Armada Oil (AOILQ) 10-Q 2014 Q1 Quarterly report

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, 2014

or

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

For the Transition Period from _________ to _________

Commission file number: 000-55128

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 9, 2014, there were 56,030,473 shares of the registrant’s common stock outstanding.

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	21
	Item 3.  Quantitative and Qualitative Disclosures About Market Risk	29
	Item 4.  Controls and Procedures	30
PART II.  OTHER INFORMATION
	Item 1.  Legal Proceedings	31
	Item 1A.  Risk Factors	31
	Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	31
	Item 3.  Defaults Upon Senior Securities	31
	Item 4.  Mine Safety Disclosures	31
	Item 5.  Other Information	31
	Item 6.  Exhibits	32
	Signatures	33

PART I – FINANCIAL INFORMATION

Item 1. Interim Consolidated Financial Statements 

ARMADA OIL, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2014			December 31, 2013
ASSETS
Current assets
Cash and cash equivalents	$	5,099,409		$	7,095,972
Accounts receivable – oil and gas		1,708,335			1,524,623
Accounts receivable – other		54,754			32,538
Deferred financing costs, net – current		7,521			13,162
Deferred tax asset – current		6,025			100,606
Prepaid expenses		261,509			202,280
TOTAL CURRENT ASSETS		7,137,553			8,969,181
Oil and gas properties, successful efforts accounting:
Properties subject to amortization, net		8,316,020			7,692,703
Properties not subject to amortization		10,657,106			10,653,825
Support facilities and equipment, net		2,628,789			2,417,898
Land		38,345			38,345
Net oil and gas properties		21,640,260			20,802,771
Property and equipment, net		218,407			242,676
Deferred tax asset – noncurrent		5,953,200			5,502,988
Deposit on asset retirement obligations		585,973			585,973
Production payment receivable		131,250			131,250
Other assets		63,430			55,598
TOTAL ASSETS	$	35,730,073		$	36,290,437
LIABILITIES
Current liabilities:
Accounts payable – trade	$	1,296,904		$	1,362,867
Revenue payable		330,758			418,213
Accrued expenses		529,003			444,972
Accrued expenses – related parties		70			70
Notes payable, net – current		8,611,323			8,767,392
Notes payable – related parties, net – current		125,188			102,158
Derivative liability, commodity contracts – current		306,718			173,806
Other current liabilities		—			10,000
TOTAL CURRENT LIABILITIES		11,199,964			11,279,478
Derivative liability, commodity contracts – noncurrent		88,050			53,289
Deferred tax liability – noncurrent		3,746,610			3,703,553
Asset retirement obligations		3,207,962			3,161,810
TOTAL LIABILITIES		18,242,586			18,198,130
Commitments and Contingencies
Equity:
Preferred stock, par value $0.01, 1,000,000 shares authorized, 0 shares issued and outstanding		—			—
Common stock, par value $0.001, 100,000,000 shares authorized, 56,030,473 shares issued and outstanding		56,030			56,030
Additional paid-in capital		16,126,400			16,108,722
Retained deficit		(4,557,386	)		(4,038,633	)
Total equity attributable to Armada Oil, Inc.		11,625,044			12,126,119
Noncontrolling interest		5,862,443			5,966,188
TOTAL EQUITY		17,487,487			18,092,307
TOTAL LIABILITIES AND EQUITY	$	35,730,073		$	36,290,437

See accompanying notes to unaudited consolidated financial statements.

3

ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended March 31,
	2014			2013
Revenues	$	3,174,000		$	3,438,838
Operating expenses:
Lease operating expense		1,837,150			1,853,195
Environmental remediation expense		252,135			—
Exploration cost		159,529			—
Dry hole expense		—			2,585,062
Depletion, depreciation, amortization, accretion and impairment		420,079			759,768
Gain on settlement of asset retirement obligations		—			(1,328	)
General and administrative expense		1,035,859			1,023,180
Total operating expense		3,704,752			6,219,877
Loss from operations		(530,752	)		(2,781,039	)
Other income (expense):
Interest income		151			3,376
Interest expense		(216,592	)		(198,015	)
Realized gain (loss) on commodity contracts		(165,511	)		115,678
Unrealized loss on change in derivative value – commodity contracts		(167,673	)		(534,699	)
Other income		143,176			6,980
Total other expense		(406,449	)		(606,680	)
Loss before income taxes		(937,201	)		(3,387,719	)
Income tax benefit		314,703			876,271
Net loss		(622,498	)		(2,511,448	)
Net loss attributable to noncontrolling interest		(103,745	)		—
Net loss attributable to Armada Oil, Inc.	$	(518,753	)	$	(2,511,448	)
Net loss per common share:
Basic	$	(0.01	)	$	(0.07	)
Diluted	$	(0.01	)	$	(0.07	)
Weighted average number of common shares outstanding:
Basic		56,030,473			34,985,730
Diluted		56,030,473			34,985,730

See accompanying notes to these unaudited consolidated financial statements.

4

ARMADA OIL, INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the Three Months Ended March 31, 2014

	Common Stock				Additional
					Paid-In		Retained			Noncontrolling
	Shares		Par		Capital		Deficit			Interest			Total
Balances at December 31, 2013		56,030,473	$	56,030	$	16,108,722	$	(4,038,633	)	$	5,966,188		$	18,092,307
Share-based compensation		—		—		17,678		—			—			17,678
Net loss		—		—		—		(518,753	)		(103,745	)		(622,498	)
Balances at March 31, 2014		56,030,473	$	56,030	$	16,126,400	$	(4,557,386	)	$	5,862,443		$	17,487,487

See accompanying notes to these unaudited consolidated financial statements.

