Armada Oil 10Q 2014 Q2 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 June 30, 2014

¨ 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 August 18, 2014, there were 56,030,473 shares of the registrant’s common stock outstanding.

Table of Contents

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	22

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	32

	Item 4. Controls and Procedures	33

PART II. OTHER INFORMATION

	Item 1. Legal Proceedings	34

	Item 1A. Risk Factors	34

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	34

	Item 3. Defaults Upon Senior Securities	34

	Item 4. Mine Safety Disclosures	34

	Item 5. Other Information	34

	Item 6. Exhibits	35

	Signatures	36

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Interim Consolidated Financial Statements

ARMADA OIL, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30, 2014		December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	2,380,933	$	7,095,972
Accounts receivable – oil and gas		171,912		1,524,623
Accounts receivable – other		586,179		32,538
Deferred financing costs, net – current		76,989		13,162
Deferred tax asset – current		6,025		100,606
Prepaid expenses		75,235		202,280
Assets held for sale		570,926		—
TOTAL CURRENT ASSETS		3,868,199		8,969,181

Oil and gas properties, successful efforts accounting:
Properties subject to amortization, net		6,643,346		7,692,703
Properties not subject to amortization		9,949,307		10,653,825
Support facilities and equipment, net		97,519		2,417,898
Land		38,345		38,345
Net oil and gas properties		16,728,517		20,802,771

Property and equipment, net		169,608		242,676
Deferred tax asset – noncurrent		5,361,605		5,502,988
Deposit on asset retirement obligations		40,000		585,973
Production payment receivable		131,250		131,250
Cost method investment		7,789,190		—
Other assets		75,098		55,598

TOTAL ASSETS	$	34,163,467	$	36,290,437

LIABILITIES
Current liabilities:
Accounts payable – trade	$	111,593	$	1,362,867
Revenue payable		2,862		418,213
Accrued expenses		206,078		444,972
Accrued expenses – related parties		27		70
Notes payable, net – current		8,515,725		8,767,392
Notes payable – related parties, net – current		100,000		102,158
Derivative liability, commodity contracts – current		—		173,806
Other current liabilities		133,334		10,000
TOTAL CURRENT LIABILITIES		9,069,619		11,279,478

Derivative liability, commodity contracts – noncurrent		—		53,289
Deferred tax liability – noncurrent		6,622,398		3,703,553
Asset retirement obligations		455,346		3,161,810
TOTAL LIABILITIES		16,147,363		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		16,219,248		16,108,722
Retained earnings (deficit)		1,740,826		(4,038,633	)
Total equity attributable to Armada Oil, Inc.		18,016,104		12,126,119
Noncontrolling interest		—		5,966,188
TOTAL EQUITY		18,016,104		18,092,307

TOTAL LIABILITIES AND EQUITY	$	34,163,467	$	36,290,437

See accompanying notes to unaudited consolidated financial statements.

Table of Contents

ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013

Revenues	$	543,245		$	3,105,108		$	3,717,245		$	6,543,946

Operating expenses:
Lease operating expense		62,042			2,414,415			1,899,192			4,267,610
Environmental remediation expense		—			—			252,135			—
Exploration cost		7,895			92,346			167,424			92,346
Dry hole expense		—			24,804			—			2,609,866
Depletion, depreciation, amortization, accretion and impairment		312,938			271,361			733,017			1,031,129
Gain on settlement of asset retirement obligations		—			—			—			(1,328	)
General and administrative expense		765,398			1,579,682			1,801,259			2,602,862
Total operating expense		1,148,273			4,382,608			4,853,027			10,602,485

Loss from operations		(605,028	)		(1,277,500	)		(1,135,782	)		(4,058,539	)

Other income (expense):
Interest income		—			1,092			151			4,468
Interest expense		(176,413	)		(199,215	)		(393,005	)		(397,230	)
Realized gain (loss) on commodity contracts		—			35,059			(165,511	)		150,737
Gain (loss) on change in derivative value – commodity contracts		—			586,527			(167,673	)		51,828
Loss on modification of offering		—			(65,749	)		—			(65,749	)
Bargain purchase gain		—			—			—			1,455,879
Gain on sale of equity in subsidiary		11,105,788			—			11,105,788			—
Other income		5,502			17,611			148,678			24,591
Total other income		10,934,877			375,325			10,528,428			1,224,524

Net income (loss) before income taxes		10,329,849			(902,175	)		9,392,646			(2,834,015	)
Income tax benefit (expense)		(4,031,635	)		411,658			(3,716,932	)		1,287,929
Net income (loss)	$	6,298,214		$	(490,517	)	$	5,675,714		$	(1,546,086	)
Net loss attributable to noncontrolling interest		—			—			(103,745	)		—
Net income (loss) attributable to Armada Oil, Inc.	$	6,298,214		$	(490,517	)	$	5,779,459		$	(1,546,086	)

Net income (loss) per common share:
Basic	$	0.11		$	(0.01	)	$	0.10		$	(0.03	)
Diluted	$	0.11		$	(0.01	)	$	0.10		$	(0.03	)

Weighted average number of common shares outstanding:
Basic		56,030,473			55,717,536			56,030,473			45,355,981
Diluted		56,030,473			55,717,536			56,030,473			45,355,981

See accompanying notes to these unaudited consolidated financial statements.

Table of Contents

ARMADA OIL, INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the Six Months Ended June 30, 2014

(Unaudited)

					Additional
	Common Stock				Paid In		Retained			Noncontrolling
	Shares		Par		Capital		Earnings (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		—		—		25,297		—			—			25,297

Warrants granted to extend notes recorded as deferred financing cost		—		—		85,229		—			—			85,229

Sale of controlling interest in TNRH		—		—		—		—			(5,862,443	)		(5,862,443	)

Net income		—		—		—		5,779,459			(103,745	)		5,675,714

Balances at June 30, 2014		56,030,473	$	56,030	$	16,219,248	$	1,740,826		$	—		$	18,016,104

See accompanying notes to these unaudited consolidated financial statements.

Table of Contents

ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	5,675,714		$	(1,546,086	)

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization, accretion and impairment		733,017			1,031,129
Dry hole expense		—			2,609,866
Deferred income taxes		3,716,932			(1,287,929	)
Share-based compensation		25,297			594,932
(Gain) loss on settlement of asset retirement obligations		—			(1,328	)
Amortization of debt discount charged to interest expense		87,726			57,465
Amortization of deferred financing costs		21,401			11,282
Realized gain on derivative commodity contracts		165,511			(150,737	)
Unrealized loss on change in derivative value – commodity contracts		167,673			(51,828	)
Bargain purchase gain		—			(1,455,879	)
Loss on offering modification		—			65,749
Gain on sale of controlling interest in TNR Holdings, LLC		(11,105,788	)		—
Changes in operating assets and liabilities:
Accounts receivable – oil and gas		(354,808	)		(319,896	)
Accounts receivable – other		—			132,122
Prepaid expenses		96,452			31,213
Accounts payable and accrued expenses		178,659			(558,910	)
Accrued expenses – related party		26,606			(40,065	)
Revenue payable		(84,867	)		172,329
CASH USED IN OPERATING ACTIVITIES		(650,475	)		(706,571	)

