UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2012

Commission file number: 0-53972

MESA ENERGY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)

Delaware		98-0506246
(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)
	(972) 490-9595
(Registrant’s telephone number,  Including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:  Common Stock, $0.0001 par value per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes ¨    No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨    No x

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x    No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

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

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

The aggregate market value of the voting common equity held by non-affiliates as of June 29, 2012, based on the closing sales price of the Common Stock as quoted on the OTC Markets was approximately $5,795,910. For purposes of this computation, all officers, directors, and 5 percent beneficial owners of the registrant are deemed to be affiliates.  Such determination should not be deemed an admission that such directors, officers, or 5 percent beneficial owners are, in fact, affiliates of the registrant.

As of March 27, 2013, there were 84,330,477 shares of registrant’s common stock outstanding.

Table of Contents

		Page
Explanatory Note		3
Part I
Item 1.	Business	5
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
Item 3.	Legal Proceedings	30
Item 4.	Mine Safety Disclosures	30
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6.	Selected Financial Data	32
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	40
Item 8.	Financial Statements and Supplementary Data	40
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	40
Item 9A.	Controls and Procedures	40
Item 9B.	Other Information	41
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	42
Item 11.	Executive Compensation	48
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	52
Item 13.	Certain Relationships and Related Transactions, and Director Independence	54
Item 14.	Principal Accounting Fees and Services	55
Part IV
Item 15.	Exhibits, Financial Statement Schedules	57
Signatures		60

 Explanatory Note

As previously reported, Mesa Energy Holdings, Inc., a Delaware corporation (“Mesa,” “we” or “us”) entered into an Asset Purchase Agreement and Plan of Reorganization dated as of November 14, 2012, as amended by Amendment No. 1 thereto dated as of February 19, 2013 (the “Acquisition Agreement”), among Armada Oil, Inc., a Nevada corporation (“Armada”), Mesa and Mesa Energy, Inc., a corporation organized under the laws of the State of Nevada (“MEI”), pursuant to which Mesa would sell to Armada and Armada would purchase from Mesa, 100% of the issued and outstanding shares of MEI, constituting substantially all of Mesa’s assets, (the “Acquisition”).  The Acquisition closed on March 28, 2013, (the “Closing”), and MEI is now a wholly owned subsidiary of Armada.

The information contained in this Report is historical and does not reflect the Closing of the Acquisition.

On March 28, 2013, in connection with the consummation of the Acquisition, and immediately prior to the Closing, Mesa and MEI entered into an Assignment and Assumption Agreement, as contemplated by the Acquisition Agreement, pursuant to which Mesa assigned to MEI and MEI assumed all of the assets and liabilities of Mesa as provided therein.  A copy of form of the Assignment and Assumption Agreement is filed as an exhibit to this Report.

As consideration for the Acquisition, Mesa received and will distribute to Mesa stockholders 0.40 shares of Armada common stock (the “Acquisition Consideration”) for each share of Mesa common stock that a Mesa stockholder owned as of the close of business on March 27, 2013, the business day immediately preceding the closing date of the Acquisition (other than shares owned by Mesa as treasury stock).  No fractional Armada common shares will be issued.  Mesa stockholders to whom fractional shares would have otherwise been issued will be entitled to receive a number of shares of Armada common stock rounded up or down to the nearest whole share (with a fractional interest equal to 0.5 rounded upward to the nearest whole number); provided that each Mesa stockholder shall receive at least one share of Armada common stock.

As of the Closing, and as a result of the Acquisition, each outstanding share of the common stock of the Company was converted into the right to receive the Acquisition Consideration.

Additionally, as part of the Acquisition, Armada assumed all outstanding stock options and restricted stock awards,whether or not vested, and warrants previously granted or issued by Mesa, with each such award or warrant entitling the holder to receive a number of Armada shares of Armada common stock equal to 0.40 multiplied by the number of Mesa common shares subject to the original award or warrant (with any fraction rounded to the nearest whole number, and with 0.5 shares rounded upward, unless such Mesa award or warrant provides for different treatment of fractions of a share in such circumstances), with an exercise price per share (if applicable) equal to the exercise price of the original Mesa award or warrant divided by 0.40 (rounded to the nearest whole cent, and with $0.005 rounded upward, unless the Mesa award or warrant provides for different treatment of fractions of a cent in such circumstances), and with the same vesting schedule (if any) and other terms as the original award or warrant.

In connection with the Closing, The F&M Bank & Trust Company (“Lender”), under the Loan Agreement (the “Loan Agreement”) dated July 22, 2011, among the Lender, MEI, as Borrower, and Mesa, Tchefuncte Natural Resources, LLC (“TNR”), a Louisiana limited liability company and subsidiary of MEI, and Mesa Gulf Coast, LLC (“MGC”), a Texas limited liability company and subsidiary of MEI, as Guarantors, consented to the consummation of the transactions contemplated by the Acquisition Agreement and released Mesa form its obligations as a Guarantor of MEI’s obligations under the Loan Agreement.  Armada simultaneously provided a substitute guarantee of MEI’s obligations under the Loan Agreement.

Shares of Armada common stock are currently quoted on the OTCQB under the symbol “AOIL.”

In accordance with the Acquisition Agreement, having received the Acquisition Consideration, Mesa will be wound up and dissolved and will cease its corporate existence (the “Dissolution”).  Mesa will file a Certificate of Dissolution with the Secretary of State of the State of Delaware on or about April 1, 2013.  The Acquisition Consideration will be distributed to our stockholders as part of the Mesa winding up process.  Upon completion of the Dissolution, all shares of Mesa Common Stock shall be void and no holder of shares of Mesa Common Stock shall have any further rights or obligations with regard to Mesa.

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The information contained in Mesa’s Definitive Proxy Statement dated March 15, 2013 (the “Proxy Statement”), filed with the Securities and Exchange Commission (the “SEC”) on that date, under the captions “The Acquisition — Interests of Mesa’s Executive Officers and Directors in the Acquisition” beginning on page 78 and “The Acquisition Agreement,” “The Assignment and Assumption,” “The Voting Agreements,” “Description of Armada’s Securities” and “Comparison of Stockholder Rights” beginning on page 145 is incorporated herein by reference.

