29 years. No stock options have been exercised.

Restricted Stock

The following table summarizes the Company’s restricted stock activity for the three months ended March 31, 2013:

	Shares
Unvested Restricted Shares at December 31, 2012		348,000
Granted		—
Vested and issued		(43,200	)
Cancelled/Expired (1)		(240,000	)
Unvested Restricted Shares at March 31, 2013 (2)		64,800

	(1)	Includes 240,000 share restricted stock grant converted to options on March 20, 2013
	(2)	Upon closing of the Acquisition, unvested grants of 162,000 restricted shares were multiplied by .4 pursuant to the terms of the Acquisition leaving 64,800 unvested restricted shares at March 31, 2013. Because the fair value of the unvested shares at March 31 had been previously determined using the closing trading price on the date of grant of $0.15, while the closing trading price on the date of acquisition was $0.55 per share, incremental expense of $11,340 was added to the unamortized stock compensation expense of $24,300 for total unamortized stock compensation expense of $35,640.

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At March 31, 2013, the Company had $27,372 of unrecognized compensation expense related to outstanding restricted stock grants which is expected to be recognized over the next six months.

NOTE 11 – SUBSEQUENT EVENTS

In April 2013, options to purchase 1,270,000 shares of restricted common stock were awarded to members of the board of directors. The fair value of these options at the grant date was determined, using a Black-Scholes Model, to be $507,439. Assumptions used in the Black-Scholes Model are summarized in the table below:

Exercise price	$	0.40
Vesting period in years (1)		1
Term of options in years		5
Expected volatility		214.57	%
Expected dividend yield		0	%
Risk free interest rate		0.72	%

(1)

Vesting schedule – April 19, 2013 – 50%, April 19, 2014 – 50%

On April 1, 2013, the Company entered into Executive Employment Agreements with Randy M. Griffin, Chief Executive Office, and James J. Cerna, Jr., President. Each agreement is for a two-year term and automatically renews for successive one year term unless either party to each agreement provides three months prior written notice of his or its intention not to renew the Agreement. Annual base salaries for Mr. Griffin and Mr. Cerna are $210,000 and $144,000, respectively.

On April 23, 2013, the Company entered into a Third Modification of Office Lease on its office space in Dallas, Texas, to increase the total square feet leased from 4,462 to 5,229, an addition of approximately 767 square feet. Monthly rental expense will increase by $1,085 from $6,305 to $7,390. An additional security deposit of $1,085 was paid concurrently with the signing of the lease, increasing the security deposit on the leased Dallas office space from $6,305 to $7,390.

On April 23, 2013, the Company entered into an Offering Modification Agreement (“Modification”) of a Subscription Agreement which closed on November 26, 2012 (“Subscription Agreement”) with subscribers to the Subscription Agreement. Under the Subscription Agreement, 800,002 each of shares and warrants were issued, of which the warrants were to be exercisable at $0.90 per share through November 25, 2015. Pursuant to the Modification, an additional 639,998 shares of common stock and warrants to purchase an additional 639,998 shares of the common stock at $0.75 per share were issued, exercisable May 26, 2013 through March 1, 2018. In addition, the prior issuance of warrants to purchase 800,002 shares was modified so that the exercise price was reduced from $0.90 per share to $0.75 share and the exercise period was modified to begin May 26, 2013 through March 1, 2018.

On April 30, 2013, an additional subscription was received under the Private Placement. The debt discount and relative fair value of warrants issued were $7,831 calculated using a Black Scholes model and the following assumptions:

	April 30, 2013
Weighted average grant date fair value	$	0.75
Weighted average grant date	April 30, 2013
Risk-free interest rate		0.77	%
Expected life (in years)		4.8
Weighted average volatility		212.41	%
Expected dividends	$	—

On May 1, 2013, F&M Bank performed a redetermination of the Company’s credit facility and reduced the Company’s borrowing base from $14,500,000 to $13,375,000 and reinstated its requirement that the Company make monthly principal reduction payments of $75,000 until reset by F&M at the next scheduled redetermination of the Borrowing Base on or around October 1, 2013. As a result of the reduction in the borrowing base, F&M determined the existence of a Borrowing Base deficiency of $450,000. The Company has elected, pursuant to terms of its Loan Agreement with F&M Bank to make six equal monthly payments of $75,000, beginning May 22, 2013, to reduce the deficiency to an amount equal to the Borrowing Base.