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisition and development of oil and gas properties		(7,229,473	)		(2,240,688	)
Cash received for sale of oil and gas properties		—			85,000
Cash paid for support facilities and equipment		(413,166	)		(68,282	)
Cash proceeds from settlement of derivative commodity contracts		(165,511	)		150,737
Cash received from deconsolidation of a subsidiary, net		4,173,812			—
Cash paid for acquisition of Armada		—			(293,106	)
Cash paid for deposits		(20,000	)		—
Cash paid for property and equipment		—			(4,590	)
CASH USED IN INVESTING ACTIVITIES		(3,654,338	)		(2,370,929	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings on debt, net of financing costs		—			305,515
Proceeds from borrowings on debt – related parties, net of financing costs		—			135,000
Principal payments on debt		(373,560	)		(864,310	)
Installment payments on software		(36,666	)		(79,629	)
CASH USED IN FINANCING ACTIVITIES		(410,226	)		(503,424	)

NET CHANGE IN CASH		(4,715,039	)		(3,580,924	)
CASH AT BEGINNING OF PERIOD		7,095,972			5,884,649
CASH AT END OF PERIOD	$	2,380,933		$	2,303,725

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest	$	287,935		$	372,848
Cash paid for income taxes	$	—		$	75,000

NON-CASH INVESTING AND FINANCING TRANSACTIONS
Financed prepaid assets	$	58,256		$	—
Debt discount related to warrants issued in conjunction with notes payable and notes payable – related parties	$	—		$	142,133
Deferred financing cost incurred in extending maturity of debt by issuance of warrants	$	85,229		$	—
Change in asset retirement obligations	$	349,604		$	30,716
Common stock issued in satisfaction of stock payable	$	—		$	325,000
Common stock issued for purchase of Mesa Energy Holdings, Inc.	$	—		$	14,056,342

See accompanying notes to these unaudited consolidated financial statements.

Table of Contents

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 balance sheets 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 Midcontinent LLC (“MMC”), and Armada Midcontinent, LLC, formerly known as MMC Resources, LLC (“AMC”). Consolidated statements of operations and cash flows include those of the Company, AOG, AOP, MEI, MMC, and AMC for the six months ended June 30, 2014, as well as those of TNR Holdings, LLC (TNRH”) and its wholly owned subsidiaries, Tchefuncte Natural Resources, LLC (“TNR”) and Mesa Gulf Coast, LLC (“MGC”) for the three months ended March 31, 2014. The Company owned 65.625% of TNRH as of March 31, 2014, but the Company’s ownership was reduced to 27.124% during the second quarter of 2014. The Company deconsolidated the financial statements of TNRH, which includes the financial statements of TNR and MGC, as of April 1, 2014, in accordance with ASC 810-15-10 because the Company lost its ability to impose significant influence, and control of the operations and assets of TNRH were restricted by the then non-controlling member as of April 1, 2014.

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.

The Company’s oil and gas operations are conducted by its wholly owned subsidiaries. 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, Wyoming, and Texas.

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.

Table of Contents

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year and the reported amount of proved natural gas and oil reserves. Management bases its estimates on historical experience and various other assumptions that it believes are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from these estimates and changes in these estimates are recorded when known.

Reclassifications

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

Earnings (Loss) Per Common Share

The Company’s earnings (loss) per common 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 June 30,					For the Six Months Ended June 30,
	2014		2013			2014		2013
Numerator:
Net income (loss) available to stockholders	$	6,298,214	$	(490,517	)	$	5,779,459	$	(1,546,086	)
Basic net income allocable to participating securities (1)		—		—			—		—
Basic net income (loss) available to stockholders		6,298,214		(490,517	)		5,779,459		(1,546,086	)

Denominator:
Weighted average number of common shares – Basic		56,030,473		55,717,536			56,030,473		45,355,981
Effect of dilutive securities (2) :
Options and warrants		—		—			—		—
Weighted average number of common shares – Diluted		56,030,473		55,717,536			56,030,473		45,355,981

Net income (loss) per common share:
Basic and diluted	$	0.11	$	(0.01	)	$	0.10	$	(0.03	)

(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 and six months ended June 30, 2014, stock options and warrants representing 2,757,000 and 7,953,333 shares, respectively were antidilutive and, therefore, excluded from the diluted share calculation. For the three and six months ended June 30, 2013, stock options and warrants representing 2,793,200 and 3,491,247 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.

Table of Contents

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.

Armada was the legal acquirer of Mesa, the accounting acquirer, 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, which was included in the purchase price. 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.

Table of Contents

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

NOTE 3 – ACQUISITION AND DIVESTITURE

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

In April 2014, Gulfstar purchased 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 with net cash received of $6,419,573), representing an additional 25.925% membership interest in TNRH by Gulfstar increasing Gulfstar’s aggregate member interest in TNRH to 60.299% (“Tranche B”). As result of this purchase, Gulfstar gained control of TNRH. Our financial statements for periods beginning April 1, 2014, 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”). The Company accounts for its investment in TNRH by the cost method. The financial statements of TNRH and its wholly owned subsidiaries, TNR and MGC, are deconsolidated from the financial statements of the Company effective April 1, 2010, because the Company lost its ability to impose significant influence, and control of operations and assets of TNRH were restricted by rights of the then non-controlling member as of April 1, 2014, see NOTE 1. The funds received from the closing of Tranche B were primarily used to purchase the Kansas properties as discussed below.

As a result of the deconsolidation of the financial statements, the consolidated balance sheets as of June 30, 2014, reflect only the balances of the Company and its wholly owned subsidiaries and do not include those of TNRH and its subsidiaries. The consolidated statement of operations contains the results of operations of the Company and TNRH and its subsidiaries, less the net loss attributable to the non-controlling interest (TNRH) for the three months ended March 31, 2014. The consolidated statement of operations for the three months ended June 30, 2014, contains only the result of operations for the Company and does not include those of TNRH and its subsidiaries.

On May 16, 2014, and June 16, 2014, the Company sold an additional 1,400 and 2,380 units at $564.31 per unit, respectively, to Gulfstar for $790,034 and $1,343,058, respectively, for an aggregate of $2,133,092 (“Tranche D”). Net cash received was $2,041,576. The Company’s interest in TNRH was reduced to 27.124%. Due to the Company’s inability to enforce significant influence over any part of TNHR operations, the Company’s remaining investment was recorded on the balance sheet as a cost method investment.

Table of Contents

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		16,753
Support facilities and equipment, net		2,628,792
Net oil and gas properties		10,858,069

Other assets		581,038

TOTAL ASSETS		18,098,251

LIABILITIES

Current liabilities		2,329,986
Deferred tax liability		403,283
Asset retirement obligations		3,106,376
Derivative liabilities		88,050

TOTAL LIABILITIES		5,927,695

NET ASSETS	$	12,170,556

	For the Three Months Ended March 31, 2014

Revenue	$	3,161,809
Net loss	$	(301,802	)

A gain of $11,105,788 was recognized on our sale of the controlling interest and deconsolidation of TNRH as follows:

Gain on deconsolidation of TNRH
Fair value of proceeds that resulted in loss of control	$	6,419,573
Fair value of noncontrolling interest retained (cost method investment)		9,830,766
Carrying amount of noncontrolling interest in former subsidiary on the date the subsidiary is deconsolidated		5,862,443
		22,112,782
Less carrying amount of TNRH’s net assets		(12,170,556	)
Less intercompany payables		1,163,562
Gain on deconsolidation of TNRH	$	11,105,788

As of June 30, 2014, the Company recorded a cost method investment for its remaining 27.124% noncontrolling interest held in TNRH as follows:

Cost method investment
Fair value of noncontrolling interest retained the date TNRH is deconsolidated	$	9,830,766
Less Tranche D net proceeds from sale units in TNRH		(2,041,576	)
Cost method investment as of June 30, 2014	$	7,789,190

Table of Contents

Kansas Acquisition

During the six months ended June 30, 2014, the Company consummated the purchase of developed leasehold interests (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 $6,368,106, of which $6,285,106 was applied to purchased leasehold and $83,000 to support facilities and equipment, 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.