The foregoing description of the Acquisition, and of the rights of holders of common stock of Mesa and of Mesa stock options, restricted stock awards and warrants under the Acquisition Agreement (including the descriptions incorporated herein by reference), does not purport to be complete and is qualified in its entirety by reference to the Acquisition Agreement and the Assignment and Assumption Agreement, copies of which are filed as Appendix A and Appendix B, respectively, to the Proxy Statement filed with the SEC, and are incorporated into this Item by reference.

Mesa submitted approval of the Acquisition Agreement, the Assignment and Assumption Agreement and the Dissolution to a vote of the holders of its common stock, by written consent in lieu of a meeting, and solicited proxies with respect thereto by means of the Proxy Statement.  Consent of holders of at least a majority of the shares of Mesa common stock outstanding was required to approve the proposal.  As of March 26, 2013, the numbers of votes cast for and against (withheld), as well as the number of abstentions and broker non-votes, were as follows:

For:	44,410,978
Against:	33,100
Abstain:	—

At that time, 84,330,477 shares of Mesa common stock were outstanding.

Mesa will report the final vote tally, if different, in a subsequent filing.

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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.mesaenergy.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 accounts of Mesa Energy Holdings, Inc. and its wholly-owned subsidiaries, Mesa Energy, Inc. (“MEI”), Mesa Energy Operating, LLC (“Mesa Operating”), Mesa Gulf Coast, LLC (“MGC”) , Tchefuncte Natural Resources, LLC (“TNR”), Mesa Midcontinent LLC (“MMC”), and MMC Resources, LLC (“MMCR”) collectively referred to as “we”, “us” 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 16.

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.

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

· Lake Hermitage Field, a producing oil and natural gas field in Plaquemines Parish, Louisiana;

· Valentine Field, a producing oil and natural gas field in Lafourche Parish, Louisiana;

· Larose Field, a producing oil and natural gas field in Lafourche Parish, Louisiana;

· Bay Batiste Field, a producing natural gas field in Plaquemines Parish, Louisiana;

· Manila Village Field, a currently shut-in field in Plaquemines Parish, Louisiana;

· Turkey Creek Field, an area of interest in which we hold undeveloped leasehold interests and a farm-out in Garfield and Major Counties, Oklahoma; and

· Java Field, a natural gas development project in Wyoming County in western New York.

History

MEI is a company whose predecessor entity, Mesa Energy, LLC, was formed in April 2003 to engage in the oil and gas industry. MEI’s oil and gas operations are conducted through itself and its wholly owned subsidiaries. Mesa Gulf Coast, LLC operates all properties in Louisiana. Mesa Energy Operating, LLC is a qualified operator in the states of Texas, Oklahoma, and Wyoming but does not currently operate any properties. MEI is a qualified operator in the State of New York and operates the Java Field. Mesa Midcontinent, LLC operates our properties in Oklahoma.  Our operating entities have historically employed, and will continue in the future to employ, on an as-needed basis, the services of drilling and recompletion contractors, other drilling related vendors, field service companies and professional petroleum engineers, geologists and landmen (to the extent that they are not on staff) as required in connection with future drilling and production operations.

General Philosophy

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 expect this approach to result in steady reserve growth, strong earnings, and significant capital appreciation.

Our philosophy is 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. The current 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.

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, 2012. This table excludes acreage in which our interests are limited to royalty and overriding royalty interests.

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The Company holds oil and gas lease interests in Louisiana, New York, and Oklahoma.  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
Louisiana		6,920.20		6,833.80		348.90		261.68		7,269.10		7,095.48	Life of Production
New York		2,851.50		2,851.50		0.00		0.00		2,851.50		2,851.50	Life of Production
Oklahoma		1,677.05		1,653.09		2,067.49		1,531.75		3,744.54		3,184.84		4.39
Total		11,448.75		11,338.39		2,416.39		1,793.43		13,865.14		13,131.82

Louisiana Area

On July 22, 2011, the Company’s wholly owned subsidiary, Mesa Energy, Inc. (“MEI”), completed the acquisition of Tchefuncte Natural Resources, LLC (“TNR”), a Louisiana operator.  Immediately prior to MEI’s closing of the TNR acquisition, TNR completed the acquisition of properties in five fields in South Louisiana from Samson Contour Energy E & P, LLC (“Samson”).  TNR, now a wholly owned subsidiary of MEI, owns 100% working interests in the Lake Hermitage Field in Plaquemines Parish, Louisiana along with various working interests in producing properties in four additional fields in Plaquemines and Lafourche Parishes, Louisiana.

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

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

Lake Hermitage Field – Plaquemines Parish, Louisiana

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

The Company owns a 100% working interest and 75% net revenue interest in each of the eighteen wells in the Lake Hermitage Field.  A total of 3,589 mineral acres is held by production in the field. Ten wells are currently shut-in pending evaluation for workover and/or future recompletion in uphole zones, and an additional well is being evaluated for conversion to a salt water disposal well, which would reduce expenses and allow for increased daily handling of fluid.  There are three processing facilities and tank batteries in the field. The high gravity crude oil produced at Lake Hermitage is transported out of the field by barge.

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In January 2013, MGC completed a successful workover of the LLDSB #10 well in Lake Hermitage Field and the initial results have been promising, with daily production rates for the well as high as 200 BOPD.  Additional strategic workovers have been executed with initial results showing daily field production rates as high as 400 BOE/D.  The Company has implemented an aggressive workover and recompletion program in the field for 2013 and expects additional positive results. An extensive geological and engineering evaluation of the field is ongoing, and thirty-nine potential drilling locations have been evaluated, five of which are proved undeveloped (“PUD”) locations with multiple stacked pay zones.

Lake Hermitage Field

· Our Operated Wells: 7 Producing Oil and Gas Wells and 11 Shut-in Oil and Gas Wells, one of which we expect to convert to a salt water disposal well in 2013.

· Our Non-Operated Wells: None.

· Reservoir Thickness: Each productive sand is 35’ – 142’ thick.

· Producing Depth: 10,750’ – 14,600’.

