armadaoil10q033115.htm

10-Q 1 armadaoil10q033115.htm 10-Q armadaoil10q033115.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended March 31, 2015

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

For the Transition Period from _________ to _________

Commission file number: 000-55128

ARMADA OIL, INC.

(Exact name of registrant as specified in its charter)

Nevada		98-0195748
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5220 Spring Valley Road, Suite 615

Dallas, Texas 75254

(Address of principal executive offices) (zip code)

(972) 490-9595

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company þ

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

As of May 14, 2015, there were 57,105,473 shares of the registrant’s common stock outstanding.

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ARMADA OIL, INC.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION

	Item 1. Consolidated Interim Financial Statements (Unaudited)	3

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	27

	Item 4. Controls and Procedures	27

PART II. OTHER INFORMATION

	Item 1. Legal Proceedings	28

	Item 1A. Risk Factors	28

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

	Item 3. Defaults Upon Senior Securities	28

	Item 4. Mine Safety Disclosures	28

	Item 5. Other Information	28

	Item 6. Exhibits	29

	Signatures	30

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PART I – FINANCIAL INFORMATION

Item 1. Interim Consolidated Financial Statements

ARMADA OIL, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31, 2015			December 31, 2014
ASSETS
Current assets
Cash and cash equivalents	$	72,764		$	406,306
Accounts receivable – oil and gas		55,660			84,129
Accounts receivable – other		101,064			100,339
Deferred financing costs, net – current		25,288			33,732
Prepaid expenses		94,818			61,345
TOTAL CURRENT ASSETS		349,594			685,851

Oil and gas properties, successful efforts accounting:
Properties subject to depletion, net		6,295,849			6,335,092
Properties not subject to depletion		13,938,870			13,927,669
Support facilities and equipment, net		92,746			96,109
Land		38,345			38,345
Net oil and gas properties		20,365,810			20,397,215

Property and equipment, net		103,407			125,476
Deposit on asset retirement obligations		40,000			40,000
Other assets		75,098			75,098

TOTAL ASSETS	$	20,933,909		$	21,323,640

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable – trade	$	2,196,950		$	2,068,395
Revenue payable		4,855			3,107
Accrued expenses		440,492			451,902
Accrued expenses – related parties		52			52
Stock payable		25,898			43,065
Notes payable		4,019,701			4,000,313
Notes payable – related parties		200,000			200,000
Other current liabilities		66,669			66,669
TOTAL CURRENT LIABILITIES		6,954,617			6,833,503

Asset retirement obligations		468,156			463,814
TOTAL LIABILITIES		7,422,773			7,297,317

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, 56,605,473 and 56,105,473 shares issued and outstanding, respectively		56,605			56,105
Additional paid-in capital		16,429,013			16,356,838
Accumulated deficit		(2,974,482	)		(2,386,620	)
TOTAL STOCKHOLDERS’ EQUITY		13,511,136			14,026,323

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	20,933,909		$	21,323,640

See accompanying notes to unaudited consolidated financial statements.

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ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended March 31,
	2015			2014

Revenues	$	168,327		$	3,174,000

Operating expenses:
Lease operating expense		142,030			1,837,150
Environmental remediation expense		—			252,135
Exploration expense		—			159,529
Depletion, depreciation, amortization, accretion and impairment expense		69,017			420,079
General and administrative expense		426,251			1,035,859
Total operating expense		637,298			3,704,752

Loss from operations		(468,971	)		(530,752	)

Other income (expense):
Interest income		—			151
Interest expense		(119,713	)		(216,592	)
Realized loss on commodity contracts		—			(165,511	)
Loss on change in derivative value – commodity contracts		—			(167,673	)
Other income		822			143,176
Total other expense		(118,891	)		(406,449	)

Loss before income taxes		(587,862	)		(937,201	)
Income tax benefit		—			314,703
Net loss		(587,862	)		(622,498	)
Net loss attributable to noncontrolling interest		—			(103,745	)
Net loss attributable to Armada Oil, Inc.	$	(587,862	)	$	(518,753	)

Net loss per common share:
Basic	$	(0.01	)	$	(0.01	)
Diluted	$	(0.01	)	$	(0.01	)

Weighted average number of common shares outstanding:
Basic		56,488,806			56,030,473
Diluted		56,488,806			56,030,473

See accompanying notes to these unaudited consolidated financial statements.

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ARMADA OIL, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

For the Three Months Ended March 31, 2015

	Common Stock				Additional
					Paid-In		Accumulated
	Shares		Par		Capital		Deficit			Total

Balances at December 31, 2014		56,105,473	$	56,105	$	16,356,838	$	(2,386,620	)	$	14,026,323

Share-based compensation		500,000		500		72,175		—			72,675

Net loss		—		—		—		(587,862	)		(587,862	)

Balances at March 31, 2015		56,605,473	$	56,605	$	16,429,013	$	(2,974,482	)	$	13,511,136

See accompanying notes to these unaudited consolidated financial statements.

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ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three Months Ended March 31,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(587,862	)	$	(622,498	)

Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion, amortization, accretion and impairment expense		69,017			420,079
Deferred income tax benefit expense		—			(314,703	)
Share-based compensation		55,508			17,678
Amortization of debt discount charged to interest expense		—			57,333
Amortization of deferred financing costs		21,126			5,641
Realized loss on derivative commodity contracts		—			165,511
Loss on change in derivative value – commodity contracts		—			167,673
Changes in operating assets and liabilities:
Accounts receivable – oil and gas		28,469			(183,712	)
Accounts receivable – other		(725	)		(22,216	)
Prepaid expenses		5,641			(29,096	)
Accounts payable		117,354			(247,327	)
Accrued expenses		(11,410	)		84,031
Revenue payable		1,748			(87,455	)
CASH USED IN OPERATING ACTIVITIES		(301,134	)		(589,061	)

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for development of oil and gas properties		—			(759,689	)
Cash paid for support facilities and equipment		—			(243,965	)
Cash paid for settlement of derivative commodity contracts		—			(165,511	)
CASH USED IN INVESTING ACTIVITIES		—			(1,169,165	)

CASH FLOWS FROM FINANCING ACTIVITIES
Payment of deferred financing cost		(12,682	)		—
Principal payments on notes payable		(19,726	)		(228,337	)
Installment payments on financed liabilities		—			(10,000	)
CASH USED IN FINANCING ACTIVITIES		(32,408	)		(238,337	)

NET CHANGE IN CASH		(333,542	)		(1,996,563	)
CASH AT BEGINNING OF PERIOD		406,306			7,095,972
CASH AT END OF PERIOD	$	72,764		$	5,099,409

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest	$	62,114		$	156,033
Cash paid for income taxes	$	—		$	—

NON-CASH INVESTING AND FINANCING TRANSACTIONS
Financed prepaid assets	$	39,114		$	37,965
Change in accrued oil and gas development costs	$	11,201		$	116,170
Common stock issued in satisfaction of stock payable	$	8,602		$	—

See accompanying notes to these unaudited consolidated financial statements.