5

ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three Months Ended March 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(622,498	)	$	(2,511,448	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization, accretion and impairment		420,079			759,768
Dry hole expense		—			2,585,062
Deferred income taxes		(314,703	)		(876,271	)
Share-based compensation		17,678			56,653
Gain on settlement of asset retirement obligations		—			(1,328	)
Amortization of debt discount charged to interest expense		57,333			11,321
Amortization of deferred financing costs		5,641			5,641
Realized (gain) loss on derivative commodity contracts		165,511			(115,678	)
Unrealized loss on change in derivative value – commodity contracts		167,673			534,699
Changes in operating assets and liabilities:
Accounts receivable – oil and gas		(183,712	)		(407,612	)
Accounts receivable – other		(22,216	)		92,461
Prepaid expenses		(29,096	)		(4,612	)
Accounts payable and accrued expenses		(163,296	)		(203,335	)
Accrued expenses – related party		—			53
Revenue payable		(87,455	)		163,264
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(589,061	)		88,638
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for development of oil and gas properties		(759,689	)		(2,285,325	)
Cash paid for support facilities and equipment		(243,965	)		(20,996	)
Cash (used in)/provided by settlement of derivative commodity contracts		(165,511	)		115,678
Cash received from acquisition of Armada		—			31,894
Cash paid for property and equipment		—			(1,136	)
CASH USED IN INVESTING ACTIVITIES		(1,169,165	)		(2,159,885	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings on debt, net of financing costs		—			378,166
Principal payments on debt		(228,337	)		(46,471	)
Installment payments on software		(10,000	)		(56,875	)
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(238,337	)		274,820
NET CHANGE IN CASH		(1,996,563	)		(1,796,427	)
CASH AT BEGINNING OF PERIOD		7,095,972			5,884,649
CASH AT END OF PERIOD	$	5,099,409		$	4,088,222
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest	$	156,033		$	176,652
Cash paid for income taxes	$	—		$	35,500
NON-CASH INVESTING AND FINANCING TRANSACTIONS
Prepaid insurance financed with notes payable	$	37,965		$	38,938
Change in accrued oil and gas development costs	$	116,170		$	—
Common stock issued in satisfaction of common stock payable	$	—		$	325,000
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.

6

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.

The consolidated financial statements include the accounts of the Company. and its wholly-owned subsidiaries, Armada Oil and Gas, Inc. (“AOG”), Armada Operating, LLC (“AOP”), Mesa Energy, Inc. (“MEI”), Mesa Gulf Coast, LLC (“MGC”), Tchefuncte Natural Resources, LLC (“TNR”), Mesa Midcontinent LLC (“MMC”),  Armada Midcontinent, LLC, formerly known as MMC Resources, LLC (“AMC”), and TNR Holdings, LLC (“TNRH”) (the Company owned 65.625% of this subsidiary as of March 31, 2014, but the Company’s ownership was reduced to 25.925% as of April 10, 2014, see NOTE 10 – SUBSEQUENT EVENTS).

On March 28, 2013, Armada completed 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 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 TNR in July 2011.  TNR owns interests in 80 wells and related surface production equipment in four fields located in Plaquemines and Lafourche Parishes, Louisiana.   MGC became the operator of all operated properties in Louisiana in October 2011.  MMC 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.   AOP is a qualified operator in Kansas.

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 landmen 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 2013, 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 and majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

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.

7

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.

Loss Per Common Share

The Company’s loss per share are computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted loss per share reflects the potential dilution of securities, if any, that could share in the loss of the Company and is calculated by dividing net loss 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.

	For the Three Months Ended March 31,
	2014			2013
Numerator:
Net loss	$	(622,498	)	$	(2,511,448	)
Less:  Net loss attributable to noncontrolling interest		(103,745	)		—
Net loss available to stockholders		(518,753	)		(2,511,448	)
Basic net loss allocable to participating securities (1)		—			—
Basic net loss available to stockholders	$	(518,753	)	$	(2,511,448	)
Denominator:
Weighted average number of common shares – Basic		56,030,473			34,985,730
Effect of dilutive securities (2) :		—			—
Warrants		—			—
Weighted average number of common shares – Diluted		56,030,473			34,985,730
Net loss per common share:
Basic	$	(0.01	)	$	(0.07	)
Diluted	$	(0.01	)	$	(0.07	)

(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, 2014, stock options and warrants representing 2,775,000 and 7,553,333 shares, respectively were antidilutive and, therefore, excluded from the diluted share calculation. For the three months ended March 31, 2013, stock options and warrants representing 2,344,000 and 8,054,787 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.

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).

8

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 0.4 common shares of Armada for each Mesa share, or 21,094,633 common shares, valued at $11,602,048, assumed 7,414,787 warrants with a fair value of $1,969,399, assumed 1,064,000 options with a fair value of $484,895, and paid a consultant who worked with the Company in effecting the Acquisition $325,000.  The Company also assumed a liability to issue the consultant stock valued at $325,000.  This liability was settled with this issuance of 380,651 common shares on April 19, 2013.  The total equity instruments issued or assumed in the Acquisition had a fair value of $14,056,342 as of the date of the Acquisition.  Total equity and payments resulted in a purchase price of $14,381,342 and the transaction generated goodwill of $8,536,758.  The purchase price was adjusted during the fourth quarter of 2013 to remove a deferred tax asset of $6,088,885 and record a deferred tax liability of $1,999,046.  This change generated goodwill of $8,536,758 which was immediately impaired during the fourth quarter of 2013.

Assumptions used in determining the fair values of the options and warrants noted above were as follows:

Options
Grant date fair value	$	0.55
Discount rate		0.77	%
Expected life (in years)		7.3
Volatility		110.93	%
Expected dividends	$	—
Warrants
Grant date fair value	$	0.55
Weighted average discount rate		0.63	%
Weighted average expected life (in years)		4.0
Weighted average volatility		106.70	%
Expected dividends	$	—

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 were recorded at their fair value. MEI’s assets and liabilities were carried forward at their historical cost. 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		50,000
Total current assets		114,955
Oil and gas properties subject to amortization		514,249
Oil and gas properties not subject to amortization		9,948,551
Total assets acquired		10,577,755
Liabilities assumed:
Accounts payable and accrued liabilities		2,471,665
Note payable, net of discount of  $103,001		197,197
Deferred tax liability		1,999,046
Asset retirement obligations		65,263
Total liabilities assumed		4,733,171
Net assets acquired		5,844,584
Goodwill		8,536,758
Consideration paid:
Equity instruments issued at their fair value	$	14,381,342

9

Pro forma results of operations for the three month period ended March 31, 2013, as though this acquisition had taken place at the beginning of that 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
Revenues	$	3,545,644
Net loss	$	(4,077,126	)
Loss per common share:
Basic and diluted	$	(0.07	)
Weighted average number of common shares outstanding:
Basic and diluted		55,142,344

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, 2014 and December 31, 2013.

	March 31, 2014
	Carrying Value			Fair Value Measurement
				Level 1		Level 2			Level 3
Derivative liability – commodity contracts	$	(394,768	)	$	—	$	(394,768	)	$	—

	December 31, 2013
	Carrying Value			Fair Value Measurement
				Level 1		Level 2			Level 3
Derivative liability – commodity contracts	$	(227,095	)	$	—	$	(227,095	)	$	—

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, 2014 and 2013.