On May 13, 2013, TNR entered into Amendment #2 to Commercial Lease of its office space in Covington, Louisiana to increase the total square feet leased from 3,916 to 7,832, an addition which doubles the square footage leased. Monthly rental expense will increase from $3,851 to $6,851.

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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 2012 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.

History

On March 28, 2013 Armada Oil, Inc. formed a business combination with Mesa Energy Holdings, Inc. (“Mesa”) Pursuant to which Armada acquired from Mesa substantially all of the assets of Mesa consisting of all of the issued and outstanding shares of Mesa Energy, Inc. (“MEI”), whose predecessor entity, Mesa Energy, LLC, was formed in April 2003 as an exploration and production company in the oil and gas industry. Although Armada was the legal acquirer, Mesa was the accounting acquirer

Through its wholly owned subsidiary, Armada Oil and Gas, Inc. (“Armada Oil and Gas”), the Company is pursuing projects located in Southern Wyoming. Armada Oil and Gas was incorporated on January 19, 2012. Accordingly, it did not have any operations prior to this time. Armada Oil and Gas holds interests in Carbon County, Wyoming that include leasehold interests in 1,280 acres (the “Wyoming Property”), and a farmout agreement with Anadarko Petroleum in the Niobrara play near existing infrastructure, which includes oil and natural gas pipelines, oil refineries and gas processing plants as well as various productive oil and natural gas fields.

Overview

We are an oil and gas exploration and production (“E & P”) company engaged primarily in the acquisition, drilling, development, production and rehabilitation of oil and gas properties.

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Our business plan is to build a strong, balanced and diversified portfolio of oil and gas reserves and production revenue through the acquisition of properties with solid, long-term existing production with enhancement potential and the development of highly diversified, multi-well developmental drilling opportunities.

We continuously evaluate opportunities in the United States’ most productive basins, and we currently have interests in the following:

	·	Lake Hermitage Field, a producing oil and natural gas field in Plaquemines Parish, Louisiana;
	·	Valentine Field, a producing oil and natural gas field in Lafourche Parish, Louisiana;
	·	Larose Field, a producing oil and natural gas field in Lafourche Parish, Louisiana;
	·	Bay Batiste Field, a producing natural gas field in Plaquemines Parish, Louisiana;
	·	Manila Village Field, a currently shut-in field in Plaquemines Parish, Louisiana;
	·	Turkey Creek Field, an area of interest in which we hold undeveloped leasehold interests and a farm-out in Garfield and Major Counties, Oklahoma;
	·	Carbon County, Wyoming, an area of interest in which we hold leasehold interests and a farm-out agreement with Anadarko Petroleum Company; and
	·	Java Field, a natural gas development project in Wyoming County in western New York.

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.

Louisiana Area

On July 22, 2011, the Company’s wholly owned subsidiary, Mesa Energy, Inc. (“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 five 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.

We believe that, as a result of our ongoing program of recompleting or otherwise returning shut-in wells to production, improving operational efficiencies and continued optimization of the gas lift systems, significant increases in production can continue to be achieved in these fields. We expect to continue our recompletion program and to accomplish a number of additional enhancements and upgrades to processing facilities and flow lines in 2013, all of which to be funded out of cash flow. These efforts should significantly increase production and PDP reserves. Extensive geological and engineering evaluations of the Lake Hermitage and Valentine Fields have revealed multiple opportunities and we are prioritizing and planning for those opportunities on an ongoing basis. In addition, our technical team is in the process of refining a number of additional drilling locations 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 are actively pursuing additional acquisition opportunities in South Louisiana.