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ARMADA OIL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1 – ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Organization

Armada Oil, Inc. (the “Company”) 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 (“AMC”), formerly known as MMC Resources, LLC. Consolidated statements of operations and cash flows include those of the Company, AOG, AOP, MEI, MMC, and AMC for the three months ended March 31, 2015. For the three months ended March 31, 2014, the statements of operations and cash flows also include the accounts of TNR Holdings, LLC (“TNRH”), which was deconsolidated on April 1, 2014, and its wholly owned subsidiaries, Tchefuncte Natural Resources, LLC (“TNR”) and Mesa Gulf Coast, LLC (“MGC”).

The Company’s oil and gas operations are conducted by its wholly owned subsidiaries. MMC is a qualified operator in the state of 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 2014, as reported in the Form 10-K, have been omitted.

Principles of Consolidation

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

Use of Estimates

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

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.

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Loss Per Common Share

The Company’s loss per common share is 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 and convertible debt.

	For the Three Months Ended March 31,
	2015			2014
Numerator:
Net loss	$	(587,862	)	$	(622,498	)
Less: Net loss attributable to noncontrolling interest		—			(103,745	)
Net loss available to stockholders		(587,862	)		(518,753	)
Basic net loss allocable to participating securities (1)		—			—
Basic net loss available to stockholders	$	(587,862	)	$	(518,753	)

Denominator:
Weighted average number of common shares outstanding – Basic		56,488,806			56,030,473
Effect of dilutive securities (2) :		—			—
Options and warrants		—			—
Weighted average number of common shares outstanding – Diluted		56,488,806			56,030,473

Net loss per common share:
Basic	$	(0.01	)	$	(0.01	)
Diluted	$	(0.01	)	$	(0.01	)

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

(2) For the three months ended March 31, 2015, stock options and warrants representing 3,563,000 and 7,953,333 shares, respectively were antidilutive and, therefore, excluded from the diluted share calculation. For the three months ended March 31, 2014, stock options and warrants representing 2,775,000 and 7,553,333 shares, respectively, were antidilutive and, therefore, excluded from the diluted share calculation.

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 date the consolidated financial statements were issued for subsequent event disclosure consideration.

NOTE 2 – GOING CONCERN

The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America which contemplate continuation of the Company as a going concern. The Company has incurred recurring losses from operations through March 31, 2015, has a working capital deficit at March 31, 2015 of $6,605,023 and has limited sources of revenue. These conditions have raised substantial doubt as to the Company’s ability to continue as a going concern. These financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

To address these matters, management has been seeking additional oil and gas properties to provide a source of recurring revenues and the necessary financing to complete an acquisition. Although the Company is pursuing additional financing to acquire producing oil and gas properties, there can be no assurance that the Company will be able to secure financing when needed or to obtain such financing on terms satisfactory to the Company.

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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 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 starting from April 1, 2014, no longer consolidated TNRH and its wholly owned subsidiaries, TNR and MGC, but accounted for our ownership interest in TNRH as a cost method investment in accordance with ASC Topic 810, Consolidation (“ASC 810”). The financial statements of TNRH and its wholly owned subsidiaries, TNR and MGC, were deconsolidated from the consolidated financial statements of the Company 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 rights of the then non-controlling member as of April 1, 2014, see NOTE 1. Net funds received by the Company upon deconsolidation of TNRH were $1,790,580 (Tranche B proceeds noted above less cash balances held by TNRH as of March 31, 2014). 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 TNRH financial statements, the consolidated balance sheets as of March 31, 2015 and December 31, 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 for the three months ended March 31, 2015 contains the results of operations of the Company and for the three months ended March 31, 2014, the consolidated statement of operations also includes those of TNRH and its subsidiaries.

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

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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 $2,042,856. The Company’s interest in TNRH was reduced to 27.124%.

A gain of $10,170,656 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)		9,830,895
Carrying amount of noncontrolling interest in former subsidiary on the date the subsidiary was deconsolidated		5,862,443
Subtotal		22,112,911
Less carrying amount of TNRH’s net assets		(12,170,553	)
Plus intercompany balances		228,298
Gain on deconsolidation of TNRH	$	10,170,656

After the Tranche D funding, the Company had 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	$	9,830,895
Less Tranche D net proceeds from sale units in TNRH		(2,042,856	)
Cost method investment as of June 30, 2014	$	7,788,039

During the third quarter of 2014, the Company sold its remaining interest in TNRH on November 26, 2014. The Company received $5,012,502 in cash for its remaining cost method investment in TNRH comprising 8,152 Member Units at $614.88 per Unit. The difference between the carrying value of the cost method investment and cash received was applied to the gain on deconsolidation of TNRH as follows:

Sale of cost method investment
Gain on deconsolidation of TNRH after Tranche B funding	$	10,170,656
Cash received for remaining investment in TNRH		5,012,502
Cost method investment for interest in TNRH		(7,788,039	)
Gain on sale of TNRH interest	$	7,395,119

Kansas Acquisition

During the second quarter of 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 – COMMODITY DERIVATIVE INSTRUMENTS

During the three months ended March 31, 2015, the company utilized no commodity derivative instruments.

During the three months ended March 31, 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.

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For the three months ended March 31, 2015 and 2014 the Company recorded unrealized loss of $0 and $167,673, respectively, on the statements of operations. The Company also recorded a realized loss of $0 and $165,511 for the three months ended March 31, 2015 and 2014, respectively, from the settlements of these derivatives as reported in other income as realized gain (loss) on commodity contracts.

NOTE 5 – PROPERTY AND EQUIPMENT

Oil and Gas Properties

The Company’s oil and gas properties at March 31, 2015 are located in the United States of America.

The carrying values of the Company’s oil and gas properties, net of depletion and impairment, at March 31, 2015 and December 31, 2014 were:

	March 31,		December 31,
Property	2015		2014

Bear Creek Prospect, Carbon County, Wyoming	$	13,933,157	$	13,921,956
Woodson County, Kansas		6,301,562		6,340,805
Total	$	20,234,719	$	20,262,761

Net oil and gas properties at March 31, 2015 were:

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

2013 and prior	$	19,270,825	$	9,537,526	$	(3,057,836	)	$	(2,436,535	)	$	(4,967,452	)	$	18,346,528
2014		6,708,324		4,832,756		—			(8,837,248	)		(787,599	)		1,916,233
2015		—		11,201		—			—			(39,243	)		(28,042	)
Total	$	25,979,149	$	14,381,483	$	(3,057,836	)	$	(11,273,783	)	$	(5,794,294	)	$	20,234,719

During the three months ended March 31, 2015 and 2014, we incurred $0 and $159,529, respectively, of exploration expense which is included on our consolidated statement of operations.