10

The details of the commodity derivatives, at March 31, 2014, are summarized below:

Costless Gas Collar

		Weighted
		Average
Production Period	Total Volumes	Floor/Ceiling				Fair Value
Apr 2014-Oct 2014 (1)	91,000 MMBtu	$	3.75	/	4.25	$	(28,668	)
Nov 2014-Dec 2014 (1)	26,000 MMBtu	$	3.75	/	4.50	$	(10,772	)

Gas Fixed Price Swaps

Production Period	Total Volume	Fixed Price		Fair Value
Jan 2015-Dec 2015(3)	42,000 MMBtu	$	4.00	$	13,536

Oil Fixed Price Swaps

		Average
Production Period	Total Volumes	Fixed Price		Fair Value
Apr 2014-Dec 2014 (1)	45,000 Bbls	$	95.75	$	(233,312	)
Jan 2015-Mar 2015 (1)	11,049 Bbls	$	92.50	$	(36,803	)
Apr 2015-Dec 2015 (2)	31,500 Bbls	$	89.50	$	(98,749	)

(1)	Costless gas collar and oil fixed price swap was entered into on March 8, 2013.
(2)	Fixed oil price swap was entered into on September 30, 2013.
(3)	Fixed price natural gas swap was entered into on January 23, 2014.

At March 31, 2014, the Company recognized a short-term derivative liability of $306,718 and a long-term derivative liability of $88,050.  For the three months ended March 31, 2014 and 2013, the Company recorded unrealized losses of $167,673 and $534,699, respectively, on the statement of operations. The Company also recorded a realized loss of $165,511 for the three months ended March 31, 2014 and a realized gain of $115,678 for the three months ended March 31, 2013, from settlements of these derivatives as reported in other income as realized gain (loss) on commodity contracts.

11

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

Costless Gas Collars

		Weighted
		Average
Production Period	Total Volumes	Floor/Ceiling				Fair Value
Jan 2014-Oct 2014 (1)	130,000 MMBtu	$	3.75	/	4.25	$	(16,940	)
Nov 2014-Dec 2014 (1)	26,000 MMBtu	$	3.75	/	4.50	$	(5,912	)

Oil Fixed Price Swaps

		Average
Production Period	Total Volumes	Fixed Price		Fair Value
Jan 2014-Dec 2014 (1)	60,000 Bbls	$	95.75	$	(216,665	)
Jan 2015-Mar 2015 (1)	11,049 Bbls	$	92.50	$	(14,750	)
Apr 2015-Dec 2015 (2)	31,500 Bbls	$	89.50	$	(38,718	)

Oil Basis Swap

Production Period	Total Volume	Basis Price		Fair Value
Jan 2014-Dec 2014 (3)	60,000 Bbls	$	4.85	$	65,312

(1)	Costless gas collar and oil fixed price swap entered into on March 8, 2013.
(2)	Fixed oil price swap was entered into on September 30, 2013.
(3)	On July 15, 2013, the Company unwound its basis swaps covering 40,800 Bbls of oil for settlement periods July 2013 through December 2013 and realized a gain of $146,540 on the transaction. On the same date, the Company entered into new basis swaps covering 60,000 Bbls of oil over monthly settlement periods of 5,000 Bbls from January 2014 through December 2014. The basis differential is $4.85/Bbl between Louisiana Light Sweet Crude Oil and NYMEX Light Sweet Crude Oil.

At December 31, 2013, the Company recognized a short-term derivative net liability of $173,806, and a long-term derivative net liability of $53,289.

12

NOTE 5 – PROPERTY AND EQUIPMENT

Oil and Gas Properties

The Company’s oil and gas properties at March 31, 2014 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, 2014 and December 31, 2013 were:

	March 31,		December 31,
Property	2014		2013
Bear Creek Prospect	$	9,958,544	$	9,957,839
Lake Hermitage Field		4,335,573		3,644,986
Valentine Field		1,875,851		1,895,504
Larose Field		1,043,040		1,112,275
Bay Batiste Field		974,816		953,197
Turkey Creek Field		785,302		782,727
Total	$	18,973,126	$	18,346,528

Net oil and gas properties at March 31, 2014 were:

Year Incurred	Acquisition Costs		Exploration and Development Costs		Dry Hole Costs			Disposition of Assets			Depletion, Amortization, and Impairment			Total
2012 and prior	$	8,848,195	$	7,360,855	$	(466,066	)	$	(2,090,383	)	$	(3,810,942	)	$	9,841,659
2013		10,422,630		2,176,671		(2,591,770	)		(346,152	)		(1,156,510	)		8,504,869
2014		—		875,859		—			—			(249,261	)		626,598
Total	$	19,270,825	$	10,413,385	$	(3,057,836	)	$	(2,436,535	)	$	(5,216,713	)	$	18,973,126

During the three months ended March 31, 2014 and 2013, we incurred $159,529 and $0, respectively, of exploration expense which is included on our consolidated statement of operations.

Lake Hermitage Field – Plaquemines Parish, Louisiana

The Company owns 100% working interests in eighteen wells in the Lake Hermitage Field, of which seven are producing, ten wells are currently shut-in pending evaluation for workover or recompletion and one well is awaiting conversion to a salt water disposal well. During the three months ended March 31, 2014, the Company spent $875,859 on development of the Lake Hermitage Field.

Well Name	Amount		Description of work performed
LLDSB #1	$	672,105	Conversion to salt water disposal well
LLDSB #4		83,115	Equipment
LLDSB #30		120,639	Recompletion
	$	875,859

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.

13

Turkey Creek Field – Garfield and Major Counties, Oklahoma

In the three months ended March 31, 2014, the Company spent $0.

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.

Bear Creek and Overland Trail Prospects – Carbon County, Wyoming

Pursuant to a Share Exchange Agreement in 2012, the Company assumed a Purchase and Option Agreement between Armada Oil and Gas and TR Energy, Inc. through which it received leasehold interests in 1,280 acres of land, engineering data, and 2D seismic.  During the year ended December 31, 2013, the Company determined that this agreement was not in the best interest of the Company, terminated the agreement and surrendered the 1,280 acres of land to TR Energy, Inc.

On November 2, 2012, Armada executed a Seismic and Farm Out Option Contract (the “Anadarko Contract”) whereby Anadarko E&P Onshore LLC (successor in interest to Anadarko E&P Company LP), and Anadarko Land Corp. (collectively “Anadarko”) agreed to 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 a 100 percent (100%) operated working interest in the section upon which the well was drilled.  Anadarko will retain a twenty percent (20%) royalty interest in future production.  The Company delivered the seismic data to Anadarko as agreed, has selected a drilling location for the initial test well and is making preparations to drill the well in the summer of 2014.

On October 28, 2013, the Company and Anadarko entered into a Third Amendment to the Seismic and Farmout Option Contract dated October 22, 2012 which included the following changes to the original agreement, as amended:

The Company is now:

· obligated to commence drilling of the Initial Test Well on or before July 31, 2014 (previously December 31, 2013);

· granted an option for a period of 180 days from date Initial Contract Depth is reached in the Initial Test Well to commence drilling of a Continuous Option Test well, regardless of well type; and

· allowed to reduce control of well insurance coverage from $25,000,000 to $10,000,000.