The Louisiana Area is located in Lafourche and Plaquemines Parishes in Louisiana and includes:

Producing Fields - Plaquemines and Lafourche Parishes, Louisiana

Lake Hermitage Field – Plaquemines Parish, Louisiana

The Lake Hermitage Field is located in Plaquemines Parish, Louisiana, approximately 25 miles south-southeast of New Orleans, Louisiana. The field is a salt dome structure discovered in 1928 and has produced significant quantities of oil and gas from multiple sandstone reservoirs between 3,100 and 14,200 feet deep. It is situated in a shallow, marshy environment on the west side of the Mississippi River.

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The Company owns a 100% working interest and 75% net revenue interest in each of the eighteen wells in the Lake Hermitage Field. A total of 3,589 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, and an additional well is being evaluated for conversion to a salt water disposal well, which would reduce expenses and allow for increased daily handling of fluid. 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. In the first quarter of 2013, we successfully replaced the tubing string in the LLDSB #10 well which resulted in a return to stable daily production of over 100 barrels per day. In addition, the LLDSB #3 was successfully recompleted into the UL-4 sand which not only resulted in more production out of the UL-4 in that location but will allow us to re-enter and deepen the LLDSB #4 as a part of our developmental drilling efforts later this year. As of May 1, 2013, we have initiated a new round of workovers and recompletions in the field and expect those efforts to have a positive impact on production, by the end of the second quarter of 2013.

Valentine Field – Lafourche Parish, Louisiana

The Valentine Field is located in the Mississippi Delta area in Lafourche Parish, Louisiana, approximately 35 miles southwest of New Orleans, Louisiana. This gas and oil field was discovered in 1933 on the east flank of the Valentine Salt Dome as a result of torsion-balance and reflection-seismic surveying.

The company owns approximately 3,082 net mineral acres that are held by production in the field and holds working interests that range from 14% to 100% with net revenue interests from 14% to 82.4%.

Twenty-five of the forty wells operated by MGC are currently shut-in pending evaluation for future workover or recompletion to uphole zones. There are three salt water disposal wells in the field. An extensive geological and engineering evaluation review of the Valentine Field is ongoing. As a result of those efforts to date, we have identified a number of recompletion opportunities as well as a couple of potential drilling locations. Two recompletions in the Valentine Field are scheduled as part of the program initiated on May 1st as outlined above.

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.

Larose Field – Lafourche Parish, Louisiana

The Larose Field, discovered in 1953 is located in Lafourche Parish, Louisiana, and is approximately 25 miles southwest of New Orleans, Louisiana. The field is on a southwesterly plunging anticlinal ridge that trends in a NE-SW direction and is approximately five miles along the NE-SW axis and is two and one-half miles wide. There are three major faults, striking east to west and dipping to the south that cross the ridge and separates the field into three main producing segments.

The company owns various working interests that range from 10.4% to 100% and net revenue interests from 8.7% to 72.3% covering approximately 350 net mineral acres. The processing facilities and tank batteries are well located and have plenty of excess capacity, and the access to pipelines and crude oil markets is excellent.

MGC has a production handling agreement (“PHA”) in place with an outside operator which takes advantage of the excess capacity and generates additional revenue. Also, the PHA provides the additional advantage of access to artificial lift gas on an as needed basis.

Bay Batiste Field - Plaquemines Parish, Louisiana

The Bay Batiste Field, discovered in 1983, is located in Plaquemines Parish, Louisiana approximately 35 miles east-southeast of New Orleans, Louisiana. It is situated in a shallow water environment on the west side of the Mississippi River.

The Company owns an average 59.43% working interest and 41.89% net revenue interest in seven wells in the Bay Batiste Field. One well is currently producing and the other four 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.