NOTE 4 – FAIR VALUE MEASUREMENTS

The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and December 31, 2013.

June 30, 2014

Carrying Value

Fair Value Measurement

Level 1

Level 2

Level 3

Derivative liability – commodity contracts

—

	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 5 – COMMODITY DERIVATIVE INSTRUMENTS

Through the first quarter of 2014, the Company had engaged 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 was designated as a cash flow hedge. Changes in fair value of derivative instruments 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 limited the Company's ability to benefit from increases in the price of oil and natural gas, it was also intended to reduce the Company's potential exposure to significant price declines. These derivative transactions were generally placed with major financial institutions that the Company believes to be financially stable.

The Company had 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 a result of the Company’s sale of the controlling interest in TNRH to Gulfstar, TNRH agreed in the Amendment to Unit Purchase Agreement dated April 10, 2014 to assume the hedging contracts between the Company and the counterparty. Prosperity Bank, successor by merger to F&M Bank & Trust Company, agreed to the Company transferring and novating its interest in its hedges to TNRH in the Sixth Amendment to the Loan Agreement dated July 22, 2011, on May 30, 2014, see NOTE 7. As a result the Company has no assets or liabilities associated with commodity derivative instruments at June 30, 2014.

For the six months ended June 30, 2014 and 2013, the Company recorded a realized loss of $165,511 and realized gain of $150,737 respectively, and an unrealized loss of $167,673 and unrealized gain of $51,828, respectively, on the statement of operations.

Table of Contents

NOTE 6 – PROPERTY AND EQUIPMENT

Oil and Gas Properties

The Company’s oil and gas properties at June 30, 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 June 30, 2014, and December 31, 2013, were:

	June 30,		December 31,
Property	2014		2013

Bear Creek Prospect	$	10,025,359	$	9,957,839
Woodson County, Kansas		6,567,294		—
Lake Hermitage Field		—		3,644,986
Valentine Field		—		1,895,504
Larose Field		—		1,112,275
Bay Batiste Field		—		953,197
Turkey Creek Field		—		782,727
Total	$	16,592,653	$	18,346,528

Net oil and gas properties at June 30, 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		6,666,273		912,803		—			(8,800,203	)		(532,748	)		(1,753,875	)
Total	$	25,937,098	$	10,450,329	$	(3,057,836	)	$	(11,236,738	)	$	(5,500,200	)	$	16,592,653

During the six months ended June 30, 2014 and 2013, we incurred $167,424 and $92,346, respectively, of exploration expense which is included on our consolidated statement of operations.

During the six months ended June 30, 2014, Gulfstar purchased the controlling interest in TNRH, and the Company deconsolidated the assets of the subsidiaries of TNRH, TNR and MGC, from the Company’s balance sheet. The net book value of these properties, $8,229,277, was removed from the Company’s balance sheet effective April 1, 2014, because the Company lost its ability to impose significant influence, and control of operations and assets of TNRH were restricted by the then non-controlling member effective April 1, 2014. The remaining amount of disposals relates to the $570,926 of Turkey Creek Field assets reclassified to held for sale, see below.

On April 10, 2014, the Company acquired a 100% working interest in six developed and producing leases in Woodson County, Kansas, for a cash purchase price of $6,368,106. The purchase price was allocated as follows:

Lease	Support Facilities and Equipment		Purchased Leasehold
Wingrave Pasture	$	25,000	$	3,159,053
John Wingrave		10,000		945,216
Light		15,000		1,895,432
Stockebrand		20,000		107,362
Karmann		13,000		178,043
	$	83,000	$	6,285,106

Table of Contents

Asset retirement cost of $349,604 was established for these properties.

Turkey Creek Field – Garfield and Major Counties, Oklahoma

During the six months ended June 30, 2014, the Company reclassified $570,926 of undeveloped leasehold costs to assets held for sale and impaired $121,112 and $10,000 of undeveloped and developed leasehold costs, respectively, and $84,209 of intangible drilling costs associated with the Thomas Unit #5 well, reducing the Company’s investment in Oklahoma to $0.

In the six months ended June 30, 2013, the Company spent $1,578,272 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 $2,528,783 and $24,804 to dry hole expense in the three and six months ended June 30, 2013, respectively.

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 selected a drilling location for the initial test well and, through June 30, 2014, engaged in 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:

·	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.

During the six months ended June 30, 2014, the Company obtained permits and performed site preparation work for the drilling of the Bear Creek #1 well spending $66,764. Projected total vertical depth of this well is 8,457 feet. Intangible and tangible drilling costs are estimated to total $1,122,804. Intangible and tangible completion costs are estimated to be an additional $2,357,000. Total drilling and completion costs are estimated to be $3,479,804.

Table of Contents

Support Facilities and Equipment

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

		June 30,			December 31,
	Years	2014			2013

Tank batteries	7-12	$	44,000		$	807,580
Production equipment	7		33,000			1,034,599
Production Facilities	7		6,000			108,702
Field offices	20		—			150,000
Crew boats	7		—			172,413
Vehicles			17,748			—
Construction in progress (not depreciated)			—			43,696
Asset retirement cost	7		—			786,828
			100,748			3,103,818
Accumulated depreciation			(3,229	)		(685,920	)
Total support facilities and equipment, net		$	97,519		$	2,417,898

During the six months ended June 30, 2014 Gulfstar purchased the controlling interest in TNRH, and the Company deconsolidated the assets of the subsidiaries comprising TNRH, TNR and MGC, from the Company’s balance sheet, see NOTE 3.

In the six months ended June 30, 2014 and 2013, the Company recognized depreciation expense of $104,457 and $145,345, respectively, on support facilities and equipment.

Office Furniture, Equipment, and Other

		June 30,			December 31,
	Years	2014			2013

Office equipment, computer equipment, purchased software, and leasehold improvements	3	$	220,300		$	251,912
Furniture and fixtures	10		37,570			55,569
			257,873			307,481
Accumulated depreciation			(88,263	)		(64,805	)
Total property and equipment, net		$	169,608		$	242,676

During the six months ended June 30, 2014, Gulfstar purchased the controlling interest in TNRH, and the Company deconsolidated the assets of the subsidiaries comprising TNRH, TNR and MGC, from the Company’s balance sheet, see NOTE 3.

During the six months ended June 30, 2014 and 2013, the Company recognized depreciation expense of $45,204 and $23,115, 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.

Table of Contents

NOTE 7 – DEBT

Credit Facility and Notes Payable

The Company’s notes payable at June 30, 2014 and December 31, 2013 were as follows:

	June 30,			December 31,
	2014			2013

Credit facility	$	8,072,693		$	8,222,693
Notes issued pursuant to private placement of securities		500,000			655,000
Less: debt discount on private placement of notes		—			(87,725	)
Other term notes		43,032			79,582
Notes payable outstanding		8,615,725			8,869,550
Less: Current maturities		(8,615,725	)		(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 June 30, 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 were 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.

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 six months ended June 30, 2014, the Company repaid $150,000 of principal on the credit facility.

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, the Company 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.

Table of Contents

· 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.

The Credit Facility required 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.

On May 30, 2014, the Company entered into the Sixth Amendment to the Loan Agreement with Prosperity Bank by which the Termination Date was extended to September 22, 2014 and Lender consented to the Company’s transfer and novation of its interest in the hedges to TNRH. As a result of the Company’s sale of the controlling interest in TNRH to Gulfstar, TNRH agreed in the Amendment to Unit Purchase Agreement dated April 10, 2014 to assume the hedging contracts between the Company and the counterparty. Prosperity Bank agreed to the Company transferring and novating its interest in its hedges to TNRH in the Sixth Amendment to the Loan Agreement dated July 22, 2011, on May 30, 2014, see NOTE 5.

