armadaoil10k123114.htm

PART I

ITEM 1.

BUSINESS

Forward Looking Statements

This Annual Report on Form 10-K (including the section regarding Management's Discussion and Analysis of Financial Condition and Results of Operations) contains forward-looking statements regarding our business, financial condition, results of operations and prospects. Words such as "expects," "anticipates," "intends," "plans," "believes," "seeks," "estimates" and similar expressions or variations of such words are intended to identify forward-looking statements, but are not deemed to represent an all-inclusive means of identifying forward-looking statements as denoted in this Annual Report on Form 10-K. Additionally, statements concerning future matters are forward-looking statements.

Although forward-looking statements in this Annual Report on Form 10-K reflect the good faith judgment of our Management, such statements can only be based on facts and factors currently known by us. Consequently, forward-looking statements are inherently subject to risks and uncertainties and actual results and outcomes may differ materially from the results and outcomes discussed in or anticipated by the forward-looking statements. Factors that could cause or contribute to such differences in results and outcomes include, without limitation, those specifically addressed under the heading "Risks Factors” below, as well as those discussed elsewhere in this Annual Report on Form 10-K. Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this Annual Report on Form 10-K. We file reports with the Securities and Exchange Commission ("SEC"). We make available on our website under "Investor Relations/SEC Filings," free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file such materials with or furnish them to the SEC. Our website address is www.armadaoil.us. You can also read and copy any materials we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. You can obtain additional information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

We undertake no obligation to revise or update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this Annual Report on Form 10-K. Readers are urged to carefully review and consider the various disclosures made throughout the entirety of this annual Report, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operations and prospects.

This Annual Report on Form 10-K includes the consolidated accounts of Armada Oil, Inc. 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”), as well as those of TNR Holdings, LLC (“TNRH”), Tchefuncte Natural Resources, LLC (“TNR”), and Mesa Gulf Coast, LLC (“MGC”) through March 31, 2014, at which time we owned 65.625% of TNRH which owned 100% of TNR and MGC, collectively referred to as “we”, “us,” “our,” “Armada” or the "Company".

For definitions of certain oil and gas industry terms used in this Annual Report on Form 10-K, please see the Glossary beginning on page 13.

Overview of Our Business

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.

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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 year ended December 31, 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.

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

The Company’s oil and gas operations are conducted by its wholly owned subsidiaries. MMC is a qualified operator in the state of Oklahoma. 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.

General Philosophy

Our philosophy has been to operate, or directly control the operation of, through our wholly-owned subsidiaries or their designees, all properties that we own or acquire. In our opinion, the lack of control resulting from leaving operational control in the hands of third parties substantially increases the risks associated with oil and gas drilling, development and production.

We plan for our portfolio to consist of a balanced and diversified mix of multiple asset components that include current production, multiple recompletion and enhancement opportunities along with developmental drilling opportunities. We expect that the production acquisition component in our business plan should expand an already strong revenue base resulting in long-term, dependable revenue and stability. The developmental drilling program, we believe, should provide a relatively low risk method of achieving rapid and repeatable growth in revenue and reserves.

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Various federal and state regulations regarding the discharge of materials into the environment are applicable to our operations. We maintain strict compliance with these regulations and endeavor to do all we can to make certain that the environment is protected in and around our operations. The cost of environmental control facilities and efforts is included as a line item in the budget of each operation as appropriate. We anticipate no extraordinary capital expenditures for environmental control facilities related to any of our existing operations for the current fiscal year.

Our Properties

The table below lists and summarizes our acreage by area as of December 31, 2014. This table excludes acreage in which our interests are limited to royalty and overriding royalty interests.

The Company holds oil and gas lease interests in Kansas and New York. The approximate acreage in each property is outlined in the table below. The Company evaluates each of its properties upon completion of drilling and assessment of reserves to either classify the properties as “properties subject to amortization” or impair them.

Area	Developed Acreage				Undeveloped Acreage				Total Acreage				Weighted Average Remaining Lease Term
	Gross		Net		Gross		Net		Gross		Net
Kansas		312.50		312.50		727.50		727.50		1,040.00		1,040.00	Life of Production
New York		2,851.50		2,851.50		0.00		0.00		2,851.50		2,851.50	Life of Production
Total		3,164.00		3,164,00		727.50		727.50		3,891.50		3,891.50

Kansas Area

During the second quarter of 2014, the Company consummated the purchase of proved developed and 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.

Vernon Field – Woodson County, Kansas

The Company operates 103 shallow oil wells, 5 injection wells and 1 saltwater disposal well in the Vernon Field with 100% working interest and 86.625% net revenue interest in 4 leases covering 800 gross and net acres, more or less. All of the Company’s production in the Vernon Field is from the Squirrel Sand, a sandy zone in the upper part of the Cherokee Shale, which overlies the Mississippian Limestone. The Squirrel Sand is prominent and broadly distributed throughout eastern Kansas and is known to provide stable, low decline, long life production with low operating costs. The Company has identified the potential to drill over 150 new wells in the Vernon Field.

·	Operated Wells: 109

·	Non-operated Wells: None

·	Reservoir Thickness: The Squirrel Sand averages 90’ thick with an average 24’ of net pay in the lower and upper productive intervals.

·	Producing Depth: 950’ – 1,100’

·	Drilling Method: Vertical

·	Production Characteristics: As much as 40 years of production with reserve calculations done by decline-curve analysis

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Winterschied Field – Woodson County, Kansas

The Company operates 15 shallow oil wells, and 1 saltwater disposal well in the Winterschied Field with 100% working interest and 86.625% net revenue interest in 2 leases covering 240 gross and net acres, more or less. Our wells in the field produce from both the Squirrel Sand and the Mississippian Limestone. The Company has identified the potential to drill approximately 70 new wells in the Winterschied Field targeting the Mississippian Limestone and the Squirrel Sand.

·	Operated Wells: 16

·	Non-operated Wells: None

·	Reservoir Thickness: The Squirrel Sand averages 104’ thick with an average 37’ of net pay in the lower and upper productive intervals. The Mississippian Limestone averages 62.5’ thick with an average 11.5’ of net pay.

·	Producing Depth: Squirrel Sand 1,162’ – 1,321’, Mississippian Limestone 1,551’ – 1,666’

·	Drilling Method: Vertical

·	Production Characteristics: As much as 40 years of production with reserve calculations done by decline-curve analysis

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 December 31, 2014, 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.

	·	Operated Wells: 19 Producing Gas Wells
	·	Non-Operated Wells: None
	·	Reservoir Thickness: The Medina Sandstone averages 82’ thick and the Marcellus Shale averages 105’ thick with approximately 24’ of net pay
	·	Producing Depth - Medina: 2,850’ – 3,500’
	·	Drilling Method: Vertical
	·	Production Characteristics: 25+ years of production from each horizon
	·	Key Considerations: Understanding the effective drainage area of each well supports the exploitation field development of the conventional producing horizons and the unconventional shale horizons in Java Field

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 has been processed and evaluated, and the results not only confirmed potential in a number of the deep conventional zones but also solid potential in the Niobrara 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.

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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.

Under the Anadarko Contract, 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 $3,973,354. 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. The table below depicts the relative location of the reservoirs within the wellbore.

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Development capital for unconventional horizontal wells in the Niobrara Shale is expected to come from a joint venture financing scenario and/or additional project financing. We cannot guarantee, however, that we will be able to raise the funds required to continue our drilling program in the Niobrara Shale.

Commodity Price Environment

Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. Commodity prices are beyond our control and are difficult to predict. The prices we have received for the sale of our oil production dropped precipitously during the fourth quarter of 2014 resulting in a significant negative impact on the Company’s cash flow and results of operations. Many factors enter into the price of oil, both domestic and foreign, and opinions vary widely as to the timeframe for a recovery. The foreign aspect of the equation is almost impossible to predict. Domestically, many believe that the supply and demand equation will begin to improve late 2015 with significant improvement in 2016. We believe that a great buying opportunity has presented itself and we hope to acquire additional producing properties later in 2015. There can, however, be no assurance of any short term improvement in commodity prices or in our ability to take advantage of acquisition opportunities.

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Government Regulations

General

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Most of our drilling operations will require permits or authorizations from federal, state or local agencies. Changes in any of these laws and regulations or the denial or vacating of permits could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with applicable laws and regulations. There are no pending or threatened enforcement actions related to any such laws or regulations. We further believe that the existence and enforcement of such laws and regulations will have no more restrictive an effect on our operations than on other similar companies in the energy industry.

Proposals and proceedings that might affect the oil and gas industry are constantly pending before Congress, the Federal Energy Regulatory Commission (“FERC”), state legislatures and commissions and the courts. We cannot predict when or whether any such proposals may become effective. The energy industry has always been heavily regulated and there is no reason to believe that the regulatory approach currently pursued by various agencies will not continue. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material adverse effect upon our capital expenditures, earnings, or competitive position.

Federal Regulation of Sales and Transportation of Natural Gas

Historically, the transportation and sale of natural gas and its component parts in interstate commerce have been regulated under several laws enacted by Congress and the regulations passed under these laws by FERC. Our sales of natural gas, including condensate and liquids, may be affected by the availability, terms, and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and FERC that affect the economics of natural gas production, transportation and sales. In addition, FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry.

The ultimate impact of the complex rules and regulations issued by FERC cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and final FERC decisions. We cannot predict what further action FERC will take on these matters. Some of FERC’s more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with whom we compete.

State Regulation

Our operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing of wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandonment of wells, and the disposal of fluids used and produced in connection with operations. Our operations are also subject to various conservation laws and regulations pertaining to the size of drilling and spacing units or proration units and the unitization or pooling of oil and gas properties.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory capacity requirements, but, except as noted above, does not generally entail rate regulation. These regulatory burdens may affect profitability, but we are unable to predict the future cost or impact of complying with such regulations.

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Environmental Matters

Our operations are subject to numerous federal, state and local laws and regulations controlling the generation, use, storage, and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences; restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling, production, and natural gas processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as use of pits and plugging of abandoned wells; restrictions on injection of liquids into subsurface strata that may contaminate groundwater; and impose substantial liabilities for pollution resulting from our operations. Environmental permits required for our operations may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. We believe that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws.

Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on us as well as the natural gas and crude oil industry in general. We are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations.

We are not currently involved in any administrative, judicial or legal proceedings arising under domestic or foreign federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our consolidated financial position or results of operations. Moreover, we maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.

Superfund

The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund," and comparable state statutes impose strict joint and several liability on certain classes of persons who are considered to have contributed to the release of a “hazardous substance" into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that generated, disposed, or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, such persons or companies may be retroactively liable for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is common for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment. In the course of our operations, we may generate waste that may fall within CERCLA's definition of a "hazardous substance." We may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed. Although CERCLA currently contains a "petroleum exclusion" from the definition of “hazardous,” state laws affecting our operations impose cleanup liability relating to petroleum related products, including crude oil cleanups. In addition, although the Resource Conservation and Recovery Act of 1976, as amended (“RCRA”) regulations currently classify certain wastes which are uniquely associated with field operations as "non-hazardous," such exploration, development and production wastes could be reclassified by regulation as hazardous wastes thereby administratively making such wastes subject to more stringent handling and disposal requirements.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of natural gas and crude oil. Although we utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators; to clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination.

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Oil Pollution Act of 1990

United States federal regulations also require certain owners and operators of facilities that store or otherwise handle crude oil, such as us, to prepare and implement spill prevention, control and countermeasure plans and spill response plans relating to possible discharge of crude oil into surface waters. The federal Oil Pollution Act ("OPA") contains numerous requirements relating to prevention of, reporting of, and response to crude oil spills into waters of the United States. For facilities that may affect state waters, OPA requires an operator to demonstrate $10 million in financial responsibility. State laws mandate crude oil cleanup programs with respect to contaminated soil. A failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA's financial responsibility and other operating requirements will not have a material adverse effect on us.

U.S. Environmental Protection Agency

U.S. Environmental Protection Agency regulations address the disposal of crude oil and natural gas operational wastes under three federal acts more fully discussed in the paragraphs that follow. The RCRA provides a framework for the safe disposal of discarded materials and the management of solid and hazardous wastes. The direct disposal of operational wastes into offshore waters is also limited under the authority of the Clean Water Act. When injected underground, crude oil and natural gas wastes are regulated by the Underground Injection Control program under the Safe Drinking Water Act. If wastes are classified as hazardous, they must be properly transported, using a uniform hazardous waste manifest, documented, and disposed of at an approved hazardous waste facility. We have coverage under the applicable Clean Water Act permitting requirements for discharges associated with exploration and development activities.

Resource Conservation and Recovery Act

RCRA is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a "generator" or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most crude oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA's requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes crude oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

Clean Water Act

The Clean Water Act imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters. Further, the Environmental Protection Agency has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Safe Drinking Water Act

Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from crude oil and natural gas production. The Safe Drinking Water Act of 1974, as amended establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. We currently own and operate various underground injection wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

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Air Pollution Control

The Clean Air Act and state air pollution laws adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

Naturally Occurring Radioactive Materials ("NORM")

NORM materials are not covered by the Atomic Energy Act. Their radioactivity is enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the crude oil and natural gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards.

Abandonment Costs

All of our crude oil and natural gas wells will require proper plugging and abandonment when they are no longer producing. As necessary, we post financial assurance deposits with regulatory agencies to ensure compliance with our plugging responsibility. Plugging and abandonment operations and associated reclamation of the surface production site are important components of our environmental management system. We plan accordingly for the ultimate disposition of properties that are no longer producing.

Competition

The oil and gas industry is intensely competitive with respect to the acquisition of prospective oil and natural gas properties and oil and natural gas reserves. Our ability to effectively compete is dependent on our geological, geophysical and engineering expertise and our financial resources. We must compete against a substantial number of major and independent oil and natural gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for drilling and completion of wells. Consequently, drilling equipment may be in short supply from time to time. However, drilling rigs and equipment are reasonably available at the present time in the areas where we operate.

Employees

As of December 31, 2014, we had five employees, including our executive officers. We anticipate the need for additional accounting, land, technical, and field personnel from time to time. Although demand for quality staff can be high in the oil and gas industry, we believe we will be able to fill these positions in a timely manner.

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GLOSSARY OF OIL AND GAS TERMS

The following are the meanings of some of the oil and gas industry terms that may be used in this annual report.

2-D seismic: (two-dimensional seismic data) Geophysical data that depicts the subsurface strata in two dimensions. A vertical section of seismic data consisting of numerous adjacent traces acquired sequentially.

3-D seismic: A set of numerous closely-spaced seismic lines that provide a high spatially sampled measure of subsurface reflectivity. Events are placed in their proper vertical and horizontal positions, providing more accurate subsurface maps than can be constructed on the basis of more widely spaced 2D seismic lines. In particular, 3D seismic data provide detailed information about fault distribution and subsurface structures.

Barrel: Standard volume of measure for crude oil and liquid petroleum products.

Basin: A depression of the earth's surface into which sediments are deposited, usually characterized by sediment accumulation over a long interval; a broad area of the earth beneath which layers of rock are inclined, usually from the sides toward the center.

BCF: Billion cubic feet.

BOE: Barrel of oil equivalent. One barrel equals 42 US gallons. One/sixth of a barrel is equivalent to one MCF (thousand cubic feet) of natural gas.

BOE/D: Barrel of oil equivalent per day.

Completion: The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Crude oil: A general term for unrefined petroleum or liquid petroleum.

Defined-risk: Projects defined by multiple evaluation techniques in order to estimate more reasonably the potential for success. These techniques may include 2-D or 3-D seismic, geo-chemistry, subsurface geology, surface mapping, data from surrounding wells, and/or satellite imagery.

Developmental drilling: Drilling that occurs after the initial discovery of hydrocarbons in a reservoir.

Devonian Shale: Shale formed from organic mud deposited during the Devonian Period (416–359 million years ago).

Dry hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

E&P: Exploration and production.

Exploration: The initial phase in petroleum operations that includes generation of a prospect or play or both, and drilling of an exploration well. Appraisal, development and production phases follow successful exploration.

Exploratory well: A well drilled to find and produce oil and gas reserves that is not a development well.

Fairway: A term used in the industry to describe an area believed to contain the most productive mineral acreage in a play.

Farm-out: An agreement whereby the owner of a lease (farmor) agrees to assign part or all of a leasehold interest to a third party (farmee) in return for drilling of a well or wells and/or the performance of other required activities. The farmee is said to “farm-in.”

Field: An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding cost: The total cost to drill, complete and hook up a well divided by the mcf or barrels of proved reserves.

Formation: An identifiable layer of rocks named after the geographical location of its first discovery and dominant rock type.

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Fracturing or “Fracking”: Hydraulic fracturing is a method used to create fractures that extend from a borehole into rock formations, which are typically maintained by a proppant, a material such as grains of sand, ceramic beads or other material which prevent the fractures from closing. The method is informally called fracking or hydro-fracking. The technique of hydraulic fracturing is used to increase or restore the rate at which fluids, such as oil, gas or water, can be produced from the desired formation. By creating fractures, the reservoir surface area exposed to the borehole is increased.

Gas show: While drilling a well through different rock formations, gas may appear in the drilling mud which is circulating through the drill pipe, which indicates the presence of gas in the formation being drilled; drillers call this a “gas show”.

Hamilton Group: A bedrock unit in New York, Pennsylvania, Maryland and West Virginia; the oldest strata of the Devonian gas shale sequence. In the interior lowlands of New York, the Hamilton Group contains the Marcellus, Skaneateles, Ludlowville, and Moscow Formations, in ascending order, with the Tully Limestone above.

Horizontal well: a well in which the borehole is deviated from vertical at least 80 degrees so that the borehole penetrates a productive formation in a manner parallel to the formation. A single horizontal lateral can effectively drain a reservoir and eliminate the need for several vertical boreholes.

Hydrocarbon: A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane [CH 4], but many are highly complex molecules, and can occur as gases, liquids or solids. The molecules can have the shape of chains, branching chains, rings or other structures. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.

Lead: a possible prospect.

Marcellus Shale: The lowest unit of the Devonian age Hamilton Group; a unit of marine sedimentary rock found in eastern North America. Named for a distinctive outcrop near the village of Marcellus, New York, it extends throughout much of the Appalachian Basin. The shale contains largely untapped natural gas reserves, and its proximity to the high-demand markets along the East Coast of the United States makes it an attractive target for energy development.

MCF: Standard measure of volume for natural gas which is one thousand cubic feet.

MCFE: Six thousand cubic feet of natural gas is equivalent to one barrel of oil.

MCFE/D: MCF equivalent per day.

Medina Sandstone: The Lower Silurian age Medina Group sandstones comprise the dominant tight gas sandstone play in western and southwestern New York. Depths vary from 1,800 feet in the west central part of the state to 4,500 feet in the western part of the state.

Net revenue interest (NRI): The portion of oil and gas production revenue remaining after the deduction of royalty and overriding royalty interests.

NYMEX: The New York Mercantile Exchange, the world's largest physical commodity futures exchange, located in New York City.

Operator: The individual or company responsible for the exploration and/or exploitation and/or production of an oil or gas well or lease.

Overriding royalty interest (ORRI): an interest carved out of the lessee’s working interest that entitles its owner to a fraction of production free of any production or operating expense, but not free of production or severance tax levied on the production. An overriding interest’s duration derives from the lease in which it was created.

Participation interest: The proportion of exploration and production costs each party will bear and the proportion of production each party will receive, as set out in an operating agreement.

Play: A group of oil or gas fields or prospects in the same region that are controlled by the same set of geological circumstances.

Production: The phase that occurs after successful exploration and development and during which hydrocarbons are drained from an oil or gas field.

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Prospect: A specific geographic area, which based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Recompletion: After the initial completion of a well, the action and technique of re-entering the well and repairing the original completion or completing the well in a different formation to restore the well’s productivity.

Reservoir: A subsurface, porous, permeable rock formation in which oil and gas are found.

Royalty interest: An ownership interest in the portion of oil, gas and/or minerals produced from a well that is retained by the lessor upon execution of a lease or to one who has acquired possession of the royalty rights, based on a percentage of the gross production from the property free and clear of all costs except taxes.

Seismic: Pertaining to waves of elastic energy, such as that transmitted by P-waves and S-waves, in the frequency range of approximately 1 to 100 Hz. Seismic energy is studied by scientists to interpret the composition, fluid content, extent and geometry of rocks in the subsurface. "Seismic," used as an adjective, is preferable to "seismics," although "seismic" is used commonly as a noun.

Shale: A fine-grained sedimentary rock composed of flakes of clay minerals and tiny fragments of other minerals, especially quartz and calcite. Shale is characterized by thin laminate, or parallel layering or bedding less than one centimeter in thickness.

Shut in: Not currently producing.

Theresa Sandstone: An Upper Cambrian age sandstone underlying most of western New York at depths ranging from 3,000 feet to 13,000 feet. Theresa wells are typically drilled to depths ranging from 5,000 feet to 7,000 feet.

Twin well: A well drilled on the same location as another well or closely offsetting it.

Working interest: The interest in oil or gas that includes the responsibility for all drilling, developing and operating costs.

Workover: The performance of one or more of a variety of remedial operations on a producing well to try to increase or restore production.

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ITEM 1A.

RISK FACTORS

Risks Relating to Our Business:

If we are unable to generate or obtain sufficient capital to fund our capital budgets, business operations could be harmed and if we do obtain additional capital in the form of equity financing, existing shareholders could suffer substantial dilution.

We currently anticipate that we will require approximately $4,000,000 to adequately fund our current drilling and completion budget for 2015. To the extent that we make additional acquisitions or choose to drill additional wells, which is a distinct possibility, additional capital would be required. It is our intent to establish a new comprehensive credit facility as part of the acquisition of additional properties and to include the drilling and completion budget referenced above in that facility. There can be no assurance that additional financing will be available for those activities in amounts or on terms acceptable to us. An inability to obtain additional capital could restrict our ability to acquire additional properties and implement our business plan. Any additional equity financing could involve substantial dilution to then existing shareholders

Our current lack of diversification could increase the risk of an investment in our company.

Our business focus is on the oil and gas industry in a limited number of geographic areas, currently in Kansas, western New York, and Wyoming. Larger companies have the ability to manage their risk by geographic diversification. It is our intent to pursue opportunities in other geographic areas as those opportunities present themselves as is discussed above. However, we may continue to have a lack of diversification for the near future. As a result, we could be impacted more acutely by factors affecting our industry in the regions in which we operate than we would if our business were more diversified, thereby enhancing our risk profile.

Future investment in drilling projects will increase the risks inherent in our oil and gas activities and our drilling operations may not be successful.

We intend to develop a portfolio consisting of a balanced and diversified mix of existing production and developmental drilling opportunities. Some drilling projects are more exploratory in nature, and those projects come with greater risks than in acquisitions and developmental drilling. Whether developmental or exploratory all drilling comes with risk, both geological and mechanical, and there is no assurance that these activities will be successful or that we will discover meaningful levels of reserves. We cannot be sure that an overall drilling success rate or production operations within a particular area will ever come to fruition and, in any event, production rates inevitably decline over time. We may not recover all or any portion of the capital investment in our wells or the underlying leaseholds. Unsuccessful drilling activities would have a material adverse effect upon our results of operations and financial condition.

Investment in drilling and/or recompletion of existing wells does not come without risk.

Additionally, there are significant uncertainties as to the future costs and timing of drilling and completing new wells and/or recompleting existing wells. Our drilling operations have been and may continue to be curtailed, delayed, or canceled as a result of a variety of factors, including:

	·	lack of funding;
	·	current commodity pricing environment making it uneconomical to explore for or develop reserves;
	·	unexpected drilling conditions;
	·	equipment failures or accidents;
	·	adverse weather conditions;
	·	compliance with governmental requirements; and
	·	shortages or delays in the availability of drilling rigs and the delivery of equipment or materials.