For the year ended December 31, 2014, the table above reflects the removal of the properties associated with TNRH in the amount of $8,229,277 related to the Gulfstar purchase of the Company’s remaining interest in TNRH. (See NOTE 3.) The remaining amount of 2014 disposals relates to the $570,425 of Turkey Creek Field assets sold, see below, and sale of $37,546 of leasehold interest in Grayson County, Texas.

The Company holds oil and gas leasehold interests in Kansas and New York as well as a Seismic and Farmout Option Contract in Wyoming. The Company evaluates each of its properties upon completion of drilling and assessment of reserves to determine which, if any, is subject to impairment.

Bear Creek Prospect – Carbon County, Wyoming

On November 2, 2012, Armada executed a Seismic and Farm Out Option Contract (the “Anadarko Contract”), effective October 22, 2012, 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. The 3D survey was completed in a timely manner. The Company subsequently drilled a test well on the contract acreage, as discussed below, but has not yet completed the well. If and when the Company completes the well or a subsequent 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% operated working interest in the section upon which the well was drilled. Anadarko will retain a 20% royalty interest in future production. The Company delivered the seismic data to Anadarko as required and is evaluating potential funding opportunities for completion of the test well and the drilling of subsequent wells.

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On December 13, 2012, the Company and Anadarko entered in a First Amendment to the Seismic and Farmout Option Contract dated October 22, 2012 which added Wyoming State Lease ST WY 12-00422 covering all of Section 16-T20N-R79W to the Anadarko Contract.

On May 23, 2013, the Company and Anadarko entered in a Second Amendment to the Seismic and Farmout Option Contract dated October 22, 2012 which corrected a tract description in the original agreement and also extended the deadline for drilling of the Initial Test Well until December 31, 2013.

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.

Under the Third Amendment, the Company was:

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.

As a result of the precipitous drop in oil prices, the completion of the Bear Creek # 1 well and plans for the drilling of the first Continuous Option Test Well have been delayed. In an effort to allow additional time for oil prices to improve, effective March 16, 2015, the Company and Anadarko entered into a Fourth Amendment to the Seismic and Farmout Option Contract dated October 22, 2012, which included the following changes to the original agreement, as amended.

Under the Fourth Amendment, the Company was:

·	granted an extension to December 15, 2015 (previously 180 days from date Initial Contract Depth was reached in the Initial Test Well) to commence drilling of the first Continuous Option Test Well;

·	obligated to have removed or discharged any lien filed against the Anadarko mineral interests associated with the Seismic and Farmout Option Contract Lands by August 31, 2015.

During the three months ended March 31, 2015, no capital costs were incurred on the Bear Creek #1 well.

During the year ended December 31, 2014, the Company drilled and cased the Bear Creek #1 well spending $3,973,654. Total vertical depth of this well is 8,921 feet (8,896 cased). Intangible and tangible completion costs are estimated to be an additional $457,381. Total drilling and completion costs are estimated to be $4,251,035. This well is classified as an exploratory well whose costs are recorded in construction-in-progress and reported on our consolidated balance sheets in properties not subject to amortization at March 31, 2015.

During the three months ended March 31, 2014, all capital expenditures for oil and gas properties were focused in our Louisiana properties which we divested as of April 1, 2014.

Support Facilities and Equipment

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

		March 31,			December 31,
	Years	2015			2014

Tank batteries	7-12	$	44,000		$	44,000
Production equipment	7		38,351			38,351
Production Facilities	7		6,000			6,000
Vehicles	7		17,748			17,748
			106,099			106,099
Accumulated depreciation			(13,353	)		(9,990	)
Total support facilities and equipment, net		$	92,746		$	96,109

As of April 1, 2014, Gulfstar obtained control of the Company’s remaining interest in TNRH, and the Company removed the assets of the subsidiaries comprising TNRH, TNR and MGC, from the Company’s consolidated balance sheet, see NOTE 3.

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During the three months ended March 31, 2015 and 2014, the Company recognized depreciation expense of $3,363 and $101,528, respectively, on support facilities and equipment.

Office Furniture, Equipment, and Other

		March 31,			December 31,
	Years	2015			2014

Office equipment, computer equipment, software, and leasehold improvements	3	$	220,301		$	220,301
Furniture and fixtures	10		37,570			37,570
			257,871			257,871
Accumulated depreciation			(154,464	)		(132,395	)
Total property and equipment, net		$	103,407		$	125,476

During the three months ended March 31, 2015 and 2014, the Company recognized depreciation expense of $22,069 and $23,138, respectively, on office furniture, equipment, and other.

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

NOTE 6 – DEBT

Credit Facility and Notes Payable

The Company’s notes payable at March 31, 2015 and December 31, 2014 were as follows:

	March 31,			December 31,
	2015			2014

Credit Facility	$	3,472,693		$	3,472,693
Notes issued pursuant to private placement of securities		500,000			500,000
Other term notes		247,008			227,620
Notes payable outstanding		4,219,701			4,200,313
Less: Current maturities		(4,219,701	)		(4,200,313	)
Notes payable – noncurrent	$	—		$	—

Prosperity Bank Credit Facility

On July 22, 2011, the Company entered into a $25 million senior secured revolving line of credit (“Credit Facility") with Prosperity Bank (formerly F&M Bank and Trust Company) that, under its original terms, was to mature on July 22, 2013. The interest rate was the Prosperity 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. The interest rate was 5.75%. A 2.00% annual fee was 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 $102,877 loan origination fee which was to be 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, were to be determined concurrently with each semi-annual redetermination. In September 2012, Prosperity Bank performed a second redetermination and increased the Company’s borrowing base from $13,500,000 to $14,500,000. In addition, the term of the note was extended from July 22, 2013 to July 22, 2014. In December 2012, the Company drew an additional $4 million from its Credit Facility, resulting in an outstanding principal balance of $9,195,963.

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On May 1, 2013, Prosperity 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, Prosperity Bank determined the existence of a Borrowing Base deficiency of $450,000. The Company elected, pursuant to terms of its Loan Agreement with Prosperity 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, Prosperity 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 year ended December 31, 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 (“Lender”). Terms of the amendment and associated documents included:

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 no longer constituted borrowings by MEI under the Loan Agreement.

A First Amendment to the Security Agreement and a First Amendment to the Mortgage, Collateral Assignment, Security Agreement and Financing Statement amending the original of those documents dated July 22, 2011 (“Amended Security Agreement and Mortgage”) was entered into by which the properties and all associated collateral located in the Lake Hermitage Field thereafter secured 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 continued 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 were to pay to Lender the Limitation Amount in satisfaction of Mesa Energy, Inc.’s (“Borrower”) outstanding indebtedness on the Revolving Loan, Lender would 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 was reset by Lender to $8.2 million and the Company’s obligation to make monthly principal reduction payments which, as of last redetermination were $50,000 per month, was eliminated.

·	The Borrowing Base would not be increased until such time as the Louisiana Mortgage and all associated security interests granted by TNR were released as security for the Loan and TNRH was 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.