At inception of the Credit Facility, deferred financing costs of $102,877 were incurred. For the six months ended June 30, 2014 and 2013, $11,281 of amortized deferred financing costs had been recognized as interest expense. At June 30, 2014 and December 31, 2013, $1,880 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 June 30, 2014, it was not in compliance with the percentage of general and administrative expense to revenues for the quarter ended June 30, 2014, calculated at 140.89% although required under the Loan Agreement, as amended, to be less than or equal to 27%. The Company was not in compliance with this covenant for the quarter ended March 31, 2014, as well. The Company’s noncompliance with this covenant for two consecutive quarters constitutes an event of default under the Loan Agreement. Upon an event of default, the entire principal amount of outstanding indebtedness under the Credit Facility, together with all accrued but unpaid interest thereon, shall, at the option of Prosperity Bank, be matured without further notice and become immediately due and payable. The Company has requested a default waiver from Prosperity Bank relating to the Company’s noncompliance with this ratio covenant. As of August 19, 2014, the Company has not received any indication from Prosperity Bank whether the waiver will be granted or denied.

For the six months ended June 30, 2014 and 2013, the Company recognized interest expense of 254,231 and $252,580, respectively, on the Credit Facility.

Table of Contents

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 was 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. Mr. Schlumberger’s note was paid in full during the three months ended June 30, 2014. $962 in interest expense was paid on this Note. $14,645 of debt discount was associated with this Note; and warrants exercisable, as described above, for 46,667 shares were issued.

During the six months ended June 30, 2014, one of the Notes in the amount of $25,000 attained maturity and was paid in full while three Notes totaling $105,000 were paid in full on April 10, 2014, prior to the maturity date of May 30, 2014. $4,821 in interest expense was paid on these retired Notes. On May 16, 2014, the maturity date of the three remaining Notes, including the $100,000 note subscribed by James J. Cerna, Jr., totaling $500,000 were extended from May 30, 2014, to May 30, 2015. As consideration for this extension, the Company reduced the exercise price of the Series D Warrants held by the remaining holders of the Notes to $0.30 per share and issued an additional Series D Warrant (the “Additional Warrants”) to each of the remaining holders. The Additional Warrants were issued for the purchase of up to the number of shares of common stock of the Company equal to 100% of the quotient of the amount of each of the remaining Notes divided by $1.00. The Additional Warrants are exercisable at a purchase price of $0.30 per share for a period of five (5) years. Deferred financing cost of $8,280 resulted from the reduction of the exercise price.

During the six months ended June 30, 2014, the Company recognized $29,070 of interest expense on the face value of the Notes; full amortization of the remaining debt discount resulted in the recognition of $87,726 as interest expense; and $983 of deferred financing costs was amortized to interest expense.

During the six months ended June 30, 2013, the Company recognized interest expense of $15,932 on the face value of the Notes, and amortization of the debt discount resulted in the recognition of $57,465 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.

Table of Contents

NOTE 8 – ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the six months ended June 30, 2014.

	June 30, 2014			December 31, 2013

Beginning asset retirement obligations	$	3,161,810		$	3,507,798
Deconsolidation of TNRH		(3,106,376	)		—
Obligations assumed from acquisition (1)		349,604			65,263
Revaluation of asset retirement obligations (2)		—			(468,519	)
Accretion expense		50,308			172,927
Sale of Young and Archer County properties		—			(99,891	)
Settlement of asset retirement obligations		—			(15,768	)
Ending asset retirement obligations	$	455,346		$	3,161,810

	(1)	2014 - ARO of Woodson County, Kansas, properties acquired on April 10, 2014. 2013- ARO of Archer and Young County, Texas, properties acquired in the Acquisition.
	(2)	ARO of Texas and Louisiana properties.

During the six months ended June 30, 2014, the Company’s ownership status in TNRH changed from controlling to non-controlling, and the Company adopted the cost method of accounting for its investment in TNRH, deconsolidating the financial statements of TNRH from that of the Company; and the Company purchased developed leasehold in Woodson County, Kansas, and assumed the liability to plug and abandon wells from the seller.

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.

NOTE 9 – 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 six months ended June 30, 2014. There were no interest and penalties related to unrecognized tax positions for the six months ended June 30, 2014. The tax years subject to examination by tax jurisdictions in the United States are 2010 through 2014.

In April 2014, the Company sold its controlling interest in TNRH, see NOTE 3, and a gain of $11,105,788 was recognized on the sale. This is the primary reason for the increase in our deferred tax liability from $3,703,553 at December 31, 2013 to $6,622,398 at June 30, 2014.

As of June 30, 2014, the Company has U.S. net operating loss carry forwards of approximately $5.2 million which begin to expire in 2029.

Table of Contents

NOTE 10 – SHARE BASED COMPENSATION

Warrants

The following table summarizes the Company’s warrant activity for the six months ended June 30, 2014:

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

Outstanding at December 31, 2013		7,553,333	$	1.92	3.0 years	$	—
Granted		400,000		0.30	4.9 years	$	—
Exercised		—		—
Cancelled/Expired		—		—
Outstanding at June 30, 2014		7,953,333	$	1.84	4.2 years	$	—

Exercisable at June 30, 2014		7,953,333	$	1.84	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	$	—

During the six months ended June 30, 2014, the exercise price of warrants issued to James J. Cerna, Jr., a member of our board of directors, and two others was reduced from $0.75 to $0.30 in exchange for agreeing to extend the maturity of notes payable to them from May 30, 2014, to May 30, 2015, see NOTE 7. The reduction in the exercise price resulted in $8,280 of additional cost recognized as deferred financing costs of which $983 was recognized as interest expense through June 30, 2014. In addition, 400,000 warrants were issued to two note holders (not including James J. Cerna, Jr.) whose exercise price had been modified in exchange for their agreement to the note extension. The fair value of those warrants was determined through a Black Scholes model to be $76,948, which was charged to deferred financing costs as a cost associated with financing debt of which $9,136 was amortized to interest expense.

Assumptions used in determining the fair values of the additional warrants issued were as follows:

	2014
Weighted average grant date fair value	$	0.20
Discount rate		1.56	%
Expected life (in years)		5.0
Weighted average volatility		191.29	%
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.

Table of Contents

The following table summarizes the Company’s stock option activity for the six months ended June 30, 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)		(45,000	)		0.37	—		—
Outstanding at June 30, 2014		2,757,000			0.41	3.4 years	$	—

Exercisable at June 30, 2014		2,732,200		$	0.41	3.4 years	$	—

(1)

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

Compensation expense related to stock options of $25,297 and $551,448 was recognized for the six months ended June 30, 2014 and 2013, respectively. At June 30, 2014, the Company had $7,568 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.

Restricted Stock

The Company had no restricted stock activity during the six months ended June 30, 2014, and no unamortized compensation expense related to granted restricted stock awards.

During the six months ended June 30, 2013, the Company had 64,800 unvested restricted shares and recognized $21,828 in stock compensation expense.

NOTE 11 – SUBSEQUENT EVENTS

Sale of Undeveloped Leasehold in Major and Garfield Counties, Oklahoma

On July 23, 2014, the Company sold its interest 1,532 net mineral acres in Major and Garfield Counties, Oklahoma, for $150,000 in cash. These interests are reported in the consolidated balance sheets as assets held for sale at their cost of $570,926. The Company recognized a loss of $420,925 in the third quarter on this sale.