Because we may not operate all of our properties, we could have limited influence over their development.

Although we intend to operate or otherwise directly control the operation of all our properties, there may be certain situations wherein we acquire non-operated properties as part of an acquisition package or elect to allow others to operate. In that event, we would have limited influence over the operations of those properties. Our lack of control could result in the following:

	·	the operator may initiate exploration or development on a faster or slower pace than we prefer;
	·	the operator may propose to drill more wells or build more facilities on a project than we have budgeted for or that we deem appropriate, which may mean that we are unable to participate in the project or share in the revenues generated by the project even though we paid our share of the initial exploration costs.

Either of these events could materially reduce the value of our properties.

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Drilling initiatives on the “Bear Creek” project may not prove successful.

We hold a farmout agreement with Anadarko relating to the Bear Creek project located in Carbon County, Wyoming. Our primary initiative for the Bear Creek project is to identify and exploit resources from potential reservoirs in the Niobrara Formation. There is no guarantee that our efforts on Bear Creek project will ever produce commercial volumes of oil or gas, which could have a material adverse effect upon our results of operations.

We do not own all of the land on which our pipelines are located or on which we may seek to locate pipelines in the future, which could disrupt our operations and growth.

We do not own the land on which our pipelines have been constructed, but we do have right-of-way and easement agreements from landowners, some of which may require annual payments to maintain the agreements and most of which have a perpetual term. New pipeline infrastructure construction may subject us to more onerous terms or to increased costs if the design of a pipeline requires redirecting. Such costs could have a material adverse effect on our business, results of operations and financial condition.

Pending New York legislative initiatives and environmental studies of the effect of hydraulic fracturing may limit our exploration and developmental efforts in the Marcellus Shale in New York.

The New York Department of Environmental Conservation is currently engaged in an environmental review of the impacts of hydraulic fracturing in New York. Until such time as this review has been completed, New York has imposed a moratorium on high volume hydraulic fracturing. Additionally, bills have been introduced in the New York state legislature that, if enacted, could result in the imposition of a permanent moratorium on hydraulic fracturing operations in the state. The imposition of such a moratorium or any negative outcome of an environmental study leading to restrictions, limitations or prohibitions on hydraulic fracturing in New York could limit our exploration and developmental efforts in the Marcellus shale.

If we are unable to continue to retain the services of Randy M. Griffin and/or, Rachel L. Dillard or if we are unable to successfully recruit qualified managerial and field personnel having experience in oil and gas exploration, our operations could suffer.

Success depends to a significant extent upon the continued services of Randy M. Griffin, our Chief Executive Officer, and Rachel L. Dillard, our Chief Financial Officer. Loss of the services of either of these officers could have a material adverse effect on growth, revenues and prospective business. We currently do not have key-man insurance covering either of these officers. In order to successfully implement and manage our business plan, we will be dependent upon, among other things, successfully recruiting qualified managerial and field personnel having experience in the oil and gas development and production business. Competition for qualified individuals is intense. There can be no assurance that we will be able to find and attract new employees and retain existing employees or that we will be able to find, attract and retain qualified personnel on acceptable terms.

Our directors and executive officers control a significant portion of our stock and, if they choose to vote together, would have sufficient voting power to have a significant impact on substantially all corporate matters.

As of March 31, 2015, our directors and executive officers beneficially owned approximately 24.3% of our outstanding common stock in the aggregate. Our directors and executive officers, in their capacities as stockholders, may have significant influence over our policies and affairs, including the election of future directors. Should they act as a group, they would have substantial influence over the election of all of our directors and all other corporate matters.

We may have difficulty managing growth in our business.

Because of the relatively small size of our company, growth in accordance with our long-term business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we increase our activities and the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of required personnel could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

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Risks Relating to Our Industry:

Lower prices for oil reduce our ability to raise capital and generate cash flow, and this could have a material adverse effect on our revenue and profitability and on our ability to continue in business.

Benchmark West Texas Intermediate (“WTI”) crude prices peaked at $105 per barrel in 2014 but declined to approximately $45 per barrel at the end of March 2015. Our ability to generate cash flow from our oil producing properties and to raise capital to acquire new producing or exploration properties is directly affected by trends in oil prices. Any prolonged reduction in oil prices could depress the near-term levels of exploration, development, and production activity and well as the willingness of investment capital to enter the oil and gas exploration and production market. Perceptions of longer-term lower oil prices by investors and banking institutions that finance oil and natural gas companies could make it difficult for us to raise capital to complete our existing projects, to meet capital investment commitments and to commit to new exploration or production projects. These factors could have a material adverse effect on our financial position, revenue, and profitability. Additionally, the longer these low price trends continue, the greater the risk that we will not be able to continue as a viable business.

We may not be able to develop oil and gas reserves on an economically viable basis and our reserves and production may decline as a result.

To the extent that we succeed in discovering additional oil and/or natural gas reserves, we cannot assure that these reserves will be capable of production levels that are commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.

Future oil and gas exploration may involve unsuccessful efforts, not only from dry holes, but from wells that are marginally productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, they cannot be totally eliminated and could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.

Estimates of oil and natural gas reserves that we make may be inaccurate and our actual revenues may be lower than our financial projections.

We make estimates of oil and natural gas reserves using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, other capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. We depend to a significant degree on third-party engineering firms to evaluate our properties.

In addition, economic factors beyond our control such as interest rates and commodity prices will also impact the value of our reserves. The process of estimating oil and natural gas reserves is complex and requires us to use a number of assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from those we estimate. If actual production results vary substantially from our reserve estimates, this could materially reduce our revenues and result in the impairment of our oil and natural gas interests.

Subject to the above, third-party estimates of our proved reserves as of December 31, 2014 was 621,508 BOE compared to 5,234,550 BOE as of December 31, 2013. This decrease in proved reserves is primarily the result of our divestiture of our interest in TNRH, which held TNR, owner of our Louisiana properties, net of the addition of proved reserves in Kansas.

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Competitive industry conditions may negatively affect our ability to conduct operations.

We operate in the highly competitive areas of oil and gas exploration, development, and production. We compete with other oil and gas companies for the purchase of leases, most of which have materially greater economic resources than we do. These leases include exploration prospects as well as properties with proved reserves. Factors that affect our ability to compete in the marketplace include:

	·	our access to the capital necessary to drill wells and acquire properties;
	·	our ability to acquire and analyze seismic, geological and other information relating to a property;
	·	our ability to retain the personnel to properly evaluate seismic, geological and other information relating to a property;
	·	our ability to obtain pipe, drilling rigs and associated equipment and field personnel in a timely manner and at competitive prices;
	·	the location of, and our access to, pipelines and other facilities used to produce and transport oil and gas production;
	·	the standards we establish for the minimum projected return on an investment or our capital; and
	·	the availability of alternative fuel sources.

Our competitors include major integrated oil companies, independent energy companies, and affiliates of major interstate and intrastate pipelines and national and local gas gatherers, many of which possess greater financial, technological and other resources than we do.

Our decision to drill a prospect, whether developmental or exploratory, is subject to a number of factors and we may decide to alter our drilling schedule or not drill at all.

We describe our current properties and our plans to explore these properties in this report. Our proved properties are in various stages of evaluation and range from existing wells to be recompleted in other zones to drilling prospects which may require additional testing, data processing and interpretation. Whether we ultimately drill or continue to drill a prospect may depend on multiple factors, including, but not limited to, the following:

	·	acquisition and utilization of various evaluation technologies;
	·	material changes in oil or gas prices;
	·	the costs and availability of drilling rigs and equipment;
	·	the success or failure of wells drilled in comparable formations or which would use the same production facilities;
	·	availability and cost of capital;
	·	if warranted, our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; and
	·	decisions of our joint working interest owners, if any.

We are constantly gathering data about our prospects, and it is possible that additional information may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all. You should understand that our plans regarding our prospects are subject to change.

Weather, unexpected subsurface conditions, and other unforeseen hazards may adversely impact our ability to conduct business.

There are many operating hazards in exploring for and producing oil and gas, including:

	·	our drilling operations may encounter unexpected formations, pressures, lost circulation and/or other unforeseen conditions which could cause damage to equipment, personal injury or equipment failure;
	·	we may experience power outages, evacuation due to adverse weather conditions, labor disruptions, fire and/or equipment failures which could curtail or stop drilling or production; and
	·	we could experience blowouts, sour gas leakages, mechanical failures or damages to productive formations that may require a well to be re-drilled or other corrective action to be taken.

In addition, any of the foregoing may result in environmental damages for which we could be liable. We cannot offer assurance that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations.

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A shortage of drilling rigs and other equipment and geophysical service crews could hamper our ability to exploit any oil and gas resources we may acquire.

Competition for available drilling rigs and related services and equipment is intense. We may not be able to procure the necessary drilling rigs and related services and equipment, or the cost of such items may be prohibitive. Our ability to generate revenues from oil and gas production could be hampered as a result of this and our business could suffer.

Drilling wells could result in liabilities that could endanger our interests in our prospective properties and assets.

There are risks associated with the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, sour gas releases, fires and spills. The occurrence of any of these events could significantly reduce our future revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. We carry insurance with respect to these hazards as appropriate to our activities, but such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets. Moreover, we may not be able to maintain adequate insurance in the future at rates that are considered reasonable. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Decommissioning costs are unknown and may be substantial; unplanned costs could divert resources from other projects.

We are responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we may use for production of oil and gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We have a cash escrow account in place with the State of New York and a Letter of Credit in place with the State of Oklahoma for wells in those states. If decommissioning is required before economic depletion of these properties or if the actual cost of decommissioning exceeds the value of the escrow account or the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

Our inability to obtain necessary facilities and equipment could hamper our operations.

Oil and natural gas exploration and development activities are dependent on the availability and cost of drilling and related equipment, transportation, power and technical support in the particular areas where these activities will be conducted. To the extent that we conduct our activities in remote areas or “in the water” environments, needed facilities may not be proximate to these areas which will increase our expenses. Demand for limited equipment and facilities or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. The quality and reliability of necessary facilities may also be unpredictable and we may be required to make efforts to standardize our facilities, which may entail unanticipated costs and delays. Shortages and/or the unavailability of necessary equipment or other facilities will impair our activities, either by delaying our activities, increasing our costs or both.

Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our business.

Oil and natural gas prices will continue to fluctuate in the future. Price fluctuations could have, and are presently having, a significant impact upon our revenue, the return from our reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and gas industry. We currently have no hedge positions in place for our oil and gas production, and decreases in the prices of oil and natural gas will continue to have a material adverse effect on our consolidated financial condition, the future results of our operations, quantities of reserves recoverable on an economic basis, and our ability to acquire and fund the acquisition of reserves to replace the Louisiana reserves sold to Gulfstar, develop proved reserves, and complete the Bear Creek #1 well in Wyoming.

Compliance with environmental and other government regulations could be costly and could negatively impact production.

Our operations are subject to numerous federal, state and local laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

	·	require that we acquire permits before commencing drilling;
	·	restrict the substances that can be released into the environment in connection with drilling and production activities;
	·	limit or prohibit drilling activities on protected areas such as wetland or wilderness areas; and
	·	require remedial measures to mitigate pollution from former operations, such as dismantling abandoned production facilities.

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Under these laws and regulations, we could be liable for personal injury and cleanup costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from some or all of our properties in the event of significant environmental damage.

Factors beyond our control affect our ability to market production and our financial results.

The ability to market oil and gas produced from our wells depends upon numerous factors beyond our control. These factors include:

	·	the extent of domestic production and imports of oil and gas;
	·	the proximity of the gas production to gas pipelines;
	·	the availability of pipeline capacity;
	·	economic conditions experienced by commodity buyers;
	·	the demand for oil and gas by utilities and other end users;
	·	pipeline curtailments and/or delays;
	·	the availability of alternative fuel sources;
	·	the effects of inclement weather;
	·	state and federal regulation of oil and gas marketing; and
	·	federal regulation of gas sold or transported in interstate commerce.

Additionally, world prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls, or any combination of these and other factors, and respond to changes in domestic, international, political, social, and economic environments. Also, due to worldwide economic uncertainty, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project. These changes and events may, and currently do, materially adversely affect our financial performance.

Because of these factors, we may continue to be unable to obtain favorable prices of the oil and gas that we might produce until such time as the oil market resets and prices rise to previous levels.

Our insurance may be inadequate to cover liabilities we may incur.

Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although we carry insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to us. If we suffer a significant event or occurrence that is not fully insured, or if the insurer of such event is not solvent, we could be required to divert funds from capital investment or other uses towards covering our liability for such events.

Oil and gas operations are subject to comprehensive regulation which may cause substantial delays or require capital outlays in excess of those anticipated causing an adverse effect on our company.

Oil and gas operations are subject to federal, state, and local laws relating to the protection of the environment, including laws regulating the removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to federal, state, and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government bodies are required for drilling and production operations to be conducted and no assurance can be given that such permits will be received. Environmental standards imposed by federal, provincial, or local authorities may be changed and any such changes may have material adverse effects on our activities. Moreover, compliance with such laws may cause substantial delays or require capital outlays in excess of those anticipated, thus causing an adverse effect on us. Additionally, we may be subject to liability for pollution or other environmental damages. We generally maintain insurance coverage customary to the industry; however, we are not fully insured against all possible environmental risks. To date we have not been required to spend any material amount on compliance with environmental regulations. However, we may be required to do so in the future and this may affect our ability to expand or maintain our operations.

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Drilling activities are subject to certain environmental regulations which may prevent or delay the commencement or continuance of our operations.

In general, our drilling activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. Such laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Compliance with these laws and regulations has not had a material effect on our consolidated results of operations or financial condition to date. Specifically, we are subject to legislation regarding emissions into the environment, water discharges and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. However, such laws and regulations are frequently changed and we are unable to predict the ultimate cost of compliance. Generally, environmental requirements do not appear to affect us any differently or to any greater or lesser extent than other companies in the industry.

We believe that our operations comply, in all material respects, with all applicable environmental regulations.

Risks Relating to Our Common Stock:

There has been a limited trading market for our common stock.

From time to time, the lack of an active market may impair your ability to sell your shares at the time you wish to sell them or at a price that you consider reasonable. The lack of an active market may also reduce the fair market value of your shares. An inactive market could also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire additional properties or other companies by using common stock as consideration.

You may have difficulty trading and obtaining quotations for our common stock.

Our common stock is considered to be a thinly traded stock and the bid and asked prices may fluctuate widely. As a result, investors may find it difficult to dispose of or to obtain accurate quotations of the price of our securities. This severely limits the liquidity of the common stock and could reduce the market price of our common stock and hamper our ability to raise additional capital.

Our common stock is not currently traded at high volume, and you may be unable to sell at or near ask prices or at all if you need to sell or liquidate a substantial number of shares at one time.

Our common stock is currently traded with relatively low volume, meaning that the number of persons interested in purchasing our common stock at or near bid prices at any given time may be relatively small. This situation is attributable to a number of factors, including the fact that we are a small company which is still relatively unknown to stock analysts, stock brokers, institutional investors and others in the investment community that generate or influence sales volume, and that even if we came to the attention of such persons, they tend to be risk-averse and would be reluctant to follow an unproven company such as ours or purchase or recommend the purchase of our shares until such time as we became more seasoned and viable. As a consequence, there may be periods when trading activity in our shares is minimal as compared to a seasoned issuer which has a large and steady volume of trading activity that will generally support continuous sales without an adverse effect on share price. We cannot give you any assurance that a broader or more active public trading market for our common stock will develop or be sustained, or that trading levels will be sustained.

Shareholders should be aware that, according to Commission Release No. 34-29093, the market for “penny stocks” has suffered in recent years from patterns of fraud and abuse. Such patterns include (1) control of the market for the security by one or a few broker-dealers that are often related to the promoter or issuer; (2) manipulation of prices through prearranged matching of purchases and sales and false and misleading press releases; (3) boiler room practices involving high-pressure sales tactics and unrealistic price projections by inexperienced sales persons; (4) excessive and undisclosed bid-ask differential and markups by selling broker-dealers; and (5) the wholesale dumping of the same securities by promoters and broker-dealers after prices have been manipulated to a desired level, along with the resulting inevitable collapse of those prices and with consequent investor losses. Our management is aware of the abuses that have occurred historically in the penny stock market. Although we do not expect to be in a position to dictate the behavior of the market or of broker-dealers who participate in the market, management will strive within the confines of practical limitations to prevent the described patterns from being established with respect to our securities. The occurrence of these patterns or practices could increase the future volatility of our share price.

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The market price of our common stock is likely to be highly volatile and subject to wide fluctuations.

The market price of our Common Stock is likely to be highly volatile and could be subject to wide fluctuations in response to a number of factors, some of which are beyond our control, including:

dilution caused by our issuance of additional shares of Common Stock and other forms of equity securities in connection with future capital financings to fund our operations and growth, to attract and retain valuable personnel and in connection with future strategic partnerships with other companies;

quarterly variations in our revenues and operating expenses;

changes in the valuation of similarly situated companies, both in our industry and in other industries;

changes in analysts’ estimates affecting our company, our competitors and/or our industry;

changes in the accounting methods used in or otherwise affecting our industry;

additions and departures of key personnel;

fluctuations in interest rates and the availability of capital in the capital markets; and

the sale of large blocks of our common stock.

These and other factors are largely beyond our control, and the impact of these risks, singly or in the aggregate, may result in material adverse changes to the market price of our Common Stock and/or our results of operations and financial condition.

We have not paid dividends in the past and do not expect to pay dividends in the future. Any return on investment may be limited to the value of our common stock.

We have never paid cash dividends on our common stock and do not anticipate paying cash dividends in the foreseeable future. The payment of dividends on our common stock will depend on earnings, financial condition and other business and economic factors affecting it at such time as the Board of Directors may consider relevant.

You may experience dilution of your ownership interests because of the future issuance of additional shares of our common stock.

In the future, we may issue additional authorized but previously unissued equity securities resulting in the dilution of the ownership interests of our present and future stockholders. We are currently authorized to issue an aggregate of 101,000,000 shares of capital stock comprising 100,000,000 shares of common stock and 1,000,000 shares of preferred stock with preferences and rights to be determined by our Board of Directors. As of March 31, 2015, there were 56,605,473 shares of our common stock and no shares of our preferred stock outstanding. There are 5,000,000 shares of our common stock reserved for issuance under our 2012 Long-Term Incentive Plan. Shares issued and outstanding do not include shares of our common stock issuable upon the exercise of outstanding options and warrants.

Any future issuance of our equity or equity-backed securities may dilute then-current stockholders’ ownership percentages and could also result in a decrease in the fair market value of our equity securities, because our assets would be owned by a larger pool of outstanding equity. As described above, we may need to raise additional capital through public or private offerings of our common or preferred stock or other securities that are convertible into or exercisable for our common or preferred stock. We may also issue such securities in connection with hiring or retaining employees and consultants (including stock options issued under our equity incentive plans), as payment to providers of goods and services, in connection with future acquisitions or for other business purposes. Our Board of Directors may at any time authorize the issuance of additional common or preferred stock without common stockholder approval, subject only to the total number of authorized common and preferred shares set forth in our certificate of incorporation. The terms of equity securities issued by us in future transactions may be more favorable to new investors, and may include dividend and/or liquidation preferences, superior voting rights and the issuance of warrants or other derivative securities, which may have a further dilutive effect. Also, the future issuance of any such additional shares of common or preferred stock or other securities may create downward pressure on the trading price of the common stock. There can be no assurance that any such future issuances will not be at a price (or exercise prices) below the price at which shares of the common stock are then traded.

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We may obtain additional capital through the issuance of preferred stock, which may limit your rights as a holder of our Common Stock.

Without any stockholder vote or action, our Board of Directors may designate and approve for issuance shares of our preferred stock. The terms of any preferred stock may include priority claims to assets and dividends and special voting rights which could limit the rights of the holders of our common stock. The designation and issuance of preferred stock favorable to current management or stockholders could make any possible takeover of the Company or the removal of our management more difficult.

Legislative actions, higher insurance costs and potential new accounting pronouncements may impact our future financial position and results of operations.

There have been regulatory changes, including the Sarbanes-Oxley Act of 2002, and there may potentially be new accounting pronouncements or additional regulatory rulings that will have an impact on our future financial position and results of operations. The Sarbanes-Oxley Act of 2002 and other rule changes as well as proposed legislative initiatives following the Enron bankruptcy are likely to increase general and administrative costs and expenses. In addition, insurers are likely to increase premiums as a result of high claims rates over the past several years, which we expect will increase our premiums for insurance policies. Further, there could be changes in certain accounting rules. These and other potential changes could materially increase the expenses we report under generally accepted accounting principles, and adversely affect our operating results.

If securities analysts do not initiate coverage or continue to cover our common stock or publish unfavorable research or reports about our business, this may have a negative impact on the market price of our common stock.

The trading market for our common stock may be affected by, among other things, the research and reports that securities analysts publish about our business and our company. We do not have any control over these analysts. There is no guarantee that securities analysts will cover our common stock. If securities analysts do not cover our common stock, the lack of research coverage may adversely affect its market price. If we are covered by securities analysts, and our stock is the subject of an unfavorable report, our stock price and trading volume would likely decline. If one or more of these analysts ceases to cover our company or fails to publish regular reports on us, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.

Efforts to comply with recently enacted changes in securities laws and regulations will increase our costs and require additional management resources.

As directed by Section 404 of the Sarbanes-Oxley Act of 2002, the SEC adopted rules requiring public companies to include a report of management on their internal controls over financial reporting in their annual reports on Form 10-K. In addition, in the event we are no longer a smaller reporting company, the independent registered public accounting firm auditing our financial statements would be required to attest to the effectiveness of our internal controls over financial reporting. Such attestation requirement by our independent registered public accounting firm would not be applicable to us until the report for the year ended December 31 2015, at the earliest, if at all.

Our common stock is subject to the "penny stock" rules of the SEC and the trading market in our securities is limited, which makes transactions in our stock cumbersome and may reduce the value of an investment in our stock.

The SEC has adopted Rule 15g-9 which establishes the definition of a "penny stock," for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

	·	that a broker or dealer approve a person's account for transactions in penny stocks; and
	·	the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person's account for transactions in penny stocks, the broker or dealer must:

	·	obtain financial information and investment experience objectives of the person; and
	·	make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form:

	·	sets forth the basis on which the broker or dealer made the suitability determination; and
	·	that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

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Generally, brokers may be less willing to execute transactions in securities subject to the "penny stock" rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

FINRA sales practice requirements may also limit a shareholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

The information set forth above under “Business” relating to our oil and gas properties is incorporated herein by reference.

Our corporate offices are currently located in Spring Valley Center, a six-story office complex at 5220 Spring Valley Road, Dallas, Texas 75254. The current lease for our corporate office space (Suite 615) expires on July 31, 2015. The existing office space covers 5,229 square feet with a monthly rent of $7,390. Of that total, 767 square feet are currently subleased for a monthly rent of $1,085.

ITEM 3.

LEGAL PROCEEDINGS

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. Litigation is subject to inherent uncertainties, and an adverse result in these or other matters that may arise from time to time that may harm business. To the best of our knowledge, there is currently no pending legal proceeding and, as far as we are aware, no governmental authority is contemplating any proceeding to which we are a party or to which any of our properties is subject.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Price Range of Common Stock

Our common stock is currently traded on the OTC Markets, Inc. QB Tier under the symbol “AOIL.” The following table sets forth the high and low closing prices per share of common stock for the quarters indicated.