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	2014			2013
Tank batteries	7-12	$	973,540		$	807,580
Production equipment	7		1,035,610			1,034,599
Production Facilities	7		110,607			108,702
Field offices (1)	20		150,000			150,000
Crew boats	7		198,600			172,413
Construction in progress (not depreciated)			161,053			43,696
Asset retirement cost	7		786,827			786,828
			3,431,237			3,103,818
Accumulated depreciation			(787,448	)		(685,920	)
Total support facilities and equipment, net		$	2,628,789		$	2,417,898

In the three months ended March 31, 2014 and 2013, the Company recognized depreciation expense of $101,528 and $70,285, respectively, on support facilities and equipment.

14

Office Furniture, Equipment, and Other

		March 31,			December 31,
	Years	2014			2013
Office equipment, computer equipment, purchased software, and leasehold improvements	3	$	250,655		$	251,912
Furniture and fixtures	10		55,569			55,569
			306,224			307,481
Accumulated depreciation			(87,817	)		(64,805	)
Total property and equipment, net		$	218,407		$	242,676

During the three months ended March 31, 2014 and 2013, the Company recognized depreciation expense of $23,138 and $11,422, 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, 2014 and December 31, 2013 were as follows:

	March 31,			December 31,
	2014			2013
Credit Facility	$	8,072,693		$	8,222,693
Notes issued pursuant to private placement of securities		630,000			655,000
Less: debt discount on private placement of notes		(30,394	)		(87,725	)
Other term notes		64,212			79,582
Notes payable outstanding		8,736,511			8,869,550
Less:  Current maturities		(8,736,511	)		(8,869,550	)
Notes payable – noncurrent	$	—		$	—

On July 22, 2011, the Company 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 was 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, 2014 and December 31, 2013, 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.

15

On May 1, 2013, F&M Bank performed a redetermination of the 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 Bank determined the existence of a Borrowing Base deficiency of $450,000.  The Company 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.  

Effective October 1, 2013, F&M Bank and the Company entered into the Second Amendment to the Loan Agreement dated July 22, 2011 as previously amended on September 21, 2012 (the “Amendment”).  The Amendment provided for the reduction of the Borrowing base by $675,000 to $12,700,000 from $13,375,000; reset monthly repayments of principal to $50,000 per month until the next scheduled redetermination to occur on or about April 1, 2014, and required that general and administrative expense not exceed 27% of revenue for any two consecutive quarters.  During the three months ended March 31, 2014, the Company repaid $150,000 of principal on the credit facility.

At inception of the Credit Facility, deferred financing costs of $102,877 were incurred.  For the three months ended March 31, 2014 and 2013, $5,641 of amortized deferred financing costs had been recognized as interest expense.  At March 31, 2014 and December 31, 2013, $7,521 and $13,162, respectively, of deferred financing costs remained to be amortized.

The Credit Facility contains covenants with which the Company must maintain compliance, among which are certain ratios.  The Company determined that, at March 31, 2014, it was not in compliance with the interest coverage ratio, calculated at 4.98, although required to be greater than or equal to 5.0, and the percentage of general and administrative expense to revenues, calculated at 32.64% although required to be less than or equal to 27%.  On May 14, 2014, the Company received a default waiver from Prosperity Bank, a Texas banking association and successor by merger to F&M Bank, for the three months ended March 31, 2014, of the Company’s noncompliance with the interest coverage ratio.  An event of default did not occur as the result of the Company receiving the default waiver.

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 derivative contracts with a single counterparty.  For more information see Note 4 – Commodity Derivative Instruments.

For the three months ended March 31, 2014 and 2013, the Company recognized interest expense of $143,520 and $179,842, 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(a)(2), Section 4(a)(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 issued was 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.  During the first two quarters of 2013, the Company had received subscriptions for $655,000 ($300,000 of which was acquired in the Armada acquisition) of Notes and issued warrants to purchase 873,333 shares of common stock to subscribers.  The Private Placement was closed to additional subscriptions in the second quarter of 2013. The fair value of the warrants, determined as their relative fair value to the notes, calculated using a Black Scholes model, of $248,927 ($103,001 of which was acquired in the Armada acquisition) 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
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., 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. $35,000 was subscribed by Marceau Schlumberger, who was a director of the Company at March 31, 2014.  $14,645 of debt discount is associated with this note, and warrants exercisable, as described above, for 46,667 shares were issued.

16

During the three months ended March 31, 2014, one of the notes in the amount of $25,000 attained maturity and was paid in full leaving total principal balances of $630,000 remaining to be paid in the second quarter of 2014.

During the three months ended March 31, 2014, the Company recognized $15,725 of interest expense on the face value of the notes, and amortization of the debt discount resulted in the recognition of $57,333 as interest expense.   $30,393 and $87,725, respectively, of debt discount remained to be amortized at March 31, 2014 and December 31, 2013.

During the three months ended 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.  

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, 2014 and December 31, 2013.

	March 31, 2014		December 31, 2013
Beginning asset retirement obligations	$	3,161,810	$	3,507,798
Obligations assumed from acquisition (1)		—		65,263
Revaluation of asset retirement obligations (2)		—		(468,519	)
Accretion expense		46,152		172,927
Sale of Young and Archer County properties		—		(99,891
Settlement of asset retirement obligations		—		(15,768	)
Ending asset retirement obligations	$	3,207,962	$	3,161,810

(1)	ARO of Archer and Young County, Texas, properties acquired in the Acquisition.
(2)	ARO of Texas and Louisiana properties.

During the year ended December 31, 2013, the State of Louisiana refunded the deposit of $23,448 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 of $15,768 was eliminated.  In addition, the asset retirement obligation for wells in the Keller Prospect in Young County, Texas, was revalued and increased by $30,794 and then retired upon sale of the properties.  The asset retirement obligation for the wells in Parish and Tribune Prospects in Archer County, Texas, was retired upon sale. At December 31, 2013, the Company provided $4,628,125 in letters of credit supporting its asset retirement obligations.

In the three months ended March 31, 2014 and 2013, the Company recognized $46,152 and $57,390, 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, 2014.

As of March 31, 2014, the Company has U.S. net operating loss carry forwards of approximately $8.5 million which begin to expire in 2029.