On August 1, 2014, the Company granted 75,000 shares of the Company’s restricted common stock with a fair value of $15,000 to a consultant. Shares underlying this grant have not yet been issued.

Table of Contents

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

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

On July 22, 2011, MEI acquired Tchefuncte Natural Resources, LLC (“TNR”) which owns interests in 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%. Gulfstar has not exercised its Tranche C option and we do not expect it to do so.

On April 23, 2014, James J. Cerna, Jr. resigned from the office of President of the Company. Mr. Cerna will continue to serve as a member of the Company’s Board of Directors.

On May 1, 2014, Marceau Schlumberger resigned from the Board of Directors of the Company. Mr. Schlumberger will continue to serve on the Board of Directors of TNRH and will remain actively involved in that enterprise. Mr. Schlumberger is the managing member of Gulfstar Manager, LLC which is the manager of Gulfstar and he owns a 3% interest in Gulfstar.

Table of Contents

The Company’s oil and gas operations are conducted by its wholly owned subsidiaries. MEI is a qualified operator in the State of New York and operates the Java Field. AOP is a qualified operator in Kansas, Wyoming, and Texas. MMC is a qualified operator in the state of Oklahoma and operates our properties in Garfield and Major Counties, Oklahoma.

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 $6,368,106 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 land 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%. Subsequent to closing, a 0.875% overriding royalty interest was assigned to NorthPoint Energy Partners, LLC as part of brokerage fee on the transaction leaving the Company with a net revenue interest of 86.625%.

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.

On May 16, 2014, the Company’s Board of Directors made the following appointments and changes to its management team: Randy Griffin, the Company’s Chief Executive Officer, was named President of the Company; J. Clint Unruh ceased serving as Executive Vice President and was appointed Chief Operating Officer of the Company; and Ray Unruh was appointed Executive Vice President of the Company while retaining his current position as Corporate Secretary.

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:

	·	Lake Hermitage Field, Valentine Field, Larose Field, Bay Batiste Field, and Manila Village Field in Plaquemines and Lafourche Parishes, Louisiana
	·	The Vernon Field and the Winterschied Field, producing oil fields in Woodson County, Kansas;
	·	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.

Table of Contents

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%. 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 60.299% (“Tranche B Funding”). As result of this purchase, Gulfstar gained control of TNRH. Because the Company lost its ability to impose significant influence, and control of the operations and assets of TNRH were restricted by the then non-controlling member as of April 1, 2014, our financial statements for periods beginning April 1, 2014, 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 the cost method of accounting for investments pursuant to 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 non-controlling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. Money from the Tranche B Funding was used to purchase the Kansas properties as discussed below.

On May 16, 2014, and June 15, 2014, the Company sold an additional 1,400 and 2,380 units, respectively, at $564.31 per unit, to Gulfstar for $790,034 and $1,343,058, respectively, for an aggregate of $2,133,092 (“Tranche D”). Net cash received was $2,041,576, and this was accounted for as a reduction of the Company’s investment in TNRH. The Company’s interest in TNRH was reduced to 27.124% while Gulfstar’s interest was increased to 72.876%. The closing of the Tranche D funding will enable the Company to accelerate its efforts to diversify and reallocate the bulk of its asset base to the Mid-Continent and Rocky Mountain regions.

The Louisiana Area is located in Lafourche and Plaquemines Parishes in Louisiana.

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

As of June 30, 2014, the Company owned undeveloped leasehold in Garfield and Major Counties, Oklahoma

In the second quarter of 2014, we made the decision to shift our focus from Oklahoma to our Kansas and Wyoming properties. As a result, we reclassified $570,925 of undeveloped leasehold interest in Garfield and Major Counties, Oklahoma, to assets held for sale and impaired $121,112 of undeveloped leasehold interests, $10,000 of purchased proved leasehold interests on the Thomas Unit #3 and #4 wells, and $84,209 of intangible drilling costs on the Thomas Unit #5 well, for total impairments of $215,321.

On July 23, 2014, the Company sold its interest in 1,532 net mineral acres in Major and Garfield Counties, Oklahoma, for $150,000 in cash. These interests are reported in the consolidated balance sheets as Assets held for sale at their cost of $570,925. We recognized a loss of $420,925 in the third quarter on this sale.

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 50 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 not only confirmed potential in a number of the deep conventional zones but also solid potential in the Niobrara. The Company commended the drilling of its first well in the Project Acreage, the Bear Creek #1 well, in July 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%.

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.

Table of Contents

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 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.

In the second quarter of 2014, the Company obtained permits and began site preparation work for the drilling of the Bear Creek #1 well and spudded the well in July 2014. Projected total vertical depth of this well is 8,457 feet. Intangible and tangible drilling costs are estimated to total $1,122,804. Intangible and tangible completion costs are estimated to be an additional $2,357,000. Total drilling and completion costs are estimated to be $3,479,804. The company commenced drilling of the Bear Creek #1 well in July 2014.

Kansas Area

On April 10, 2014, we purchased interests in six oil and gas leases covering approximately 1,040 (901 net) acres in Woodson County, Kansas. We paid the seller a net purchase price of $6,368,106 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%. Subsequent to closing, a 0.875% overriding royalty interest was assigned to NorthPoint Energy Partners, LLC as part of brokerage fee on the transaction leaving the Company with a net revenue interest of 86.625%.

There are currently 125 shallow wells on the Kansas leaseholds, some of which are shut in pending maintenance or recompletion work, while a number of others are used as pressure maintenance water injection wells. Current production is approximately 70 barrels per day. We believe that the existing shallow well field provides stable, low decline, long life production with low operating costs and the potential for the drilling of over 150 additional wells with a very low risk of dry holes. In addition, all depths are held by production, and there is additional potential in the Mississippian Limestone as well as in the Viola Limestone, both of which are at depths of less than 2,500 feet. There is also water-flood potential in the currently producing zone.

Evaluation of these assets is underway, and the Company expects to formulate and implement a development plan for the upgrade and enhancement of the existing wells as well as for drilling of additional wells over the next few months.

New York Area

The New York Area is located in Wyoming County, 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 2,852 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.

Table of Contents

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.

Adjusted EBITDA as a Non-GAAP Performance Measure

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

The following is a reconciliation of our net income in accordance with GAAP to our Adjusted EBITDA for the three and six-month periods ending June 30, 2014 and 2013:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013

Net income (loss)	$	6,298,214		$	(490,517	)	$	5,779,459		$	(1,546,086	)

Adjustments:
Interest (income) expense, net		176,413			198,123			392,854			392,762
Income tax (benefit) expense		4,031,635			(411,658	)		3,716,932			(1,287,929	)
Dry hole expense		—			24,804			—			2,609,866
Depreciation, depletion, accretion and impairment		312,938			271,361			733,017			1,031,129
Gain on settlement of asset retirement obligation		—			—			—			(1,328	)
Bargain purchase gain		—			—						(1,455,879	)
Unrealized (gain) loss on change in commodity derivative instruments		—			(586,527	)		167,673			(51,828	)
Loss on modification of offering terms		—			65,749			—			65,749
Gain on sale of controlling interest in TNRH		(11,105,788	)		—			(11,105,788	)		—
Share-based compensation		7,619			538,279			25,297			594,932
Adjusted EBITDA	$	(278,969	)	$	(390,386	)	$	(290,556)		$	351,388