	Fiscal Year 2013
	High		Low
First Quarter	$	0.84	$	0.50
Second Quarter	$	0.53	$	0.27
Third Quarter	$	0.35	$	0.25
Fourth Quarter	$	0.27	$	0.16

	Fiscal Year 2014
	High		Low
First Quarter	$	0.24	$	0.17
Second Quarter	$	0.22	$	0.16
Third Quarter	$	0.22	$	0.17
Fourth Quarter	$	0.20	$	0.06

On March 27, 2015, the closing sale price of our common stock was $0.05 per share and there were approximately 191 holders of record of our common stock.

Dividends

We have never paid any cash dividends on our capital stock and do not anticipate paying any cash dividends on our common stock in the foreseeable future. Also, the terms of our convertible promissory notes restrict our ability to pay dividends. We intend to retain future earnings to fund ongoing operations and future capital requirements of our business. Any future determination to pay cash dividends will be at the discretion of the Board of Directors and will be dependent upon our financial condition, results of operations, capital requirements and such other factors as the Board of Directors deems relevant.

Securities Authorized for Issuance Under Equity Compensation Plans

On September 30, 2002, the stockholders of the Company approved its 2002 Incentive Stock Plan (the “2002 Plan”), which had 4,000,000 shares reserved for issuance thereunder. The 2002 Stock Plan expired in September 2012. In anticipation of its expiration, by way of Unanimous Written Consent dated April 27, 2012, the Board of Directors approved the terms and provisions of the 2012 Long-Term Incentive Plan (“2012 Incentive Plan”). The 2012 Incentive Plan was approved by shareholders owning the majority of the Company’s shares of common stock and became effective on May 1, 2012, The 2012 Incentive Plan allows for awards of up to an aggregate of 5,000,000 shares of our common stock, subject to adjustment under certain circumstances. The 2012 Incentive Plan provided shares available for options granted to employees, directors, and others. Stock options granted under the 2012 Incentive Plan generally vest over one to five years or as otherwise determined by the Board of Directors or committee of the Board of Directors. Options to purchase shares of common stock expire no later than ten years after the date of grant. As of March 31, 2015, we have outstanding option awards under the 2012 Incentive Plan of 3,602,000 shares of our common stock, of which vested options are currently exercisable for an aggregate of 3,197,000, shares of our common stock; and our Board of Directors has granted awards of restricted stock with respect to an aggregate of 587,987 shares. We have not maintained any other equity compensation plans since our inception.

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The following table provides information as of December 31, 2014, with respect to the shares of common stock that may be issued under our existing equity compensation plans:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (2)
	(a)		(b)		(c)
Equity compensation plans approved by security holders (1)		3,602,000	$	0.38		810,013
Equity compensation plans not approved by security holders		—		—		—
Total		3,602,000	$	0.38		810,013

	(1)	2012 Long-Term Incentive Plan
	(2)	Net of 587,987 shares awarded as restricted stock grants.

Stock Transfer Agent

Our Stock Transfer Agent is Broadridge Corporate Issuer Solutions, Inc., located at 51 Mercedes Way, Edgewood, NY 11717.

Sales of Unregistered Equity Securities

Except as previously disclosed in Quarterly Reports on Form 10-Q or Current Reports on Form 8-K that we have filed, or otherwise set forth below, during the period covered by this Report we have not sold any of our equity securities that were not registered under the Securities Act of 1933, as amended (the “Securities Act”).

ITEM 6.

SELECTED FINANCIAL DATA

Not required under for smaller reporting companies.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – GOING CONCERN

The following discussion and analysis of financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements that involve risks, uncertainties and assumptions. See “Note Regarding Forward-Looking Statements.” Our actual results could differ materially from those anticipated in the forward-looking statements as a result of certain factors discussed in “Risk Factors” and elsewhere in this Annual Report on Form 10-K.

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. The discussion should be read in conjunction with our audited financial statements and related notes and the other financial information included elsewhere in this report.

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 December 31, 2014, has a working capital deficit at December 31, 2014, of $6,147,652 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 such acquisitions. 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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Adjusted EBITDA as a Non-GAAP Performance Measure

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

The following is a reconciliation of our net income in accordance with GAAP to our Adjusted EBITDA for the years ended December 31, 2014 and 2013:

	2014			2013

Net income (loss)	$	1,652,013		$	(11,369,765	)

Add:

Interest (income) expense, net		636,626			795,360
Amortization of deferred financing costs		64,658			56,292
Income tax (benefit) expense		2,315,220			(1,766,140	)
Depreciation, depletion, accretion and impairment		1,047,229			1,231,340
Dry hole expense		--			2,591,770
Impairment of goodwill		--			8,536,758
Gain on settlement of asset retirement obligation		--			(3,428	)
Loss on change in commodity derivative instruments		167,673			251,876
Loss on modification of offering terms		--			65,749
Loss on sales of oil and gas properties		539,248			86,116
Gain on sale of member interest in TNRH		(7,395,119	)		--
Share-based compensation		206,027			737,822

Adjusted EBITDA	$	(766,425	)	$	1,213,750

Recent Developments

As part of the execution of our business strategy discussed in Item I, above, we have recently taken the following steps:

	·	On December 20, 2013, we entered into a Unit Purchase Agreement with Gulfstar Resources, LLC, designed to provide additional development capital for our Louisiana properties as well as to allow us to reallocate a portion of our asset base to other operating areas. Under the terms of this agreement, we completed a first tranche closing in which we received $6,250,000 in exchange for a 34.375% interest in TNRH.
	·	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. The funds received from the closing of Tranche B were primarily used to purchase the Kansas properties as discussed below.
	·	On March 14, 2014, Armada Midcontinent, LLC, (f/k/a MMC Resources, LLC) a wholly owned subsidiary of MEI, entered into a purchase and sale agreement with Piqua Petro, Inc., pursuant to which Armada Midcontinent, LLC agreed to purchase from Piqua Petro its interests in six oil and gas leases covering approximately 1,040 acres in Woodson County, Kansas. This purchase, effective March 1, 2014, was consummated on April 11, 2014, for $6,285,106.
	·	On May 16, 2014 and June 16, 2014, the Company sold an additional 1,400 and 2,380 units of TNRH membership interest 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. As a result of this sale, the Company’s interest in TNRH was reduced to 27.124%.
	·	On November 26, 2014, the Company sold its remaining interest in TNRH, comprising 8,152 Member Units, to Gulfstar, receiving $5,012,502 in cash at $614.88 per Unit, of which $4,600,000 was applied to the principal balance of its note with Prosperity Bank thereby reducing the balance on the Company’s loan under the credit facility from $8,072,693 to $3,472,693.

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	·	On October 16, 2014, the Company entered into a purchase and sale agreement with Tabbs Bay Energy, LP, a Texas limited partnership (“TBELP”), pursuant to which we planned to purchase from the seller its interests in, and assume certain of its obligations under, eight oil and gas leases covering approximately 576 acres in Harris County, Texas, with total production of approximately 190 net barrels of oil per day. We had a term sheet for a comprehensive financing facility that would not only have financed the acquisition but would also have provided capital for drilling in Kansas and completing the Bear Creek # 1 well. As a result of the precipitous drop in commodity prices that occurred in late November 2014 ultimately causing a dramatic change in the economics of the acquisition, we were forced to terminate the transaction and the financing effort.
	·	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.

Results of Operations for the Fiscal Year Ended December 31, 2014 Compared to Fiscal Year Ended December 31, 2013

Revenue

The following table summarizes our revenues from commodity sales during the years ended December 31, 2014 and 2013.

	Years Ended
	December 31,							Percentage
	2014		2013		Difference			Change

Revenues
Oil	$	3,866,939	$	10,321,582	$	(6,454,643	)		(62.5	%)
Natural gas		509,081		1,777,673		(1,268,592	)		(71.4	%)
Natural gas liquids		23,594		186,567		(162,973	)		(87.4	%)
Total	$	4,399,614	$	12,285,822	$	(7,886,208	)		(64.2	%)

Sales volumes
Oil (Bbls)		40,227		100,126		(59,899	)		(59.8	%)
Natural gas (MCF)		95,908		456,113		(360,205	)		(79.0	%)
Natural gas liquids (Bbls)		606		4,529		(3,923	)		(86.6	%)
Total BOE		56,818		180,674		(123,857	)		(68.6	%)
Total BOE/day		156		495		(339	)		(217.0	%)

Average prices
Oil (per Bbl)	$	96.13	$	103.09	$	(6.96	)		(6.8	%)
Natural gas (per MCF)		5.31		3.90		1.41			36.2	%
Natural gas liquids (per Bbl)		38.93		41.20		(2.27	)		(5.5	%)
Total per BOE	$	77.43	$	68.00	$	9.43			13.9	%

Revenues from commodity sales decreased during the year ended December 31, 2014, over the year ended December 31, 2013, due to the divestiture of our interest in our Louisiana production as well as lower oil prices.

In addition to revenues from commodity sales, during the year ended December, 2014, we had $51,213 of revenue from lease fuel, marketing, compression and transportation fees, and production handling fees for a third party. During the year ended December 31, 2013, we had $150,388 of such income. The decrease over 2013 is attributable to lower sales volumes with which some of the fees are associated as well as elimination of overhead income and compression fee income. All of this decrease is primarily attributable to the divestiture of our interest in Louisiana production.

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Operating Expenses

Operating expenses for the years ended December 31, 2014 and 2013 are set forth in the table below.

	Years Ended
	December 31,								Percentage
	2014		2013			Difference			Change

Costs and Expenses
Lease operating expense (1)	$	1,792,583	$	6,006,287		$	(4,213,704	)		(70.2	%)
Production and ad valorem taxes (2)		368,061		1,464,680			(1,096,619	)		(74.9	%)
Environmental remediation expense (3)		252,135		—			252,135			N/A
Exploration expense		232,012		284,275			(52,263	)		(18.4	%)
Dry hole expense (4)		—		2,591,770			(2,591,770	)		(100.0	%)
Depletion, depreciation, amortization, and impairment expense (5)		1,047,229		1,231,340			(184,111	)		(15.0	%)
Loss on sale of oil and gas properties (6)		539,248		86,116			453,132			526.2	%
(Gain) loss on settlement of asset retirement obligation (7)		—		(3,428	)		3,428			(100.0	%)
Impairment of goodwill (8)		—		8,536,758			(8,536,758	)		(100.0	%)
General and administrative expense (9)		2,868,891		4,469,260			(1,600,369	)		(35.8	%)
Total operating expenses	$	7,100,159	$	24,667,058		$	(17,566,899	)		(71.2	%)

(1)	Divestiture of our interest in Louisiana assets.
(2)	Divestiture of our interest in Louisiana assets.
(3)	Oil spill in Louisiana in first quarter of 2014.
(4)	2013 mechanical failure in the drilling of the Thomas #6H well in Oklahoma.
(5)	Divestiture of our interest in Louisiana assets.
(6)	2014 loss on sale of Oklahoma assets and 2014 writeoff of production payment receivable from 2013 sale of Young County, Texas, assets net of 2014 gain on sale of Grayson County leasehold as compared to 2013 sale of Lake Hermitage Camp in Louisiana for less than net book value.
(7)	2013 gain of $1,328 on the settlement of an asset retirement obligation when the State of Louisiana returned a deposit on a well that had been plugged and abandoned when acquired, the obligation on which we had assumed at acquisition, and a 2013 gain of $2,100 on the retirement of the asset retirement obligations upon the sale of our Archer and Young County, Texas, properties.
(8)	2013 impairment of goodwill attributable to acquisition of Armada due to revision of tax basis in assets acquired.
(9)	Attributable to divestiture of our Louisiana assets resulting in decreased payroll and office expense as well as decreased 2014 stock compensation expense compared to that for 2013.

Operating expenses expressed in BOE for the years ended December 31, 2014 and 2013 are set forth in the table below:

	Years Ended
	December 31,								Percentage
	2014		2013			Difference			Change

Costs and Expenses
Lease operating expense	$	31.55	$	33.24		$	(1.69	)		(5.1	%)
Production and ad valorem taxes		6.48		8.11			(1.63	)		(20.1	%)
Environmental remediation expense		4.44		—			4.44			N/A
Exploration expense		4.08		1.57			2.51			159.9	%
Dry hole expense		—		14.35			(14.35	)		(100.0	%)
Depletion, depreciation, amortization, and impairment expense		18.43		6.81			11.62			170.6	%
Loss on sale of oil and gas properties		9.49		0.48			9.01			1,877.1	%
Gain on settlement of asset retirement obligation		—		(0.02	)		0.02			100.0	%
Impairment of goodwill		—		47.25			(47.25	)		(100.0	%)
General and administrative expense		50.49		24.74			25.75			104.1	%
Total operating expenses	$	124.96	$	136.53		$	(11.57	)		(8.5	%)

Operating (income) loss. As a result of the above described revenues and expenses, we incurred an operating loss of $2,649,332 during the year ended December 31, 2014 as compared to operating loss of $12,230,848 during the year ended December 31, 2013.

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Interest expense. Interest expense decreased to $701,435 for the year ended December 31, 2014, from $822,335 for the year ended December 31, 2013. This decrease was primarily attributable to the $4.75 million of payments made on the principal balance of our revolving loan under our Credit Facility with Prosperity Bank and payment in full of five notes, totaling $155,000, associated with a private placement of securities.

Loss on change in derivative value – commodity contracts. The unrealized loss on change in derivatives – commodity contracts for the years ended December 31, 2014 and 2013, was $167,673 and $251,876, respectively. The unrealized losses were the result of the changes in the fair value of the net derivative liability from that of the prior reporting period. The values underlying the derivatives are estimates of predicted future commodity prices based on current market activity and projections of future market activity. Additional contributors to fluctuations in the value of the recognized net liability are additions to and unwindings of hedged positions during any reporting period.

Realized gain (loss) on commodity contracts. Cash settlements from hedging our sales of oil and gas production were $165,511 payment to our counterparty in the year ended December 31, 2014 as compared to $216,100 payment from our counterparty in the year ended December 31, 2013. The change is attributable to the same factors that affect the unrealized gains or losses associated with our commodity derivative contracts except that projections of future market activity are not included in the calculation of these realized gains and losses.

Loss on modification of offering. A loss on the modification of a prior offering of shares and warrants of $65,749 was incurred during the year ended December 31, 2013. The loss was the result of a change in fair value of shares and warrants issued in relation to the funds raised as well as a decrease in the exercise price of the warrants issued in conjunction with the offering prior to the modification. No such loss occurred during the year ended December 31, 2014.

Gain on sale of subsidiaries. During the year ended December 31, 2014, a gain of $7,395,119 was recognized on the sale of TNRH to Gulfstar. No sale of subsidiaries occurred during the year ended December 31, 2013.

Income tax benefit (expense). State and federal income tax expense for the year ended December 31, 2014 was $2,315,219 compared to income tax benefit of $1,766,140 in the year ended December 31, 2013. The income tax expense in the year ended December 31, 2014 is primarily attributable to the gain on sale of our interest in TNRH. The income tax benefit for the year ended December 31, 2013, is attributable to a net loss during that period.

Net income/loss. Due to the reasons set forth above, our net income after income tax benefit (expense) for the year ended December 31, 2014 was $1,652,013 ($0.03 per basic and diluted common share). Our net loss after income tax expense for the year ended December 31, 2013 was $11,369,765 ($0.22 per basic and diluted common share).

Liquidity and Capital Resources

Overview

As of December 31, 2014, we had a working capital deficit of $6,147,652. As of December 31, 2013, we had a working capital deficit of $2,310,297. The decrease of $3,387,355 in working capital was attributable to a decrease in current assets of $8,283,330 and a decrease in current liabilities of $4,445,975, as follows:

	Decrease in total current assets:
	·	Decrease in cash of $6,689,666 primarily used to acquire and develop oil and gas properties
	·	Decrease in accounts receivable-oil and gas of $1,440,494 as a result of selling our interest in TNRH
	·	Net decreases of $153,170 in accounts receivable-other, net current deferred financing costs, current deferred tax asset, and prepaid expenses

	Decrease in total current liabilities:
	·	Net increases in accounts payable and revenue payable of $290,422 as a result developing new unproved oil and gas properties and selling producing properties
	·	Net increase in notes payable to related parties of $97,824
	·	Increases in accrued expenses and other current liabilities of $63,599
	·	Increase in stock payable of $43,065 for services of a consultant
	·	Net decrease in current notes payable of $4,767,079 which includes $4.75 million in payments on the principal balance of our debt to Prosperity Bank and retirement of $155,000 of notes associated with a 2013 private placement of securities.
	·	Decrease in current derivative liability on commodity contracts of $173,806

Our cash and accounts receivable-oil and gas balances decreased primarily as a result of our sale of our interest in TNRH which resulted in the loss of cash flow provided by revenue generated by commodity sales of the Louisiana properties.

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As of December 31, 2014, the outstanding balance of principal and accrued interest on debt was $4,206,216, a net decrease of $4,794,654 from the outstanding balance of $9,000,870 as of December 31, 2013. This net decrease was primarily due to repayment of $4.75 million principal on our debt to Prosperity Bank, $155,000 of notes issued in conjunction with a private placement commenced in 2013 prior to the Acquisition, and payments on premium financed notes for the purchase of insurance, net of a $200,000 increase in debt associated with notes issued in conjunction with a contemplated funding and acquisition transaction in the fourth quarter which did not occur. $100,000 of the $200,000 in debt was provided by Sycamore Resources, Inc., an entity controlled by Randy M. Griffin.

Our December 31, 2014, reserve report based on the SEC pricing case makes various assumptions regarding the pace of development of our proved undeveloped reserves. In order to develop these reserves on the schedule assumed in the reserve report, the capital expenditure requirement for 2015 would be $1.68 million. It is our intent to establish a new comprehensive credit facility as part of the acquisition of additional properties and to include the drilling and completion budget referenced above in that facility. There are no assurances, however, that we will be successful in this financing effort.

There are multiple factors that can affect these estimates including changes in commodity prices, adverse weather conditions and unforeseen events, both inside and outside of our business. In the event that a new credit facility is not put in place or that other unforeseen circumstances create a shortfall in the capital expenditure budget, other potential sources of funds to support the development effort include:

	·	The establishment of joint ventures with other operators or financing sources;
	·	Additional debt financing; and
	·	Additional equity offerings.

If, however, cash flow plus the additional sources outlined above are not sufficient to support our portion of the capital expenditure budget outlined in the reserve report, our ability to execute our plan of operations could be negatively impacted and drilling activity could be reduced.

Cash and Accounts Receivable

At December 31, 2014, we had cash in bank of $406,306, compared to $7,095,972 at December 31, 2013. The $6,689,666 decrease in cash was due primarily to our sale of our interest in TNRH, which resulted in the loss of cash flow provided by revenue generated by commodity sales of the Louisiana properties, and cash spent to acquire and develop oil and gas properties.

At December 31, 2014, we had accounts receivable of $184,468, compared to $1,557,161 at December 31, 2013. The $1,372,693 decrease in accounts receivable was due primarily to our sale of our interest in TNRH which resulted in decreased sales of oil and gas production from its Louisiana properties. At December 31, 2014, $84,129 of our accounts receivable was accrued December revenue from the sale of production from our Kansas properties, and $100,000 was the refundable earnest money deposit on the nonconsummated acquisition.

Liabilities

Accounts payable and accrued expenses increased by $297,334 to $2,523,456 at December 31, 2014, from $2,226,122 at December 31, 2013. The increase is due primarily to an increase of $705,528 in accounts payable net of a $415,106 reduction in revenue payable. Accounts payable increased primarily due to our 2014 drilling activity on the Bear Creek #1 well in Wyoming, net of a decrease in accounts payable due to our divestiture of our interest in TNRH. Revenue payable decreased primarily due to the divestiture of our interest in TNRH. Of the accounts payable and accrued expenses at December 31, 2014, $1,951,309 and $69,417, for a total of $2,020,726 represents costs associated with drilling the Bear Creek #1 well. Of these, three vendors have recorded liens against our Bear Creek #1 wellbore in accordance with Wyoming Statutes 29-1-312 and 29-3-106. Interest has been accrued on one in the amount of $27,541, which is in addition to the $69,417 accrued for drilling costs. These unpaid liabilities are aged from 66 days to 97 days, and we lack the liquidity to pay them until we obtain additional capital.

Cash Flows

For the year ended December 31, 2014, the net cash used in operating activities was $1,024,278, as compared to cash provided by operating activities of $483,676 at December 31, 2013. The effect of the deconsolidation of the TNRH assets from our balance sheet is not reflected in the cash used for operating activities but is, instead, reflected as a source of cash in cash used in investing activities.

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For the year ended December 31, 2014, net cash used in investing activities was $704,969 as compared to cash used for investing activities of $2,855,588 in 2013. Cash used comprised primarily the purchase of our Woodson County, Kansas, properties and cash paid for the drilling of the Bear Creek #1 well in Wyoming. Cash provided by investing activities included cash received for the deconsolidation of subsidiary upon the sale of our controlling interest in TNRH and the subsequent sale of our cost basis investment in TNRH.

For the year ended December 31, 2014, net cash used for financing activities was $4,960,419 comprising primarily repayments of $4.75 million of our debt to Prosperity Bank and $155,000 of notes issued pursuant to a private placement commenced before the Acquisition net of issuance of $200,000 in notes to two parties, one of which is an entity controlled by Randy M. Griffin which loaned us $100,000, to fund costs associated with a contemplated funding and acquisition which was to have occurred in the fourth quarter but did not.

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.

Critical Accounting Policies and Estimates

Our discussion of our financial condition and results of operations is based on the information reported in our financial statements. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities as of the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are described in Note 1 to our audited consolidated financial statements and notes thereto included in this Annual Report. We have outlined below certain of these policies that have particular importance to the reporting of our financial condition and results of operations and that require the application of significant judgment by our management.

Key Definitions

Proved reserves, as defined by the SEC, are the estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Valuations include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Prices do not include the effect of derivative instruments, if any, entered into by us.

Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods. Additional oil and gas volumes expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery would be included as proved developed reserves only after testing of a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves are those reserves that are expected to be recovered from new wells on non-drilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on non-drilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other non-drilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

Estimation of Reserves

Volumes of reserves are estimates that, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data as well as production performance data. There are numerous uncertainties in estimating crude oil and natural gas reserve quantities, projecting future production rates and projecting the timing of future development expenditures. Natural gas and oil reserve engineering must be recognized as a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. Estimates of independent engineers that we use may differ from those of other engineers. The accuracy of any reserve estimate is a function of the quantity and quality of available data and of engineering and geological interpretation and judgment. Accordingly, future estimates are subject to change as additional information becomes available.

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The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful efforts method of accounting, the calculation of depreciation, depletion and amortization of oil and gas properties and the estimate of any impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the annual year end disclosure of the related standardized measure of discounted future net cash flows.

Revenue Recognition

Revenues from the sale of crude oil and natural gas are recorded in the month the product is delivered to the purchaser at a fixed or determinable price, title transfers to the purchaser, and collectability is reasonably assured and evidenced by a contract. The Company generally receives payment from one to three months after the sale has occurred. Each month the Company estimates the volumes sold and the price at which they were sold to record revenue. Variances between estimated revenues and actual amounts are recorded in the month payment is received and are reflected in the Company’s Consolidated Statements of Operations as Revenue. These variances have historically not been material. The Company has no material imbalances resulting from natural gas sales, but if it did, it would use the sales method of accounting for natural gas imbalances. As a producer, the Company would adjust its reserves for gas imbalances. As a working interest owner, the Company would recognize an overproduced position as a liability on its balance sheet and an underproduced position as a receivable, to the extent collectible, from an overproduced owner.