Effective July 22, 2014, the Company entered into an Amendment to the Revolving Promissory Note with Prosperity Bank by which the Maturity Date was extended from September 22, 2014, to November 22, 2014.

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At inception of the Credit Facility, deferred financing costs of $102,877 were incurred. For the three months ended March 31, 2015 and 2014, $0 and $5,641, respectively, of amortized deferred financing costs had been recognized as interest expense. At March 31, 2015 and December 31, 2014, deferred financing costs of $0 remained to be amortized relating to the Credit Facility.

Conversion of Prosperity Bank Credit Facility to Term Loan (“Term Loan”)

On March 5, 2015, the Company entered into the Seventh Amendment to Loan Agreement with Prosperity Bank (“7th Amendment”) by which:

·	The revolving loan underlying the Credit Facility was converted to a Term Loan in the principal amount of $3,472,693

·	No further advances would be made by Prosperity Bank and no further Letters of Credit will be issued under the Loan Agreement

·	The description of the collateral for the loan was amended to be the oil and gas properties in Woodson County, Kansas,

·	Prosperity Bank will no longer calculate a Borrowing Base

·	The Company must continue to comply with the reporting requirements of the Loan Agreement

·	Section 8 of the Loan Agreement which sets forth financial covenants was deleted in its entirety

·	Violations of financial covenants occurring on or before March 5, 2015, were waived by Prosperity Bank

·	The Company is required to pay an origination fee of $12,682

·	The Company executed and delivered to Prosperity Bank a Term Promissory Note under the following terms:

·	Maturity date – March 5, 2016

·	Interest rate – the lesser of the Prime Rate in effect from day to day plus one percent with a floor of 5.75% and a ceiling of the Maximum Rate

·	The Prime Rate is the rate of interest then most recently established by The Wall Street Journal computed on the basis of a 360-day year

·	The Maximum Rate is the maximum rate of interest which can be charged under applicable law on the Term Promissory Note

Payment terms under the Term Promissory Note are:

·	Interest is due and payable monthly through September 5, 2015

·	Beginning October 5, 2015, and continuing monthly until the term of the Term Promissory Note, principal payments of $50,000 each plus accrued and unpaid interest, are due and payable.

During the three months ended March 31, 2015, the company amortized $886 of the $12,682 in deferred financing costs incurred for the conversion of the Credit Facility to the Term Loan, leaving a balance of $11,795 remaining to be amortized during the remainder of the term of the Term Loan as of March 31, 2015.

For the three months ended March 31, 2015 and 2014, the Company recognized interest expense of $43,935 and $143,520, respectively, on the Credit Facility.

Private Placement of Notes

On March 20, 2013, the Company offered a private placement of debt pursuant to the provisions of Section 4(a)(2), Section 4(a)(6) and/or Regulation D under the Securities Act of 1933, as amended (the “Private Placement”). Pursuant to the Private Placement the Company offered $300,000 minimum and $4 million maximum of Series A Senior Unsecured Notes carrying an interest rate of 9.625% per annum, payable quarterly, with a maturity date of May 30, 2014 (the “Notes”). Under the terms of the offering, Series D Warrants for common shares were issued at closing. The number of warrants issued was calculated by dividing the face value of each subscriber’s note by $0.75, and each warrant will be exercisable at $0.75 per share beginning September 1, 2013. At December 31, 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	$	—

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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 year ended December 31, 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, was 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, and $76,948 resulted from the issuance for the additional warrants. At March 31, 2015, $13,493 of deferred financing costs remained to be amortized.

During the three months ended March 31, 2015 and 2014, the Company recognized $12,035 and $15,725, respectively, of interest expense on the face value of the notes, amortization of the deferred financing costs of $20,239 and $0, respectively, as interest expense and amortization of the debt discount resulted in the recognition of $0 and $57,333, respectively, as interest expense.

Notes Payable – Sycamore Resources, Inc. and David J. Moss

The Company issued two promissory notes, as follows:

Issued To	Origination Date	Maturity Date	Principal Amount		Interest Rate			Interest Expense Accrued through March 31, 2015

Sycamore Resources, Inc.	October 1, 2014	December 31, 2015	$	100,000		12	%	$	5,984
David J. Moss	October 31, 2014	December 31, 2015		100,000		12	%		4,899

Totals			$	200,000				$	11,849

Sycamore Resources, Inc. (“Sycamore”) is controlled by our President and Chief Executive Officer, Randy M. Griffin. Interest is accrued monthly and payable upon maturity of the notes.

The note to Sycamore was given in exchange for cash to pay the refundable earnest money deposit on a contemplated acquisition under a Purchase and Sale Agreement with Tabbs Bay Energy, LP (“Tabbs Bay Acquisition”) which was terminated on December 11, 2014, due to falling commodity prices combined with high operating costs of the properties which were the subject of the Tabbs Bay Acquisition. The $100,000 refund owed to the Company is carried on our Consolidated Balance Sheets as an account receivable.

The note to David J. Moss was given in exchange for cash to fund the nonrefundable due diligence deposit with the lender with which we were working to fund the Tabbs Bay Acquisition

Of the accrued and unpaid interest expense $5,918 was recognized as interest expense during the three months ended March 31, 2015. Of that amount, $2,959 is attributable to Sycamore Resources, Inc.

Premium Financed Insurance Notes

On April 24, 2014, the Company entered into a premium financed note for workers compensation, automobile, and general liability insurance in the principal amount of $20,291 at an interest rate of 5.59%. During the three months ended March 31, 2015, the note balance of $4,134 at December 31, 2014, was paid in full together with $29 of interest expense.

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On July 21, 2014, the Company entered into a premium financed note for well control and comprehensive umbrella liability insurance in the principal amount of $38,887 at an interest rate of 4.49%. During the three months ended March 31, 2015, $11,731 of principal was paid, leaving a balance of $7,894; and $177 of interest expense was paid on the note.

As of December 31, 2013, the Company had two notes payable with outstanding balances of $65,254 related to auto and well control insurance and $10,372 related to boat insurance. During the year ended December 31, 2014, the Company repaid $10,372 related to the boat insurance note and $39,007 related to the auto and well control insurance note. The remaining note balance of $26,247 relating to auto and well control insurance was assumed by TNRH on April 1, 2014.

Directors and Officers Liability Insurance Note

On March 29, 2014, the Company entered into a premium financed note for directors’ and officers’ liability insurance in the principal amount of $37,965 at an interest rate of 4.49%. During the three months ended March 31, 2015, the note balance of $3,861 at December 31, 2014, was paid in full, together with $14 of interest expense.

On March 29, 2015, the Company entered into a premium financed note for directors’ and officers’ liability insurance in the principal amount of $39,114 at an interest rate of 4.49%. During the three months ended March 31, 2015, the Company had incurred and accrued $10 of interest expense.

Debt Maturities

At March 31, 2015 and December 31, 2014, all of the Company’s debt was current.