· Drilling Method: Vertical and Directional.

· Production Characteristics: 10 - 20+ years of production from each horizon and liquid condensation associated with the natural gas reservoirs which have high Btu. Reserve calculations are done by decline-curve analysis.

· Key Considerations: Each productive sand is in its own fault block, therefore each fault needs to be a “sealing fault”. Multiple pay zones in each fault block.

Valentine Field – Lafourche Parish, Louisiana

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

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

Twenty-five of the forty wells operated by MGC are currently shut-in pending evaluation for future workover or recompletion to uphole zones.  There are three salt water disposal wells in the field.  An extensive geological and engineering evaluation review of the Valentine Field will be completed in 2013, and we expect a number of additional recompletions and/or drilling opportunities to be identified.

The processing facilities and tank batteries are strategically located throughout the field and have plenty of excess capacity.  A field operations center is centrally located in the field.   Access to pipelines and crude oil markets is excellent.

Valentine Field

· Our Operated Wells: 12 Producing Gas and Oil Wells; 3 Active Salt Water Disposal Wells; and 25 Shut-in Gas and Oil Wells.

· Our Non-Operated Wells: 1 Shut-in Gas Well.

· Reservoir Thickness: Each productive sand is 10’ – 195’ thick.

· Producing Depth: 9,700’ – 13,400’.

· Drilling Method: Vertical and Directional.

· Production Characteristics: 4 - 10+ years of production from each horizon and liquid condensation associated with the natural gas reservoirs which have high Btu.  Reserve calculations are done by decline-curve analysis.

· Key Considerations: Understanding the positioning of the well to the salt dome and the offsetting faults of each productive sand, and determining if the offsetting faults are “sealing faults”.  Multiple pay zones exist in each fault block.

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Larose Field – Lafourche Parish, Louisiana

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

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

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

Larose Field

· Our Operated Wells: 1 Producing Oil Well and 1 Active Salt Water Disposal Well.

· Our Non-Operated Wells: 3 Producing Oil and Gas Wells; 1 Active Salt Water Disposal; and 2 Shut-in Gas Wells.

· Reservoir Thickness: Each productive sand is 10’ – 55’ thick.

· Producing Depth: 11,000’ – 16,200’.

· Drilling Method: Vertical and Directional.

· Production Characteristics: 5+ years of production from each horizon and liquid condensation associated with the natural gas reservoirs which have high Btu. Reserve calculations are done by decline-curve analysis.

· Key Considerations: Each productive sand is in its own fault block, therefore each fault needs to be a “sealing fault” Multiple pay zones in each fault block.

Bay Batiste Field - Plaquemines Parish, Louisiana

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

The Company owns an average 59.43% working interest and 41.89% net revenue interest in seven wells in the Bay Batiste Field.One well is currently producing and the  other four wells are currently shut-in pending evaluation for future workover or recompletion in uphole zones.  Approximately 74 net mineral acres are held by production by the producing well.  The salt water disposal well and two production facilities have plenty of excess capacity to handle production from recompleted wells or from third party operators nearby.  Access to markets is excellent.

Bay Batiste Field

· Our Operated Wells: 1 Producing Gas Well; 1 Active Salt Water Disposal; and 5 Shut-in Gas Wells.

· Our Non-Operated Wells: None.

· Reservoir Thickness: Each productive sand is 30’ – 85’ thick.

· Drilling Depth: 14,000’ – 14,500’.

· Drilling Method: Vertical and Directional.

· Production Characteristics: 10 - 20+ years of production from each horizon and liquid condensation associated with the natural gas reservoirs which have high Btu. Reserve calculations are done by decline-curve analysis.

· Key Considerations: Each productive sand is in its own fault block, therefore each fault needs to be a “sealing fault”. Multiple pay zones in each fault block.

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SE Manila Village Field – Plaquemines Parish, Louisiana

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

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

Southeast Manila Village Field

· Our Operated Wells: None.

· Our Non-Operated Wells: 2 Inactive Oil Wells to be plugged and abandoned.

· Reservoir Thickness: Each productive sand is 10’ – 28’ thick.

· Producing Depth: 11,800’ – 12,200’.

· Drilling Method: Vertical and Directional.

· Production Characteristics: The thinly laminated well-sorted and very fine-grained sands are the result of turbidity flow deposition in a distal-delta environment. The 10+ years of production from each of the two horizons of the oil and natural gas reservoirs have had water injection for the secondary recovery program that stared in 1988.  The reserve calculations are done by decline-curve analysis.

· Key Considerations: The two productive sands are in the one fault block and have been water-flooded.

New York Area

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

Java Field – Wyoming County, New York

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

The acquisition included 19 producing natural gas wells, their associated leases, units and all equipment; two surface tracts of land totaling approximately 36 acres; and two pipeline systems; a 12.4 mile pipeline and gathering system that serves the existing field, as well as a separate 2.5 mile system located northeast of the field.  The company owns approximately 78% net revenue interest in leases covering 2,851.50 gross and net acres, more or less.

Production is nominal from the wells but serves to hold the acreage for future development.  In late 2009, we evaluated a number of the existing wells in order to determine the viability of the re-entry of existing vertical wellbores for plug-back and recompletion of the wells in the Marcellus Shale.  The Marcellus Shale is approximately 1,240’ 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.

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The State of New York has placed a moratorium on high volume frac stimulation in order to develop new permitting rules. The new permitting rules have not been completed and there can be no assurance when such permitting rules will be issued or what restrictions such permits might impose on producers. Accordingly, we are unable to continue with our development plans in New York for the time being. Unless the moratorium is removed and new permitting rules provide for the economic development of these properties, production on these properties will remain marginally economic. 

Java Field

· Our Operated Wells: 19 Producing Gas Wells.

· Our Non-Operated Wells: None.

· Reservoir Thickness: The Medina Sandstone averages 82’ thick and the Marcellus Shale averages 105’ thick.

· Producing Depth: 2,850’ – 3,500’.

· Drilling Method: Vertical.

· Production Characteristics: With 25+ years of production from each horizon, rates and pressure data support the reserve calculations which are done by decline-curve analysis.

· 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.