Successful Efforts Accounting

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under the successful efforts method, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. The Company evaluates its proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. The Company follows Accounting Standards Codification ASC 360 - Property, Plant, and Equipment, for these evaluations. Unamortized capital costs are reduced to fair value if the undiscounted future net cash flows from our interest in the property’s estimated proved reserves are less than the asset’s net book value.

Impairment of Properties

We review our proved properties for potential impairment at the field level when management determines that events or circumstances indicate that the recorded carrying value of any of the properties may not be recoverable. Such events include a projection of future natural gas and oil reserves that will be produced from a well, the timing of this future production, future costs to produce the natural gas and oil, and future inflation levels. If the carrying amount of an asset exceeds the sum of the discounted estimated future net cash flows, we recognize impairment expense equal to the difference between the carrying value and the fair market value of the asset, which is estimated to be the expected discounted value of future net cash flows from reserves, without the application of any estimate of risk. We cannot predict the amount of impairment charges that may be recorded in the future. Unproved leasehold costs are reviewed periodically and impairment is recognized to the extent, if any, that the cost of the property has been impaired. We follow the Accounting Standards Codification ASC 360 Property, Plant, and Equipment, for these evaluations. Unamortized capital costs are reduced to fair value if the undiscounted future net cash flows from our interest in the property’s estimated proved reserves are less than the asset’s net book value.

Proved Reserves

Estimates of our proved reserves included in this report are prepared in accordance with accounting principles generally accepted in the United States of America and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and the impairment. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions; and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves. We engage independent reserve engineers to estimate our proved reserves.

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Share-Based Compensation

Compensation expense has been recorded for grants of restricted common stock and options based on the fair value of the common stock on the measurement date. We estimate the fair value of each stock option award at the grant date by using the Black-Scholes option pricing model. FASB ASC Topic No. 718-10 establishes standards for transactions in which an entity obtains employee services in share-based payment transactions. The guidance requires that the fair value of such equity instruments be recognized as expense in the historical financial statements as services are performed. Standards of accounting for transactions in which an entity exchanges its equity instruments for goods and services by a consultant or contractor are further governed by FASB ASC Topic No. 505-50 by which the grant is measured at the fair value of the stock exchanged and the associated expense is recorded according to the category of the goods received or service rendered.

Derivative Valuation

We estimate the fair value of financial assets and liabilities based on a three-level valuation hierarchy for disclosures of fair value measurement and enhance disclosure requirements for fair value measures.

The three levels are defined as follows:

	·	Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

	·	Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

	·	Level 3 - inputs to the valuation methodology are unobservable and significant to the fair value measurement.

All derivative instruments are recorded on the balance sheet at their fair value. Changes in the fair value of each derivative are recorded each period in current period earnings.

We do not apply hedge accounting, as our hedging program is designed only to comply with covenants underlying our credit facility with F&M Bank and not as a formal risk management program, and we do not monitor the effectiveness of the hedge. Realized gains and losses (i.e., cash settlements) are reported in the Statement of Operations. Similarly, changes in the fair value of unsettled derivative instruments are recorded as unrealized gains or losses in the Statement of Operations.

New Accounting Pronouncements

We do not expect the adoption of any recently issued accounting pronouncements to have a significant impact on our results of operations, financial position or cash flows.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required for smaller reporting companies.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our audited consolidated financial statements as of, and for the years ended, December 31, 2014 and 2013 are included beginning on Page F-1 immediately following the signature page to this report.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A.

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 (“Exchange Act”) as of December 31, 2014. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Based on management’s evaluation, our chief executive officer and chief financial officer concluded that, as a result of the material weaknesses described below, as of December 31, 2014, our disclosure controls and procedures are not effective and are not designed at a reasonable 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 December 31, 2014, we did not adequately segregate, or mitigate the risks associated with, incompatible functions among personnel to reduce the risk that a potential material misstatement of the financial statements would occur without being prevented or detected. Accordingly, management concluded that this control deficiency constituted a material weakness.

We are committed to improving our accounting and financial reporting functions. As part of this commitment, we have, from time to time, engaged additional 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 year ended December 31, 2014, as part of our cost cutting efforts related to the drop in the price of oil and the resulting decrease in our revenues, we reduced the size of our accounting staff and lost the services of our controller and revenue accountant.

Other than these events, there were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was not effective as of December 31, 2014 for the reason indicated above. The effectiveness of our internal control over financial reporting as of December 31, 2014 has not been audited by GBH CPAs, PC, our independent registered public accounting firm. Pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act, smaller reporting companies are exempt from the requirement that management’s report be subject to an audit by an independent registered public accounting firm.

ITEM 9B.

OTHER INFORMATION

None.

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PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Executive Officers and Directors

The names of our directors and executive officers and their ages, titles, and biographies as of March 27, 2015, unless otherwise indicated, are set forth below:

Name	Age	Title	Date First Appointed
Randy M. Griffin	61	Chairman of the Board and Chief Executive Officer	August 31, 2009
Rachel L. Dillard	63	Chief Financial Officer	September 19, 2011
J. Clint Unruh	36	Chief Operating Officer	April 4, 2013
Ray L. Unruh	68	Secretary and Director	August 31, 2009
James J. Cerna, Jr.	46	Director	January 5, 2010
Kenneth T. Hern	77	Director	January 27, 2010
Fred B. Zaziski	62	Director	January 5, 2010
Eric Wold	42	Director	March 28, 2013

Directors are elected to serve until the next annual meeting of stockholders and until their successors are elected and qualified. Executive officers are appointed by the Board of Directors and serve at its pleasure.

Certain biographical information for each of our executive officers and directors is set forth below.

Randy M. Griffin served as Chairman of the Board of Directors and Chief Executive Officer of Mesa from its founding in April of 2003 until the closing of the Mesa Acquisition in March of 2013, at which time he became Chairman of the Board of Directors and Chief Executive Officer of Armada. Mr. Griffin’s responsibilities include oversight of the business and administrative activities of the company, direction of the ongoing effort to identify potential acquisitions and evaluation of potential financing strategies.

From March 2001 until March 2003, Mr. Griffin was associated with a Dallas-based group of companies engaged in the development of a horizontal natural gas drilling project in Shelby County, Texas. His responsibilities included pipeline development, land management and lease acquisition. During that period, he was responsible for the negotiation and closing of the sale of that company’s natural gas production and undeveloped property in Shelby County, a divestiture valued at just under $30,000,000. In addition, he negotiated the acquisition of an acreage position in Hopkins County, Texas, and coordinated pipeline development and the drilling of a discovery well in that field.

Mr. Griffin brings 39 years of broad business development and management experience to the Company. Prior to his involvement in the oil and gas industry, he was directly responsible for the development, financing and construction of more than $35,000,000 worth of multi-family and senior housing projects.

Mr. Griffin graduated from East Texas State University in May of 1975 with a degree in Finance and Business Management.

Because of Mr. Griffin’s specific experience in, and knowledge of, the oil and gas industry, and as an entrepreneur and founder of MEI, we have concluded that Mr. Griffin should serve as a director and Chairman of the Company.

Rachel L. Dillard, CPA joined Mesa as Chief Financial Officer in September of 2011 and became Chief Financial Officer of Armada upon the closing of the Mesa Acquisition in March of 2013.

Ms. Dillard began her career in oil and gas in 1996 with CDX Gas, LLC. In an association that concluded at the end of 2006, she served CDX both as a consultant to the CEO and CFO and as an employee in matters of financial analysis, natural gas marketing and balancing, investor relations and payout analysis. During that period, Ms. Dillard also served as an accountant and consultant for Rising Star Energy, LLC, Republic Energy, Inc., and Longview Production Company. As Director of Financial Services, she centralized management of fixed assets and implemented the process of automated calculation and recording of depletion, depreciation, and amortization of pools of fixed assets of approximately $500 million.

From February to May 2007, she consulted with TransAtlantic Petroleum Corporation as Interim Controller in preparation for its divestiture of its US properties. As such, she prepared the sale price allocation of divested properties, prepared the oil & gas property section of 2006 form 10-K and Q1 2007 10-Q under full-cost accounting method, consulted with engineers in their preparation of 2006 reserve reports under both constant costs and pricing (SEC case) and escalated costs and pricing (NYMEX case) and handled inquiries from auditors.

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In June 2007, she joined Westside Energy Corporation as its Corporate Controller, serving Westside through its merger in June 2008 with Crusader Energy Group, Inc. At Westside, she directed financial reporting; prepared consolidated financial statements and reports on Forms 10-K and 10Q using the successful efforts method of accounting for oil & gas properties and spearheaded Westside’s Sarbanes-Oxley compliance project.

Following Westside’s merger with Crusader, Ms. Dillard consulted with Crusader on various transition matters. In 2009, Ms. Dillard joined the Division of Resolutions and Receiverships of the Federal Deposit Insurance Corporation as a contractor. In March 2010 she was engaged by the FDIC as Financial Institution Accountant and, in January 2011, as Accounting Technical Monitor, under the FDIC Contract Management and Oversight function, of a national servicer of a loan portfolio exceeding $1 billion.

Ms. Dillard earned her Bachelor of Science Degree in Business Administration with an emphasis in Accounting, cum laude, from The University of Texas at Dallas. She is licensed by the State of Texas as a certified public accountant and is a member of the American Institute of Certified Public Accountants, from which she holds the credential of Chartered Global Management Accountant (CGMA), and the Texas Society of Certified Public Accountants. Ms. Dillard is also a member of American Mensa.

J. Clint Unruh serves as Chief Operating Officer for Armada. He is responsible for direct oversight of all land, drilling and operational personnel and activities and assists the CEO with a number of day-to-day administrative functions.

In May of 2003, Mr. Unruh joined Mesa Energy, LLC, where he served as Vice President until May of 2007. During that time, Mr. Unruh was responsible for various administrative functions as well as the negotiation and acquisition of right-of-way for a midstream natural gas pipeline in Sequoyah County, Oklahoma.

In May of 2007, Mr. Unruh left Mesa Energy, LLC, to form Shiloh Homes, LLC, a residential and commercial construction company that he owned and operated until December of 2010. Wanting to return to the oil and gas industry, in January of 2011 Mr. Unruh left Shiloh Homes, LLC, and joined Percheron Acquisitions, LLC, where he served as a right-of-way agent and area manager overseeing the acquisition and construction of 5 midstream gathering systems for Pioneer Natural Resources Company. In February of 2012, Mr. Unruh returned to Mesa Energy, Inc., to serve as Vice President.

In March of 2013, in conjunction with the Mesa/Armada business combination, Mr. Unruh was promoted to Executive Vice President and in May of 2014, he was promoted to Chief Operating Officer.

Mr. Unruh earned a Bachelor of Business Administration degree in Finance from Texas A&M University and a Professional Land Management Certification from the University of Houston Downtown. He is a Registered Landman with, and an active member of the American Association of Professional Landmen, a member of the Dallas Association of Petroleum Landmen, and a member of the Independent Petroleum Association of America.

Ray L. Unruh is one of the founders of Mesa and served as its President until the closing of the Mesa Acquisition in March of 2013, at which time he became the Corporate Secretary of the Company.

From March 1999 until March 2003, Mr. Unruh served as the Vice-President of Santa Fe Petroleum, LLC, and the President of its operating affiliate, TexTron Southwest, LLC. During that period, he performed a variety of administrative and executive functions for both companies in connection with the oil and gas development and exploration activities undertaken by those companies in Shelby County, Texas. During Mr. Unruh’s tenure, TexTron drilled 21 horizontal James Lime wells in Shelby County, Texas, and TexTron became the largest gas producer in the county. Of the 2l wells drilled by TexTron in that field, 18 were commercially successful. As of January 2006, those wells had produced nearly 25 billion cubic feet (BCF) of gas and over 60,000 barrels of oil. In September 2002, TexTron drilled a Smackover oil well in Hopkins County, Texas, which was classified as a new field discovery well and produced, through April 2007, over 459,000 barrels of oil. Mr. Unruh left Santa Fe Petroleum, LLC, and TexTron Southwest, LLC, in March 2003 with Mr. Griffin to form and operate Mesa Energy, LLC.

Mr. Unruh owned and operated Red River Energy Supply Company, an oil field equipment company, in the early 1980′s. Between 1990 and 1998, he performed management and financial consulting services for Texas Northern Oil Company and for Phoenix Resources, LLC.

Mr. Unruh attended Oklahoma State University, where he majored in Business Administration and Finance.

Because of Mr. Unruh’s specific experience in, and knowledge of, the oil and gas industry, including his history of working with MEI and its predecessor company since its inception, we have concluded that Mr. Unruh should serve as a director of the Company.

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James J. Cerna, Jr. served as the President and Chief Executive Officer of Armada until the closing of the Mesa Acquisition in March of 2013. From the closing of the Mesa Acquisition through April 2014, Mr. Cerna served as President of Armada. From May 2006 to May 2009, Mr. Cerna served as Chairman of the Board of Lucas Energy, Inc. (NYSE Amex: LEI), and was also CEO and President thereof from May 2006 until September 2008. From 2004 to 2006, Mr. Cerna was President of the privately held Lucas Energy Resources.

Prior to joining Lucas Energy, Mr. Cerna was the Chief Oil and Gas Analyst and CFO of Petroleum Partners LLC from 2001 to 2004. He was the founder and CEO of NetCurrents, Inc., (NASDAQ: NTCS), an organization that focuses on Internet information monitoring and analysis. Prior to NetCurrents, Mr. Cerna was the manager of the GT Global/AIM Funds performance analysis group in San Francisco. Mr. Cerna has received five certificates of achievement from the Institute of Chartered Financial Analysts. He is honored by Strathmore’s Who’s Who for leadership and achievement in the Finance Industry. Mr. Cerna is the Public Affairs Officer and Pilot with the Civil Air Patrol, U.S. Air Force Auxiliary, Squadron 192.

Mr. Cerna received a Bachelor of Science degree in Finance from the California State University, Chico, in 1990.

Because of Mr. Cerna’s broad experience in, and knowledge of, the oil and gas industry, and his extensive experience in working with publicly traded companies, we have concluded that Mr. Cerna should serve as a director of the Company.

Kenneth T. Hern was appointed to the Mesa Board of Directors in January of 2010 and to the Armada Board of Directors in May of 2012. In addition, Mr. Hern currently serves, and has served since November 2009, on the Board of Directors and as Chairman of the Governance Committee of Flotek Industries, Inc. (NYSE: FTK), a supplier of drilling and production related products and services to the energy and mining industries.

Mr. Hern also served as Chairman of the Board and CEO of Nova Biosource Fuels, Inc. (NYSE Amex: NBF) (Nova), a leading provider of biodiesel fuel, and held that position from December 2, 2005 to April 2010.

Nova filed Chapter 11 in April 2009 seeking protection under federal bankruptcy statutes. By October 2010, the court approved dismissal of all Nova entities.

From January 2003 to December 2005, Mr. Hern was Chairman of the Board of Homeland Renewable Energy LLC, a privately held holding company of Fibrowatt LLC. Fibrowatt LLC is a developer, builder, owner and operator of poultry litter-fueled power plants, and is based in Pennsylvania.

From 1969 to 1994, Mr. Hern served in several capacities at Texaco, Inc., including President and Chairman of the Board of Texaco Brazil from 1989 to 1994.

Mr. Hern earned a Bachelor of Arts degree in Chemistry from Austin College in 1960 and a Master of Science degree in Organic Chemistry from North Texas State University in 1962.

Mr. Hern also received Associates Degrees from the Wharton School of Business and from Carnegie Mellon University in 1990 and 1991, respectively.

Because of Mr. Hern’s extensive experience in, and knowledge of, the oil and gas industry, including his history of working with publically traded companies and well as entrepreneurial private companies, we have concluded that Mr. Hern should serve as a director of the Company.

Fred B. Zaziski was appointed to the Board of Directors of Mesa in January of 2010 and became a director of Armada upon closing of the Mesa Acquisition in March of 2013.

Mr. Zaziski was President and CEO of Epsilon Energy Ltd. (TSX: EPS), a publicly traded exploration and production company based in Toronto and Houston, from June 2007 to May 2009.

From March 2007 until July 2008, Mr. Zaziski served as President and Chairman of PetroSouth Energy Corp. (OTCBB: PSEG), another publicly traded exploration and production company based in Houston, and from October 2004 to January 2007, he served as President, CEO and a Director of Falcon Natural Gas Corp., Houston (FNGC.PK). Prior to 2004, Mr. Zaziski worked in a number of senior management capacities for a number of other oil & gas companies including National Petroleum Technology Company, Saudi Arabia (1997 –1999) and Halliburton Energy Services, Bahrain (1977 –1997).

Mr. Zaziski graduated from Pennsylvania State University with a Bachelor of Science degree, in petroleum engineering in 1976. He received an MBA in Organizational Management and a Masters in International Business from Cairo University, Egypt in 1986 and 1987, respectively. He is a member of the Society of Petroleum Engineers, the American Petroleum Institute and the American Society of Mechanical Engineers.

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Because of Mr. Zaziski’s specific experience in, and knowledge of, the oil and gas industry, including his history of working in management capacities with a number of publicly traded oil and gas exploration and development companies, we have concluded that Mr. Zaziski should serve as a director of the Company.

Eric Wold joined the Board of Directors of Armada in May of 2012.

Mr. Wold previously served on the Board of Directors of Lucas Energy (AMEX:LEI), a publicly held company within the oil and energy sector from 2005-2009. He is currently a Senior Analyst with B. Riley & Co., a leading full-service investment bank, covering the Media and Entertainment sector, where he has more than 20 years of buy-side and sell-side equity research experience. Previously, Mr. Wold held the position of Managing Director, Equity Research at the investment banking firm Merriman Capital, Inc., where he covered the Branded Global Consumer and Media Groups. He was also Director of Corporate Finance with NightFire Software, a privately held telecommunications software company based in Oakland, California. At First Security Van Kasper, he served as Vice President and Senior Research Analyst, where he was responsible for the Restaurant and Branded Consumer sectors. Mr. Wold began his career on the buy-side with research analyst positions with both Polynous Capital Management (a hedge fund that he co-founded in 1996) and GT Global Financial Services. He received his Chartered Financial Analyst (CFA) designation in 1997 and a Bachelor’s degree in Finance from the University of California at Berkeley.

Because of Mr. Wold’s s prior service on a public company board of directors and his extensive background in finance and public markets, we have concluded that Mr. Wold should serve as a director of the Company.

Director Qualifications

The Board believes that each of our directors is highly qualified to serve as a member of the Board. Each of the directors has contributed to the mix of skills, core competencies and qualifications of the Board. When evaluating candidates for election to the Board, the Board seeks candidates with certain qualities that it believes are important, including integrity, an objective perspective, good judgment, and leadership skills. Our directors are highly educated and have diverse backgrounds and talents and extensive track records of success in what we believe are highly relevant positions.

Involvement in Certain Legal Proceedings

To the best of our knowledge, except as may be disclosed above, none of our existing directors or executive officers has been the subject of any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time, been convicted in a criminal proceeding or been subject to a pending criminal proceeding (excluding traffic violations and other minor offenses), been subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting such person’s involvement in any type of business, securities or banking activities or been found by a court of competent jurisdiction (in a civil action), the SEC, or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.

Board Independence

We are currently not required to have any independent members of the Board of Directors. The Board of Directors has determined that (i) Messrs. Griffin, Cerna and Unruh have relationships which, in the opinion of the Board of Directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director and each is not an “independent director” as defined in the Marketplace Rules of The NASDAQ Stock Market and (ii) Messrs. Hern, Wold and Zaziski are each an independent director as defined in the Marketplace Rules of The NASDAQ Stock Market.

Board Committees

We are not currently subject to listing requirements of any national securities exchange or inter-dealer quotation system which requires us to have committees or charters. Our Board of Directors, however, has determined to establish three committees: an Audit Committee; a Compensation Committee; and a Nominating and Corporate Governance Committee. Each committee operates under a charter approved by our Board of Directors. Each charter is available, free of charge, on our website at www.armadaoil.us. The membership, principal duties, and responsibilities of each committee are set forth below.

The membership of our Board committees is as follows:

Audit Committee – Eric C. Wold (Chairman) and Kenneth T. Hern

Compensation Committee – Fred B. Zaziski (Chairman), Kenneth T. Hern and Eric C. Wold

Corporate Governance – Kenneth T. Hern (Chairman) and Fred B. Zaziski.

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Audit Committee

The committee’s charter provides that the principal duties and responsibilities of the Audit Committee include:

reviewing and discussing certain regulatory filings, including our audited financial statements and quarterly financial statements, with management and our independent auditors;

reviewing earnings press releases and earnings guidance provided to analysts;

appointing, evaluating, overseeing and replacing, if necessary, our independent registered public accounting firm;

reviewing the design, implementation, adequacy and effectiveness of our internal controls and our critical accounting policies;

reviewing our compliance with applicable laws, rules and regulations, and reviewing cases of employee misconduct or fraud; and

reporting regularly to our Board of Directors with respect to issues relating to the quality or integrity of our financial statements, our compliance with legal or regulatory requirements and the performance and independence of our independent auditors.

All audit and non-audit services, other than de minimis non-audit services, provided to us by our independent registered public accounting firm must be approved in advance by our audit committee.

Compensation Committee

The committee’s charter provides that the principal duties and responsibilities of the Compensation Committee include:

reviewing and approving annual goals and objectives of our CEO and other executive officers, evaluating the performance of our CEO and other executive officers in light of those goals and objectives, determining or assisting to determine our CEO’s and other executive officers’ compensation level and making all other determinations with respect to the compensation of our CEO and other executive officers;

recommending to our Board of Directors the compensation of our CEO and other executive officers and, to the extent such authority is delegated to it by our Board of Directors, approving the compensation payable to these executive officers;

considering with respect to the compensation of the Company’s executive officers: (a) annual base salary; (b) any bonus or other short-term incentive program; (c) any long-term incentive compensation (including cash-based and equity-based awards); and (d) any employment agreements and similar arrangements or transactions;

reviewing and administering our stock and incentive compensation plans, establishing criteria for the granting of options or other incentive awards to executive officers and other employees and reviewing and approving the granting of awards in accordance with such criteria and making recommendations to our Board of Directors regarding changes to our incentive compensation and equity-based plans that are subject to approval by our Board of Directors;

reviewing and making recommendations to our Board of Directors regarding compensation, if any, of the Board of Directors and its committees; and

preparing a report of the committee for inclusion in our annual report or proxy statement with respect to our annual meeting of stockholders.

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Nominating and Corporate Governance Committee

The committee’s charter provides that the principal duties and responsibilities of the Nominating and Corporate Governance Committee include:

identifying, evaluating and selecting or recommending for selection candidates for election to our Board of Directors;

evaluating the functions, duties and composition of committees of our Board of Directors and making recommendations to our Board of Directors with respect thereto;

formulating procedures for security holders to send communications to our Board of Directors;

developing and recommending to our Board of Directors a set of corporate governance policies or procedures;

establishing and maintaining an informal orientation and continuing education program for our directors with respect to our strategic plans, significant financial, accounting and risk management matters, compliance programs, corporate governance policies or procedures, principal officers and internal and independent auditor; and

developing a plan for the succession of our CEO and discussing with our CEO a succession plan for our key senior officers.

The Nominating and Corporate Governance Committee of the Board of Directors is responsible for reviewing with the entire Board from time to time the appropriate skills and characteristics required of Board members in the context of the current make-up of the Board of Directors. The Board of Directors believes that directors should bring to the Company a variety of perspectives and skills that are derived from high quality business and professional experience and that are aligned with the Company’s strategic objectives. The composition of the Board of Directors, with respect to directors deemed independent, should at all times adhere to the standards of independence promulgated by applicable NASDAQ and SEC rules. We also require that our directors be able to attend all board and applicable committee meetings. In this respect, directors are expected to advise the Chairman of the Board of Directors and the Chairman of the Nominating and Corporate Governance Committee in advance of accepting any other public company directorship or assignment to the audit committee of the board of any other public company.