Table of Contents

Results of Operations

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Revenue

	Three Months Ended
	June 30,							Percentage
	2014		2013		Difference			Change

Revenues
Oil	$	520,933	$	2,574,081	$	(2,053,148	)		-79.8	%
Natural gas		10,601		467,105		(456,504	)		-97.7	%
Natural gas liquids		—		38,475		(38,475	)		-100.0	%
Total	$	531,534	$	3,079,661	$	(2,548,127	)		-82.7	%

Sales volumes
Oil (Bbls)		5,402		23,984		(18,582	)		-77.5	%
Natural gas (MCF)		1,693		113,883		(112,190	)		-98.5	%
Natural gas liquids (Bbl)		—		939		(939	)		-100.0	%
Total BOE		5,684		43,903		(38,219	)		-87.1	%
Total BOE/day		63		488

Average prices
Oil (per Bbl)	$	96.43	$	107.32	$	(10.89	)		-10.1	%
Natural gas (per MCF)		6.26		4.10		2.16			52.7	%
Natural gas liquids (per Bbl)		—		40.97		(40.97	)		-100.0	%
Total per BOE	$	93.51	$	70.15	$	23.36			33.3	%

Revenues from commodity sales decreased during the three months ended June 30, 2014, over the three months ended June 30, 2013, as a result of the sale of our controlling interest in TNRH which held our Louisiana properties, net of revenues from commodity sales from the Kansas properties we purchased in the second quarter of 2014.

In addition to revenues from commodity sales, during the three months ended June 30, 2014, we had $11,711 of revenue from lease fuel and gas transportation fees. During the three months ended June 30, 2013, we had $25,447 of the same type of income.

Operating expenses

Operating expenses for the three months ended June 30, 2014 and 2013 are set forth in the table below:

	Three Months Ended
	June 30,							Percentage
	2014		2013		Difference			Change

Costs and Expenses
Lease operating expense (1)	$	56,662	$	2,040,485	$	(1,983,823	)		-97.2	%
Production and ad valorem taxes (2)		5,380		373,930		(368,550	)		-98.6	%
Exploration expense (3)		7,895		92,346		(84,451	)		-91.5	%
Depletion, depreciation, amortization, and impairment expense (4)		312,938		296,165		16,773			-5.7	%
General and administrative expense (5)		765,398		1,579,682		(814,284	)		-51.5	%
Total operating expenses	$	1,148,273	$	4,382,608	$	(3,234,335	)		-73.8	%

(1)	Decreased LOE due to sale of controlling interest in Louisiana properties.
(2)	Decreased sales volumes due to sale of controlling interest in Louisiana properties.
(3)	Decreased exploration expense due to sale of controlling interest in Louisiana properties.
(4)	$215,321 charge to impairment expense on Oklahoma properties.
(5)	Decreased salaries, benefits, office rental, and other general and administrative expenses due to sale of controlling interest in Louisiana properties and decreased second quarter stock compensation expense from 2013 net of increased acquisition expenses associated with TNRH Tranche B and Tranche D funding and acquisition of Kansas properties.

Table of Contents

Operating expenses expressed in BOE for the three months ended June 30, 2014 and 2013 are set forth in the table below:

	Three Months Ended
	June 30,							Percentage
	2014		2013		Difference			Change

Costs and Expenses
Lease operating expense	$	9.97	$	46.48	$	(36.51	)		-78.6	%
Production and ad valorem taxes		0.95		8.52		(7.57	)		-88.9	%
Exploration expense		1.39		2.10		(0.71	)		-34.0	%
Depletion, depreciation, amortization, and impairment expense		55.06		6.75		48.31			716.1	%
General and administrative expense		134.66		35.98		98.68			274.2	%
Total operating expenses	$	202.02	$	99.82	$	102.19			102.4	%

Operating loss. As a result of the above described revenues and expenses, we incurred an operating loss of $605,028 in the second quarter of 2014 as compared to an operating loss of 1,277,500 in the second quarter of 2013.

Interest expense. Interest expense decreased to $176,413 for the three months ended June 30, 2014, from $199,215 for the three months ended June 30, 2013. The decrease was primarily attributable to the reduction of the principal balance on our Credit Facility.

Unrealized loss on changes in derivative value. The unrealized loss on change in derivatives – commodity contracts for the three months ended June 30, 2014 was $0, and the unrealized gain on change in derivatives for the three months ended June 30, 2013 was $586,527. Unrealized gains and 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. During the three months ended June 30, 2014, we transferred and novated our interest in the commodity hedging contracts with our counterparty to TNRH as the owner of the controlling interest in TNR, the production from which was the subject of the hedge. As a result we incurred no gain or loss on the change in the fair value of the net derivative assets and liabilities.

Realized gain (loss) on changes in derivatives – commodity contracts. Cash settlements which we paid from hedging our sales of oil and gas production were $0 in the second quarter of 2014 as compared to $35,059 which we received in the second 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. During the three months ended June 30, 2014, we transferred and novated our interest in the commodity hedging contracts with our counterparty to TNRH as the owner of the controlling interest in TNR, the production from which was the subject of the hedge. As a result we incurred no gain or loss on the change in the fair value of the settlement of hedged positions under the derivatives contracts.

Gain on sale of controlling interest in TNRH. During the three months ended June 30, 2014, we sold our controlling interest in TNRH and recognized a gain of $11,105,788.

Income tax expense (benefit). State and federal income tax expense for the three months ended June 30, 2014 was $4,031,635 compared to an income tax benefit of $411,658 for the three months ended June 30, 2013. The increase in the income tax expense is primarily due to the gain on our sale of the controlling interest in TNRH.

Net income (loss). Due to the reasons set forth above, our net income for the three months ended June 30, 2014 was $6,298,214 ($0.11 per basic and diluted common share). Our net loss for the three months ended June 30, 2013 was $490,517 ($0.01 per basic and diluted common share).

Table of Contents

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Revenue

	Six Months Ended
	June 30,							Percentage
	2014		2013		Difference			Change

Revenues
Oil	$	3,158,307	$	5,386,213	$	(2,227,906	)		-41.4	%
Natural gas		486,959		983,264		(496,305	)		-50.5	%
Natural gas liquids		23,594		102,227		(78,633	)		-76.9	%
Total	$	3,668,860	$	6,471,704	$	(2,802,844	)		-43.3	%

Sales volumes
Oil (Bbls)		31,019		49,513		(18,494	)		-37.4	%
Natural gas (MCF)		91,792		347,900		(256,108	)		-73.6	%
Natural gas liquids (Bbl)		606		2,484		(1,878	)		-75.6	%
Total BOE		46,923		109,981		(63,058	)		-57.3	%
Total BOE/day		261		611

Average prices
Oil (per Bbl)	$	101.82	$	108.78	$	(6.96	)		-6.4	%
Natural gas (per MCF)		5.31		2.83		2.48			87.6	%
Natural gas liquids (per Bbl)		38.93		41.15		(2.22	)		-5.4	%
Total per BOE	$	78.19	$	58.84	$	19.35			32.9	%

Revenues from commodity sales decreased during the six months ended June 30, 2014, over the six months ended June 30, 2013, as a result of the sale of our controlling interest in TNRH which held our Louisiana properties, net of revenues from commodity sales from the Kansas properties we purchased in the second quarter of 2014.

In addition to revenues from commodity sales, during the six months ended June 30, 2014, we had $48,385 of revenue from lease fuel, gas transportation, and production handling fees. During the six months ended June 30, 2013, we had $72,242 of the same type of income.