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SE Manila Village Field – Plaquemines Parish, Louisiana

The SE Manila Village Field is located in Plaquemines Parish, Louisiana approximately 45 miles southeast of New Orleans, Louisiana. The field was discovered in 1985 and is situated in a shallow open-water environment on the west side of the Mississippi River.

The Company owns a non-operated 21.09% gross working interests and 14.48% net revenue interest in two outside operated wells in the Manila Village Field. 16.88 net mineral acres are held by production in the field. The wells are to be plugged and abandoned.

Oklahoma Area

The Oklahoma Area is located in Garfield and Major Counties in Oklahoma. This region of the Mississippi Limestone (our Oklahoma area) is defined by the following characteristics.

Turkey Creek Project - Garfield and Major Counties, Oklahoma

During 2012, we began a leasing and acreage acquisition program in Major and Garfield Counties, Oklahoma, spending $602,377on approximately 3,200 net mineral acres. We are continuing to actively pursue agreements with operators to acquire additional 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 an excellent 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 a lot of data available with no need for seismic. The emerging horizontal play is sufficiently mature to have big company names and good results, yet it is early enough that acreage can still be acquired at moderate prices. This is an opportunity to establish a repeatable drilling program in an area with a high drilling success rate.

The Mississippian Limestone in the area of interest is at a vertical depth of approximately 7,000 feet and is 300 feet to 500 feet thick. The Woodford Shale, which would be a secondary objective in any well drilled, is immediately below the Mississippian and is about 80 feet thick. Early reports indicate that the Woodford is oil bearing and quite productive in the area of interest. Potential reserves in the Mississippian on a per well basis have been reported to be 200,000 to 400,000 barrels per well. The Woodford 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 be required. The oil is light, sweet crude with a gravity of 40 to 45 dg.

In December of 2012, we commenced the drilling of our first horizontal well in the Mississippi play. A pilot hole was drilled to a depth of 7,946 feet. A sophisticated set of logs was run in the well along with pressure testing and the retrieval of cores for evaluation. That set of information revealed not only solid potential and a good porosity streak in the Mississippian Limestone, but also excellent potential in the Woodford Shale. Unfortunately, the well-bore was ultimately lost due to the back to back mechanical failure of two horizontal drilling motors and the resulting negative affect on the tangent of the curve. These incidents combined with a difficult shale section just above the Mississippian Limestone precipitated a series of issues that ultimately could not be overcome. As a result, we had to plug and abandon the well bore, resulting in the dry hole expense disclosed in the Results of Operations below. Accordingly, we view the exercise as a geological success and a mechanical failure and expect to move over and re-drill the well from the same surface location when resources allow.

The majority of our leases in Oklahoma is not held by production but is undeveloped acreage.

Wyoming Area

Our business strategy in Wyoming, where our properties comprise the Overland Trail and Bear Creek projects, is to identify and exploit resources from the Niobrara Shale. High resistivity development in the 1st, 2nd and 3rd Niobrara Chalks, along with overlying and underlying high organic content marls has been noted in the dozen or so logged wells that have penetrated the Niobrara Formation in the area. Approximately 140 miles of 2D CDP seismic lines attest to the conformity of the Niobrara reflections that are present between thrust faults and away from well control points. In addition, there is potential for conventional development of the sandstone reservoirs in the Upper and Lower parts of the Permian-Pennsylvanian age Casper (Tensleep) Formation.

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New York Area

The New York Area is located in Wyoming County in New York. This region of the Medina Sandstone and Marcellus Shale (our New York area) is defined by the following characteristics:

Java Field – Wyoming County, New York

In 2009, MEI acquired the Java Field, which was discovered in 1978, from which the sandstone member of the Medina Formation is the productive natural gas interval of 17 of the 19 producing natural gas wells in the field. The total depth range of these vertical wells is approximately 2,850 – 3,500 feet. Besides the exploitation potential of the Medina Formation, a development project targeting the Marcellus Shale, as is present in a large area of the Appalachian Basin in the northeastern United States, is an additional target for MEI.