The Nominating and Corporate Governance Committee identifies nominees by first evaluating the current members of the Board of Directors willing to continue in service. Current members of the Board with skills and experience that are relevant to the Company’s business and who are willing to continue in service are considered for re-nomination, balancing the value of continuity of service by existing members of the Board with that of obtaining a new perspective. If any member of the Board does not wish to continue in service or if the Nominating and Corporate Governance Committee or the Board decides not to re-nominate a member for re-election, the Committee will identify the desired skills and experience of a new nominee in light of the criteria above. Current members of the Committee and Board may be consulted for suggestions as to individuals meeting the criteria above. Research may also be performed to identify qualified individuals.

Code of Ethics

We have adopted a formal Code of Ethics applicable to our directors, officers, and employees. Our Code of Ethics is available free of charge on our website at www.armadaoil.us.

Shareholder Communications

Currently, we do not have a policy with regard to the consideration of any director candidates recommended by security holders. To date, no security holders have made any such recommendations.

Compliance with Section 16(a) of the Exchange Act

Section 16(a) of the Exchange Act requires our executive officers and directors and persons who own more than 10% of a registered class of our equity securities to file with the SEC initial statements of beneficial ownership, reports of changes in ownership and annual reports concerning their ownership of our common stock and other equity securities, on Form 3, 4 and 5 respectively. Executive officers, directors and greater than 10% shareholders are required by the SEC regulations to furnish our company with copies of all Section 16(a) reports they file.

We registered our common stock pursuant to Section 12 of the Exchange Act by filing a Form 8-A with the SEC on January 15, 2014. Accordingly, our officers, directors and 10% shareholders were subject to the beneficial ownership reporting requirements of Section 16(a) of the Exchange Act with respect to our fiscal year ended December 31, 2014. Based solely upon our review of the copies of Section 16 forms that we received with respect to the fiscal year ended December 31, 2014, we believe that each person who at any time during the fiscal year was a director, officer or beneficial owner of more than 10% of our Common Stock satisfied his or her Section 16(a) filing requirements, although certain reports may have been filed on a late basis.

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ITEM 11.

EXECUTIVE COMPENSATION

The following table sets forth information concerning the total compensation paid or accrued by us during the last two fiscal years ended December 31, 2014, to (i) all individuals that served as our principal executive and principal financial officers or acted in a similar capacity for us at any time during the fiscal year ended December 31, 2014; (ii) our two most highly compensated executive officers other than the principal executive and principal financial officers who were serving as executive officers at the end of the fiscal year ended December 31, 2014, and who received annual compensation during the fiscal year ended December 31, 2014 in excess of $100,000; and (iii) up to two additional individuals who received annual compensation during the fiscal year ended December 31, 2014 in excess of $100,000 and who were not serving as executive officers of at the end of the fiscal year ended December 31, 2014.

Summary Compensation Table

Name & Principal Position	Year	Salary ($)		Bonus ($)		Stock Awards ($)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Non- Qualified Deferred Compensation Earnings ($)		All Other Compensation ($)		Total ($)
Randy M. Griffin, Chief Executive Officer (1)(2)(3)(4)	2014	$	210,000	$	—	$	—	$	41,439		—		—		—	$	251,439
	2013	$	210,000	$	—	$	—	$	199,766		—		—		—	$	409,766
Rachel L. Dillard, Chief Financial Officer (2)(3)	2014	$	134,400	$	2,000	$	—	$	13,813		—		—		—	$	150,213
	2013	$	125,000	$	8,000	$	—	$	57,283		—		—		—	$	190,283
J. Clint Unruh, Chief Operating Officer (2)(3)	2014	$	123,750	$	2,000	$	—	$	16,525		—		—		—	$	142,275
	2013	$	111,000	$	5,000	$	—	$	11,049		—		—		—	$	127,049

	(1) Mr. Griffin became our Chief Executive Officer on March 28, 2013.
	(2) Value of stock and option awards is the actual amount of stock compensation expense recognized in 2014 for the awards. The fair values of the awards on the date of grant, for which expense was recognized in 2014, were: Mr. Griffin, $62,212; Ms. Dillard, $20,737; Mr. Unruh, $44,249.
	(3) Value of stock and option awards is the actual amount of stock compensation expense recognized in 2013 for the awards. The fair values of the awards on the date of grant, for which expense was recognized in 2013, were: Mr. Griffin, $199,766; Ms. Dillard, $75,283; Mr. Unruh, $23,510.
	(4) Mr. Griffin’s 2013 reported salary does not include $37,500 paid to him as part of accrued salary from prior years which were paid to him in increments of $10,000 per month.

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Employment Agreements with Executive Officers

On April 1, 2013, the Company entered into an employment agreement with Mr. Griffin as its Chief Executive Officer. The employment agreement provides for (i) an annual base salary of $210,000 per year, subject to annual increase at the Board of Directors’ discretion. If Mr. Griffin’s employment is terminated without Cause during the first year of the agreement, or if he resigns for Good Reason (as defined in his agreement), he will be entitled to any earned but unpaid base salary and unpaid pro rata annual bonus and continued coverage, at the Company’s expense, under all benefits plans in which he was a participant immediately prior to his last date of employment with the Company for a period of six months following such cessation of employment. If such a termination should occur during the second year of the agreement or thereafter, the severance period is reduced to three months The term of the employment agreement is for a period of two years and automatically renews for successive one year periods thereafter unless terminated pursuant to the agreement. Prior to April 1, 2013, Mr. Griffin’s compensation was governed by an employment agreement with Mesa. Under the terms of that agreement, Mr. Griffin was entitled to an annual base salary of $180,000 in 2012. Mr. Griffin offered forbearance to the Company for payment of his salary for the period September 1, 2009 through July 31, 2011. Beginning January 1, 2012, the Company made monthly payments of $10,000 to Mr. Griffin until the accrued salary was repaid to him in full in 2013. Beginning March 16, 2015, Mr. Griffin has elected to accrue his salary until such time as the Company’s revenue and cash positions improve.

On September 19, 2011, Mesa entered into an employment agreement with Rachel L. Dillard, its Chief Financial Officer, which agreement was assumed by Armada upon the closing of the Mesa Acquisition. The employment agreement, as amended, provides for an annual base salary of $134,400. If Ms. Dillard’s employment is terminated without Cause, or if she resigns for Good Reason (as defined in her agreement), she will be entitled to any earned but unpaid base salary and unpaid pro rata annual bonus and continued coverage, at the Company’s expense, under all benefits plans in which she was a participant immediately prior to her last date of employment with the Company for a period of three months following such cessation of employment. The original term of the employment agreement was for a period of twelve months and it automatically renews for one year periods thereafter unless terminated pursuant to the agreement. Any unvested equity compensation vests upon Ms. Dillard’s death or disability. Under the employment agreement with Mesa, Ms. Dillard received restricted stock awards totaling 1,200,000 shares. 600,000 of those restricted shares were vested as of the date of the Mesa Acquisition and were exchanged for 240,000 shares of Armada common stock. The remaining 600,000 shares under the Mesa restricted shares awards were converted in March 2013 to Mesa incentive stock options which were assumed by Armada upon the closing of the Mesa Acquisition. Under this assumption, Ms. Dillard received options to purchase 240,000 shares of Armada common stock exercisable at a price of $0.33 per share and expiring on March 20, 2018.

While the Company does not have a written employment agreement with J. Clint Unruh, we have agreed to pay Mr. Unruh an annual salary of $126,000.

Grants of Plan-Based Awards

We have not issued any stock options or maintained any stock option or other incentive plans other than our 2012 Long-Term Incentive Plan. (See “Market for Common Equity and Related Stockholder Matters – Securities Authorized for Issuance under Equity Compensation Plans,” above).

During the year ended December 31, 2014, options to purchase 300,000 shares were granted to Randy M. Griffin, and options to purchase 100,000 shares were granted to each of Rachel L. Dillard and J. Clint Unruh.

During the year ended December 31, 2013, options to purchase 500,000 shares were granted to each of Randy M. Griffin and James J. Cerna, Jr.; and options to purchase 600,000 shares of the Company’s common stock were granted to Rachel L. Dillard in conjunction with the cancellation of two unvested previous Mesa restricted stock grants of the same number of shares of restricted stock. These options were, at consummation of the Mesa Acquisition, converted to options to purchase 240,000 shares of the Company’s common stock. A previous grant of options by Mesa to Mr. Cerna to purchase 250,000 shares, converted at consummation of the Mesa Acquisition to options to purchase 100,000 shares of the Company’s common stock, was cancelled and replaced with a grant of options to purchase 150,000 shares of the Company’s common stock.

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Outstanding Equity Awards at Fiscal Year End

The following tables set forth information regarding stock options held by our Named Executive Officers at December 31, 2014.

	Option Awards
Name	Grant Date	Number of Securities Underlying Unexercised Options Exercisable		Number of Securities Underlying Unexercised Options Unexercisable		Option Exercise Price ($/Sh)		Option Expiration Date
Randy M. Griffin	9/9/2014		150,000		150,000		0.22	9/9/2019
	4/19/2013		500,000		—		0.40	4/1/2018
	6/30/2011		400,000		—		0.38	6/30/2016
Rachel L. Dillard	9/9/2014		50,000		50,000		0.22	9/9/2019
	3/20/2013		240,000		—		0.33	3/20/2018
J. Clint Unruh	9/9/2014		50,000		50,000		0.22	9/9/2019
	2/10/2012		40,000		—		0.65	2/10/2017

Option Exercises and Stock Vested Table

The following tables set forth information regarding vested restricted stock awards held by our Named Executive Officers at December 31, 2014.

	Stock Awards
Name	Number of Shares of Restricted Stock Acquired on Vesting		Value Realized on Vesting ($)
Rachel L. Dillard		240,000	$	90,000

(1)

The value realized on vesting is based on the number of Mesa shares awarded on the date of grant, which preceded the Mesa Acquisition, times the closing market price on the date of grant ($0.15). Upon consummation of the Mesa Acquisition, the Mesa shares previously awarded were exchanged for Armada shares and grants in accordance with the exchange ratio of one Armada share for every 2.5 Mesa shares exchanged (the “Exchange Ratio”). In order to avoid altering the fair values of the grants, the grant date market price of Mesa shares was divided by the Exchange Ratio, resulting in the fair value per Armada share increasing by the same Exchange Ratio by which the Mesa granted shares were reduced, resulting in no change in the fair value of the awards. The resulting fair value price per share was calculated to be $0.375.

Director Compensation

The following table sets forth summary information concerning the total compensation paid to our non-employee directors in 2014 for services to us.

	Fees Earned		Stock Option		Restricted
	or Paid in		Awards		Stock Awards
Name	Cash($)		($)(1)		($)		Total ($)
James J. Cerna, Jr.		5,250		6,906		—		12,156
Kenneth T. Hern		8,250		10,777		—		19,027
Fred B. Zaziski		8,250		10,777		—		19,027
Ray Unruh		8,250		9,795		—		18,045
Eric Wold		8,250		11,756		—		20,006
Total:	$	38,250	$	50,011	$	—	$	88,261

(1) Represents compensation expense incurred in 2014 for the 2013 stock option awards described below. James J. Cerna’s 2013 stock award is not presented in the table below because he was an employee during 2013.

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Name	Number of shares		Fair Value		2013 Stock Compensation Expense		Remainder of 2013 Fair Value included in 2014 Value of Stock Option Awards ($)
Kenneth T. Hern		55,000	$	21,417	$	18,237	$	3,180
Fred B. Zaziski		55,000		21,417		18,237		3,180
Ray Unruh		50,000		19,470		16,581		2,889
Eric Wold		60,000		23,364		19,896		3,468
		220,000	$	85,668	$	72,951	$	12,717

On September 9, 2014, our nonemployee directors were granted restricted stock option awards, vesting over one year, with half vesting at grant and half vesting on the first year anniversary of the grant, as follows:

Name	Number of shares		Fair Value		2014 Stock Compensation Expense
James J. Cerna, Jr.		50,000	$	10,369	$	6,906
Kenneth T. Hern		55,000		11,406		7,597
Fred B. Zaziski		55,000		11,406		7,597
Ray Unruh		50,000		10,369		6,906
Eric Wold		60,000		12,442		8,288
		270,000	$	55,991	$	37,294

These options expire September 9, 2019, and have an exercise price of $0.22 per share.

On June 8, 2012, each of our non-employee directors, Messrs. Hern and Zaziski, was granted restricted stock option awards of 40,000 shares of our common stock vesting over a period of one year as follows: 20,000 shares on June 8, 2013 and 20,000 shares on June 8, 2014. We determined the fair value of each of these awards on the date of grant to be $12,556. Options expire on June 7, 2017 and have an exercise price of $0.37 per share.

On September 30, 2011, each of our non-employee directors, Messrs. Hern and Zaziski, was granted a restricted stock award of 20,000 shares of our common stock vesting over a period of two years as follows: 2,000 shares on December 30, 2011, 4,000 shares on each of March 30, 2012, September 30, 2012 and March 30, 2013 and 15,000 shares on September 30, 2013. We determined the fair value of each of these awards on date of grant to be $7,500; and, 2013 stock compensation expense recognized for these awards was $6,600 in the aggregate. On September 30, 2011, our non-employee director, Mr. Ray L. Unruh, was granted a restricted stock award of 60,000 shares of our common stock vesting over a period of two years as follows: 18,000 shares on March 30, 2012, 12,000 shares vesting on each of September 30, 2012 and March 30, 2013, and 18,000 shares vesting on September 30, 2013. We determined the fair value of this award on the date of grant to be $22,500, and 2013 stock compensation expense recognized for this award was $9,900 in the aggregate.

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ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth information with respect to the beneficial ownership of our common stock known by us as of March 31, 2015 by:

	·	each person or entity known by us to be the beneficial owner of more than 5% of our common stock;
	·	each of our directors and executive officers; and
	·	all of our directors and executive officers as a group.

Name and Address of Beneficial Owner 1	Amount and Nature of Beneficial Ownership 2			Percentage of Class 3

Randy M. Griffin		5,442,136	(4) (12)		9.6	%
Ray L. Unruh		3,293,717	(5) (12)		5.8	%
James J. Cerna, Jr.		3,232,333	(6)		5.7	%
J. Clint Unruh		545,000	(7)		*
Rachel L. Dillard		530,000	(8)		*
Kenneth T. Hern		292,500	(9)		*
Fred B. Zaziski		242,500	(10)		*
Eric Wold		216,954	(11)		*

All directors and executive officers as a group (8 persons)		13,795,140	(12)		24,4	%

David Moss		4,498,833	(13)		8.0	%
David L. Freeman		3,393,533	(14)		6.0	%

* Indicates beneficial ownership of less than 1%.

1	Unless otherwise noted, the mailing address of each beneficial owner is c/o Armada Oil, Inc., 5220 Spring Valley Road, Suite 615, Dallas, Texas 75254. Data is based on information furnished to us by the named officers and directors.

2	Beneficial ownership is determined in accordance with the rules of the SEC and generally includes having or sharing voting or investment power with respect to securities. Shares of common stock subject to options or warrants currently exercisable or convertible, or exercisable or convertible within 60 days of March 31, 2015, are deemed outstanding for computing the percentage of the person holding such option or warrant but are not deemed outstanding for computing the percentage of any other person.

3	Percentages are based upon 56,605,473 shares of Common Stock issued and outstanding as of March 31, 2015.

Includes 694,296 shares owned by Amagosa Investments Ltd. (“Amagosa”) Mr. Griffin, as General Partner of Amagosa, has sole voting and investment control with respect to our shares held by Amagosa. Also includes 761,600 shares owned by Sycamore Resources, Inc. (“Sycamore”) Mr. Griffin, as the sole shareholder of Sycamore, has sole voting and investment control with respect to our shares held by Sycamore. Also includes an aggregate of 720,000 shares of common stock that may be purchased from Ray Unruh pursuant to option agreements dated December 17, 2012. Also includes 1,050,000 shares of our common stock issuable upon the exercise of options granted under our 2012 Incentive Plan. Does not include options to purchase 150,000 shares of our restricted common stock issuable upon the exercise of options which will vest on September 9, 2015.

Includes 220,412 shares owned by Ray L. Unruh Profit Sharing Plan (the “Unruh Plan”), of which Mr. Unruh is a trustee and has voting and investment control with respect to our shares held by the Unruh Plan, 89,920 shares owned by Mr Unruh and his wife, 750,000 shares owned by Mr Unruh, and 2,158,385 shares owned by Unruh & Unruh Properties Ltd. Mr. Unruh, as President of the General Partner of Unruh & Unruh Properties Ltd. has voting and investment control with respect to our shares held by these entities. Includes the 720,000 shares owned by Ray Unruh that may be purchased by Randy Griffin pursuant to option agreements dated December 17, 2012. Also includes options to purchase 75,000 shares of our common stock vested under our 2012 Incentive Plan. Does not include options to purchase 25,000 shares of our restricted common stock issuable upon the exercise of options which will vest on September 9, 2015.

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Includes 715,000 shares of our restricted common stock issuable upon the exercise of vested options granted under our 2012 Incentive Plan. Also includes Series D warrants to purchase 133,333 shares of our restricted common stock issued in conjunction with the Company’s 2012 unit private placement. Does not include options to purchase 25,000 shares of our restricted common stock issuable upon the exercise of options which will vest on September 9, 2015.

7	Includes 90,000 shares of our restricted common stock issuable upon the exercise of options granted under our 2012 Incentive Plan. Does not include options to purchase 50,000 shares of our restricted common stock issuable upon the exercise of options which will vest on September 9, 2015.

8	Includes 290,000 shares of our restricted common stock issuable upon the exercise of vested options granted under our 2012 Incentive Plan. Does not include options to purchase 50,000 shares of our restricted common stock issuable upon the exercise of options which will vest on September 9, 2015.

9	Includes 272,500 shares of our restricted common stock issuable upon the exercise of vested options granted under our 2012 Incentive. Does not include options to purchase 27,500 shares of our restricted common stock issuable upon the exercise of options which will vest on September 9, 2015.

10	Includes 222,500 shares of our restricted common stock issuable upon the exercise of vested options granted under our 2012 Incentive Plan. Does not include options to purchase 27,500 shares of our restricted common stock issuable upon the exercise of options which will vest on September 9, 2015.

11	Includes 140,000 shares of our restricted common stock issuable upon the exercise of options granted under our 2012 Incentive Plan. Does not include options to purchase 30,000 shares of our restricted common stock issuable upon the exercise of options which will vest on September 9, 2015.
12	As Mr. Griffin has an option to purchase an aggregate of 720,000 shares of common stock from Ray Unruh, such shares have been included as beneficially owned by each of Messrs. Griffin and Unruh, both of whom are our officers and directors. However, such 720,000 shares have only been included once in the beneficial ownership of all officers and directors as a group, since a purchase of the shares by Mr. Griffin would increase his share ownership while proportionally decreasing Mr. Unruh’s ownership.

13	Includes Series D warrants to purchase 373,333 shares of our restricted common stock issued in conjunction with the Company’s 2012 unit private placement and 250,000 of 500,000 shares of our restricted common stock issued to Sundance Mountain, LLC, on January 22, 2015, an entity with which he is affiliated, in exchange for consulting services rendered to the Company.

14	Includes 1,388,592 shares owned by Freeman Energy LLC and 540,008 shares owned by H S Investments LLC. Mr. Freeman, as the sole Member of each of these entities has sole voting and investment control with respect to our shares held by such entities.

Equity Compensation Plan Information

On September 30, 2002, the stockholders of the Company approved its 2002 Incentive Stock Plan (the “2002 Plan”), which had 4,000,000 shares reserved for issuance thereunder. The 2002 Stock Plan expired in September 2012. In anticipation of its expiration, by way of Unanimous Written Consent dated April 27, 2012, the Board of Directors (the “Board”) approved the terms and provisions of the 2012 Long-Term Incentive Plan (“2012 Incentive Plan”). The 2012 Incentive Plan was approved by shareholders owning the majority of the Company’s shares of common stock and became effective on May 1, 2012, after which time no new equity awards may be made under the 2012 Incentive Plan. The Company reserved 5,000,000 shares of common stock for issuance upon grant or exercise of awards by participants under the 2012 Incentive Plan. These shares have not been registered with the SEC. The 2012 Incentive Plan provided shares available for restricted stock or options granted to employees, directors, and others. Stock options granted under the 2012 Incentive Plan generally vest over one to five years or as otherwise determined by the Board or committee of the Board. Options to purchase shares of common stock expire no later than ten years after the date of grant.

In addition, the number of shares of Common Stock subject to the 2012 Incentive Plan, any number of shares subject to any numerical limit in the 2012 Plan, and the number of shares and terms of any incentive award are expected to be adjusted in the event of any change in our outstanding Common Stock by reason of any stock dividend, spin-off, split-up, stock split, reverse stock split, recapitalization, reclassification, merger, consolidation, liquidation, business combination or exchange of shares or similar transaction.

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Administration

It is expected that the Compensation Committee of the Board of Directors, or the Board of Directors in the absence of such a committee, will administer the 2012 Incentive Plan. Subject to the terms of the 2012 Incentive Plan, the Compensation Committee would have complete authority and discretion to determine the terms of awards under the 2012 Incentive Plan.

Grants

The 2012 Incentive Plan authorizes the grant to participants of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, performance grants intended to comply with Section 162(m) of the Internal Revenue Code (as amended, the “Code”) and stock appreciation rights, as described below:

	·	Options granted under the 2012 Incentive Plan entitle the grantee, upon exercise, to purchase a specified number of shares from us at a specified exercise price per share. The exercise price for shares of Common Stock covered by an option cannot be less than the fair market value of the Common Stock on the date of grant unless agreed to otherwise at the time of the grant.
	·	Restricted stock awards and restricted stock units may be awarded on terms and conditions established by the compensation committee, which may include performance conditions for restricted stock awards and the lapse of restrictions on the achievement of one or more performance goals for restricted stock units.
	·	The compensation committee may make performance grants, each of which will contain performance goals for the award, including the performance criteria, the target and maximum amounts payable, and other terms and conditions.
	·	The 2012 Incentive Plan authorizes the granting of stock awards. The compensation committee will establish the number of shares of Common Stock to be awarded and the terms applicable to each award, including performance restrictions.
	·	Stock appreciation rights (“SARs”) entitle the participant to receive a distribution in an amount not to exceed the number of shares of Common Stock subject to the portion of the SAR exercised multiplied by the difference between the market price of a share of Common Stock on the date of exercise of the SAR and the market price of a share of Common Stock on the date of grant of the SAR.

Duration, Amendment and Termination

The Board has the power to amend, suspend or terminate the 2012 Incentive Plan without stockholder approval or ratification at any time or from time to time. No change may be made that increases the total number of shares of Common Stock reserved for issuance pursuant to incentive awards or reduces the minimum exercise price for options or exchange of options for other incentive awards, unless such change is authorized by our stockholders within one year. Unless sooner terminated, the 2012 Incentive Plan will terminate May 1, 2022.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Other than as disclosed below and in this Annual Report, there have been no transactions, since January 1, 2014, or any currently proposed transaction, in which we were or are to be a participant and the amount involved exceeds the lesser of $120,000 or 1% of the average of our total assets at year end for the last two completed fiscal years and in which any of our directors, executive officers or beneficial holders of more than 5% of our outstanding common stock, or any of their respective immediate family members, has had or will have any direct or material indirect interest.

Employment Agreements

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While the Company does not have a written employment agreement with J. Clint Unruh, we have agreed to pay Mr. Unruh an annual salary of $126,000.