NOTE 7 – ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated asset retirement obligations for the three months ended March 31, 2015 and year ended December 31, 2014.

	March 31, 2015		December 31, 2014

Beginning asset retirement obligations	$	463,814	$	3,161,810
Deconsolidation of TNRH (1)		—		(3,106,376	)
Obligations assumed from acquisition (2)		—		349,604
Accretion expense		4,342		58,776
Ending asset retirement obligations	$	468,156	$	463,814

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

During the three months ended March 31, 2015 and 2014, the Company recognized $4,342 and $46,152, respectively, of accretion expense on its asset retirement obligations.

NOTE 8 – INCOME TAXES

We recognize the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. We have not taken a tax position that, if challenged, would have a material effect on the consolidated financial statements or the effective tax rate for the three months ended March 31, 2015.

Income tax provisions or benefits for interim periods are computed based on the Company’s estimated annual effective tax rate. Based on the Company’s historical losses and its expectation of continuation of losses for the foreseeable future, the Company has determined that it is not more likely than not that deferred tax assets will be realized and, accordingly, has provided a full valuation allowance. As the Company anticipates that its net deferred tax assets at March 31, 2015, would be fully offset by a valuation allowance, there is no federal or state income tax benefit for the three months ended March 31, 2015.

As of March 31, 2015, the Company has U.S. net operating loss carry forwards of approximately $4.4 million which begin to expire in 2029.

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NOTE 9 – CONTINGENCIES

In connection with the drilling of the Bear Creek #1 well, the Company has unpaid invoices payable to vendors of $2,023,168 and $1,955,304, respectively, reflected in Accounts payable – trade, on the consolidated balance sheets as of March 31, 2015 and December 31, 2014. Of these, four vendors have recorded liens against our Bear Creek #1 wellbore in the amount of $1,087,371. Interest at 18% per annum was included with one lien filing and is reflected in accounts payable on our consolidated balance sheets in the amount of $65,014 and as interest expense on our consolidated statements of operations in the amount of $36,474.

NOTE 10 – SHARE BASED COMPENSATION

Warrants

The following table summarizes the Company’s warrant activity for the three months ended March 31, 2015:

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

Outstanding at December 31, 2014		7,953,333	$	1.84	3.3 years	$	—
Granted		—		—
Exercised		—		—
Cancelled/Expired		—		—
Outstanding at March 31, 2015		7,953,333	$	1.84	3.0 years	$	—

Exercisable at March 31, 2015		7,953,333	$	1.84	3.0 years	$	—

Stock Options

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

The following table summarizes the Company’s stock option activity for the three months ended March 31, 2015:

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

Outstanding at December 31, 2014		3,602,000			0.37	3.8 years	$	—
Granted		—			—	—		—
Exercised		—			—	—		—
Cancelled/Expired/Forfeited (1)		(39,000	)		0.37	—		—
Outstanding at March 31, 2015		3,563,000			0.36	2.75 years	$	—

Exercisable at March 31, 2015		3,158,000		$	0.38	2.9 years	$	—

(1)

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

Compensation expense related to stock options of $21,009 and $17,678 was recognized for the three months ended March 31, 2015 and 2014, respectively. At March 31, 2015, the Company had $35,112 of unrecognized compensation expense related to outstanding unvested stock options, which will be fully recognized over the next 6 months. No stock options have been exercised.

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Restricted Stock

The following table summarizes the Company’s restricted stock activity for the three months ended March 31, 2015:

	Shares
Unvested Restricted Shares at December 31, 2014		—
Granted		500,000
Vested		(500,000	)
Forfeited		—
Unvested Restricted Shares at March 31, 2015		—

Restricted shares granted and vested were issued to a consultant in exchange for services rendered during the fourth quarter of 2014 and the first quarter of 2015, the fair value of which was $51,667 of which $8,602 was recognized as expense during the three months ended March 31, 2015.

The Company had no unamortized compensation expense related to granted restricted stock awards as of March 31, 2015.

NOTE 11 – SUBSEQUENT EVENTS

On April 16, 2015, Cause No. DC-15-03885, TForce Energy Services, Inc., vs Armada Operating, LLC was filed in the 193rd Judicial District Court of Dallas County, Texas, by which plaintiff seeks to recover $309,217.75 plus attorneys’ fees from the defendant. This lawsuit has been filed to collect money associated with an unpaid invoice associated with the drilling of the Bear Creek #1 well in Wyoming. The Company has engaged counsel to extend the deadline by which AOP must file an answer or otherwise responsive pleading from May 4, 2015, to June 3, 2015.

On April 20, 2015, the Company issued 500,000 shares of our restricted common stock with a fair value of $32,585 to a consultant in exchange for services.

On April 30, 2015, the Company agreed to settle the $100,000 account receivable associated with the refundable deposit for the Tabbs Bay Acquisition, which did not occur, for $62,500. The difference of $37,500 was charged to bad debt expense.

On May 6, 2015, the Company entered into a contract for sale of real estate in Wyoming County, New York, for $18,000. This property is reported on the Company’s consolidated balance sheets as Land at a historical cost of $38,345. The Company will recognize a loss on sale of this property of $20,345 in the second quarter of 2015.

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

This report contains forward-looking statements. All statements other than statements of historical facts included in this Quarterly Report on Form 10-Q, including without limitation, statements in this Management’s Discussion and Analysis of Financial Condition and Results of Operations regarding our financial position, estimated working capital, business strategy, the plans and objectives of our management for future operations and those statements preceded by, followed by or that otherwise include the words “believe,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions or variations on such expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements, including, but not limited to, our inability to obtain adequate financing, insufficient cash flows and resulting illiquidity, our inability to expand our business, government regulations, lack of diversification, volatility in the price of oil and/or natural gas, increased competition, results of arbitration and litigation, stock volatility and illiquidity, our failure to implement our business plans or strategies and general economic conditions. A description of some of the risks and uncertainties that could cause our actual results to differ materially from those described by the forward-looking statements in this Quarterly Report on Form 10-Q appears in the section captioned “Risk Factors” in our 2014 Annual Report on Form 10-K.

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

History

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

The consolidated balance sheets contained in this Annual Report 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 three months ended March 31, 2015 and 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.

On December 16, 2013, MEI formed 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”), reducing the Company’s interest in TNRH to 65.625%. In April 2014, Gulfstar purchased 11,873 Class A Units of 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”) and reducing the Company’s interest to 39.7%. As result of this purchase, Gulfstar gained control of TNRH. Our consolidated financial statements for period beginning April 1, 2014, no longer include the consolidated accounts of TNRH and its wholly owned subsidiaries, TNR and MGC, but accounted for its investment in TNRH as a cost method investment. The consolidated financial statements of TNRH and its wholly owned subsidiaries, TNR and MGC, were deconsolidated from the consolidated financial statements of the Company effective April 1, 2014, because the Company lost its ability to impose significant influence over TNHR, and control of operations and assets of TNRH were restricted by rights of the then non-controlling member as of April 1, 2014. Net funds received by the Company upon deconsolidation of TNRH were $1,790,580 (Tranche B proceeds noted above less cash balances held by TNRH as of March 31, 2014). 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 $2,042,856. The Company’s interest in TNRH was reduced to 27.124% as a result of the Tranche D sale. On November 26, 2014, the Company sold its remaining 8,152 Membership Units to Gulfstar for $614.88 per Unit for net cash received of $5,012,502.