Oklahoma Area

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

Turkey Creek Project - Garfield and Major Counties, Oklahoma

During 2012, we began a leasing and acreage acquisition program in Major and Garfield Counties, Oklahoma, spending $602,377on approximately 3,200 net mineral acres. We are continuing to actively pursue agreements with operators to acquire additional acreage that is held by production. Total capital expense required to develop the field will be determined once all acreage is obtained. We refer to our acreage position in Major and Garfield Counties, OK, as the Turkey Creek Field.

We believe that Oklahoma is a great place to develop a drilling program. It is relatively close to Dallas, is a very oil friendly state and has good availability of services and a moderate climate. The Mississippian Limestone in Oklahoma is a proven zone that has been drilled vertically in that area for many years so there is a lot of data available with no need for seismic. The emerging horizontal play is sufficiently mature to have big company names and good results, yet it is early enough that acreage can still be acquired at moderate prices. This is an opportunity to establish a repeatable drilling program in an area with a high drilling success rate.

The Mississippian Limestone in the area of interest is at a vertical depth of approximately 7,000 feet and is 300 feet to 500 feet thick. The Woodford Shale, which would be a secondary objective in any well drilled, is immediately below the Mississippian and is about 80 feet thick. Early reports indicate that the Woodford is oil bearing and quite productive in the area of interest. Potential reserves in the Mississippian on a per well basis have been reported to be 200,000 to 400,000 barrels per well. The Woodford would increase the potential reserves recoverable. A multi-stage frac is required using acid, fresh water and a simple sand proppant. The Mississippian produces some water, so disposal wells will be required. The oil is light, sweet crude with a gravity of 40 to 45 dg.

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

The majority of our leases in Oklahoma is not held by production but is undeveloped acreage. The weighted average remaining lease term is based upon the total net undeveloped acreage.  The remaining lease term is approximately 4.39 years.

 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. We currently have a portion of our production hedged for both natural gas and oil as required under our senior debt facility. More information regarding these hedges can be found in the footnotes to the financial statements contained herein.

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.

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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.

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.

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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.

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. 

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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. In Louisiana, no underground injection may take place except as authorized by permit or rule. 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.

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 established by the State of Louisiana.

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, 2012, we had 19 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 is 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.

Block:   Subdivision of an area for the purpose of licensing to a company or companies for exploration/production rights.

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.

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 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.

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.

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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.

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.

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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.

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 anticipate that we will require approximately $17,500,000 to adequately fund our current drilling and recompletion budget for 2013. We expect those funds to come from cash flow generated from operations. To the extent cash flow from operations is insufficient; we expect to draw on cash reserves and additional borrowings on our senior credit facility. To the extent that we pursue additional acquisitions or choose to drill additional wells, which is a distinct possibility, additional capital would likely be required. 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 south Louisiana, Oklahoma, and in western New York. 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.  If we do not diversify our operations, our financial condition and results of operations could be negatively impacted.

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 developmental drilling and/or recompletion of existing wells in south Louisiana 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 may be curtailed, delayed, or canceled as a result of a variety of factors, including:

· 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.

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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.

Drilling initiatives in the Java Field may not prove successful.

The primary target for production of natural gas in our Java Field property is the Marcellus Shale. The amount of natural gas that can be commercially produced from any shale gas reservoir depends upon the rock and shale formation quality, the original free gas content of the shales, the thickness of the shales, the reservoir pressure, the rate at which gas is released from the shales, the existence of any natural fractures through which the gas can more easily flow to the well bore and the success of the hydraulic fracturing of the formation.

There is no guarantee that the potential drilling locations we now have or may acquire in the future will ever produce commercial volumes of natural gas, which could have a material adverse effect upon our results of operations.

We have no experience in drilling wells to the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in other areas of our operations.

We have no experience in drilling new development wells in the Marcellus Shale. As of the date hereof, we own 19 existing wells on our Java Field properties. Although we have recompleted two of those wells in the Marcellus Shale and the initial results have been promising, we have limited information with respect to the ultimate recoverable reserves and the production decline rate in the Marcellus Shale than we have in our other areas of operation. To the extent that we decide to re-enter and recomplete other existing wells, the wells will be susceptible to mechanical problems such as casing collapse and lost equipment in the wellbore. In addition, the fracturing of the Marcellus Shale will be more extensive and complicated than fracturing the geological formations in our other areas and will require greater volumes of water than conventional gas wells. The management of water and the treatment of produced water from Marcellus Shale wells may be more costly than the management of produced water from other geologic formations. These Marcellus Shale wells may also require horizontal drilling which would further increase our development costs.

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.

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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 the Marcellus Shale 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, David L. Freeman 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, Rachel L. Dillard, our Chief Financial Officer, and David L. Freeman, our Executive Vice President of Oil & Gas Operations.  Loss of the services of any of these officers could have a material adverse effect on growth, revenues and prospective business. We currently do not have key-man insurance covering any 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, could have sufficient voting power to control the vote on substantially all corporate matters.

As of March 27, 2013, our directors and executive officers beneficially owned approximately 34% 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.

Risks Relating to Our Industry :

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. 

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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, 2012 was 3,058,500 BOE compared to 3,500,000 BOE as of December 31, 2011. This reduction in proved developed reserves is primarily the result of 2012 production.

We are dependent upon transportation and storage services provided by third parties.

We are dependent upon transportation services provided by barge operators and various interstate and intrastate pipeline companies for the delivery and sale of oil and gas production. The performance of transportation services by interstate pipelines and the rates charged for such services are subject to the jurisdiction of the Federal Energy Regulatory Commission or state regulatory agencies. An inability to obtain transportation services at competitive rates could hinder processing and marketing operations and/or affect our sales margins.

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.

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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 assure you 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.

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.

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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.  In addition, we have Site Specific Trust Accounts (“SSTA”) in place with the State of Louisiana to address these costs in our Louisiana fields. The SSTA’s are funded with a combination of cash and letters of credit drawn against our senior credit facility. The cash portion of the accounts was determined by management to be a reasonable estimate of the abandonment costs likely to be incurred in the two years subsequent to closing of the initial acquisition. 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.