Option Grants

On September 9, 2014, we granted options to purchase our common stock to officers and directors as follows:

Grantee	Title	Number of Shares Underlying the Options Granted		Expiration	Exercise Price		Fair Value
Randy M. Griffin	Chairman and CEO		300,000	9/9/2019	$	0.22	$	0.21
Rachel L. Dillard	Chief Financial Officer		100,000	9/9/2019	$	0.22	$	0.21
J. Clint Unruh	Chief Operating Officer		100,000	9/9/2019	$	0.22	$	0.21
James J. Cerna, Jr.	Director		50,000	9/9/2019	$	0.22	$	0.21
Kenneth T. Hern	Director		55,000	9/9/2019	$	0.22	$	0.21
Fred B. Zaziski	Director		55,000	9/9/2019	$	0.22	$	0.21
Ray Unruh	Director		50,000	9/9/2019	$	0.22	$	0.21
Eric Wold	Director		60,000	9/9/2019	$	0.22	$	0.21

Half of the grants vested on the grant date, and the remaining half will vest on September 9, 2015.

Related Transactions

On October 1, 2014, the Company issued a $100,000 promissory note with an interest rate of 12% per annum to accrue until maturity to Sycamore Resources, Inc., an entity controlled by Randy M. Griffin. The note matures and is payable on December 15, 2015, together with accrued interest. The note 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 that were the subject of the Tabbs Bay Acquisition.

Director Independence

Our Board of Directors has considered the independence of its directors in reference to the definition of “independent director” established by the NASDAQ Marketplace Rule 5605(a)(2). In doing so, the Board has reviewed all commercial and other relationships of each director in making its determination as to the independence of its directors. After such review, the Board has determined that each of Messrs. Wold, Hern, and Zaziski qualifies as independent under the requirements of the NASDAQ listing standards.

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ITEM 14.

PRINCIPAL ACCOUNTING FEES AND SERVICES

Audit Fees

The aggregate fees billed to us by our principal accountant for services rendered during the fiscal years ended December 31, 2014 and 2013 are set forth in the table below:

Fee Category	2014		2013
Audit fees (1)	$	173,000	$	200,000
Audit-related fees (2)		—		—
Tax fees (3)		—		—
All other fees (4)		—		—
Total fees	$	173,000	$	200,000

(1)

Audit fees consist of fees incurred for professional services rendered for the audit of consolidated financial statements, for reviews of our interim consolidated financial statements included in our quarterly reports on Forms 10-Q and for services that are normally provided in connection with statutory or regulatory filings or engagements.

(2)

Audit-related fees consist of fees billed for professional services that are reasonably related to the performance of the audit or review of our consolidated financial statements, but are not reported under “Audit fees.”

(3)

Tax fees consist of fees billed for professional services relating to tax compliance, tax planning, and tax advice.

(4)

All other fees consist of fees billed for all other services.

Audit Committee’s Pre-Approval Policies and Procedures

Our Board of Directors includes an audit committee which is directly responsible for the appointment, compensation, retention and oversight of the work of any registered public accounting firm engaged by us for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for us, and each such registered public accounting firm must report directly to the Board. It is our audit committee’s policy to approve in advance all audit, review and attest services and all non-audit services (including, in each case, the engagement fees there for and terms thereof) to be performed by our independent auditors, in accordance with applicable laws, rules and regulations.

Our audit committee selected GBH CPAs, PC as our independent registered public accounting firm for purposes of auditing our financial statements for the year ended December 31, 2014. In accordance with Board’s practice, GBH CPAs, PC was pre-approved by the Board to perform these audit services for us prior to its engagement.

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PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Exhibits

Exhibit No.	SEC Report Reference No.	Description
2.1	2.1	Asset Purchase Agreement and Plan of Reorganization, dated as of November 14, 2012, among Armada Oil, Inc., Mesa Energy Holdings, Inc., and Mesa Energy Inc. (included as Appendix A) (1)

2.2	2.2	Amendment No. 1 to the Asset Purchase Agreement & Plan of Reorganization, dated as of February 19, 2013, among Armada Oil, Inc., Mesa Energy Holdings, Inc. & Mesa Energy, Inc. (2)

2.3	2.2	Agreement and Plan of Merger and Reorganization, dated as of August 31, 2009, by and among Mesa Energy Holdings, Inc., Mesa Energy Acquisition Corp. and Mesa Energy, Inc. (3)

3.1	3.1	Armada Oil, Inc., Articles of Incorporation. (3)

3.2	3.1	Armada Oil, Inc., Articles of Incorporation, as amended. (3)

3.3	3.3	Armada Oil, Inc., Articles of Incorporation, as amended. (3)

3.4	3.1	Amended and Restated By-Laws of Armada Oil, Inc. (4)

4.1	4.5	Form of Series A Common Stock Purchase Warrant (3)

4.2	4.6	Form of Series B Common Stock Purchase Warrant (3)

4.3	4.7	Form of Series C Common Stock Purchase Warrant (3)

4.4	4.1	Form of Armada Oil, Inc. Series A Senior Unsecured 9.625% Note (5)

4.5	4.2	Form of Series D Common Stock Purchase Warrant (5)

4.6	10.2	Form of revised Series D Warrant of Armada Oil, Inc.(6)

4.7	10.5	Form of Amendment to Series D Common Stock Purchase Warrant (16)

4.8	4.1	Term Promissory Note dated March 5, 2015 (18)

10.1	10.1	Voting Agreement, dated as of November 14, 2012, among Armada Oil, Inc. and the signatories thereto (included as Appendix C)(1)

10.2	10.2	Assignment and Assumption Agreement dated as of March 28, 2013, between Mesa Energy Holdings, Inc., and Mesa Energy Inc. (14)

10.3	10.10	Spring Valley Center Office Lease, dated June 1, 2007, between Spring Valley Center, LLP and Mesa Energy, Inc. (3)

10.4	10.11	First Modification to Office Lease, dated February 28, 2012, between Spring Valley Center, LLP and Mesa Energy, Inc. (3)

10.5	10.21	Letter Agreement, dated March 17, 2009, between Mesa Energy, Inc. and Robert Thomasson (3)

10.6	10.22	Purchase and Sale Agreement, dated June 17, 2009, between Hydrocarbon Generation, Inc. and Sycamore Resources, Inc. (3)

10.7	10.23	Assignment of Purchase and Sale Agreement, dated as of August 25, 2009, from Sycamore Resources, Inc. to Mesa Energy, Inc. (3)

10.8	10.17	Membership Interest Purchase Agreement, dated as of June 1, 2011, by and among Mesa Energy Holdings, Inc., Mesa Energy, Inc., Tchefuncte Natural Resources, LLC and its Members (3)

10.9	10.18	Employment Services Agreement dated September 19, 2011, between Mesa Energy Holdings, Inc. and Rachel L. Dillard (3)

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10.10	10.19	Amendment dated October 17, 2011 Employment Services Agreement dated September 19, 2011, between Mesa Energy Holdings, Inc. and Rachel L. Dillard (3)

10.11	10.20	Amendment dated October 1, 2012, to Employment Services Agreement dated September 19, 2011, between Mesa Energy Holdings, Inc. and Rachel L. Dillard (3)

10.12	10.22	Loan Agreement, dated July 22, 2011, by and among Mesa Energy, Inc., Mesa Energy Holdings, Inc., TNR Natural Resources, LLC, Mesa Gulf Coast, LL C and The F&M Bank & Trust Company (3)

10.13	10.23	Security Agreement dated July 22, 2011 by TNR Natural Resources, LLC for the benefit of F&M Bank & Trust Company (3)

10.14	10.24	Mortgage, Collateral Assignment, Security Agreement and Financing Statement, dated July 22, 2011 by TNR Natural Resources, LLC for the benefit of F&M Bank & Trust Company (3)

10.15	10.25	Pledge and Security Agreement dated July 22, 2011 by Mesa Energy, Inc. for the benefit of F&M Bank & Trust Company (3)

10.16	10.26	Unlimited Guaranty dated July 22, 2011, by Mesa Energy Holdings, Inc. for the benefit of F&M Bank & Trust Company (3)

10.17	10.27	Unlimited Guaranty dated July 22, 2011, by Mesa Gulf Coast, LLC for the benefit of F&M Bank & Trust Company (3)

10.18	10.28	Unlimited Guaranty dated July 22, 2011, by Tchefuncte Natural Resources, LLC for the benefit of F&M Bank & Trust Company (3)

10.19	10.33	Purchase and Option Agreement between TR Energy, Inc. and Armada Oil, Inc., dated February 7, 2012 (3)

10.20	10.34	Share Exchange Agreement dated March 21, 2012, between NDB Energy, Inc., Armada Oil, Inc. and the Armada Stockholders (3)

10.21	10.37	Amendment and Extension to the Purchase and Option Agreement dated February 7, 2012, between TR Energy, Inc. and Armada Oil, Inc. (3)

10.22	10.38	Seismic and Farmout Option Contract between Anadarko E&P Company LP, Anadarko Land Corp. and Armada Oil, Inc., dated October 22, 2012 (3)

10.23	10.40	Amendment and Extension to the Purchase and Option Agreement dated February 7, 2012, between TR Energy, Inc. and Armada Oil, Inc., dated January 10, 2013 (7)

10.24	10.41	Amendment and Extension to the Purchase and Option Agreement dated February 7, 2012, between TR Energy, Inc. and Armada Oil, Inc. dated March 5, 20 (8)

10.25	10.1	Form of Securities Purchase Agreement between Armada Oil, Inc. and certain investors (5)

10.26	10.2	Form of Armada Oil, Inc. Nonstatutory Stock Option Agreement (5)

10.27	10.2	Form of Unlimited Guarantee dated March 28, 2013 by Armada Oil, Inc. for the benefit of F&M Bank & Trust Company, for itself and as Collateral Agent (3)

10.28	10.1	Executive Employment Agreement dated as of April 1, 2013, between Armada Oil, Inc., and Randy M. Griffin (9)

10.29	10.2	Executive Employment Agreement dated as of April 1, 2013, between Armada Oil, Inc., and James J. Cerna, Jr. (9)

10.30	10.3	Form of Stock Option Agreement with directors and executive officers under the Company’s 2012 Long-Term Incentive Plan (9)

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10.31	10.1	Form of Offering Modification Agreement between Armada Oil, Inc. and purchasers of the 2012 Units (6)

10.32	10.1	Third Amendment to the Seismic and Farmout Option Contract between the Registrant and Anadarko E&P Onshore LLC (10)

10.33	10.1	Second Amendment to Loan Agreement dated October 1, 2013 by and among the Registrant, Mesa Energy, Inc., TNR Natural Resources, LLC, Mesa Gulf Coast, LLC and The F&M Bank & Trust Company (11)

10.34	10.2	Agreement to sell properties in Young County, Texas dated October 1, 2013 by and between the Registrant and Energy Management Resources, LLC (11)

10.35	10.1	Unit Purchase Agreement, dated as of December 20, 2013, among TNR Holdings LLC, Mesa Energy, Inc., the Company and Gulfstar Resources LLC (12)

10.36	10.2	Amended and Restated Limited Liability Company Agreement of TNR Holdings LLC, dated as of December 20, 2013, between Mesa Energy, Inc., and Gulfstar Resources LLC (12)

10.37	10.3	Consulting Services Agreement, dated as of December 20, 2013, between Coral Reef Capital LLC and TNR Holdings LLC (12)

10.38	10.4	Transition Services Agreement, dated as of December 20, 2013, between Mesa Energy, Inc., and TNR Holdings LLC (12)

10.39	10.5	Fourth Amendment to Loan Agreement between Mesa Energy, Inc., and The F&M Bank & Trust Company (12)

10.40	10.6	Unlimited Guaranty dated December 19, 2013, by TNR Holdings, LLC, for the benefit of The F&M Bank & Trust Company (12)

10.41	10.1	Agreement for Purchase and Sale dated as of March 13, 2014, by and between Piqua Petro, Inc., and Armada Midcontinent, LLC, or its assigns (13)

10.42	10.1	Amendment dated as of April 10, 2014, to Unit Purchase Agreement dated December 20, 2013, by and among TNR Holdings LLC, Mesa Energy, Inc., Armada Oil, Inc., and Gulfstar Resources LLC (15)

10.43	10.2	Amended and Restated Transition Services Agreement dated as of April 10, 2014, between Mesa Energy, Inc., and TNR Holdings LLC (15)

10.44	10.3	Fifth Amendment dated April 10, 2014, to Loan Agreement dated July 22, 2011, originally among Mesa Energy, Inc., Mesa Energy Holdings, Inc., Tchefuncte Natural Resources, LLC, Mesa Gulf Coast, LLC, and Prosperity Bank, successor by merger to The F&M Bank & Trust Company, as previously amended (15)

10.45	10.4	First Amendment to Mortgage, Collateral Assignment, Security Agreement and Financing Statement, dated July 22, 2011 by TNR Natural Resources, LLC for the benefit of Prosperity Bank, successor by merger to The F&M Bank & Trust Company (15)

10.46	10.5	Mortgage and Security Agreement dated April 10, 2014, by Armada Midcontinent, LLC, for the benefit of Prosperity Bank, successor by merger to The F&M Bank & Trust Company (15)

10.47	10.6	Unlimited Guaranty dated April 10, 2014 by Armada Midcontinent, LLC, for the benefit of Prosperity Bank, successor by merger to The F&M Bank & Trust Company (15)

10.48	10.1	Unit Purchase and Redemption Agreement, dated May 16, 2014 (16)

10.49	10.2	Amendment to Amended and Restated Limited Liability Company Agreement, dated May 16, 2014 (16)

10.50	10.3	Form of Amendment No. 1 to Securities Purchase Agreement (16)

10.51	10.4	Form of Amendment to 9.625% Senior Unsecured Promissory Note (16)

10.52	10.5	Form of Amendment to Series D Common Stock Purchase Warrant (16)

10.53	10.14	Purchase and Sale Agreement dated October 16, 2014 by and between the Registrant and Tabbs Bay Energy, LP (17)

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10.54	10.1	Seventh Amendment to Loan Agreement dated March 5, 2015 (18)

10.55	10.2	First Amendment to Mortgage and Security Agreement dated March 5, 2015 (18)

14.1	14.1	Code of Business Conduct and Ethics (2)

16.1	16.1	Letter regarding change in certifying accountants dated October 15, 2012 (2)

21	*	List of Subsidiaries

31.1	*	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

31.2	*	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

32.1	*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**

32.2	*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**

99.1	*	Letter from KLH Consulting to Armada Oil, Inc. dated February 4, 2015, relating to its reserves estimates dated as of January 1, 2015

101 INS				XBRL Instance Document***

101 SCH				XBRL Schema Document***

101 CAL				XBRL Calculation Linkbase Document***

101 DEF				XBRL Definition Linkbase Document***

101 LAB				XBRL Labels Linkbase Document***

101 PRE				XBRL Presentation Linkbase Document***

_________________

* Filed/furnished 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.

***

The XBRL related information in Exhibit 101 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability of that section and shall not be incorporated by reference into any filing or other document pursuant to the Securities Act, except as shall be expressly set forth by specific reference in such filing or document.

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(1) Filed with the Securities and Exchange Commission (the “SEC”) on November 29, 2012 as an Appendix to the proxy statement/prospectus forming part of the Registrant’s Registration on Form S-4, which appendix is incorporated herein by reference.

(2) Filed with the SEC on February 22, 2013, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated February 19, 2013, which exhibit is incorporated herein by reference.

(3) Filed with the SEC on December 11, 2012, as an exhibit, numbered as indicated above, to the Registrant’s Registration Statement on Form S-4, Amendment #1, which exhibit is incorporated herein by reference.

(4) Filed with the SEC on March 29, 2013, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated March 28, 2013, which exhibit is incorporated herein by reference.

(5) Filed with the SEC on March 28, 2013, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated March 20, 2013, which exhibit is incorporated herein by reference.

(6) Filed with the SEC on April 30, 2013, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated April 26, 2013, which exhibit is incorporated herein by reference.

(7) Filed with the SEC on December 11, 2012, as an exhibit, numbered as indicated above, to the Registrant’s Registration Statement on Form S-4, Amendment #2, which exhibit is incorporated herein by reference.

(8) Filed with the SEC on December 11, 2012, as an exhibit, numbered as indicated above, to the Registrant’s Registration Statement on Form S-4, Amendment #3, which exhibit is incorporated herein by reference.

(9) Filed with the SEC on April 25, 2013, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated April 19, 2013, which exhibit is incorporated herein by reference

(10) Filed with the SEC on November 6, 2013, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated October 31, 2013, which exhibit is incorporated herein by reference

(11) Filed with the SEC on November 14, 2013, as an exhibit, numbered as indicated above, to the Registrant’s Quarterly Report on Form 10-Q, for the period ended September 30, 2013, which exhibit is incorporated herein by reference

(12) Filed with the SEC on December 27, 2013, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated December 20, 2013, which exhibit is incorporated herein by reference

(13) Filed with the SEC on March 20, 2014, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated March 14, 2014, which exhibit is incorporated herein by reference

(14) Filed with the SEC on March 31, 2014, as an exhibit, numbered as indicated above, to the Registrant’s Annual Report on Form 10-K, for the fiscal year ended December 31, 2013, which exhibit is incorporated herein by reference

(15) Filed with the SEC on April 16, 2014, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated April 10, 2014, which exhibit is incorporated herein by reference

(16) Filed with the SEC on May 22, 2014, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated May 16, 2014, which exhibit is incorporated herein by reference

(17) Filed with the SEC on November 13, 2014, as an exhibit, numbered as indicated above, to the Registrant’s Quarterly Report on Form 10-K, for the fiscal quarter ended September 30, 2014, which exhibit is incorporated herein by reference

(18) Filed with the SEC on March 10, 2015, as an exhibit, numbered as indicated above, to the Registrant’s Current Report on Form 8-K, dated March 5, 2015, which exhibit is incorporated herein by reference

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ARMADA OIL, INC.

Dated: March 31, 2015	By:	/s/ RANDY M. GRIFFIN
		Randy M. Griffin, Chief Executive Officer

Dated: March 31, 2015	By:	/s/ RACHEL L. DILLARD
		Rachel L. Dillard, Chief Financial Officer

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

SIGNATURE	TITLE	DATE

/s/ RANDY M. GRIFFIN	Chairman of the Board and Chief Executive
Randy M. Griffin	Officer (principal executive officer)	March 31, 2015

/s/ JAMES J. CERNA, JR.	Director
James J. Cerna, Jr.		March 31, 2015

/s/ RAY L. UNRUH	Director
Ray L. Unruh		March 31, 2015

/s/ KENNETH T. HERN	Director
Kenneth T. Hern		March 31, 2015

/s/ FRED B. ZAZISKI	Director
Fred B. Zaziski		March 31, 2015

/s/ ERIC WOLD	Director
Eric Wold		March 31, 2015

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ARMADA OIL, INC.

INDEX TO FINANCIAL STATEMENTS

		Page

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2014 and 2013		F-3

Consolidated Statements of Operations for the Years Ended December 31, 2014 and 2013		F-4

Consolidated Statement of Changes in Equity for the Years Ended December 31, 2014 and 2013		F-5

Consolidated Statements of Cash Flows for the Years Ended December 31, 2014 and 2013		F-6

Notes to Consolidated Financial Statements		F-7

F-1

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

Armada Oil, Inc.

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Armada Oil, Inc. (the “Company”) as of December 31, 2014 and 2013 and the related consolidated statements of operations, changes in equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects the consolidated financial position of Armada Oil, Inc. as of December 31, 2014 and 2013 and the consolidated results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that Armada Oil, Inc. will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, Armada Oil, Inc. has suffered recurring losses from operations and has a working capital deficiency that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ GBH CPAs, PC

GBH CPAs, PC

www.gbhcpas.com

Houston, Texas

March 31, 2015

F-2

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ARMADA OIL, INC.

CONSOLIDATED BALANCE SHEETS

	December 31, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents	$	406,306		$	7,095,972
Accounts receivable – oil and gas		84,129			1,524,623
Accounts receivable – other		100,339			32,538
Deferred financing costs, net – current		33,732			13,162
Deferred tax assets – current		—			100,606
Prepaid expenses		61,345			202,280
TOTAL CURRENT ASSETS		685,851			8,969,181

Oil and gas properties, successful efforts accounting:
Properties subject to amortization, net		6,335,092			7,692,703
Properties not subject to amortization, net		13,927,669			10,653,825
Support facilities and equipment, net		96,109			2,417,898
Land		38,345			38,345
Net oil and gas properties		20,397,215			20,802,771

Property and equipment, net		125,476			242,676
Deferred tax asset – noncurrent		—			5,502,988
Deposits on asset retirement obligations		40,000			585,973
Production payment receivable		—			131,250
Other assets		75,098			55,598

TOTAL ASSETS	$	21,323,640		$	36,290,437

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable – trade	$	2,068,395		$	1,362,867
Revenue payable		3,107			418,213
Accrued expenses		451,902			444,972
Accrued expenses – related parties		52			70
Stock payable		43,065			—
Notes payable, net – current		4,000,313			8,767,392
Notes payable – related parties, net – current		200,000			102,158
Derivative liability, commodity contracts – current		—			173,806
Other current liabilities		66,669			10,000
TOTAL CURRENT LIABILITIES		6,833,503			11,279,478

Derivative liability – commodity contracts – noncurrent		—			53,289
Deferred tax liability – noncurrent		—			3,703,553
Asset retirement obligations		463,814			3,161,810
TOTAL LIABILITIES		7,297,317			18,198,130

Commitments and contingencies

Equity:
Preferred stock, par value $0.01, 1,000,000 shares authorized, 0 shares issued and outstanding		—			—
Common stock, par value $0.001, 100,000,000 shares authorized, 56,105,473 and 56,030,473 shares issued and outstanding, respectively		56,105			56,030
Additional paid-in capital		16,356,838			16,108,722
Accumulated deficit		(2,386,620	)		(4,038,633	)
Total equity attributable to Armada Oil, Inc.		14,026,323			12,126,119
Noncontrolling interest		—			5,966,188
TOTAL EQUITY		14,026,323			18,092,307

TOTAL LIABILITIES AND EQUITY	$	21,323,640		$	36,290,437

See accompanying notes to consolidated financial statements.

F-3

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ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2014			2013

Revenues	$	4,450,827		$	12,436,210

Operating expense:
Lease operating expense		2,160,644			7,470,967
Environmental remediation expense		252,135			—
Exploration expense		232,012			284,275
Dry hole expense		—			2,591,770
Depletion, depreciation, amortization, accretion and impairment expense		1,047,229			1,231,340
Loss on sale of oil and gas properties		539,248			86,116
Gain on settlement of asset retirement obligations		—			(3,428	)
General and administrative expense		2,868,891			4,469,260
Impairment of goodwill		—			8,536,758
Total operating expense		7,100,159			24,667,058

Loss from operations		(2,649,332	)		(12,230,848	)

Other income (expense):
Interest income		151			4,412
Interest expense		(701,435	)		(822,335	)
Realized gain (loss) on commodity contracts		(165,511	)		216,100
Loss on change in derivative value – commodity contracts		(167,673	)		(251,876	)
Loss on modification of offering		—			(65,749	)
Gain on sale of subsidiaries		7,395,119			—
Other income		152,168			14,391
Total other income (expense)		6,512,819			(905,057	)

Net income (loss) before taxes		3,863,487			(13,135,905	)
Income tax benefit (expense)		(2,315,219	)		1,766,140
Net income (loss)		1,548,268			(11,369,765	)
Net loss attributable to noncontrolling interest		(103,745	)		—
Net income (loss) attributable to Armada Oil, Inc.	$	1,652,013		$	(11,369,765	)

Net income (loss) per common share:
Basic	$	0.03		$	(0.22	)
Diluted	$	0.03		$	(0.22	)

Weighted average number of common shares outstanding:
Basic		56,061,911			50,751,878
Diluted		56,061,911			50,751,878

See accompanying notes to consolidated financial statements.