The acquisition included 19 producing natural gas wells, their associated leases, units and all equipment; two surface tracts of land totaling approximately 36 acres; and two pipeline systems; 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. The company owns approximately 78% net revenue interest in leases covering 2,851.50 gross and net acres, more or less.

Production is nominal from the wells 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 vertical wellbores for plug-back and recompletion of the wells in the Marcellus Shale. The Marcellus Shale is approximately 1,240 feet above the productive Medina Formation in the Java Field. As a result of this evaluation, we selected the Reisdorf Unit #1 well and the Ludwig #1 well 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 Shale 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 believe that horizontal drilling, successfully done at this depth in other basins, 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.

Anadarko Seismic and Farm Out Option

On November 2, 2012, the Company and Anadarko E & P Company, LP and Anadarko Land Corp. (collectively “Anadarko”) entered into a Seismic and Farm Out Option Contract (the “Anadarko Contract”), whereby Anadarko executed a mineral permit granting the Company the non-exclusive right, until May 1, 2013, to conduct 3D survey operations on and across the contracted acreage in Carbon County, Wyoming. The Anadarko Contract was subsequently amended on December 13, 2012 to expand the contracted acreage. The 3-D survey operations were completed prior to May 1, 2013 as required under the Anadarko Contract. If Armada drills an initial test well capable of production in paying quantities to the initial contract depth (approximately 9,500 feet), completes it as a producer and otherwise complies with and performs all other terms, covenants, and conditions of the Anadarko Contract, Armada will earn and be entitled to receive from Anadarko a lease, effective 30 days from the date of the release of the rotary rig from the location, covering all of Anadarko’s oil and gas estate in the respective drill site section limited to the earned depth. The Lease earned by Armada will (i) be for a primary term of three (3) years; and (ii) provide for a lessor’s royalty of twenty percent (20%), proportionately reduced as appropriate and subject to any gas sales, purchase, transportation or gathering contracts affecting the leased lands on the date of the Anadarko Contract. The Company will then have the right to continue to drill additional wells on the contracted acreage, subject to a drilling schedule, and earn additional sections as described above. The contracted acreage covers approximately 8,750 net mineral acres.

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The Company is obligated to commence drilling of the initial test well on or before October 1, 2013. If the Company fails to drill said well in a timely manner, the Company shall be deemed to have relinquished its right to acquire any interest in Anadarko’s contract acreage under the Anadarko Contract.

The Company is evaluating the acreage and expects to select a location for said well in the second quarter of 2013.

Armada intends to develop and produce reserves at a low cost and take an aggressive approach to exploiting its nearly contiguous acreage position through utilization of recent drilling technology advancements and best-practices seismic techniques. The implementation of its drilling strategy using new shale drilling and completion techniques should enable it to identify and develop oil and gas reserves in the Overland Trail and Bear Creek Project area.

Texas Area

Armada’s plan of operation in Texas is to continue to evaluate the Gonzales County Property (consisting of approximately 300 acres of undeveloped land in Gonzales County, Texas, acquired in July 2011) in order to ascertain whether it possesses commercially exploitable quantities of oil and gas reserves and to take over operations and attempt to enhance production from the Young County Property (consisting of two leases totaling approximately 120 contiguous acres of land and fourteen wells in Young County, Texas, acquired in July 2011). The Company intends to sell the Archer County Property (consisting of two leases totaling approximately 140 acres of land and twelve wells in Archer County, Texas, acquired in September 2011) as it is a non-core asset. Armada does not know if an economically viable oil and gas reserve exists on the Gonzales County Property and there is no assurance that it will discover one.