Our ability to sell natural gas and/or receive market prices for natural gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.

If our drilling programs that involve natural gas production are successful, the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If that occurs, it will be necessary for new pipelines and gathering systems to be built. Capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas from our properties to interstate pipelines. In such event, we might have to shut in one or more of our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations. 

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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 are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control.  World prices for oil and natural gas have fluctuated widely in recent years.  The average price per barrel was $61.95 in 2009, $79.48 in 2010, $94.88 in 2011, and $94.05 in 2012; and the average wellhead price per thousand cubic feet of natural gas was $3.67 in 2009, $4.48 in 2010, $3.95 in 2011, and $2.77 in 2012 (source: U.S. Energy Information Administration). We expect that prices will continue to fluctuate in the future.  Price fluctuations will have 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.  Although we have hedge positions in place for a significant portion of our oil and gas production, decreases in the prices of oil and natural gas could still have a material adverse effect on our consolidated financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.

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.

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 materially adversely affect our financial performance.

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 Because of these factors, we may be unable to market all of the oil or gas that we might produce. In addition, we may be unable to obtain favorable prices of the oil and gas that we might produce.

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.

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.

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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.

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.

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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 310,000,000 shares of capital stock consisting of 300,000,000 shares of common stock and 10,000,000 shares of preferred stock with preferences and rights to be determined by our board of directors. As of March 27, 2013, there were 84,330,477 shares of our common stock and no shares of our preferred stock outstanding. There are 1,013,000 shares of our common stock reserved for issuance under our 2009 Equity Incentive Plan. These numbers 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.

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.

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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, 2013 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 June 30, 2015. The existing office space covers 4,462 square feet with a monthly rent of $6,305.

In addition, we have 3,916 square feet of office space in a single story building at 71683 Riverside Drive, Covington, LA 70433 with a monthly rent of $3,851. That lease expires March 31, 2014, and our operational team is at that location. We occupy approximately half of the building and have a first right to lease the other half on similar terms. We believe that there is ample space to accommodate additional growth in the foreseeable future by exercising our first right in the existing building.

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 Bulletin Board under the symbol “MSEH.” Prior to April 5, 2012, our common stock traded on the OTC Markets under the symbol “MSEH.” Prior to August 4, 2009, our common stock was quoted on the Over-the-Counter Bulletin Board under the symbol “MSQT.” The following table sets forth the high and low closing prices per share of common stock for the quarters indicated.

	Fiscal Year 2011
	High		Low
First Quarter	$	0.19	$	0.07
Second Quarter	$	0.20	$	0.06
Third Quarter	$	0.19	$	0.10
Fourth Quarter	$	0.18	$	0.12

	Fiscal Year 2012
	High		Low
First Quarter	$	0.37	$	0.14
Second Quarter	$	0.27	$	0.12
Third Quarter	$	0.23	$	0.12
Fourth Quarter	$	0.25	$	0.12

On March 27, 2013, the closing sale price of our common stock was $0.14 per share and there were approximately 152 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

We adopted our 2009 Equity Incentive Plan on August 20, 2009 and the plan was approved by the holders of a majority of our outstanding shares of common stock on August 21, 2009. The 2009 Equity 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. If an incentive award granted under the 2009 Equity Incentive Plan expires, terminates, is unexercised or is forfeited, or if any shares are surrendered to us in connection with an incentive award, the shares subject to such award and the surrendered shares will become available for further awards under the 2009 Equity Incentive Plan. As of March 27, 2013, we have outstanding option awards under the 2009 Equity Incentive Plan of 2,847,000, exercisable for an aggregate of 2,138,000, shares of our common stock, and our Board has granted awards of restricted stock with respect to an aggregate of 988,000 shares. We have not maintained any other equity compensation plans since our inception.

The following table provides information as of December 31, 2012, 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)		2,847,000	$	0.19		1,013,000
Equity compensation plans not approved by security holders		—		—		—
Total		2,847,000	$	0.19		1,013,000

(1)	2009 Equity Incentive Plan
(2)	Net of 1,140,000 shares awarded as restricted stock grants.

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Stock Transfer Agent

Our Stock Transfer Agent is Continental Stock Transfer & Trust Company, located at 17 Battery Place, New York, New York 10004.

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”).

 On February 15, 2012, Brio Capital, LP elected to convert $50,000 of its Convertible Promissory Note resulting in the issuance of 400,000 shares of our common stock.

 On February 17, 2012, Chestnut Ridge Partners, LP elected to convert $62,500 of its Convertible Promissory Note resulting in the issuance of 500,000 shares of our common stock.

On April 9, 2012, Whalehaven Capital Fund, Ltd. elected to convert $200,000 of its Convertible Promissory Note resulting in the issuance of 1,600,000 shares of our common stock.

On April 16, 2012, Chestnut Ridge Partners, LP elected to convert $62,500 of its Convertible Promissory Note resulting in the issuance of 500,000 shares of our common stock.

On May 30, 2012, Whalehaven Capital Fund, Ltd. elected to convert $41,019 of its Convertible Promissory Note resulting in the issuance of 328,153 shares of our common stock.

On September 21, 2012, Brio Capital, L.P. elected to convert $50,000 of its Convertible Promissory Note resulting in the issuance of 400,000 shares of our common stock.

The above offerings and sales were deemed to be exempt from registration under the Securities Act under either rule 506 of Regulation D of the Securities Act and Section 4(2) of the Securities Act.  No advertising or general solicitation was employed in offering the securities. The offerings and sales were made to a limited number of persons, all of whom were accredited investors or business associates of ours, and transfer was restricted by us in accordance with the requirements of the Securities Act of 1933. In addition to representations by the above-referenced persons, we have made independent determinations that all of the above-referenced persons were accredited or sophisticated investors, and that they were capable of analyzing the merits and risks of their investment, and that they understood the speculative nature of their investment. Except as expressly set forth above, the individuals and entities to which we issued securities as indicated in this section are unaffiliated with us.

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

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.

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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.