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ARMADA OIL, INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the Years Ended December 31, 2014 and 2013

	Common Stock						Additional			Retained
							Paid-In			Earnings			Noncontrolling
	Shares			Par			Capital			(Deficit)			Interest			Total

Balances at December 31, 2012		84,330,477		$	8,433		$	829,273		$	7,331,132		$	—		$	8,168,838

Common stock issued for Armada acquisition		21,094,633			21,095			14,035,247			—			—			14,056,342
Acquisition adjustment – shares		(50,598,286	)		(50,598	)		50,598			—			—			—
Acquisition adjustment – par value					75,897			(75,897	)		—			—			—

Share-based compensation		183,000			183			737,639			—			—			737,822

Shares issued for stock payable		380,651			380			324,620			—			—			325,000

Issuance of common stock for modification of debt offering		639,998			640			65,109			—			—			65,749

Issuance of warrants as debt discount with debt offering		—			—			142,133			—			—			142,133

Issuance of equity in subsidiary to settle note payable		—			—			—			—			600,000			600,000

Sale of noncontrolling interest in TNR Holdings, LLC		—			—			—			—			5,366,188			5,366,188

Net loss		—			—			—			(11,369,765	)		—			(11,369,765	)

Balances at December 31, 2013		56,030,473			56,030			16,108,722			(4,038,633	)		5,966,188			18,092,307

Share-based compensation		75,000			75			162,887			—			—			162,962

Deferred financing cost		—			—			85,229			—			—			85,229

Sale of noncontrolling interest in TNR Holdings, LLC		—			—			—			—			(5,862,443	)		(5,862,443	)

Net income (loss)		—			—			—			1,652,013			(103,745	)		1,548,268

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

See accompanying notes to consolidated financial statements.

F-5

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ARMADA OIL, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2014 and 2013

	Year Ended December 31,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	1,548,268		$	(11,369,765	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization, accretion and impairment		1,047,229			1,231,340
Impairment of goodwill		—			8,536,758
Dry hole expense		—			2,591,770
Deferred income tax (benefit) expense		2,315,219			(1,766,140	)
Share-based compensation		206,027			737,822
Loss on sale of oil and gas properties		539,248			86,116
Gain on settlement of asset retirement obligations		—			(3,428	)
Amortization of debt discount charged to interest expense		87,726			161,201
Amortization of deferred financing costs		64,659			56,292
Realized (gain) loss on derivative commodity contracts		165,511			(216,100	)
Loss on change in derivative value – commodity contracts		167,673			251,876
Loss on offering modification		—			65,749
Gain on sale of controlling interest in subsidiary		(7,395,119	)		—
Changes in operating assets and liabilities:
Accounts receivable – oil and gas		(267,025	)		68,635
Accounts receivable – other		18,884			247,892
Prepaid expenses and other current assets		49,229			161,854
Accounts payable and accrued expenses		323,605			(387,206	)
Accrued expenses – related parties		(18	)		(54,770	)
Revenue payable		(84,622	)		83,780
Other current liabilities		189,228			—
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(1,024,278	)		483,676

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for acquisition and development of oil and gas properties		(9,146,878	)		(2,689,064	)
Cash received from sale of oil and gas properties		200,000			85,000
Cash paid for support facilities and equipment		(418,518	)		(241,821	)
Cash received from sale of support facilities and equipment		—			54,018
Cash proceeds from settlement of derivative commodity contracts		(165,511	)		216,100
Cash received from sale of controlling interest in TNR Holdings, LLC, less cash in TNRH bank accounts of $4,628,993 as of April 1, 2014		1,790,580			—
Cash received from sale of cost basis investment, net		7,055,358			—
Cash paid for acquisition of Armada		—			(293,106	)
Cash paid for property and equipment		—			(10,163	)
Cash received for refund of deposit on asset retirement obligation		—			23,448
Cash paid for deposit		(20,000	)		—
CASH USED IN INVESTING ACTIVITIES		(704,969	)		(2,855,588	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings on notes payable		100,000			786,271
Proceeds from borrowings on notes payable – related parties		100,000			135,000
Principal payments on notes payable		(5,027,860	)		(2,583,224	)
Installment payments on financed liabilities		(132,559	)		(121,000	)
Cash received from sale of noncontrolling interest in subsidiary, net of placement costs		—			5,366,188
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(4,960,419	)		3,583,235

NET CHANGE IN CASH		(6,689,666	)		1,211,323
CASH AT BEGINNING OF YEAR		7,095,972			5,884,649
CASH AT END OF YEAR	$	406,306		$	7,095,972

SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION
Cash paid for interest	$	557,114		$	695,288
Cash paid for income taxes	$	—		$	75,000

NON-CASH INVESTING AND FINANCING TRANSACTIONS
Financed prepaid assets	$	97,143		$	214,980
Software purchased with installment payments	$	—		$	40,000
Deferred financing cost incurred in extending maturity debt by issuance of warrants	$	85,229		$	—
Deposit reclassified to accounts receivable other	$	100,000		$	—
Oil and gas property sold for production payment receivable	$	—		$	131,250
Cost method investment recorded as a result of selling member interest in subsidiary	$	9,830,895		$	—
Change in accrued oil and gas development costs	$	2,020,726		$	(65,692	)
Note payable issued to settle account payable	$	—		$	1,384,139
Issuance of equity in subsidiary to settle note payable	$	—		$	600,000
Common stock issued in satisfaction of stock payable	$	—		$	325,000
Debt discount related to warrants issued in conjunction with notes payable and notes payable – related parties	$	—		$	142,133
Change in asset retirement obligations	$	(2,756,772	)	$	(559,227	)
Common stock issued and options and warrants assumed for Armada acquisition	$	—		$	14,056,342

See accompanying notes to consolidated financial statements.

F-6

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ARMADA OIL, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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 (“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 year ended December 31, 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 financial statements starting from April 1, 2014, no longer consolidated TNRH and its wholly owned subsidiaries, TNR and MGC, but accounted for its investment in TNRH by the cost method. The financial statements of TNRH and its wholly owned subsidiaries, TNR and MGC, were deconsolidated from the financial statements of the Company effective April 1, 2014, because the Company lost its ability to impose significant influence on TNHR, and control of operations and assets of TNRH were restricted by rights of the then non-controlling member as of April 1, 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.Basis of Presentation and Principles of Consolidation

The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of the Company and those of its 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 we believe 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.

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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.

Cash and Cash Equivalents

Cash equivalents are highly liquid investments with an original maturity of three months or less.

Accounts Receivable

Accounts receivable are stated at the historical carrying amount net of writeoffs and allowance for uncollectible accounts. The carrying amount of the Company's accounts receivable approximates fair value because of the short-term nature of the instruments.

The Company routinely assesses the collectibility of all material trade and other receivables. The Company's oil and gas receivables primarily comprise receivables from purchasers of the Company's oil and gas and from joint interest owners on properties the Company operates. The Company may have the ability to withhold future revenue disbursements to recover any nonpayment of these joint interest billings. Joint interest receivables are recorded when the Company incurs expenses on behalf of the non-operator interest owners in the properties the Company operates.

The Company's reported balance of accounts receivable, net of allowance for doubtful accounts, represents management's estimate of the amount that ultimately will be realized in cash. The Company reviews the adequacy of the allowance for doubtful accounts on an ongoing basis, using historical payment trends, the age of the receivables and knowledge of the individual customers or joint interest owners. When the analysis indicates, management increases or decreases the allowance accordingly. However, if the financial condition of our customers were to deteriorate, additional allowances might be required.

Deferred Financing Costs

The costs of issuing debt are capitalized. These costs are amortized over the expected life of the related instrument. When a security is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed.

Oil and Gas Properties, Successful Efforts Method

The cost of oil and gas properties is amortized at the well level based on the unit of production method. Unit of production rates are based on oil and gas reserves and developed producing reserves estimated to be recoverable from existing facilities based on the current terms of the respective production agreements. The Company’s reserve estimates represent crude oil and natural gas which management believes can be reasonably produced within the current terms of their production agreements.

The Company evaluates its proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. The Company follows Accounting Standards Codification ASC 360 - Property, Plant, and Equipment, for these evaluations. Unamortized capital costs are reduced to fair value if the undiscounted future net cash flows from our interest in the property’s estimated proved reserves are less than the asset’s net book value.

Support Facilities and Equipment

Our support facilities and equipment are generally located in proximity to certain of our principal fields. Depreciation of these support facilities is provided on the straight-line method based on estimated useful lives of 7 to 20 years.

Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.

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Proved Reserves

Estimates of the Company’s proved reserves included in this report are prepared in accordance with GAAP and guidelines from the United States Securities and Exchange Commission (“SEC”). The Company’s engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and impairment. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserves estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions, and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of the Company’s estimated proved reserves. The Company engages independent reserve engineers to estimate its proved reserves.

Fair Value of Financial Instruments

The Company adopted the framework for measuring fair value that establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described below:

Level 1:

Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2:

Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instruments, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

Level 3:

Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). The Company’s valuation models are primarily industry standard models. Level 3 instruments include derivative warrant instruments. The Company does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 1 or Level 2.

The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The estimated fair value of the derivative warrant instruments was calculated using a modified lattice valuation model.

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013:

Fair Value Measurement at

Carrying Value

December 31, 2014

Level 1

Level 2

Level 3

Derivative assets, commodity contracts

—

Derivative liabilities, commodity contracts

—

				Fair Value Measurement at
	Carrying Value			December 31, 2013
				Level 1		Level 2			Level 3

Derivative assets, commodity contracts	$	—		$	—	$	—		$	—
Derivative liabilities, commodity contracts		(227,095	)		—		(227,095	)		—

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

Asset Retirement Obligations

The Company follows the provisions of the Accounting Standards Codification ASC 410 - Asset Retirement and Environmental Obligations. The fair value of an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. The Company’s asset retirement obligations relate to the abandonment of oil and gas producing facilities and facilities that support the production of oil and gas. The amounts recognized are based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rate. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds and the capitalized costs are depreciated on a unit-of-production basis. Both the accretion and the depreciation will be included in depreciation, depletion and amortization expense on our consolidated statements of operations.

Revenue Recognition

The Company recognizes sales revenues for natural gas, oil, and NGLs based on the amount of each product sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when product has been delivered to a pipeline or when a tanker lifting has occurred. The Company follows the sales method of accounting for natural-gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production.

Share-Based Compensation

The Company follows the Accounting Standards Codification ASC 718 - Compensation - Stock Compensation. Under ASC 718, the Company estimates the fair value of each stock option award at the grant date by using the Black-Scholes option pricing model and common shares based on the last quoted market price of the Company’s common stock on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation expenses may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, as defined in ASC 718, if any, are recognized as an addition to paid-in capital.

Income Taxes

The Company is a taxable entity and recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to be in effect when the temporary differences reverse. The effect on the deferred tax assets and liabilities of a change in tax rates is recognized in income in the year that includes the enactment date of the rate change. A valuation allowance is used to reduce deferred tax assets to the amount that is more likely than not to be realized. Interest and penalties associated with income taxes are included in selling, general, and administrative expense.

The Company has adopted ASC 740 “Accounting for Uncertainty in Income Taxes” which prescribes a comprehensive model of how a company should recognize, measure, present, and disclose in its financial statements uncertain tax positions that the company has taken or expects to take on a tax return. ASC 740 states that a tax benefit from an uncertain position may be recognized if it is "more likely than not" that the position is sustainable, based upon its technical merits. The tax benefit of a qualifying position is the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority having full knowledge of all relevant information.

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Earnings (Loss) Per Common Share

The Company’s earnings (loss) per share are computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share reflects the potential dilution of securities, if any, that could share in the earnings (loss) of the Company and are calculated by dividing net income by the diluted weighted average number of common shares. The diluted weighted average number of common shares is computed using the treasury stock method for common stock that may be issued for outstanding stock options and convertible debt.

	December 31,
	2014		2013
Numerator:
Net income (loss) available to stockholders	$	1,652,013	$	(11,369,765	)
Basic net income allocable to participating securities (1)		—		—
Income (loss) available to Armada Oil, Inc.'s stockholders	$	1,652,013	$	(11,369,765	)

Denominator:
Weighted average number of common shares outstanding-Basic		56,061,911		50,751,878
Effect of dilutive securities (2) :
Options and warrants		—		—
Weighted average number of common shares outstanding-Diluted		56,061,911		50,751,878

Net income (loss) per share:
Basic	$	0.03	$	(0.22	)
Diluted	$	0.03	$	(0.22	)

	(1)	Restricted share awards that contain non-forfeitable 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 year ended December 31, 2014, “out of the money” stock options representing 3,602,000 shares and warrants representing 7,953,333 shares were antidilutive and, therefore, excluded from the diluted share calculation. For the year ended December 31, 2013, “out of the money” stock options representing 2,802,000 shares and warrants representing 7,553,333 shares were antidilutive and, therefore, excluded from the diluted share calculation.

Recently Issued Accounting Pronouncements

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

Subsequent Events

The Company has evaluated all 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 December 31, 2014, has a working capital deficit at December 31, 2014 of $6,147,652 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 – BUSINESS COMBINATION

On March 28, 2013, Armada completed the acquisition (the “Acquisition”) of substantially all of the assets of Mesa Energy Holdings, Inc. consisting of all of the issued and outstanding shares of MEI pursuant to the terms of the Asset Purchase Agreement and Plan of Reorganization Among Armada Oil, Inc., Mesa Energy Holdings, Inc., and Mesa Energy, Inc. (the “APA”). The Company accounted for the assets, liabilities and ownership interests in accordance with the provisions of ASC 805, Business Combinations.

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

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

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

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

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

Assets acquired:
Cash	$	31,894
Prepaid assets		33,061
Other current assets		50,000
Total current assets		114,955

Oil and gas properties, subject to amortization		514,249
Oil and gas properties, not subject to amortization		9,948,551
Total assets acquired		10,577,755

Liabilities assumed:
Accounts payable and accrued liabilities		2,471,665
Note payable, net of discount of 103,001		197,197
Deferred tax liability		1,999,046
Asset retirement obligations		65,263
Total liabilities assumed		4,733,171

Net assets acquired		5,844,584
Goodwill		8,536,758
Consideration paid – cash and equity instruments at fair value	$	14,381,342

Pro forma results of operations for the year ended December 31, 2013, as though this acquisition had taken place at the beginning of the period, is as follows. The pro forma results are not necessarily indicative of what actually would have occurred had the acquisition been in effect for the entire period presented.

	Year Ended December 31, 2013

Revenues	$	12,485,258
Net loss	$	(12,201,632	)
Loss per common share – basic and diluted	$	(0.24	)
Weighted average common shares outstanding - basic and diluted		50,751,878

NOTE 4 – 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 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 contains the results of operations of the Company for the year ended December 31, 2014, and of TNRH and its subsidiaries for the three months ended March 31, 2014.

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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	)

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

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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 5 – COMMODITY DERIVATIVE INSTRUMENTS

Through the first quarter of 2014, the Company had engaged in price risk management activities from time to time, through utilizing derivative instruments consisting of swaps, floors and collars, to attempt to reduce the Company’s exposure to changes in commodity prices. None of the Company’s derivatives was designated as a cash flow hedge. Changes in fair value of derivative instruments not designated as cash flow hedges are recorded in other income (expense) as realized and unrealized (gain) loss on commodity derivatives.

While the use of these arrangements limited the Company's ability to benefit from increases in the price of oil and natural gas, it was also intended to reduce the Company's potential exposure to significant price declines. These derivative transactions were generally placed with major financial institutions that the Company believes to be financially stable.

The Company had commodity derivative instruments with a single counterparty for which it determined the fair value using period-end closing oil and gas prices, interest rates and volatility factors for the periods under each contract. As a result of the Company’s sale of the controlling interest in TNRH to Gulfstar, TNRH agreed in the Amendment to Unit Purchase Agreement dated April 10, 2014 to assume the hedging contracts between the Company and the counterparty. Prosperity Bank, successor by merger to F&M Bank & Trust Company, agreed to the Company transferring and novating its interest in its hedges to TNRH in the Sixth Amendment to the Loan Agreement dated July 22, 2011, on May 30, 2014, see NOTE 7. As a result the Company has no assets or liabilities associated with commodity derivative instruments at December 31, 2014.

For the years ended December 31, 2014 and 2013, the Company recorded a realized loss of $165,511 and realized gain of $216,100, respectively, and unrealized losses of $167,673 and $251,876, respectively, on the statements of operations.

NOTE 6 – PROPERTY AND EQUIPMENT

Oil and Gas Properties

The Company’s oil and gas properties at December 31, 2014 and 2013 are located in the United States of America.

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The carrying values of the Company’s oil and gas properties, net of depletion, depreciation, amortization, and impairment at December 31, 2014 and 2013 were:

	December 31,
Property	2014		2013

Bear Creek Prospect	$	13,921,956	$	9,957,839
Woodson County, Kansas		6,340,805		—
Lake Hermitage Field (1)		—		3,644,986
Valentine Field (1)		—		1,895,504
Larose Field (1)		—		1,112,275
Bay Batiste Field (1)		—		953,197
Turkey Creek Field		—		782,727
Total	$	20,262,761	$	18,346,528

(1)

Properties held by TNRH which was deconsolidated as of April 1, 2014, see Note 4.

Net oil and gas properties at December 31, 2014 and 2013 were as follows:

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

2012 and prior	$	8,848,195	$	7,360,855	$	(466,066	)	$	(2,090,383	)	$	(3,810,942	)	$	9,841,659
2013		10,422,630		2,176,671		(2,591,770	)		(346,152	)		(1,156,510	)		8,504,869
2014		6,708,324		4,832,756		—			(8,837,248	)		(787,599	)		1,916,233
Total	$	25,979,149	$	14,370,282	$	(3,057,836	)	$	(11,273,783	)	$	(5,755,051	)	$	20,262,761

During the years ended December 31, 2014 and 2013, we incurred $232,012 and $284,275, respectively, of exploration expense which is included on our consolidated statements of operations.

During the year ended December 31, 2014, Gulfstar purchased the all of the Company’s interest in TNRH. The net book value of these properties, $8,229,277, was removed from the Company’s balance sheet. The remaining amount of 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, are subject to impairment.

Turkey Creek Field – Garfield and Major Counties, Oklahoma

During the year ended December 31, 2014, the Company sold its undeveloped leasehold interest carried at $570,425 for $150,000, recognizing a loss of $420,425, and impaired $121,112 and $10,000 of undeveloped and developed leasehold costs, respectively, and $84,209 of intangible drilling costs associated with the Thomas Unit #5 well, reducing the Company’s investment in Oklahoma to $0.

During the year ended December 31, 2013, the Company spent $1,674,539 on drilling the Thomas Unit #6H well. The Thomas Unit #6H was not completed due to mechanical issues and has been plugged and abandoned with total costs of $2,591,770 charged to dry hole expense. The Company also impaired $57,945 in undeveloped leasehold costs associated with Section 29 and $20,000 in developed leasehold costs associated with the Traylor Unit #1.

Bear Creek Prospect – Carbon County, Wyoming

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

On November 2, 2012, Armada executed a Seismic and Farm Out Option Contract (the “Anadarko Contract”) whereby Anadarko E&P Onshore LLC (successor in interest to Anadarko E&P Company LP), and Anadarko Land Corp. (collectively “Anadarko”) agreed to execute a mineral permit granting the Company the nonexclusive right, until May 1, 2013, to conduct 3D survey operations on and across the contracted acreage in Carbon County, Wyoming. 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 percent (100%) operated working interest in the section upon which the well was drilled. Anadarko will retain a twenty percent (20%) royalty interest in future production. The Company delivered the seismic data to Anadarko as required and is evaluating potential funding opportunities for completion of the test well and the drilling of subsequent wells.

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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.

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 December 31, 2014.

As a result of the precipitous drop in oil prices, the completion of the Bear Creek # 1 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, Anadarko has agreed to extend the required date for commencement of drilling of the first Continuous Option Test Well until December 31, 2015. As of the date of this filing, the extension is being prepared by Anadarko’s legal department.

Grayson County, Texas, Acquisition of Leasehold Interest Held for Sale

During the year ended December 31, 2014, the Company acquired from a related party a two-year term assignment of an oil and gas lease on 250 acres in Grayson County, Texas, for the purpose of reselling this interest at a profit. The Company paid $37,540 for this interest and sold it for $50,000, recognizing a gain of $12,460.

Young County, Texas

In June 2013, Armada formally took over operatorship of a lease in which it had, in July 2011, acquired a non-operated interest. The leasehold includes approximately 120 acres of land and fourteen stripper wells. Shortly after we took over operatorship, the wells were shut in. The Company recognized a $212,160 impairment of the leasehold, leaving a fair value of $150,000.

As of October 1, 2013, the Company sold its Young County, Texas, properties for $131,250, recognized a loss of $18,750 on the sale. The Company exchanged the property for a temporary override in the production of the properties until the sale price has been received in full. As of December 31, 2013, the purchaser has to develop the property and the Company has recorded a production payment receivable of $131,250. During the year ended December 31, 2014, we evaluated the production payment receivable, determined it uncollectible, and charged it to loss on sale of oil and gas properties.

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

On August 31, 2009, the Company acquired the Java Field, a natural gas development project targeting the Marcellus Shale present in Wyoming County in western New York. The acquisition included 19 producing natural gas wells and their associated leases/units, two surface tracts of land totaling approximately 36 acres and two pipeline systems, including a 12.4 mile pipeline and gathering system that serves the existing field as well as a separate 2.5 mile system located northeast of the field. Our average net revenue interest (NRI) in the leases is approximately 78%. Production from the wells is nominal but serves to hold the acreage for future development.

As of December 31, 2014, 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.

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Support Facilities and Equipment

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

		December 31,
	Years	2014			2013

Tank batteries	7 - 12	$	44,000		$	807,580
Production equipment	7		38,351			1,034,599
Production facilities	7		6,000			108,702
Field offices	20		—			150,000
Crew boat	7		—			172,413
Vehicles	7		17,748			—
Construction in progress (not depreciated)	N/A		—			43,696
Asset retirement cost	7		—			786,828
Subtotal			106,099			3,103,818
Accumulated depreciation			(9,990	)		(685,920	)
Total support facilities and equipment, net		$	96,109		$	2,417,898

During the year ended December 31, 2014, Gulfstar purchased the Company’s entire interest in TNRH, and the Company removed the assets of the subsidiaries comprising TNRH, TNR and MGC, from the Company’s balance sheet, see NOTE 4.

During the year ended December 31, 2013, the Company sold for $54,018 the land and building comprising the Lake Hermitage field office/camp which was seriously damaged by Hurricane Isaac in 2012. The net book value of the camp when sold was $119,467 ($109,467 – building, $10,000 – land), and a loss of $65,449 was incurred on the sale of the camp.

The Company recognized depreciation expense of $111,517 and $311,894 during the years ended December 31, 2014 and 2013, respectively.

Office Furniture, Equipment, and Other

		December 31,
	Years	2014			2013

Office equipment, computer equipment, purchased software, and leasehold improvements	3	$	220,301		$	251,912
Furniture and fixtures	10		37,570			55,569
Subtotal			257,871			307,481
Accumulated depreciation			(132,395	)		(64,805	)
Total property and equipment, net		$	125,476		$	242,676

During the years ended December 31, 2014 and 2013, respectively, the Company recognized depreciation expense of $89,337 and $49,114 during the years ended December 31, 2014 and 2013, respectively.