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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.

Overview and Going Concern

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:

	·	Bear Creek Prospect, where we hold a farmout agreement with Anadarko on approximately 9,400 mineral acres in Carbon County, Wyoming;
	·	Producing wells and leases in the Vernon and Wintersheid Fields in Woodson County, Kansas; 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.

Recent Developments

On March 5, 2015, the Company entered into the Seventh Amendment to the Loan Agreement with Prosperity Bank whereby the revolving note under the Credit Facility was converted to a Term Loan in the principal amount of $3,472,693, with a maturity of March 5, 2016. No further advances will be made pursuant to the new Term Loan, the bank will discontinue redeterminations under the loan and the Company will pay interest only on the Term Loan through September 2015 and pay interest plus $50,000 per month in principal to maturity. Our financial covenants pursuant to the Loan Agreement were eliminated, and all events of noncompliance with financial covenants prior to March 15, 2015, were waived.

Effective March 16, 2015, Randy M. Griffin, our Chief Executive Officer, has elected to defer and accrue his salary until such time as the Company’s revenue and cash positions improve.

Going Concern

The Company has incurred recurring losses from operations through March 31, 2015, has a working capital deficit at March 31, 2015, of $6,605,023 and has limited sources of revenue. The current financial condition of the Company raises substantial doubt as to the Company’s ability to continue as a going concern. These consolidated financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

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Kansas Area

During the second quarter of 2014, the Company consummated the purchase of proved developed and proved undeveloped leasehold interests in Woodson County, Kansas (the “Kansas Properties”). The Kansas Properties comprise six oil and gas leases covering approximately 1,040 gross and net acres all of which is held by production with no depth restrictions. The acquisition was primarily funded from drawing down Tranche B under the Unit Purchase Agreement between us and Gulfstar. The acquisition of the Kansas Properties was finalized on April 10, 2014, effective as of March 1, 2014. Approximately 800 acres are located in the Vernon Field and the other 240 acres, more or less, are located in the Winterschied Field. We believe that the existing wells provide stable, low decline, long life production with low operating costs and that the potential exists for the drilling of over 220 additional wells with a very low risk of dry holes. There is also water-flood potential in the currently producing zones.

New York Area

Java Field – Wyoming County, New York

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

Production is nominal from the wells but serves to hold the acreage for future development. In late 2009, we evaluated a number of the existing wells in order to determine the viability of the re-entry of existing vertical wellbores for plug-back and recompletion of the wells in the Marcellus Shale. The Marcellus Shale is approximately 1,240’ above the productive Medina Formation in the Java Field. As a result of this evaluation, we selected the Reisdorf Unit #1 well and the Ludwig #1 well as our initial targets and these two wells were recompleted in the Marcellus Shale and fracked in May and June of 2010. The initial round of testing and analysis provided a solid foundation of data that strongly supports further development of the Marcellus Shale in western New York. Formation pressures and flow-back rates were much higher than expected providing a clear indication of the potential of the resource.

We believe that horizontal drilling, successfully done at this depth in other basins, is ultimately what is needed to maximize the resource. However, as of March 31, 2015, a moratorium placed by the State of New York on high volume fracture stimulation remains in effect, as the New York General Assembly passed, on June 16, 2014, a new three year moratorium to allow for further study of hydraulic fracturing. Accordingly, we are unable to pursue 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.

Wyoming Area

The Bear Creek Prospect – Carbon County, Wyoming

The Company holds a farmout agreement with Anadarko (the “Anadarko Contract”) on approximately 9,400 net mineral acres in Carbon County, Wyoming (“Project Acreage”). The Project Acreage is generally 55 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 was 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 Shale. The Company has well logs from nearby wells showing the presence of all three Niobrara “benches”, and we believe 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 approximately $5,500,000, potential reserves per well of 300,000 to 600,000 barrels and liquids ratios of 60% to 80%.

On the conventional side, four nearby fields in conventional zones have produced in excess of 47 million barrels of oil and 13 BCF of gas. A number of potential conventional drilling locations were identified/confirmed as a result of the 3-D seismic shoot completed in 2013.

Based on a May 2013 article in the Oil & Gas Investor, “The Niobrara Extends its Reach”, by Chris Sheehan, CFA, 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. A similar drilling plan on the Anadarko farmout acreage, which would include portions of the Muddy and the Lakota rather than the Codell, could theoretically result in as many as 150 horizontal wells on the existing Anadarko farmout acreage block. Anadarko owns the minerals underlying the contracted acreage as well as a substantial amount of additional acreage in the area.

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Under the Anadarko Contract as amended, the Company was obligated to commence drilling of the initial test well on or before July 31, 2014. Per the Contract, if the Company drills an initial test well capable of production in paying quantities to the initial contract depth (approximately 8,500 feet), completes it as a producer and otherwise complies with and performs all other terms, covenants, and conditions of the Anadarko Contract, the Company will earn and be entitled to receive from Anadarko a lease, effective 30 days from the date of the release of the rig from the test well location, covering all of Anadarko’s oil and gas estate in the respective drill site section limited to the earned depth. The lease to be so earned by Armada will (i) be for a primary term of three (3) years; and (ii) provide for a lessor’s royalty of twenty percent (20%), proportionately reduced as appropriate and subject to any gas sales, purchase, transportation or gathering contracts affecting the leased lands on the date of the Anadarko Contract. The Company will then have the right to continue to drill additional wells on the contracted acreage, subject to a drilling schedule, and earn additional drill site sections as described above. The initial test well has been drilled but not yet completed and locations for additional future wells are being evaluated. Subject to the availability of the necessary funds, 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.

As indicated above, the Company drilled and cased the initial test well, the Bear Creek #1, per the Anadarko Contract, completing the drilling phase in September 2014, spending $3,973,654. Although the drilling phase was much more expensive than expected due to complications in the lower section of the well, the quantity and quality of scientific data obtained from the effort was phenomenal and will be invaluable in the planning and execution of the project’s future development. Total vertical depth of this well is 8,921 feet (8,896 cased). Intangible and tangible completion costs are estimated to be an additional $457,381. Total drilling and completion costs are estimated to be $4,430,735.