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, 2012 and 2011:

	2012			2011
Net income	$	(140,711	)	$	4,151,958
Add:
Interest (income) expense, net		495,036			405,755
Amortization of deferred financing costs		44,213			140,871
Income tax (benefit)/expense		489,265			(2,783,792	)
Depreciation, depletion, accretion and impairment		1,832,537			1,429,100
Loss on settlement of asset retirement obligation		116,394			--
Loss on change in commodity derivative instruments		912,963			(938,950	)
(Gain)/loss on change in convertible debt derivative		534,989			113,083
Gain on settlement of accounts payable with common stock		--			(286,041	)
Loss on conversion of debt		--			62,306
Gain on sales of assets		--			(22,396	)
Share-based compensation		349,407			324,325
Adjusted EBITDA	$	4,634,093		$	2,596,219

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Recent Developments

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

· F&M Credit Facility - On July 22, 2011, MEI entered into a $25 million senior secured revolving line of credit (“Credit Facility") with F&M Bank and Trust Company (“F&M Bank”) that had an initial maturity date of July 22, 2013. The interest rate is the F&M Bank Base Rate plus 1% subject to a floor of 5.75%. At present, interest is accruing at 5.75% and is paid monthly. A 2.00% annual fee is applicable to letters of credit drawn under the Credit Facility. The Credit Facility provided financing for the acquisition of TNR, working capital for field enhancements, and general corporate purposes. The Credit Facility was 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.

· In April 2012, F&M Bank & Trust Company (“F&M”) performed the first scheduled redetermination of the Company’s credit facility and increased our borrowing base from $10,500,000 to $13,500,000. The redetermination also lifted the Company’s obligation to make the $150,000 monthly payments required prior to the redetermination.

· In September 2012, F&M Bank & Trust Company (“F&M”) performed the second scheduled redetermination of the Credit Facility, increased our borrowing base from $13,500,000 to $14,500,000, and extended the maturity date to July 22, 2014.

· In December 2012, MEI drew $4,000,000 against the Credit Facility to fund the drilling of the Thomas #6H well in Oklahoma.

· In the 3rd quarter of 2012, we made the decision to insource our oil and gas accounting operations and implemented an enterprise resource planning (ERP) system.

· On November 14, 2012, we executed an Asset Purchase Agreement and Plan of Reorganization (the “Acquisition Agreement”) with Armada Oil, Inc., a Nevada corporation (“Armada”).

The Armada Closing

On March 28, 2013, we closed (the “Closing”) the sale to Armada of 100% of the issued and outstanding shares of MEI, constituting substantially all of our assets (the “Acquisition”).  MEI is now a wholly owned subsidiary of Armada.  In connection with the consummation of the Acquisition, and immediately prior to the Closing, we and MEI entered into an Assignment and Assumption Agreement (the “Assignment and Assumption Agreement”), as contemplated by the Acquisition Agreement, pursuant to which we assigned to MEI and MEI assumed all of our assets and liabilities.

As consideration for the Acquisition, we received and will distribute to our stockholders 0.40 shares of Armada common stock (the “Acquisition Consideration”) for each share of our common stock that a stockholder of ours owned as of the close of business on March 27, 2013, the business day immediately preceding the closing date of the Acquisition.  As of the Closing, and as a result of the Acquisition, each outstanding share of our common stock was converted into the right to receive the Acquisition Consideration.  In accordance with the Acquisition Agreement, after the distribution of the Acquisition Consideration, we will be wound up and dissolved and we will cease our corporate existence.

The foregoing description of the Acquisition is not complete and is qualified in its entirety by reference to the Acquisition Agreement and the Assignment and Assumption Agreement, copies of which are filed as Appendix A and Appendix B, respectively, to our Definitive Proxy Statement dated March 15, 2013, filed with the SEC on that date.

Results of Operations for the Fiscal Year Ended December 31, 2012 Compared to Fiscal Year Ended December 31, 2011

Revenue

We generated revenues of $14,865,169 for the year ended December 31, 2012 and $6,960,597 for the year ended December 31, 2011. The increase in revenue reflects a complete fiscal year of operations after our acquisition of TNR, whereas 2011 revenues reflect a little over five months of operations after our acquisition of TNR. We received average prices of $2.93 and $3.56 per Mcf for our natural gas production during 2012 and 2011, respectively. The average price of oil we sold during the years ended December 31, 2012 and 2011 was $108.78 and $111.75 per barrel, respectively. Oil sales volumes increased 104% during 2012 to 653 barrels per day from 320 barrels per day during 2011. Natural gas sales volumes increased 131% during 2012 to 3,918 Mcf per day from 1,699 Mcf per day in 2011  Included in 2012 revenues is $323,201 of other revenue from operations comprising marketing, compressor allocation, gas transportation, COPAS overhead, and production handling fees, as well as a small amount of sales of natural gas liquids.

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Operating Expenses

· Lease operating expense. 2012 production expense increased 148% to $7,062,611 from $2,849,484 in 2011. This increase mostly reflects a complete fiscal year of operations after our acquisition of TNR, whereas 2011 production expense reflects a little over five months of operations after our acquisition of TNR. The increase was also attributable to heavy repair and maintenance expense associated with our acquisition of TNR, as equipment on those wells required substantial initial attention as well as increased expense associated with the cleanup and repairs resulting from Hurricane Isaac. 2012 production costs decreased 20% to $22.85 per BOE as compared from $28.52 per BOE in 2011. The decrease in production costs is attributable to the increased production comprising the denominator used in the calculation by virtue of 2012 having a full year of production.

· Environmental remediation expense. Environmental remediation expense for the year ended December 31, 2012 was $244,237 as compared to $0 for year ended December 31, 2011 and was incurred in connection with an oil spill which occurred while attempting to convert the LLDSB #7 well to a salt water disposal well. As a result of the spill and additional complications, the conversion of the well was unsuccessful and the well was plugged and abandoned.

· Exploration Expense. Exploration expense decreased to $115,276 in 2012 from $129,478 in 2011.

· General and Administrative Expense. The 96% increase in general and administrative expense of $1,780,728 to $3,636,010 in 2012 from $1,855,282 in 2011 primarily reflects a full year of increased payroll burden following the acquisition of TNR, expense associated with our business combination with Armada Oil, Inc., and increased use of consultants to support the growth of our business operations.