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

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NOTE 7 – DEBT

The Company’s notes payable consisted of the following at December 31, 2014 and 2013:

	December 31,
	2014			2013

Credit Facility	$	3,472,693		$	8,222,693
Notes issued pursuant to private placement of securities		500,000			655,000
Less: debt discount on private placement notes		—			(87,725	)
Other term notes		227,620			79,582
Notes payable outstanding		4,200,313			8,869,550
Less: current maturities		(4,200,313	)		(8,869,550	)
Notes payable – noncurrent	$	—		$	—

Credit Facility and Notes Payable

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. At December 31, 2014 and 2013, the interest rate was 5.75%. A 2.00% annual fee is applicable to letters of credit drawn under the Credit Facility.

The Credit Facility provided financing for the 2011 acquisition of TNR, working capital for field enhancements, and general corporate purposes. The Credit Facility was originally subject to an initial borrowing base of $10,500,000 which was fully utilized by the Company with the completion of the acquisition of TNR. The Company obtained letters of credit in the amount of $4,704,037 that were provided to the State of Louisiana to secure asset retirement obligations associated with the properties. $5,693,106 was funded to MEI to complete the transaction, provide working capital for field enhancements and for general corporate purposes. In addition, MEI paid a $102,877 loan origination fee which is being amortized over the life of the loan. The borrowing base is subject to two scheduled redeterminations each year. Loans made under this credit facility were secured by TNR’s proved developed producing reserves (“PDP”) as well as guarantees provided by the Company, MEI, and the Company’s other wholly-owned subsidiaries. Monthly commitment reductions were initially set at $150,000 beginning November 22, 2011, and continuing until the first redetermination on or about April 1, 2012. At the first redetermination, the Company was relieved of its obligation to make monthly commitment reductions, and its borrowing base was increased from $10,500,000 to $13,500,000. Future principal reduction requirements, if any, will be determined concurrently with each semi-annual redetermination. In September 2012, 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.

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.

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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 include:

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

· A First Amendment to the Security Agreement and a First Amendment to the Mortgage, Collateral Assignment, Security Agreement and Financing Statement amending the original of those documents dated July 22, 2011 (“Amended Security Agreement and Mortgage”) was entered into by which the properties and all associated collateral located in the Lake Hermitage Field 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 pays Lender the Limitation Amount in satisfaction of Mesa Energy, Inc.’s (“Borrower”) outstanding indebtedness on the Revolving Loan, Lender shall deliver to TNR a partial release of the Louisiana Mortgage and Security Agreement with the only remaining obligations of TNRH being related to the Excluded LC’s.

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

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

The Borrowing Base 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 shall have been released from its obligations under the Restated Guaranty.

The Credit Facility required that 50% of the projected production from the acquired properties be hedged for 24 months at $100 per barrel or above. The Company entered into various commodity derivative contracts with a single counterparty.

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

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.

At inception of the Credit Facility, deferred financing costs of $102,877 were incurred. For the years ended December 31, 2014 and 2013, $13,162 and $22,563, respectively, of amortized deferred financing costs had been recognized as interest expense. At December 31, 2014, no deferred financing costs remained to be amortized.

The Credit Facility contains covenants with which the Company must maintain compliance, among which are certain ratios. The Company determined that, at December 31, 2014, it was not in compliance with the percentage of general and administrative expense to revenues calculated at 164.48% although required under the Loan Agreement, as amended, to be less than or equal to 27%. The Company was not in compliance with this covenant for the quarters ended March 31, 2014, June 30, 2014, and September 30, 2014, as well. The Company’s noncompliance with the percentage of general and administrative expense to revenues covenant for two consecutive quarters constitutes an event of default under the Loan Agreement. The company was also in violation of its current ratio and interest covenant ratio at December 31, 2014, also constituting an event of default. Upon an event of default, the entire principal amount of outstanding indebtedness under the Credit Facility, together with all accrued but unpaid interest thereon, shall, at the option of Prosperity Bank, be matured without further notice and become immediately due and payable. As of March 5, 2015, Prosperity Bank waived all violations of financial covenants occurring on or before March 5, 2015. See Note 13.

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For the years ended December 31, 2014 and 2013, the Company recognized interest expense of $441,214 and $520,146, 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	$	—

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 December 31, 2014, $33,732 of deferred financing costs remained to be amortized

During the years ended December 31, 2014 and 2013, the Company recognized interest expense of $52,162 and $47,656, respectively, on the face value of the notes, and amortization of the debt discount resulted in the recognition of $87,626 and $161,201, respectively, as interest expense. During the year ended December 31, 2014, $51,496 of interest expense was recognized upon amortization of deferred financing costs associated with the change in exercise price and issuance of additional warrants. Prior to the acquisition of Mesa on March 27, 2013, $198 of interest expense on the notes and $5,190 of debt discount amortization were recognized as interest expense, and were allocated to the purchase price of the Acquisition on March 28, 2013. No debt discount remains unamortized at December 31, 2014.

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

During the year ended December 31, 2014, the Company issued two promissory notes, as follows:

Issued To	Origination Date	Maturity Date	Principal Amount		Interest Rate			Interest Expense Accrued through December 31, 2014

Sycamore Resources, Inc.	October 1, 2014	December 31, 2015	$	100,000		12	%	$	3,025
David J. Moss	October 31, 2014	December 31, 2015		100,000		12	%		1,940

Totals			$	200,000				$	4,965

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.

Premium Financed Insurance Notes

On April 24, 2014 the Company entered into a premium financed note for general liability, auto and workers compensation insurance in the principal amount of $20,291 at an interest rate of 5.59%. At December 31, 2014, the outstanding balance on this note was $4,134. Interest expense incurred and paid on this note during the year ended December 31, 2014, was $495.

On July 21, 2014 the Company entered into a premium financed note for umbrella and well control insurance in the principal amount of $38,887 at an interest rate of 4.49%. At December 31, 2014, the outstanding balance on this note was $19,625. Interest expense incurred and paid on this note during the year ended December 31, 2014 was $584.

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%. At December 31, 2014, the outstanding balance on this note was $3,861, and the company had incurred and paid $771 of interest expense.

As of December 31, 2013, the Company had a balance of $3,957 on a premium financed note for directors’ and officers’ liability insurance. This balance was paid in full during the year ended December 31, 2014.

Debt Maturities

At December 31, 2014, the Company had no long-term debt, and all maturities are current.

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NOTE 8 – ASSET RETIREMENT OBLIGATIONS

The following table provides a reconciliation of the changes in the estimated present value of asset retirement obligations for the years ended December 31, 2014 and 2013.

	For the Year Ended December 31,
	2014			2013

Beginning asset retirement obligations	$	3,161,810		$	3,507,798
Deconsolidation of TNRH		(3,106,376	)		—
Obligations assumed from acquisition (1)		349,604			65,263
Revaluation of asset retirement obligations (2)		—			(468,519	)
Accretion expense		58,776			172,927
Sale of Young and Archer County properties		—			(99,891	)
Settlement of asset retirement obligations		—			(15,768	)
Ending asset retirement obligations	$	463,814		$	3,161,810

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

During the year ended December 31, 2014, the Company’s ownership status in TNRH changed from controlling to non-controlling, and the Company adopted the cost method of accounting for its investment in TNRH, deconsolidating the financial statements of TNRH from that of the Company, before the Company sold the remainder of its interest in TNRH. Also, during the year ended December 31, 2014, the Company purchased developed leasehold in Woodson County, Kansas, and assumed the liability to plug and abandon wells from the seller.

During the year ended December 31, 2013, the State of Louisiana refunded the deposit of $23,448 made by the Company on the Valentine Sugars #10 well which was plugged and abandoned before it was acquired from TNR on July 22, 2011. As a result, the asset retirement obligation on the well of $15,768 was eliminated. In addition, the asset retirement obligation for wells in the Keller Prospect in Young County, Texas, was revalued and increased by $30,794 and then retired upon sale of the properties. The asset retirement obligation for the wells in Parish and Tribune Prospects in Archer County, Texas, was retired upon sale. Gains on sales and settlements of asset retirements obligations during the year ended December 31, 2013 were $3,428. At December 31, 2013, the Company provided $4,628,125 in letters of credit supporting its asset retirement obligations.

NOTE 9 – INCOME TAXES

The components of the income tax provision (benefit) for each of the periods presented below are as follows:

	Year Ended December 31,
	2014		2013
Current	$	451,465	$	2,180
Deferred		1,863,754		(1,768,320	)
Total	$	2,315,219	$	(1,766,140	)

The effective income tax expense differed from the computed “expected” federal income tax expense on earnings before income taxes for the following reasons:

	Year Ended December 31,
	2014			2013
Computed federal income tax provision	$	1,313,584		$	(4,466,208	)
Nondeductible expenses and nontaxable income		1,173			2,905,046
State income taxes (net of federal benefit)		269,223			(159,296	)
Increase in valuation allowance		853,638			–
Other		(122,399	)		(45,683	)
Total	$	2,315,219		$	(1,766,140	)

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Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Components of our deferred income taxes as of December 31, 2014 and 2013 are as follows:

	December 31,
Current Deferred Tax Assets/(Liabilities)	2014			2013
Imputed interest	$	6,025		$	6,025
Derivatives		—			—
Valuation allowance		(1,282	)		94,581
Net current deferred tax assets/(liabilities)	$	4,743		$	100,606

	December 31,
Noncurrent Deferred Tax Assets/(Liabilities)	2014			2013
Difference in depreciation, depletion, and capitalization methods – oil and natural gas properties	$	1,251,753		$	1,481,806
Net operating losses		1,439,435			2,497,935
Share based compensation		1,052,069			988,341
Derivatives		21,513			—
Tax credits		128,659			—
Debt discount		—			149,622
Capitalized merger costs		522,202			385,284
Other		28			—
Valuation allowance		(816,069	)		—
Total noncurrent deferred tax asset	$	3,599,590		$	5,502,988

Difference in depreciation, depletion, and intangible drilling costs - oil and natural gas properties	$	(3,604,333	)	$	(3,685,274	)
Other		—			(18,279	)
Total noncurrent deferred tax liabilities	$	(3,604,333	)	$	(3,703,553	)

Net deferred tax asset/(liability)	$	—		$	1,900,041

The Company has US net operating loss carry forwards of approximately $3.8 million which begin to expire in 2029.

Utilization of the NOL is subject to a substantial annual limitation due to the ownership change limitations provided by the Internal Revenue Code of 1986, as amended. The Company does not expect any of its NOL carryforwards to expire unutilized as a result of existing ownership changes. If we incur an additional limitation, then the NOL carryforwards, as disclosed, could be reduced by the impact of any future limitation that would result in existing NOL carryforwards and tax credit carryforwards expiring unutilized.

In 2011, the Company achieved positive earnings, primarily due to the Company’s successful acquisition of Tchefuncte Natural Resources LLC. Based on the weight of available objective evidence, management believed that it was more likely than not that its deferred tax asset would be realized. Accordingly, the Company eliminated its valuation allowance in 2011. The benefit from the reduction was recorded as a tax benefit in accordance with accounting standards for income taxes. During the year ended December 31, 2014, falling commodity prices and the Company’s inability to replace the revenues associated with the controlling interest in TNRH which the Company sold, management determined that it is less likely than not, in the current commodity pricing environment and without acquiring new reserves that would be economically feasible to purchase and produce, that its deferred tax asset would be realized. Accordingly, the Company reestablished its valuation allowance at December 31, 2014.

The Company recognizes 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 years ended December 31, 2014 and 2013. There were no interest and penalties related to unrecognized tax positions for the years ended December 31, 2014 and 2013. The tax years subject to examination by tax jurisdictions in the United States are 2010 through 2014.

As of December 31, 2014, the Company recorded a net valuation allowance of $816,069 for net deferred tax assets of $0. As of December 31, 2013, the Company recorded deferred tax assets, net of deferred tax liabilities $1,900,041.

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NOTE 10 – COMMITMENTS AND CONTINGENCIES

Contractual Obligations

The Company leases its corporate office in Dallas, Texas, at monthly rental amount of $7,390. The Dallas office subleases a portion of its square footage. In addition, the Company leased a field office in Covington, Louisiana, and a residence to house crews at Lake Hermitage field in Louisiana at monthly rental amounts of $6,852 and $1,800, respectively, through March 31, 2014, as well as office space in California on a month-to-month basis at a monthly rental of $930 through April 2014. The Dallas office lease expires on June 30, 2015. During the year ended December 31, 2014, the Company paid rent totaling $76,215 (net of reimbursement from sublessee), $21,533, $3,720, and $7,200 for its Dallas, Covington, and California offices and Lake Hermitage residence, respectively.

The Company also leased, through March 31, 2014, four trucks used in its field operations in Louisiana. The leases for these trucks qualified as operating leases. During the year ended December 31, 2014, the Company made total payments of $6,050 for the trucks.

The Company also leased a copier at monthly rental of $299 through March 31, 2014, for its Covington, Louisiana, office. During the year ended December 31, 2014, the Company paid $897 in rental for the copier.

During 2014, the Company’s rental expense was $128,080 for all operating leases.

During 2013, the Company’s rental expense was $213,936 for all operating leases.

Information regarding all the Company’s contractual lease obligations, at December 31, 2014, is set forth in the following table.

	Operating
	Leases

2015	$	51,730
2016		—
2017 and thereafter		—
Total	$	51,730

Contingencies

From time to time, the Company may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters that may arise from time to time that may harm the Company’s business.

Other than routine litigation arising in the ordinary course of business that the Company does not expect, individually or in the aggregate, to have a material adverse effect on the Company, there are currently no pending legal proceedings.

Liens

In connection with the drilling of our Bear Creek #1 well, the Company has unpaid invoices payable to vendors of $2,024,721 of which $1,955,304 are reflected in Accounts Payable – Trade and $69,417 in Accrued Expenses on our consolidated balance sheets as of December 31, 2014. Of these, three vendors have recorded liens against our Bear Creek #1 wellbore in the amount of $1,015,898. Interest at 18% per annum was included with one lien filing and is reflected in accrued expenses on our consolidated balances sheets and as interest expense on our consolidated statements of operations in the amount of $27,541.

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NOTE 11 – EQUITY

Common Stock

The following table shows the Company’s common stock activities for the year ended December 31, 2014:

	Common
	Shares
	Issued

Shares issued as compensation to a consultant		75,000

Total shares issued during the year ended December 31, 2014		75,000

The following table shows the Company’s common stock activities for the year ended December 31, 2013:

	Common
	Shares
	Issued

Shares issued in Acquisition		21,094,633
Adjustment to Mesa Energy Holdings, Inc. common shares in Acquisition		(50,598,286	)
Shares issued in conjunction with issuance of debt (See Note 7)		639,998
Shares issued as compensation (See Note 12) (1)		563,651

Total change in common shares for the year ended December 31, 2013		(28,300,004	)

(1)

Restricted common stock with fair value of $380,515 which vested pursuant to grants awarded in 2013 to employees pursuant to our 2012 Long-term Incentive Plan (“2012 Incentive Plan”) (108,000 shares) and to consultants (455,651 shares). Fair value was determined by multiplying the number of shares granted by the closing price of the Company’s common stock on the date of grant.

Warrants

The following table summarizes the Company’s warrant activities for the year ended December 31, 2014 and 2013:

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

Outstanding and exercisable at December 31, 2012		200,000			1.00	2.5 years		—
Assumed under Armada acquisition (See Note 3)		7,414,787			3.25	2.3 years		—
Modified		639,998			0.75	3.2 years		—
Granted		473,333			0.75	3.2 years		—
Exercised		—
Cancelled/expired		(1,174,785	)		1.25	—		—
Outstanding at December 31, 2013		7,553,333		$	1.96	3.2 years	$	—
Granted		400,000			0.30	4.4 years		—
Exercised		—			—	—		—
Cancelled/Expired		—			—	—		—
Outstanding at December 31, 2014		7,953,333		$	1.84	3.3 years	$	—

Exercisable at December 31, 2014		7,953,333		$	1.84	3.3 years	$	—

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During the year ended December 31, 2014, the exercise price of warrants issued to James J. Cerna, Jr., a member of our board of directors, and two others was reduced from $0.75 to $0.30 in exchange for agreeing to extend the maturity of notes payable to them from May 30, 2014, to May 30, 2015, see NOTE 7. The reduction in the exercise price resulted in $8,280 of additional cost recognized as deferred financing costs of which $5,003 was recognized as interest expense through September 30, 2014. In addition, 400,000 warrants were issued to two note holders (not including James J. Cerna, Jr.) whose exercise price had been modified in exchange for their agreement to the note extension. The fair value of those warrants was determined through a Black Scholes model to be $76,948, which was charged to deferred financing costs as a cost associated with financing debt of which $46,494 was amortized to interest expense.

During the year ended December 31, 2013, 1,174,785 of Series A Warrants with an exercise price of $1.25 expired.

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

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

During the year ended December 31, 2013, pursuant to the Offering Modification (NOTE 5), eight investors who in October and November 2012 contributed $720,000 in the aggregate to participate in an offering of securities comprising 800,002 shares of common stock and warrants to purchase an equal number of shares of common stock at $1.25 per share were granted an additional 639,998 shares and warrants to purchase an equal number of shares of common stock at $0.75 per share. In addition, the exercise price of $1.25 per share of the initially granted warrants was reduced to $0.75 per share. As a result of the Offering Modification the fair value of the common shares was reduced by $112,063 from $477,192 to $365,039. The fair value of the warrants was increased by $177,902 from $177,059 to $354,961. The changes in fair value were recognized in Additional Paid-In Capital, with a loss on the modification of $65,749 recognized in Other Income.

Under a private placement commenced on March 20, 2013, Series D Warrants to purchase 873,333 common shares were issued at periodic closings through April 30, 2013, of which 400,000 were assumed under the Armada acquisition and 473,333 were issued after the consummation of the Armada acquisition. Each warrant became exercisable at $0.75 per share beginning September 1, 2013. The fair value of the warrants, determined as their relative fair value to the notes, calculated using a Black Scholes model, was $241,083. Assumptions used in determining the fair values of the warrants were as follows:

	2013
Weighted average grant date fair value	$	0.53
Discount rate		0.77	%
Expected life (in years)		4.9
Weighted average volatility		205.74	%
Expected dividends	$	—

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

5220 Spring Valley Road, Suite 615 Dallas, Texas	75254
(Address of principal executive office)	(Zip Code)

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

		Page

Part I

Item 1.	Business	3

Item 1A.	Risk Factors	16

Item 1B.	Unresolved Staff Comments	25

Item 2.	Properties	25

Item 3.	Legal Proceedings	25

Item 4.	Mine Safety Disclosures	25

Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26

Item 6.	Selected Financial Data	27

Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	35

Item 8.	Financial Statements and Supplementary Data	35

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	35

Item 9A.	Controls and Procedures	36

Item 9B.	Other Information	36

Part III

Item 10.	Directors, Executive Officers and Corporate Governance	37

Item 11.	Executive Compensation	43

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	47

Item 13.	Certain Relationships and Related Transactions, and Director Independence	49

Item 14.	Principal Accounting Fees and Services	51

Part IV

Item 15.	Exhibits, Financial Statement Schedules	52

Signatures		57

		(972) 490-9595
(Registrant’s telephone number, Including area code)

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

Outstanding at December 31, 2012		1,138,800			0.76	3.1 years
Assumed under Armada acquisition (See Note 3)		1,064,000			1.06	0.0 years			—
Granted (1)		2,052,000			0.39	3.1 years			—
Exercised		—			—		—		—
Cancelled/Expired/Forfeited (2)		(1,452,800	)		—		—		—
Outstanding at December 31, 2013		2,802,000			0.41	2.9 years		$	—
Granted		900,000			0.22	4.1 years			—
Exercised		—			—		—		—
Cancelled/Expired/Forfeited		(100,000	)		—		—		—
Outstanding at December 31, 2014		3,602,000			0.37	3.8 years		$	—

Exercisable at December 31, 2014		3,197,000		$	0.38	3.1 years		$	—

	(1)	Comprises 240,000 shares of restricted stock grant converted to options on March 20, 2013, 1,720,000 options granted to directors, and 92,000 options granted to employees.
	(2)	Comprises 119,200 of expired options, 942,000 of forfeited unvested options previously granted to former officers and directors prior to the Armada Acquisition, 91,600 of forfeited vested and unvested options previously granted to employees, and 300,000 granted to directors which were cancelled and replace by new option grants,

	2013
Weighted average grant date fair value	$	0.34
Weighted average risk-free interest rate		0.49	%
Expected life (in years)	4.8
Weighted average volatility		158.8	%
Expected dividends	$	-

	Shares
Unvested Restricted Shares at December 31, 2012		870,000
Granted		455,651
Vested		(563,651	)
Cancelled (1)		(240,000	)
Unvested Restricted Shares at December 31, 2013		—
Granted		75,000
Vested		(75,000	)
Forfeited		—
Unvested Restricted Shares at December 31, 2014		—

	2014			2013

Undeveloped properties not subject to amortization	$	9,961,003		$	10,653,825
Proved properties subject to amortization		6,634,710			12,660,155
Exploratory well capitalized as work-in-progress		3,966,666			—
Accumulated depreciation, depletion and amortization		(299,618	)		(4,967,452	)
Net capitalized costs	$	20,262,761		$	18,346,528

	2014		2013

Proved acreage	$	6,290,820	$	151,421
Undeveloped acreage		37,540		9,952,637
Development costs		872,578		1,484,542
Exploration expense		3,966,666		284,275
Total	$	11,167,604	$	11,872,875

	2014 Quarter Ended
	March 31			June 30			September 30			December 31
Net revenues from production:
Sales of oil and gas production	$	3,137,327		$	531,534		$	410,260		$	322,022

Net losses from disposition of oil and gas properties		—			—			420,425			118,823

Production Expenses:
Oil and gas operating expense		1,837,150			62,042			122,976			138,476
Exploration expenses		159,529			7,895			31,472			33,116
Depreciation, depletion, and amortization		249,261			68,166			55,603			175,849

Results of operations before income tax expense:	$	891,387		$	393,431		$	(220,216	)	$	(144,242	)
Income tax benefit (expense)		(303,072	)		(133,767	)		74,873			49,042
Results of operations	$	588,315		$	259,664		$	(145,343	)	$	(95,200	)

Net cash flows at December 31,	2014			2013

Future cash inflows	$	55,195,631		$	380,215,130
Future production costs		(19,374,419	)		(110,045,029	)
Future development costs		(1,680,000	)		(50,633,990	)
Future income tax expense		(7,877,426	)		(71,519,884	)
Future net cash flows		26,263,786			148,016,227
10% annual discount for estimated timing of cash flow		(16,305,939	)		(57,972,758	)
Standard measure of discounted future net cash flows related to proved reserves	$	9,957,847		$	90,043,469

	2014			2013
Balance, beginning of period	$	90,043,469		$	65,797,638
Sales and transfers of oil and gas produced during the period		(2,228,994	)		(4,839,930	)
Sales of minerals in place		(170,087,342	)		—
Purchases of minerals in place		11,700,316			—
Net change in sales price, net of production costs		(3,122,215	)		(11,857,860	)
Net changes due to extensions and discoveries		—			69,652,153
Changes in estimated future development costs		43,624,923			(14,086,502	)
Previously estimated development costs incurred during the period		872,578			(1,148,091	)
Net change due to revisions in quantity estimates		1,683,141			7,103,228
Other		(8,483,111	)		(15,902,254	)
Accretion of discount		1,246,281			9,926,350
Net change in income tax		44,708,801			(14,601,263	)
Balance, end of period	$	9,957,847		$	90,043,469