Table of Contents

Operating expenses

Operating expenses for the six months ended June 30, 2014 and 2013 are set forth in the table below:

	Six Months Ended
	June 30,								Percentage
	2014		2013			Difference			Change

Costs and Expenses
Lease operating expense (1)	$	1,535,956	$	3,588,157		$	(2,052,201	)		-57.2	%
Production and ad valorem taxes (2)		363,236		679,453			(316,217	)		-46.5	%
Environmental remediation expense (3)		252,135		—			252,135			N/A
Exploration expense (4)		167,424		92,346			75,078			81.3	%
Dry hole expense (5)		—		2,609,866			(2,609,866	)		-100.0	%
Depletion, depreciation, amortization, and impairment expense (6)		733,017		1,031,129			(298,112	)		-28.9	%
(Gain) loss on settlement of asset retirement obligation (7)		—		(1,328	)		1,328			100.0.	%
General and administrative expense (8)		1,801,259		2,602,862			(801,603	)		-30.8	%
Total operating expenses	$	4,853,027	$	10,602,485		$	(5,749,458	)		-54.2	%

(1)	Decreased LOE on nonoperated properties in the first quarter; effect of our sale of the controlling interest in TNRH in the second.
(2)	Decreased sales volumes attributable in the second quarter to our sale of the controlling interest in TNRH.
(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 our sale of the controlling interest in TNRH net of second quarter impairment of Oklahoma properties.
(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 and lower salaries, benefits, office rental, and other general and administrative expenses as a result of our sale of the controlling interest in TNRH in the second quarter.

Operating expenses expressed in BOE for the six months ended June 30, 2014 and 2013 are set forth in the table below:

	Six Months Ended
	June 30,								Percentage
	2014		2013			Difference			Change

Costs and Expenses
Lease operating expense	$	32.73	$	32.63		$	0.11			0.3	%
Production and ad valorem taxes		7.74		6.18			1.56			25.3	%
Environmental remediation expense		5.37		—			5.37			N/A
Exploration expense		3.57		0.84			2.73			324.9	%
Dry hole expense		—		23.73			(23.73	)		-100.0	%
Depletion, depreciation, amortization, and impairment expense		15.62		9.38			6.25			66.6	%
(Gain) loss on settlement of asset retirement obligation		—		(0.01	)		0.01			100.0	%
General and administrative expense		38.39		23.67			14.72			62.2	%
Total operating expenses	$	103.43	$	96.40		$	7.02			7.3	%

Operating loss. As a result of the above described revenues and expenses, we incurred operating losses of $1,135,782 and $4,058,539 during the six months ended June 30, 2014 and 2013, respectively.

Interest expense. Interest expense decreased to $390,005 for the six months ended June 30, 2014, from $397,230 for the six months ended June 30, 2013. The decrease was primarily attributable to the reduction of the principal balance on our Credit Facility.

Table of Contents

Unrealized loss on changes in derivative value. The unrealized loss on change in derivatives – commodity contracts for the six months ended June 30, 2014 was $167,673 and an unrealized gain on change in derivatives for the six months ended June 30, 2013 of $51,828, respectively. Unrealized gains and 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. During the second quarter of 2014, we transferred and novated our interest in the commodity hedging contracts with our counterparty to TNRH as the owner of the controlling interest in TNR, the production from which was the subject of the hedge. As a result we incurred no gain or loss on the change in the fair value of the net derivative assets and liabilities.

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 during the six months ended June 30, 2014, as compared to $150,737 during the six months ended June 30, 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. During the second quarter of 2014, we transferred and novated our interest in the commodity hedging contracts with our counterparty to TNRH as the owner of the controlling interest in TNR, the production from which was the subject of the hedge.

Gain on sale of controlling interest in TNRH. During the second quarter of 2014, we sold our controlling interest in TNRH and recognized a gain of $11,105,788.

Income tax expense (benefit). State and federal income tax expense for the six months ended June 30, 2014 was $3,716,932 compared to an income tax benefit of $1,287,929 during the six months ended June 30, 2013. The increase in the income tax expense during the six months ended June 30, 2014 is primarily due to the gain on our sale of the controlling interest in TNRH.

Net income. Due to the reasons set forth above, our net income for the six months ended June 30, 2014 was $5,779,459 ($0.10 per basic and diluted common share). Our net loss for the six months ended June 30, 2013 was $1,546,086 ($0.03 per basic and diluted common share).

Liquidity and Capital Resources

Overview

As of June 30, 2014, we had a working capital deficit of $5,201,420. 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 $8,615,725 (gross of discount)
	·	Decreased revenues from oil and gas sales.
	·	The purchase of our Kansas properties for cash.

A reorganization of our Credit Facility took place in April 2014 as discussed elsewhere in this report. As a result, a short extension of the Credit Facility took place as part of the 6th Amendment to Loan Agreement dated May 30, 2014 to allow time for the mid-year reserve report to be completed to allow for a longer term extension or refinance of the facility in the third quarter. In addition, Tranche D of the Gulfstar transaction was funded in the second quarter. Gulfstar has not exercised its Tranche C option, and we do not expect it to do so. The bulk of the Tranche D funds are being used for the drilling of the Bear Creek #1 well, the initial test well on the Company’s Anadarko farmout acreage in Carbon County, Wyoming.

Cash and Accounts Receivable

At June 30, 2014, we had cash and cash equivalents of $2,380,933, compared to $7,095,972 at December 31, 2013. Cash decreased by $4,715,039 due to transaction expenses associated with the Tranche B and Tranche D funding by Gulfstar and the acquisition of our Kansas properties net of cash received from the Tranche B and Tranche D fundings.

Liabilities

Accounts payable, accrued expenses, and other current liabilities decreased by $1,782,228 to $453,894 at June 30, 2014, from $2,236,122 at December 31, 2013, primarily due to the removal of $1,997,022 of accounts payable and accrued expenses from our balance sheet as a result of our sale of the controlling interest in TNRH net of an increase of $123,334 in other current liabilities.

As of June 30, 2014, the outstanding balance of principal on debt, net of discount, was $8,615,725, a net decrease of $253,825 from the outstanding balance of $8,869,550, as of December 31, 2013. The decrease was due to principal reduction payments on the Credit Facility, payment in full of two premium financed insurance notes, net of the addition of one premium financed insurance note, and the repayment of four notes associated with the 2013 private placement of debt which matured during the quarter.

Table of Contents

Cash Flows

For the six months ended June 30, 2014 and 2013, the net cash used in operating activities was $650,475 and $706,571 respectively, a decrease in cash used of $56,096. This is attributable to a 2014 increase of $7,221,800 in net income primarily due to the gain we realized on our sale of the controlling interest in TNRH, a 2014 decrease of $298,112 in depletion, depreciation, and amortization expense net of a 2014 impairment item, the elimination of the 2013 add back of dry hole expense totaling $2,609,886, the 2014 increase in deferred income taxes of $5,004,861 resulting mostly from the tax effect of the gain we realized on our sale of the controlling interest in TNRH, a 2014 decrease in stock compensation expense of $559,635, a 2014 increase of interest expense of $40,380 associated with amortization of debt discount and deferred financing costs, 2014 realized and unrealized gains on changes in fair values of settled and unsettled commodity derivatives of $535,749, a 2013 bargain purchase gain and loss on offering modification that did not occur in 2014 totaling $1,455,879 and $65,749, respectively, the 2014 gain on sale of controlling interest in TNRH of $11,105,788, and a $445,249 increase in cash provided by operating assets and liabilities.

For the six months ended June 30, 2014 and 2013, net cash used in investing activities was $3,654,338 and $2,370,929, respectively, an increase in cash used of $1,283,409. This is attributable to increased spending on acquisition of oil and gas properties and support facilities and equipment, net of cash received from our sale of the controlling interest in TNRH.