· Depreciation, depletion, amortization, and accretion expense. The $403.437 increase in depreciation, depletion, amortization, and accretion expense to $1,832,537 in 2012 from $1,429,100 in 2011 reflects a full year of field operations in 2012 over 163 days of field operations in 2011following our acquisition of TNR.

· Loss on settlement of asset retirement obligation. We recognized a loss of $116,394 for the plugging and abandonment of two wells during the year ended December 31, 2012. We incurred no comparable loss during the year ended December 31, 2011. We did have a gain of $22,396 on the sale of our Coal Creek Property in Oklahoma in 2011.

Operating income. As a result of the above described revenues and expenses and because 2012 was our first full year of operations following the TNR acquisition, we produced operating income of $1,858,104 in 2012 as compared to operating income of $719,649 in 2011.

Interest Expense. Interest expense decreased 8% to $503,638 in 2012, from $549,512 in 2011. This was primarily a result of the conversion of all previously outstanding notes payable, and retirement of our debt associated with the Lake Hermitage camp and crew boat.

Realized Gain on Change in Commodity Contract Derivative Instruments. During 2012, we realized a gain on the changes in the value of our commodity contract derivative instruments represented by cash settlements of $440,699. The commodity contract derivative instruments are associated with our hedging program commenced in the third quarter of 2011 as required by covenants underlying our credit facility with F&M Bank. During 2011, we realized such a gain in the amount of $137,358.

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Unrealized Gain on Change in Derivative Instruments – Commodity Contracts. Unrealized derivative losses based on change in fair value of derivatives – commodity contracts for the twelve months ended December 31, 2012 were $912,963 compared an unrealized gain of $938,950 for the twelve months ended December 31, 2011. Unrealized losses in 2012 were primarily the result of changes in realized derivative gains of $440,699, West Texas Intermediate crude oil collars executed in July 2012 and change of mark-to-market value decreases of $157,486, new natural gas collars executed in June 2012 and change of mark-to-market value decreases of $24,186, and mark to market value decreases of $262,698 for expiring derivatives.

Realized Gain (Loss) on Derivative Instruments - Convertible Stock. The unrealized gain on the change in derivative values is derived from the conversion feature of our convertible promissory notes issued in 2009 and 2010. The conversion feature was accounted for as an embedded financial derivative and, accordingly, valued each reporting period based on a valuation model that considered market rate inputs and management’s assumptions. The change in value is recorded in the statement of operations. In 2012 we experienced a loss of $534,989. In 2011 we experienced a loss of $113,083.

Gain on Settlement of Accounts Payable. During 2012, we did not settle any accounts payable.  During 2011, we recognized a gain of $286,041 on settlement of accounts payable to two vendors through the issuance of common shares with fair value less than the amounts due to the vendors in lieu of cash payment.

Income Tax Benefit/Expense. Income tax expense for 2012 was $489,265.  Income tax benefit for 2011 was $2,783,792 resulting from the elimination of our tax valuation allowance resulting from net operating losses from prior years and recognition in 2011 of a deferred income tax asset. This occurred because we had net income for 2011 and expect to continue to have net income to utilize our net operating losses.

Net Income/Loss. Our net loss for 2012 was $140,711 ($0.00 per basic and diluted share) and net income for 2011 was $4,151,958 ($0.07 per basic and $0.06 per diluted share) due to increased 2012 depreciation, depletion, amortization, accretion and impairment; general and administrative; lease operating; and environmental remediation expenses, as well as significant losses on convertible debt and commodity derivatives and the large swing from the 2011 income tax benefit to the 2012 income tax expense.

Liquidity and Capital Resources

Overview

As of December 31, 2012, we had working capital of $5,649,632. As of December 31, 2011, we had working capital of $3,104,453. The increase in the working capital was attributable to:

· A full year of 2012 revenues from the properties acquired from TNR versus only a little over five months of revenue from the TNR properties for the year ended December 31, 2011.

· Increased cash resulting from our $4,000,000 draw against our Credit Facility in December 2012.

· The conversion of $466,655 of convertible debt to common stock. 

Our current assets increased by $1,606,840 during the year ended December 31, 2012.

As of December 31, 2012, the outstanding balance of principal and accrued interest on debt was $9,351,052, a net increase of $3,165,070 from the outstanding balance of $6,185,982 as of December 31, 2011. This net increase was primarily due to our draw of $4,000,000 against our Credit Facility in December 2012 offset partially by our retiring our debt associated with the Lake Hermitage camp and crew boat.

Our January 1, 2013 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 2013 is $13,885,000, with 2014 and 2015 being $16,510,200 and $0, respectively. Based on the parameters and assumptions contained in the reserve report, cash flow from operations is expected to be sufficient to provide for this capital requirement.

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However, 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. If the reserve report assumptions are accurate, we expect no additional capital to be needed. In the event that unforeseen circumstances reduce our cash flow and create a shortfall in the capital expenditure budget, we have a number of other potential sources of funds to support the development effort including:

· Existing cash reserves of approximately $5.9 million;

· Additional debt financing; and

· Additional equity offerings.

If, however, cash flow plus the additional sources outlined above are not sufficient to support 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, 2012, we had cash in banks of $5,884,649, compared to $3,182,392 at December 31, 2011. The $2,702,057 increase in cash was due primarily to our drawing of $4,000,000 from our Credit Facility and cash revenues from operations, net of capital expenditures and operating expenses.

Liabilities

Accounts payable and accrued expenses decreased by $440,319 to $2,134,313 at December 31, 2012, from $2,574,632 at December 31, 2011. The decrease was primarily attributable to our clearing certain accounts payable balances at December 31 to facilitate an ERP system implementation.

Cash Flows

For the year ended December 31, 2012, the net cash provided by operating activities of $3,564,616, as compared to cash provided by operating activities of $3,364,451 in 2011, results primarily from operating cash flow from field operations of our Louisiana properties.