Data from the Bear Creek #1 well combined with subsurface geological well control from nearby wells surrounding the properties and the 3-D seismic data confirm a number of deeper conventional structures as well as the presence of all 3 Niobrara benches. An independent third-party log analysis of wireline logging data indicates a total of 205 feet of potential pay in multiple conventional reservoirs, including the Sundance, Muddy, Lakota and Casper/Tensleep Formations. Armada plans to initially perforate and test 20 feet of matrix porosity in the Casper/Tensleep and eight of the 40 feet of net Sundance pay in the Bear Creek #1.

Although the drop in oil prices has had a negative effect on the effort to raise development capital for the Anadarko Contract area, we continue to expect such capital to come from a joint venture financing scenario and/or additional project financing. Although there are ongoing discussions with a number of potential joint venture partners, we cannot guarantee that we will be able to raise the funds required to continue our drilling program in the area covered by the Anadarko Contract in a timely manner.

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.

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The following is a reconciliation of our net income in accordance with GAAP to our Adjusted EBITDA for the three-month periods ending March 31, 2015 and 2014:

	For the Three Months Ended March 31,
	2015			2014

Net loss	$	(587,862	)	$	(518,753	)

Adjustments:
Interest (income) expense, net		119,713			216,441
Income tax (benefit) expense		—			(314,703	)
Depreciation, depletion, accretion and impairment		69,017			420,079
Unrealized loss on change in commodity derivative instruments		—			167,673
Share-based compensation		55,508			17,678
Adjusted EBITDA	$	(343,624	)	$	(11,585	)

Results of Operations

Three Months Ended March 31, 2015, Compared to Three Months Ended March 31, 2014

Revenue

	Three Months Ended
	March 31,							Percentage
	2015		2014		Difference			Change

Revenues:
Oil	$	157,041	$	2,637,375	$	(2,480,334	)		-94.0	%
Natural gas		10,414		476,358		(465,944	)		-97,8	%
Natural gas liquids		—		23,594		(23,594	)		-100.0	%
Other		872		42,673		(41,801	)		-98.0	%
Total	$	168,327	$	3,174,000	$	(3,005,673	)		-94.7	%

Sales volumes:
Oil (Bbls)		3,680		25,617		(21,937	)		-85.6	%
Natural gas (MCF)		2,264		90,018		(87,754	)		-97.5	%
Natural gas liquids (Bbl)		—		606		(606	)		-100.0	%
Other		—		—		—			—
Total BOE		4,057		41,226		(110,297	)		-267.5	%
Total BOE/day		45		458

Average prices:
Oil (per Bbl)	$	42.67	$	102.95	$	(60.28	)		-58.6	%
Natural gas (per MCF)		4.60		5.29		(0.69	)		-13.0	%
Natural gas liquids (per Bbl)		—		38.93		(38.93	)		-100.0	%
Other		—		—		—			—
Total per BOE	$	41.27	$	76.10	$	(99.90	)		-131.3	%

Revenues from commodity sales decreased during the three months ended March 31, 2015, over the three months ended March 31 2014, due to divestiture of our interest in the Louisiana production due to our sale of our cost basis investment in TNRH as well as lower oil prices.

In addition to revenues from commodity sales, during the three months ended March 31, 2015, we had $872 of revenue from gas transportation fees. During the three months ended March 31, 2014, we had $36,673 of revenue from lease fuel, compressor allocation, gas transportation, COPAS overhead, and production handling fees.

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Operating expenses

Operating expenses for the three months ended March 31, 2015 and 2014 are set forth in the table below:

	Three Months Ended
	March 31,							Percentage
	2015		2014		Difference			Change

Costs and Expenses
Lease operating expense (1)	$	135,975	$	1,483,143	$	(1,347,168	)		-90.8	%
Production and ad valorem taxes (2)		6,055		354,007		(347,952	)		-98.3	%
Environmental remediation expense (3)		—		252,135		(252,135	)		-100.0
Exploration expense (4)		—		159,529		(159,529	)		-100.0
Depletion, depreciation, amortization, and impairment expense (5)		69,017		420,079		(351,062	)		-83.6	%
General and administrative expense (6)		426,251		1,035,859		609,608			-58.9	%
Total operating expenses	$	637,298	$	3,704,752	$	(3,067,454	)		-82.8	%

(1)	Divestiture of our Louisiana assets.
(2)	Divestiture of our Louisiana assets resulting in lower sales volumes and property value.
(3)	None incurred at March 31, 2015. Environmental remediation expense at March 31, 2014, resulted from a pipeline leak between two tank batteries in and a spill from a dump valve on the heater treater from Louisiana assets divested in 2014.
(4)	None incurred at March 31, 2015. Exploration expense at March 31, 2014 resulted from purchase of seismic data for Louisiana assets divested in 2014.
(5)	Divestiture of our Louisiana assets.
(6)	Decreased salaries, office rent, and legal and other consulting fees resulting from divestiture of our Louisiana assets.

Operating expenses expressed in BOE for the three months ended March 31, 2015 and 2014 are set forth in the table below:

	Three Months Ended
	March 31,							Percentage
	2015		2014		Difference			Change

Costs and Expenses
Lease operating expense	$	33.51	$	35.98	$	(2.47	)		-6.9	%
Production and ad valorem taxes		1.49		8.59		(7.10	)		-82.7	%
Environmental remediation expense		—		6.12		(6.12	)		-100.0
Exploration expense		—		3.87		(3.87	)		-100.0	%
Depletion, depreciation, amortization, and impairment expense		17.01		10.19		6.83			67.0	%
General and administrative expense		105.06		25.13		79.93			318.1	%
Total operating expenses	$	157.07	$	89.88	$	67.20			74.8	%

Operating loss. As a result of the above described revenues and expenses, we incurred an operating loss of $468,971 in the first quarter of 2015 as compared to an operating loss of $530,752 in the first quarter of 2014.

Interest expense. Interest expense decreased to $119,713 for the three months ended March 31, 2015, from $216,592 for the three months ended March 31, 2014. The decrease was primarily attributable to the significant paydown of the principal balance of our Term Loan with Prosperity Bank in the fourth quarter of 2014.

Loss on changes in derivative value – commodity contracts. The unrealized loss on change in derivatives – commodity contracts for the three months ended March 31, 2015 and 2014 was $0 and $167,673, respectively. Unrealized losses were the result of the change in value of the net derivative liability from that of the prior reporting period. The values underlying the derivatives are estimates of predicted future commodity prices based on current market activity and projections of future market activity. Additional contributors to fluctuations in the value of the recognized net liability are additions to and unwindings of hedged positions during any reporting period. We utilized no commodity derivative contracts during the three months ended March 31, 2015.

Realized loss on commodity contracts. Cash settlements which we paid from hedging our sales of oil and gas production were $0 in the first quarter of 2015 as compared to $165,511 which we received in the first quarter of 2014. 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. We utilized no commodity derivative contracts during the three months ended March 31, 2015.

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Income tax benefit. State and federal income tax benefit for the first quarter of 2015 was $0 compared to an income tax benefit of $314,703 in the first quarter of 2014. This change is the result of our establishing a full valuation allowance for deferred tax assets after determining at December 31, 2014, that it was not more likely than not that our deferred tax assets would be realized.