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-month periods ending March 31, 2013 and 2012:

	For the Three Months Ended March 31,
	2013			2012

Net loss	$	(2,511,448	)	$	(665,762	)

Adjustments:
Interest (income) expense, net		194,639			174,292
Income tax (benefit) expense		(876,271	)		(353,848	)
Dry hole expense		2,585,062			—
Depreciation, depletion, accretion and impairment		759,768			420,340
Gain on settlement of asset retirement obligation		(1,328	)		116,394
Unrealized loss on change in commodity derivative instruments		534,699			843,281
Loss on change in convertible debt derivative		—			765,013
Share-based compensation		56,653			86,860
Adjusted EBITDA	$	741,774		$	1,386,570

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Results of Operations

Quarter Ended March 31, 2013 Compared to Quarter Ended March 31, 2012

Revenue

Revenue from sales of oil and natural gas was $3,438,838 in the first quarter of 2013 as compared to $4,394,812 in the first quarter of 2012. This decrease in revenues primarily reflects a reduction in oil volumes sold due to the LLDSB #3, #4, and #10 wells being offline for recompletions and other work during the month of January, as well as decreases in commodity prices. Average natural gas prices decreased by $0.64/Mcf to $2.21/Mcf in the first quarter of 2013 from an average price of $2.84/Mcf in the first quarter of 2012. The average price of oil in the first quarter of 2013 decreased by $2.71/bbl to $110.51/bbl from an average price of $113.22/bbl in the first quarter of 2012. Natural gas sales volumes increased during the first quarter of 2013 by 30,175 Mcf to 234,018 Mcf from 203,843 Mcf during the first quarter of 2012. Oil sales volumes decreased by 7,979 barrels to 25,447 barrels from 33,426 barrels during the first quarter of 2012. Revenue from sales of natural gas liquids increased by $33,056 to $63,752 in the first quarter of 2013 from $30,696 in the first quarter of 2012.

Operating expenses

	·	Lease operating expense. Production expense decreased by $129,769 to $1,853,195 in the first quarter of 2013 from $1,982,964 in the first quarter of 2012. This decrease was primarily attributable to lower production taxes due to decreased production.
	·	Environmental remediation expense. There were no environmental remediation expenditures in the first quarter of 2013. Environmental remediation expense of $216,214 was recognized in the first quarter of 2012 in connection with an oil spill which occurred while attempting to convert a 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. There were no exploration expenses incurred during the three months ended March 31, 2013 compared to $52,132 during the three months ended March 31, 2012. The 2012 expenditures were attributable to the commencement of our 2012 leasing program in Oklahoma.
	·	General and administrative expense. General and administrative expense increased by $164,457 to $1,023,180 for the three months ended March 31, 2013 from $858,723 for the first three months of 2012. This increase is attributable primarily to transaction fees associated with the acquisition of MEI by the Company and, to a lesser extent, increased payroll burden due to the addition of staff to assist in our operations, additional consultants to assist us in our land management, implementation of our ERP system and insourcing of the accounting process, and additional stock compensation expense attributable to the combining of the Company’s and Mesa’s commitments under equity compensation plans.
	·	Dry hole expense. Dry hole expense of $2,585,062 was incurred during the three months ended March 31, 2013 due to the mechanical failure in the drilling of the Thomas #6H well in Oklahoma. No dry hole expense was incurred during the three months ended March 31, 2012.
	·	Depreciation, depletion, accretion, and impairment expense. The $339,428 increase in depreciation, depletion, accretion, and impairment expense to $759,768 for the three months ended March 31, 2013 from $420,340 for the three months ended March 31, 2012 reflects additional capital expenditures made on producing properties, support facilities, and furniture, fixtures, and equipment.
	·	Gain on settlement of asset retirement obligation. In the first quarter of 2013, we recognized a gain of $1,328 on the settlement of an asset retirement obligation when the State of Louisiana returned a deposit on a well that had been plugged and abandoned when acquired, the obligation on which we had assumed at acquisition. We recognized a loss of $116,394 for the plugging and abandonment of two wells during the first quarter of 2012.