17

NOTE 9 – SHARE BASED COMPENSATION

Warrants

The following table summarizes the Company’s warrant activity for the three months ended March 31, 2014:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
Outstanding at December 31, 2013		7,553,333	$	1.96	4.2 years	$	—
Granted		—		—
Exercised		—		—
Cancelled/Expired		—		—
Outstanding at March 31, 2014		7,553,333	$	1.96	3.8  years	$	—
Exercisable at March 31, 2014		7,553,333	$	1.96	3.8 years	$	—

During the first quarter of 2013, under a private placement, Series D Warrants to purchase 840,000 common shares were issued at closing. Each warrant was 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
Discount rate		0.77	%
Expected life (in years)		4.9
Weighted average volatility		205.74	%
Expected dividends	$	—

Stock Options 

The Board of Directors of the Company previously adopted the 2012 Incentive Plan which provides for the issuance of incentive awards of up to 5,000,000 shares of common stock to officers, key employees, consultants and directors of the Company and its subsidiaries.  

The following table summarizes the Company’s stock option activity for the three months ended March 31, 2014:

	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
Outstanding at December 31, 2013		2,802,000			0.41	3.9 years		—
Granted		—			—	—		—
Exercised		—			—	—		—
Cancelled/Expired/Forfeited (1)		(27,000	)		—	—		—
Outstanding at March 31, 2014		2,775,000			0.41	3.7 years	$	—
Exercisable at March 31, 2014		2,545,200		$	0.41	3.7 years	$	—

(1) Forfeited shares comprise options granted to employees who terminated their employment with the Company.

Compensation expense related to stock options of $17,678 and $45,143 was recognized for the three months ended March 31, 2014 and 2013, respectively. At March 31, 2014, the Company had $30,870 of unrecognized compensation expense related to outstanding unvested stock options, which will be fully recognized over the next 12 months. No stock options have been exercised.

18

Restricted Stock

The Company had no restricted stock activity during the three months ended March 31, 2014, and no unamortized compensation expense related to granted restricted stock awards.

During the three months ended March 31, 2013, the Company had 64,800 unvested restricted shares and recognized $11,508 in stock compensation expense.

NOTE 10 – SUBSEQUENT EVENTS

Amendment of Loan Agreement with Prosperity Bank (formerly F&M Bank)

On April 10, 2014, in contemplation of the sale of additional Class A Units in TNRH to Gulfstar and the acquisition of properties in Woodson County, Kansas, we entered into the Fifth Amendment to Loan Agreement and other associated documents with Prosperity Bank, a Texas banking association and successor by merger to The F&M Bank and Trust Company (“Lender”).  Terms of the amendment and associated documents include:

· Letters of credit issued by Lender originally for the account of TNR and subsequently amended  for the account of MGC were excluded from the definition of “Letters of Credit” under the Loan Agreement (“Excluded LC’s), meaning that these letters of credit shall no  longer constitute borrowings by MEI under the Loan Agreement.  

· A First Amendment to the Security Agreement and a First Amendment to the Mortgage, Collateral Assignment, Security Agreement and Financing Statement  amending the original of those documents  dated July 22, 2011 (“Amended Security Agreement and Mortgage”) was entered into by which the properties and all associated collateral located in the Lake Hermitage Field shall thereafter secure only the obligations of MGC related to the Excluded LC’s, and the remaining properties and all associated collateral covered by the Amended Security Agreement and Mortgage shall continue to secure all secured obligations other than the Excluded LC’s.  

· The Guaranties of the Loan Agreement by TNR and MGC were released.  

· TNRH delivered to Lender a Restated Guaranty limiting TNRH’s obligation under the Restated Guaranty to a maximum amount of $4.6 million (“Limitation Amount”).  

· In the event, for any reason, that TNRH pays Lender the Limitation Amount in satisfaction of Mesa Energy, Inc.’s (“Borrower”) outstanding indebtedness on the Revolving Loan, Lender shall deliver to TNR a partial release of the Louisiana Mortgage and Security Agreement with the only remaining obligations of TNRH being related to the Excluded LC’s.  

· AMC delivered to Lender a mortgage covering the Kansas properties and an Unlimited Guaranty.  

· The Borrowing Base has been reset by Lender to $8.2 million and our obligation to make monthly principal reduction payments which, as of last redetermination, were $50,000 per month, was eliminated.  

· The Borrowing base will not be increased until such time as the Louisiana Mortgage and all associated security interests granted by TNR have been released as security for the Loan and TNRH shall have been released from its obligations under the Restated Guaranty.

Sale of Additional Class A Units in TNR Holdings, LLC, to Gulfstar Resources, LLC (“Gulfstar”)

On April 10, 2014, we sold to Gulfstar 11,873 Class A Units of TNR Holdings, LLC (“TNRH”) at a price of $564.31 per Class A Unit ($6,700,053 in the aggregate), representing an additional 25.925% membership interest in TNRH by Gulfstar increasing Gulfstar’s aggregate member interest in TNRH to 60.3% (“Tranche B”).  As result of this purchase, Gulfstar gained control of TNRH.  Our financial statements for periods after the closing of the purchase will no longer consolidate TNRH and its wholly owned subsidiaries, Tchefuncte Natural Resources, LLC (“TNR”) and Mesa Gulf Coast, LLC (“MGC”), but will account for ownership interest in TNRH in accordance with ASC Topic 810, Consolidation (“ASC 810”). ASC 810 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income (loss) attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. ASC 810 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. The funds were primarily used to purchase the Kansas properties as discussed below.

19

TNRH’s balances as of March 31, 2014 and for the three month period ended March 31, 2014 were as follows:

	As of March 31, 2014
ASSETS
Current assets	$	6,659,144
Oil and gas properties, successful efforts accounting:
Properties subject to amortization, net		8,212,524
Properties not subject to amortization		16,756
Support facilities and equipment, net		2,628,789
Net oil and gas properties		10,858,069
Other assets		581,038
TOTAL ASSETS	$	18,098,251
LIABILITIES AND  EQUITY
Current liabilities	$	2,329,986
Asset retirement obligations		3,106,376
Other liabilities		88,050
TOTAL LIABILITIES	$	5,524,412

	For the Three Months Ended March 31, 2014
Revenue	$	3,161,809
Net loss	$	(301,802	)

Kansas Acquisition

On March 13, 2014, we entered into a purchase and sale agreement with Piqua Petro, Inc., pursuant to which we purchased certain oil and gas working interests in Woodson County, Kansas (the “Kansas Properties”). The Kansas Properties comprise six oil and gas leases covering approximately 1,040 gross (901 net) acres (excluding royalty and overriding royalty interests). Including adjustments from an effective date of March 1, 2014, the purchase price was $6,367,843, and the Company assumed the future asset retirement obligations of $349,604 associated with the Kansas Properties. The acquisition was primarily funded from drawing down Tranche B under the Unit Purchase Agreement between us and Gulfstar, as more fully described in the preceding paragraph.  The acquisition of the Kansas Properties was finalized on April 10, 2014.