Net loss. Due to the reasons set forth above, our net loss for the three months ended March 31, 2015 was $587,862 ($0.01 per basic and diluted common share). Our net loss for the three months ended March 31, 2014 was $518,753 ($0.01 per basic and diluted common share).

Liquidity and Capital Resources

Overview

As of March 31, 2015, we had a working capital deficit of $6,605,023. As of December 31, 2014, we had a working capital deficit of $6,147,652. The $457,371 increase in the working capital deficit was attributable to significant decreases in balances of cash and cash equivalents, resulting primarily from decreased revenues from oil and gas sales. The precipitous drop in oil prices since September 2014 has had a significant adverse effect on the liquidity and capital resources of the Company. Although oil pricing has recovered somewhat, our operating cash flow is still negative. We have reduced our general and administrative expenses as much as possible and continue to raise cash by settling old accounts, negotiating with vendors and making efforts to sell off non-productive assets, all while continuing to pursue a producing property acquisition, attempting to raise equity capital through stock sales and pursuing joint venture financing for our Anadarko Contract area. Although we remain optimistic regarding the efforts outlined above and continue to work diligently in that regard, there can be no assurance that these efforts will be successful.

Cash and Accounts Receivable

At March 31, 2015, we had cash and cash equivalents of $72,764, compared to $406,306 at December 31, 2014. Cash decreased by $333,542 due to reductions in cash flow from revenue. We had accounts receivable of $156,724 at March 31, 2015, compared to $184,468 at December 31, 2014. The decrease of $27,744 is primarily attributable to a reduction in product sales receivable due to decreasing oil prices.

Liabilities

Accounts payable and accrued expenses increased by $118,893 to $2,642,349 at March 31, 2015, from $2,523,456 at December 31, 2014, primarily due to

$10,882 of accrued interest payable on $200,000 of notes payable given in exchange for advancing funds for the failed Tabbs Bay acquisition in the fourth quarter of 2014. $5,984 of this interest is payable to Sycamore Resources, LLC, an entity controlled by Randy M. Griffin, our President and Chief Executive Officer.

·	$8,750 of deferred salary to Randy M. Griffin.

·	The timing of payment of accounts payable. As cash flow has decreased, we are delaying payment of some invoices.

As of March 31, 2015, the outstanding balance of principal on debt was $4,219,701, a net decrease of $19,388 from the outstanding balance of $4,200,313, as of December 31, 2014. The decrease was due to principal payments on our premium financed insurance notes, net of the addition of one premium financed insurance note.

Cash Flows

For the three months ended March 31, 2015, net cash used for operating activities was $301,134 compared to net cash used for operating activities for the three months ended March 31, 2014 of $589,061, a net decrease in cash used of $287,927 due primarily to significant decreases in accounts receivable for oil and gas revenues and increases in accounts payable balances. The decrease in accounts receivable for oil and gas revenues results primarily from the sale of the controlling interest in TNRH after the March 31, 2014, balance sheet date. The increase in accounts payable balances results primarily from the delaying of payment to vendors of some invoices due to decreased cash flow.

For the three months ended March 31, 2015 and 2014, net cash used in investing activities was $0 and $1,169,165, respectively, a decrease in cash used of $1,169,165. This is attributable to the suspension of drilling and other capital spending due to the lack of working capital.

For the three months ended March 31, 2015 and 2014, net cash used for financing activities was $32,408 and $238,337, respectively, a decrease in cash used of $205,929. This was primarily because during the three months ended March 2014, we were obligated under the terms of our then Credit Facility to make principal reduction payments and financed insurance premiums were significantly higher, resulting in higher payments of principal.

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Subsequent Events

On April 16, 2015, Cause No. DC-15-03885, TForce Energy Services, Inc. vs Armada Operating, LLC was filed in the 193rd Judicial District Court of Dallas County, Texas, by which plaintiff seeks to recover $309,217.75 plus attorneys’ fees from the defendant. This lawsuit has been filed to collect money associated with an unpaid invoice associated with the drilling of the Bear Creek #1 well in Wyoming. The Company has engaged counsel to extend the deadline by which AOP must file an answer or otherwise responsive pleading from May 4, 2015, to June 3, 2015.

On April 20, 2015, the Company issued 500,000 shares of our restricted common stock with a fair value of $32,585 to a consultant in exchange for services.

Off-Balance Sheet Arrangements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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

Item 4. Controls and Procedures

a) Evaluation of disclosure controls and procedures.

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of March 31, 2015. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Based on management’s evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as a result of the material weaknesses described below, as of March 31, 2015, 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 March 31, 2015, we did not adequately segregate, or mitigate the risks associated with, incompatible functions among personnel to reduce the risk that a potential material misstatement of the financial statements would occur without being prevented or detected. Accordingly, management concluded that this control deficiency constituted a material weakness.

We are committed to improving our accounting and financial reporting functions. As part of this commitment, we are considering the engagement of additional employees and have engaged consultants to assist in the preparation and filing of financial reports. With the precipitous drop in the price of oil and the resulting decrease in our revenues, however, our efforts to improve our accounting functions have slowed.

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

(b) Changes in internal control over financial reporting.

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

During the three months ended March 31, 2015, as a further cost cutting measure, we eliminated the use of contractors and consultants to support the preparation of financial statements and financial reports.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

As of March 31, 2015, we were not a party to any material legal proceedings or claims. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Subsequent Events” above for disclosure relating to a claim filed against us on April 6, 2015.

Item 1A. Risk Factors

For information regarding risk factors, please refer to the Company’s Annual Report on Form 10-K filed with the SEC on March 31, 2015, which may be accessed via EDGAR through the Internet at www.sec.gov.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit No.		Description
4.1		Term Promissory Note dated March 5, 2015 (included as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 10, 2014 and incorporated herein by reference)
10.1		Seventh Amendment to Loan Agreement dated March 5, 2015 (included as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 10, 2014 and incorporated herein by reference)
10.2		First Amendment to Mortgage and Security Agreement dated March 5, 2015 (included as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 10, 2014 and incorporated herein by reference)
31.01*		Certification of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02*		Certification of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01**		Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.02**		Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101INS*		XBRL Instance Document***
101SCH*		XBRL Schema Document***
101CAL*		XBRL Calculation Linkbase Document***
101LAB*		XBRL Labels Linkbase Document***
101PRE*		XBRL Presentation Linkbase Document***
101DEF*		XBRL Definition Linkbase Document***

*		Filed herewith.

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

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

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SIGNATURES

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

	ARMADA OIL, INC.

Date: May 15, 2015	By:	/s/ RANDY M. GRIFFIN
		Randy M. Griffin
		Chief Executive Officer (Principal Executive Officer)


Date: May 15, 2015	By:	/s/ RACHEL L. DILLARD
		Rachel L. Dillard
		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)