Operating loss. As a result of the above described revenues and expenses, we incurred an operating loss of $2,781,039 in the first quarter of 2013 as compared to an operating loss of $748,045 in the first quarter of 2012.

Interest expense. Interest expense increased to $198,015 for the three months ended March 31, 2013, from $177,364 for the three months ended March 31, 2012. The increase was primarily attributable to amortization of discount on notes payable associated with a private placement of securities as well as interest expense on premium financed insurance notes..

Unrealized losses on changes in derivative value. The unrealized loss on change in derivatives – commodity contracts for the three months ended March 31, 2013 and 2012 was $534,699 and $843,281, respectively. Unrealized losses in the first quarter of 2013 were the result of the change in value of the net derivative liability from that of the prior reporting period. The values underlying the derivatives are estimates of predicted future commodity prices based on current market activity and projections of future market activity. Additional contributors to fluctuations in the value of the recognized net liability are additions to and unwindings of hedged positions during any reporting period. The unrealized loss on change in derivatives – convertible debt for the three months ended March 31, 2013 and 2012 was $0 and $765,013, respectively.

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Realized gain on changes in derivatives – commodity contracts. Cash settlements from hedging our sales of oil and gas production were $115,678 in the first quarter of 2013 as compared to $9,393 in the first quarter of 2012. The increase is attributable to our hedging program, implemented in accordance with covenants associated with our credit facility with F&M Bank.

Income tax benefit. State and federal income tax benefit for the first quarter of 2013 was $876,271 compared to an income tax benefit of $353,848 in the first quarter of 2012. The increase in the income tax benefit in the first quarter of 2013 is primarily to the dry hole expense associated with drilling costs of the Thomas #6H well.

Net loss. Due to the reasons set forth above, our net loss for the three months ended March 31, 2013 was $2,511,448 ($0.07 per basic and diluted common share). Our net loss for the three months ended March 31, 2012 was $665,762 ($0.2 per basic and diluted common share).

Liquidity and Capital Resources

Overview

As of March 31, 2013, we had working capital of $1,733,645. As of December 31, 2012, we had working capital of $5,649,632. The decrease in the working capital was attributable to:

	·	Decreased revenues from oil and gas sales.
	·	Capital expenditures on our producing properties, drilling costs in Oklahoma, transaction expenses associated with our business combination, and increased general and administrative expenses associated with additional staff and use of consultants as well as additional software and equipment to support our operations.

Cash and Accounts Receivable

At March 31, 2013, we had cash and cash equivalents of $4,088,222, compared to $5,884,649 at December 31, 2012. Cash decreased by $1,796,427 due to payments for capital expenditures on our producing properties, drilling costs in Oklahoma, transaction expenses associated with our business combination, and increased general and administrative expenses associated with additional staff and use of consultants as well as additional software and equipment to support our operations.

Liabilities

Accounts payable and accrued expenses increased by $1,927,700 to $3,727,579 at March 31, 2013, from $1,799,879 at December 31, 2012, primarily due to the liabilities of Armada assumed by the accounting acquirer, MEI, in the business combination consummated on March 28, 2013, as well as an increased level of operating and capital expenditure activity associated with additional wells and facilities.

As of March 31, 2013, the outstanding balance of principal on debt, net of discount, was $9,692,858, a net increase of $406,478 from the outstanding balance of $9,286,380, as of December 31, 2012. The increase was due to the $630,000 of notes payable associated with a private placement of debt issued in the first quarter of 2013, net of amortized discount at March 31, 2013, of $225,218.

Cash Flows

For the three months ended March 31, 2013 the net cash provided by operating activities was $88,638 compared to net cash provided by operating activities for the three months ended March 31, 2012 of $1,106,524, a net increase in cash used of $1,017,886. This is attributable, as are our decreases in working capital and cash, to payments for capital expenditures on our producing properties, drilling costs in Oklahoma, transaction expenses associated with our business combination, and increased general and administrative expenses associated with additional staff and use of consultants as well as additional software and equipment to support our operations.