Retirement of Notes Issued Pursuant to Private Placement

On April 11, 2014, we paid in full the principal balances of $130,000 of four notes issued pursuant to our private placement in the first two quarters of 2013, together with interest of $450.  The notes repaid had maturity dates of May 31, 2014.  Of the notes repaid, $35,000 plus interest of $121 was to Marceau Schlumberger, a member of our board of directors at the time.  Balances remaining on these notes total $500,000, of which $100,000 is held by James J. Cerna, Jr., a member of our board of directors.

20

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 2013 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

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.  Armada is party to a farmout agreement with Anadarko Petroleum in the Niobrara play near existing oil and natural gas fields. Armada had one wholly owned subsidiary, Armada Oil and Gas, Inc. incorporated on January 19, 2012.

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 four 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.  

On December 16, 2013, MEI formed TNR Holdings, LLC (“TNRH”), a Delaware limited liability company as a wholly owned subsidiary, and contributed its member’s capital in TNR and MGC to TNRH.  On December 20, 2013, the Company entered into a Unit Purchase Agreement with Gulfstar Resources, LLC, (“Gulfstar”) pursuant to which Gulfstar contributed $6,250,000 of capital in exchange for 6,250 Class A Units of TNRH membership interest at a price of $1,000 per Class A Unit, representing a 34.375% membership interest in TNRH (“Tranche A”).  As part of the transaction, Gulfstar was  obligated to purchase an additional aggregate 11,873 Class A Units of TNRH at a price of $564.31 per Class A Unit ($6,700,053 in the aggregate), representing an additional 25.925% membership interest in TNRH, and did so on April 10, 2014 (“Tranche B”).  In addition, Gulfstar has an option to purchase up to an additional 9,718 Class A Units, at one or more additional closings, at a price of $468.20 per Class A Unit ($4,549,968 in the aggregate), representing an additional 9.7% membership interest in TNRH (“Tranche C” and together with Tranche A and Tranche B, the “Gulfstar Transaction”).  Upon closing and funding of Tranche B of the Gulfstar Transaction, MEI’s interest in TNR Holdings, LLC was reduced to 39.7%.

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.

21

On March 14, 2014, Armada Midcontinent, LLC, (formerly known as MMC Resources, LLC), a wholly owned subsidiary of MEI, entered into a purchase and sale agreement with Piqua Petro, Inc., pursuant to which it purchased from Piqua Petro, Inc., on April 10, 2014, Piqua Petro’s interests in six oil and gas leases covering approximately 1,040 (901 net) acres in Woodson County, Kansas, paying the seller a net purchase price of $6,367,843 in cash.  The capital used for this purchase came primarily from the closing of Tranche B of the Gulfstar Transaction.  We acquired 100% of the leasehold working interest in the lands covered by the leases, subject to royalties, overriding royalties, and other expense-free burdens on production not to exceed 12.5% of 8/8ths, such that the net revenue interest in the leases conveyed to us was 87.5%.

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.

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.

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:

· The Vernon Field and the Winterschied Field, producing oil fields in Woodson County, Kansas;

· 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;

· 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 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.  As a result of this transaction, TNR became a wholly owned subsidiary of MEI.

22

On December 20, 2013, the Company and its wholly owned subsidiary, MEI, completed an asset reallocation financing transaction with Gulfstar as described above.   As of March 31, 2014, MEI’s membership interest in TNRH was 65.625%. TNR, now a wholly owned subsidiary of TNRH, owns 100% working interest in the Lake Hermitage Field in Plaquemines Parish, Louisiana along with various working interests in producing properties the Valentine and Larose Fields in Lafourche Parish, Louisiana and the Bay Batiste Field in Plaquemines Parish, Louisiana.  The capital provided by the initial closing of Tranche A December 20, 2013 is expected to accelerate development of the south Louisiana reserves.  On April 10, 2014,the Company closed on a purchase by Gulfstar of 11,873 Class A Units of TNR Holdings, LLC (“TNRH”) at a price of $564.31 per Class A Unit ($6,700,053 in the aggregate), representing an additional 25.925% membership interest in TNRH by Gulfstar increasing Gulfstar’s aggregate member interest in TNRH to 60.3% (“Tranche B Funding”).  As result of this purchase, Gulfstar gained control of TNRH.  Our financial statements for periods after the closing of the purchase will no longer consolidate TNRH and its wholly owned subsidiaries, Tchefuncte Natural Resources, LLC (“TNR”) and Mesa Gulf Coast, LLC (“MGC”), but will account for ownership interest in TNRH in accordance with ASC Topic 810, Consolidation (“ASC 810”). ASC 810 establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income (loss) attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. ASC 810 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owner. Money from the Tranche B Funding was used to purchase the Kansas properties as discussed below.

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.

TNR owns a 100% working interest and an approximate 75% net revenue interest in each of the eighteen wells in the Lake Hermitage Field.  A total of 3,589 mineral acres are held by production in the field. Seven wells are currently shut-in pending evaluation for workover and/or future recompletion in uphole zones, and an additional well has been converted to a salt water disposal well which is expected to 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.

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.

TNR owns approximately 3,082 net mineral acres that are held by production in the field and holds working interests that range from 68% to 100% with net revenue interests from 51% to 82.4%.

Twenty of the thirty-eight 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.  

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.

23

TNR 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.

TNR owns various working interests that range from 26.8% to 100% and net revenue interests from 19.43% to 77% in seven wells in the Bay Batiste Field.  One well is currently producing and the other five 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.

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

The Company owns 2,230.82 gross and 1,965.23 net acres of undeveloped leasehold with an average remaining lease term of approximately 1.2 years.  The Mississippian Limestone in Oklahoma is a proven zone that has been drilled vertically in Oklahoma for many years so there is a lot of data available with no need for seismic.  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, the Company commenced the drilling of its first horizontal well in the 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.  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.

Wyoming Area

The Company holds a farmout agreement with Anadarko (Anadarko Contract) on approximately 9,800 net mineral acres in Carbon County, Wyoming (“Project Acreage”).  The Project Acreage is generally 40 miles west of Laramie, Wyoming and lies in the emerging fairway of the Niobrara Shale play which is currently very active in northern Colorado and eastern Wyoming.  In addition, there are a number of conventional zones, both above and below the Niobrara, which are highly productive in the area.  A 3-D seismic shoot over the acreage position by the Company has been processed and evaluated, and the results have not only confirmed potential in a number of the deep conventional zones but also solid potential in the Niobrara.  The Company expects to drill its first well in the Project Acreage before July 31, 2014.  The Company has well logs from nearby wells showing the presence of all three Niobrara “benches”, and well control and core data indicates that the Niobrara in this area meets or exceeds the positive attributes of the DJ Basin and Wattenberg Fields in northern Colorado, both of which are being actively drilled by Anadarko, EOG, Noble and other major independents.