For the six months ended June 30, 2014 and 2013, net cash used in financing activities was $410,226 and $503,424, respectively, a decrease in cash used of $93,198. This was primarily because we made greater reductions of principal on our credit facility in 2014 than in the same period of 2013.

Credit Facility Default

The Credit Facility contains covenants with which we must maintain compliance, among which are certain ratios. We determined that, at June 30, 2014, we were not in compliance with the percentage of general and administrative expense to revenues for the quarter ended June 30, 2014, calculated at 140.89% although required under the Loan Agreement, as amended, to be less than or equal to 27%. We were not in compliance with this covenant for the quarter ended March 31, 2014, as well. Our noncompliance with this covenant for two consecutive quarters constitutes an event of default under the Loan Agreement. Upon an event of default, the entire principal amount of outstanding indebtedness under the Credit Facility, together with all accrued but unpaid interest thereon, will, at the option of Prosperity Bank, be matured without further notice and become immediately due and payable. We have requested a default waiver from Prosperity Bank relating to our noncompliance with this ratio covenant. As of August 19, 2014, we have not received any indication from Prosperity Bank whether the waiver will be granted or denied.

If our request for a waiver of the Credit Facility default is not granted, Prosperity Bank will have the right to demand immediate payment of the outstanding indebtedness under the Credit Facility, together with all accrued but unpaid interest thereon. If Prosperity Bank makes this demand, we may not be able to make the required payment and our ability to fund our operations and obligations, as well as our business, financial results and financial condition, could be adversely affected.

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.”

Table of Contents

Item 4. Controls and Procedures

a) Evaluation of disclosure controls and procedures.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of June 30, 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 June 30, 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:

As of June 30, 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 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.

Table of Contents

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

We have defaulted on a covenant obligation under our Credit Facility and, as a result, our operations may be interrupted and our business and financial results could be adversely affected.

In July 2011, we entered into a $25 million senior secured revolving line of credit (the “Credit Facility") pursuant to a certain loan agreement, as amended to date (the “Loan Agreement”), with F&M Bank and Trust Company (“F&M Bank”), now with Prosperity Bank, successor to F&M Bank by way of a merger. We are not in compliance with a covenant of the Loan Agreement and, as a result, we are in default under the Loan Agreement and the Credit Facility. Because of this default, Prosperity Bank has the option to require immediate repayment of the entire principal amount of outstanding indebtedness under the Credit Facility, together with all accrued but unpaid interest thereon. We have requested a waiver of these default provisions from Prosperity Bank.

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

As previously reported, on May 1, 2013, the Company entered into a Securities Purchase Agreement (the “SPA”) with certain investors (the “Purchasers”) for the purchase of up to $4,000,000 worth of Series A Senior Unsecured 9.625% Notes (the “Series A Notes”) with a maturity date of May 30, 2014 and Series D Common Stock Purchase Warrants (the “Series D Warrants”) with an exercise price of $0.75 per share. On May 16, 2014, the Company’s Board of Directors approved an amendment to the SPA (the “Amendment”), whereby the maturity date of the Series A Notes was extended to May 30, 2015.

On May 16, 2014, the maturity date of the three remaining Series A Notes, including the $100,000 note subscribed by James J. Cerna, Jr., totaling $500,000 were extended from May 30, 2014, to May 30, 2015. As consideration for this extension, the Company reduced the exercise price of the Series D Warrants held by the remaining holders of the Series A Notes to $0.30 per share and issued an additional Series D Warrant (the “Additional Warrants”) to each of the remaining Purchasers. The Additional Warrants were issued for the purchase of up to the number of shares of common stock of the Company equal to 100% of the quotient of the amount of each of the remaining Series A Notes divided by $1.00. The Additional Warrants are exercisable at a purchase price of $0.30 per share for a period of five (5) years.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Table of Contents

Item 6. Exhibits

Exhibit No.		Description
10.1		Amendment dated as of April 10, 2014, to Unit Purchase Agreement dated December 20, 2013, by and among TNR Holdings LLC, Mesa Energy, Inc., Armada Oil, Inc., and Gulfstar Resources LLC (included as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2014 and incorporated herein by reference)
10.2		Amendment dated as of April 10, 2014, to Unit Purchase Agreement dated December 20, 2013, by and among TNR Holdings LLC, Mesa Energy, Inc., Armada Oil, Inc., and Gulfstar Resources LLC (included as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2014 and incorporated herein by reference)
10.3		Amended and Restated Transition Services Agreement dated as of April 10, 2014, between Mesa Energy, Inc., and TNR Holdings LLC (included as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2014 and incorporated herein by reference)
10.4		Fifth Amendment dated April 10, 2014, to Loan Agreement dated July 22, 2011, originally among Mesa Energy, Inc., Mesa Energy Holdings, Inc., Tchefuncte Natural Resources, LLC, Mesa Gulf Coast, LLC, and Prosperity Bank, successor by merger to The F&M Bank & Trust Company, as previously amended (included as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2014 and incorporated herein by reference)
10.5		First Amendment to Mortgage, Collateral Assignment, Security Agreement and Financing Statement, dated July 22, 2011 by TNR Natural Resources, LLC for the benefit of Prosperity Bank, successor by merger to The F&M Bank & Trust Company (included as Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2014 and incorporated herein by reference)
10.6		Mortgage and Security Agreement dated April 10, 2014, by Armada Midcontinent, LLC, for the benefit of Prosperity Bank, successor by merger to The F&M Bank & Trust Company (included as Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2014 and incorporated herein by reference)
10.7		Unlimited Guaranty dated April 10, 2014 by Armada Midcontinent, LLC, for the benefit of Prosperity Bank, successor by merger to The F&M Bank & Trust Company (included as Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2014 and incorporated herein by reference)
10.8		Unit Purchase and Redemption Agreement, dated May 16, 2014 (included as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 22, 2014 and incorporated herein by reference)
10.9		Amendment to Amended and Restated Limited Liability Company Agreement, dated May 16, 2014 (included as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 22, 2014 and incorporated herein by reference)
10.10		Form of Amendment No. 1 to Securities Purchase Agreement (included as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 22, 2014 and incorporated herein by reference)
10.11		Form of Amendment to 9.625% Senior Unsecured Promissory Note (included as Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 22, 2014 and incorporated herein by reference)
10.12		Form of Amendment to Series D Common Stock Purchase Warrant (included as Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 22, 2014 and incorporated herein by reference)
10.13		Form of Series D Warrant (included as Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 20, 2013 and incorporated herein by reference)
31.01*		Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02*		Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01**		Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.02**		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101INS*		XBRL Instance Document***
101SCH*		XBRL Schema Document***
101CAL*		XBRL Calculation Linkbase Document***
101LAB*		XBRL Labels Linkbase Document***
101PRE*		XBRL Presentation Linkbase Document***
101DEF*		XBRL Definition Linkbase Document***

*		Filed herewith.

**		This certification is being furnished and shall not be deemed “filed” with the SEC for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except if and to the extent that the Registrant specifically incorporates it by reference.

***		This XBRL exhibit is being furnished and shall not be deemed “filed” with the SEC for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that the Registrant specifically incorporates it by reference.

Table of Contents

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: August 19, 2014	By:	/s/ RANDY M. GRIFFIN
		Randy M. Griffin
		Chief Executive Officer (Principal Executive Officer)


Date: August 19, 2014	By:	/s/ RACHEL L. DILLARD
		Rachel L. Dillard
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. junior Avg

Armada Oil (AOILQ) Inactive 10-Q2014 Q2 Quarterly report

Content analysis