For the three months ended March 31, 2013 and 2012, net cash used in investing activities was $2,159,885 and $171,225, an increase in cash used of $1,988,660. This is attributable to our drilling and recompletion activities in the first quarter of 2013.

For the three months ended March 31, 2013 and 2012, net cash provided by (used in) financing activities was $274,820 and ($292,849) respectively, an increase in cash provided of $567,669. This was primarily attributable to proceeds from our first quarter private placement of debt, net of principal payments on term notes, and the elimination in April 2012 of our requirement to make principal reduction payments on our credit facility with F&M Bank.

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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 March 31, 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.

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 March 31, 2013, 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:

As of March 31, 2013, 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 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. During the quarter ended March 31, 2013, we discontinued the outsourcing of our oil and gas transactional accounting and implemented an enterprise resource planning system in-house.

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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

For information regarding risk factors, please refer to the Company’s 424(b)(2) prospectus filed with the SEC on March 18, 2013, which may be accessed via EDGAR through the Internet at www.sec.gov.

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

During the quarter ended March 31, 2013, Armada sold $630,000 principal amount of Series A Senior Unsecured Notes carrying an annual interest rate of 9.625% per annum, payable quarterly, with a maturity date of May 30, 2014 (the “Notes”) in a private placement pursuant to the provisions of Section 4(2) and/or Regulation D under the Securities Act of 1933, as amended (the “Private Placement”). Under the terms of the Private Placement, Series D Warrants for 840,000 shares of our common stock were issued along with the Notes upon the closing of the Private Placement. The number of warrants to be issued is to be calculated by dividing the face value of each subscriber’s note by $0.75. The warrants are exercisable at $0.75 per share beginning September 1, 2013 and are exercisable for 5 years. As of March 31, 2013, the Company had received subscriptions for $630,000 of Notes and recorded 840,000 of warrants to subscribers.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit No.		Description
2.1		Asset Purchase Agreement and Plan of Reorganization, dated as of November 14, 2012, among Armada Oil, Inc., Mesa Energy Holdings, Inc., and Mesa Energy Inc. (included as Appendix A to the proxy statement/prospectus forming a part of the Registration Statement on Form S-4 filed with the Securities and Exchange Commission on November 29, 2012 and incorporated herein by reference)
2.2		Amendment No. 1 to the Asset Purchase Agreement & Plan of Reorganization, dated as of February 19, 2013, among Armada Oil, Inc., Mesa Energy Holdings, Inc. & Mesa Energy, Inc. (included as Appendix A to the proxy statement/prospectus forming a part of the Registration Statement on Form S-4/A filed with the Securities and Exchange Commission on February 21, 2013 and incorporated herein by reference
4.1		Form of Series A Senior Unsecured 9.625% Note (included as an exhibit to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 28, 2013 and incorporated herein by reference)
4.2		Form of Series D Common Stock Purchase Warrant (included as an exhibit to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 28, 2013 and incorporated herein by reference)
10.1		Form of Securities Purchase Agreement between Armada Oil, Inc. and certain investors (included as an exhibit to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 28, 2013 and incorporated herein by reference)
10.2		Form of Armada Oil, Inc. Nonstatutory Stock Option Agreement (included as an exhibit to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 28, 2013 and incorporated herein by reference)
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.

***		This XBRL exhibit 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 to the extent that the Registrant specifically incorporates it by reference

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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.

	ARMADA OIL, INC.

Date: May 20, 2013	By:	/s/ RANDY M. GRIFFIN
		Randy M. Griffin
		Chief Executive Officer (Principal Executive Officer)


Date: May 20, 2013	By:	/s/ RACHEL L. DILLARD
		Rachel L. Dillard
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)