Initial indications from those fields indicate drilling and completion costs for a horizontal well in the Niobrara of under $5,000,000, potential reserves per well of 300,000 to 600,000 barrels and liquids ratios of 60% to 80%. 

24

On the conventional side, three nearby fields in conventional zones have produced in excess of 65 million barrels of oil and 23 BCF of gas.  A number of potential conventional drilling locations were identified/confirmed as a result of the 3-D seismic shoot completed in 2013.

Based on a recent article in the Oil & Gas Investor, companies drilling the Niobrara in the DJ Basin to the south are horizontally drilling all three Niobrara benches separately plus the deeper Codell formation, resulting in as many as 16 horizontal wells per section.  That drilling plan could theoretically result in over 200 wells on the existing Anadarko farmout acreage.  Anadarko owns the minerals underlying the contracted acreage as well as a substantial amount of additional acreage in the area.

Under the Anadarko Contract, the Company is obligated to commence drilling of the initial test well on or before July 31, 2014.  If the Company fails to commence drilling said well in a timely manner, the Company shall be deemed to have relinquished its right to acquire any interest in Anadarko’s acreage under the Anadarko Contract.  If the Company drills an initial test well capable of production in paying quantities to the initial contract depth (approximately 8,500 feet), completes it as a producer and otherwise complies with and performs all other terms, covenants, and conditions of the Anadarko Contract, the Company will earn and be entitled to receive from Anadarko a lease, effective 30 days from the date of the release of the rig from the test well location, covering all of Anadarko’s oil and gas estate in the respective drill site section limited to the earned depth. The lease to be so 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 drill site sections as described above.  A location for the Initial Test Well has been selected and additional locations for future wells are being evaluated.   The Company intends to take an aggressive approach to exploiting the Anadarko acreage position. The implementation of an aggressive drilling schedule using leading-edge shale drilling and completion technology should enable the Company to rapidly identify and develop significant oil and gas reserves in the Niobrara Shale.

Kansas Area

On March 14, 2014, we entered into a purchase and sale agreement with Piqua Petro, Inc., pursuant to which, on April 10, 2014, we purchased its interests in six oil and gas leases covering approximately 1,040 (901 net) acres in Woodson County, Kansas, with total current production of approximately 80 barrels per day.  We paid the seller a net purchase price of $6,367,843 in cash for the leases.  We acquired 100% of the leasehold working interest in the lands covered by the leases, subject to royalties, overriding royalties, and other expense-free burdens on production that do not exceed 12.5% of 8/8ths, such that the net revenue interest in the leases conveyed to us were 87.5%. 

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

MEI operates 19 producing gas wells and a 12.4 mile pipeline and gathering system in the Java Field with an approximate 78% net revenue interest in leases covering 2,851.5 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’ 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.  However, 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. 

25

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, 2014 and 2013:

	For the Three Months Ended March 31,
	2014			2013
Net loss	$	(518,753	)	$	(2,511,448	)
Adjustments:
Interest (income) expense, net		216,441			194,639
Income tax (benefit) expense		(314,703	)		(876,271	)
Dry hole expense		—			2,585,062
Depreciation, depletion, accretion and impairment		420,079			759,768
Gain on settlement of asset retirement obligation		—			(1,328	)
Unrealized loss on change in commodity derivative instruments		167,673			534,699
Loss on change in convertible debt derivative		—			—
Share-based compensation		17,678			56,653
Adjusted EBITDA	$	(11,585	)	$	741,774

Results of Operations

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Revenue

	Three Months Ended
	March 31,							Percentage
	2014		2013		Difference			Change
Revenues
Oil	$	2,637,375	$	2,812,132	$	(174,757	)		-6.2	%
Natural gas		476,358		516,159		(40,158	)		-7.7	%
Natural gas liquids		23,594		63,752		(39,801	)		-63.0	%
Total	$	3,137,327	$	3,392,043	$	(254,717	)		-7.5	%
Sales volumes
Oil (Bbls)		25,617		25,447		170			0.7	%
Natural gas (MCF)		90,018		234,018		(144,000	)		-61.5	%
Natural gas liquids (Bbl)		606		1,545		(939	)		-60.8	%
Total BOE		41,226		65,995		(144,769	)		-219.4	%
Total BOE/day		458		733
Average prices
Oil (per Bbl)	$	102.95	$	110.51	$	(7.56	)		-6.8	%
Natural gas (per MCF)		5.29		2.21		3.09			139.9	%
Natural gas liquids (per Bbl)		38.93		41.26		(2.33	)		-5.6	%
Total per BOE	$	76.10	$	51.40	$	6.80			-13.2	%

26

Revenues from commodity sales decreased during the three months ended March 31, 2014, over the three months ended March 31 2013, due to natural decline in well production and lower prices for oil and natural gas liquids.  Natural gas sales were down primarily because, in Bay Batiste Field, pressure declined to the point that the addition of a gas lift is needed to bring production up to prior levels.  

In addition to revenues from commodity sales, during the three months ended March 31, 2014, we had $36,673 of revenue from lease fuel, compressor allocation, gas transportation, COPAS overhead, and production handling fees.  During the three months ended March 31, 2013, we had $46,795 of the same type of income.

Operating expenses

Operating expenses for the three months ended March 31, 2014 and 2013 are set forth in the table below:

	Three Months Ended
	March 31,								Percentage
	2014		2013			Difference			Change
Costs and Expenses
Lease operating expense (1)	$	1,483,143	$	1,546,306		$	(63,163	)		-4.1	%
Production and ad valorem taxes (2)		354,007		306,889			47,118			15.4	%
Environmental remediation expense (3)		252,135		—			252,135			N/A
Exploration expense (4)		159,529		—			159,529			N/A
Dry hole expense (5)		—		2,585,062			(2,585,062	)		-100.0	%
Depletion, depreciation, amortization, and impairment expense (6)		420,079		759,768			(339,689	)		-44.7	%
(Gain) loss on settlement of asset retirement obligation (7)		—		(1,328	)		1,328			100.0.	%
General and administrative expense (8)		1,035,859		1,023,180			12,679			1.2	%
Total operating expenses	$	3,704,752	$	6,219,877		$	(2,515,125	)		-40.4	%

(1)	Decreased LOE on nonoperated properties.
(2)	Decreased sales volumes.
(3)	Resulted from a pipeline leak between two tank batteries in Valentine Field and a spill from a dump valve on the heater treater for the MR Fee well in Larose Field.
(4)	Purchase of seismic data for Louisiana properties.
(5)	2013 mechanical failure in the drilling of the Thomas #6H well in Oklahoma.
(6)	Primarily attributable to reduction in asset retirement costs for wells after December 31, 2013, revaluation of asset retirement obligations as well as lower natural gas production.
(7)	No asset retirement obligations were settled in 2014.
(8)	Increased legal and professional fees associated with Gulfstar Tranche B funding and Kansas acquisition less decreased stock compensation expense.

27

Operating expenses expressed in BOE for the three months ended March 31, 2014 and 2013 are set forth in the table below:

	Three Months Ended
	March 31,								Percentage
	2014		2013			Difference			Change
Costs and Expenses
Lease operating expense	$	35.98	$	23.43		$	12.55			53.6	%
Production and ad valorem taxes		8.59		4.65			3.94			84.7	%
Environmental remediation expense		6.12		—			6.12			N/A
Exploration expense		3.87		—			3.87			N/A	%
Dry hole expense		—		39.13			(39.13	)		-100.0	%
Depletion, depreciation, amortization, and impairment expense		10.19		11.51			(1.32	)		-11.5	%
(Gain) loss on settlement of asset retirement obligation		—		(0.02	)		0.02			100.0	%
General and administrative expense		25.13		15.50			9.63			62.1	%
Total operating expenses	$	89.88	$	94.20		$	(4.32	)		-4.6	%

Operating loss. As a result of the above described revenues and expenses, we incurred an operating loss of $530,752 in the first quarter of 2014 as compared to an operating loss of $2,781,039 in the first quarter of 2013.

Interest expense. Interest expense increased to $216,592 for the three months ended March 31, 2014, from $198,015 for the three months ended March 31, 2013. 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 loss on changes in derivative value. The unrealized loss on change in derivatives – commodity contracts for the three months ended March 31, 2014 and 2013 was $167,673 and $534,699, respectively. Unrealized losses 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. 

Realized gain (loss) on changes in derivatives – commodity contracts. Cash settlements which we paid from hedging our sales of oil and gas production were $165,511 in the first quarter of 2014 as compared to $115,678 which we received in the first quarter of 2013. Changes in realized gains and losses associated with our commodity contracts are attributable to the same factors that affect the unrealized gains or losses associated with our commodity derivative contracts.

Income tax benefit. State and federal income tax benefit for the first quarter of 2014 was $314,703 compared to an income tax benefit of $876,271 in the first quarter of 2013.  The increase in the income tax benefit in the first quarter of 2014 is primarily due to lower first quarter 2014 net loss.

Net loss. Due to the reasons set forth above, our net loss for the three months ended March 31, 2014 was $518,753 ($0.01 per basic and diluted common share). Our net loss for the three months ended March 31, 2013 was $2,511,448 ($0.07 per basic and diluted common share).

Liquidity and Capital Resources

Overview

As of March 31, 2014, we had a working capital deficit of $4,062,011. As of December 31, 2013, we had a working capital deficit of $2,310,297. The increase in the working capital deficit was attributable to:

· The classification as current of all of our debt in the amount of $8,766,904 (gross of discount)

· Decreased revenues from oil and gas sales.

· Capital expenditures on our producing properties. 

The anticipated reorganization of our credit facility in April 2014 as a function of the Gulfstar Transaction resulted in a delay in the extension of the facility.  The reorganization took place in April 2014 as discussed elsewhere in this report.  As a result, we now expect a short extension of the facility prior to maturity to allow time for the mid-year reserve report to be completed and a new borrowing base to be established, followed by a longer term extension of the facility in the third quarter.  In addition, we expect Tranche C of the Gulfstar transaction to be funded in the second quarter, providing resources for the drilling and development of our properties.

28

Cash and Accounts Receivable

At March 31, 2014, we had cash and cash equivalents of $5,099,409, compared to $7,095,972 at December 31, 2013. Cash decreased by $1,996,563 due to payments for capital expenditures on our producing properties, transaction expenses associated with the Tranche B funding by Gulfstar and the acquisition of our Kansas properties, and increased cash payments of interest.

Liabilities

Accounts payable and accrued expenses decreased by $69,387 to $2,156,665 at March 31, 2014, from $2,226,052 at December 31, 2013, primarily due to an increased level of operating and capital expenditure activity associated with additional wells and facilities, a decreased amount of revenue payable to royalty and working interest owners, and payment for additional user licenses for our ERP system.

As of March 31, 2014, the outstanding balance of principal on debt, net of discount, was $8,736,511, a net decrease of $133,039 from the outstanding balance of $8,869,550, as of December 31, 2013. The decrease was due to principal reduction payments on our credit facility, payment in full of two premium financed insurance notes, net of the addition of one premium financed insurance note, the repayment of one note associated with the 2013 private placement of debt which matured during the quarter.

Cash Flows

For the three months ended March 31, 2014, the net cash used in operating activities was $589,061 compared to net cash provided by operating activities for the three months ended March 31, 2013 of $88,638, a net increase in cash used of $677,699.  

For the three months ended March 31, 2014 and 2013, net cash used in investing activities was $1,169,165 and $2,159,885, respectively, a decrease in cash used of $990,720.  This is attributable to decreased spending on development of oil and gas properties and payment for settlement of expired hedges in 2014 versus payment received for settlement of expired hedges in the first quarter of 2013, despite increased spending on support facilities and equipment.

For the three months ended March 31, 2014 and 2013, net cash (used in) provided by financing activities was ($238,337) and $274,820, respectively, an increase in cash used of $513,157.  This was primarily because in the first three months of March 2013, we had received proceeds from private placement of debt but had received none in 2014 and because we made significantly greater reductions of principal on our credit facility in 2014 than in the same period of 2013.

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.”

29

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, 2014. 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, 2014, our disclosure controls and procedures are not effective and are not presently designed at a level to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The material weaknesses, which relate to internal control over financial reporting, that were identified are:

1. As of March 31, 2014, 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.

30

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 Annual Report on Form 10-K filed with the SEC on March 31, 2014, which may be accessed via EDGAR through the Internet at www.sec.gov.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

31

Item 6. Exhibits

Exhibit No.	Description
10.1	Agreement for Purchase and Sale dated as of March 13, 2014, by and between Piqua Petro, Inc., and Armada Midcontinent, LLC, or its assigns (included as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 20, 2014 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.

32

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 15, 2014	By:	/s/ RANDY M. GRIFFIN
		Randy M. Griffin
		Chief Executive Officer (Principal Executive Officer)
Date:  May 15, 2014	By:	/s/ RACHEL L. DILLARD
		Rachel L. Dillard
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

33