For the year ended December 31, 2012, net cash used for investing activities was $4,430,436 as compared to cash used for investing activities of $5,613,630 in 2011.  2012 cash used comprised additional capital projects associated with our Louisiana properties, our Oklahoma leasing program, and drilling activities associated with the Thomas #5H and Thomas #6H wells in Oklahoma whereas the principal 2011 investing activity was related to the purchase and development of oil and gas properties associated with the TNR acquisition.

For the year ended December 31, 2012, net cash provided by financing activities was $3,568,077 comprising primarily a $4,000,000 draw against our Credit Facility to finance our Oklahoma drilling activity, net of retirements of notes associated with our Lake Hermitage camp and crew boat, compared to $5,425,475 in 2011 which comprised, primarily, borrowings on our credit facility to acquire TNR. 

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 – ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES 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.

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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.

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.

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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.

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 good 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.

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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 the 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, 2012 and 2011 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.

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, 2012. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

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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, 2012, our disclosure controls and procedures 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: 

1. As of December 31, 2012, we did not adequately segregate, or mitigate the risks associated with, incompatible functions among personnel to reduce the risk that a potential material misstatement of the financial statements would occur without being prevented or detected. Accordingly, management concluded that this control deficiency constituted a material weakness.

We are committed to improving our accounting and financial reporting functions. As part of this commitment, we have engaged additional employees and consultants to assist in the preparation and filing of financial reports.

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

(b) Changes in internal control over financial reporting.

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

In July 2012, we hired an operations controller to oversee the oil and gas transactional accounting process.

In August 2012, we made the decision to insource our oil and gas transactional accounting process which had previously been outsourced to an accounting firm in Louisiana.  We purchased an enterprise resource planning (ERP) system and implemented it in the fourth quarter.  We “went live” with the new system and insourced processes in January 2013.

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.

(c) Management’s report on 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, 2012 for the reason indicated above. The effectiveness of our internal control over financial reporting as of December 31, 2012 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, 2013, are set forth below:

Name	Age	Title	Date First Appointed
Randy M. Griffin	59	Chairman of the Board and Chief Executive Officer	August 31, 2009
Ray L. Unruh	65	President, Secretary, and Director	August 31, 2009
Rachel L. Dillard	61	Chief Financial Officer	September 19, 2011
David L. Freeman	55	Executive Vice President – Oil and Gas Operations	August 31, 2009
James J. Cerna, Jr.	44	Director	January 5, 2010
Kenneth T. Hern	75	Director	January 27, 2010
Fred B. Zaziski	59	Director	January 5, 2010

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 has served as our Chairman of the Board of Directors and Chief Executive Officer since August 31, 2009. He had served in the same capacities for Mesa Energy, Inc. and its predecessor entity, Mesa Energy, LLC, since its inception in April 2003. Mr. Griffin’s responsibilities include oversight of the business and administrative activities of our company as well as direction of the ongoing effort to identify, acquire, and develop high-quality drilling and production prospects. He performed the same functions for MEI’s predecessor entity, Mesa Energy, LLC, from its inception in April 2003. From March 2001 until March 2003, Mr. Griffin was associated with a Dallas-based group of companies engaged in oil and gas exploration and development, pipeline development and construction, land management and lease acquisition. During that period, he served as President of Southwest Land Management, L.P., and Americo Gas Pipeline, LLC, where he was responsible for prospect and lease generation, land management and pipeline development. He also served as chief operating officer of an affiliate of those entities, Santa Fe Petroleum, LLC. Mr. Griffin graduated from East Texas State University in May 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.

Ray L. Unruh has served as our President, Secretary and a director since August 31, 2009. He had served in the same capacities for Mesa Energy, Inc. and its predecessor entity, Mesa Energy, LLC, since its inception in April 2003. Mr. Unruh’s responsibilities include oversight and management of company operations including drilling and land management. He performed the same functions for MEI’s predecessor entity, Mesa Energy, LLC, from its inception in April 2003. From March 1999 until March 2003, Mr. Unruh served as Vice-President of Santa Fe Petroleum, L.L.C. and President of its operating affiliate, TexTron Southwest, LLC. Mr. Unruh left Santa Fe Petroleum, LLC and TexTron Southwest, LLC, in March 2003 with Mr. Griffin to form and operate Mesa Energy, LLC. Previously, Mr. Unruh performed management and financial consulting services for Texas Northern Oil Company in the early 1990’s and Phoenix Resources, LLC from 1995 to 1998. He owned and operated Red River Energy and Supply Company, an oil field equipment company in the early 1980’s. 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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Rachel L. Dillard, CPA serves as our Chief Financial Officer. She began her career in oil and gas in 1996 with CDX Gas. In an association that concluded at the end of 2006, she served CDX both as a consultant to the Chief Executive Officer and Chief Financial Officer and as an employee in matters of financial analysis, natural gas marketing and balancing, investor relations and payout analysis. 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, a Canadian 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 and handled inquiries from auditors.

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 and created a set of tax books for Crusader from Westside’s historical general ledger. 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 loan portfolios exceeding $1 billion.

Ms. Dillard joined Mesa Energy Holdings, Inc. as Chief Financial Officer in September 2011.

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 Council of Petroleum Accountants Societies (COPAS), Texas Society of Certified Public Accountants, and the American Institute of Certified Public Accountants.

David L. Freeman has served as our Executive Vice President – Oil and Gas Operations since August 31, 2009. He has served in the same position with MEI since January 1, 2008. Mr. Freeman has over thirty years experience in oil and gas operations, business development, and property transactions. From 2003 until July 2005, Mr. Freeman worked as an acquisition consultant to Celebrex Energy, LLC. From August 2005 until July 2006, Mr. Freeman generally spent his time involved in cleanup activities related to Hurricane Katrina. He subsequently worked as Manager and a partner in Poydras Energy Partners, LLC until January 2008. Early in his career, Mr. Freeman received extensive training in Electronics Technology and Business Management at Delgado Junior College, Port Sulphur Vo-Tech School, and Our Lady of Holy Cross College, as well as 500 hours of professional training in petroleum production operations at the Petroleum Institute of Technology.

James J. Cerna, Jr. was appointed to our Board of Directors on January 5, 2010. Mr. Cerna is the President and Chief Executive Officer of NDB Energy (OTC: NDBE). 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. Currently, in addition to serving on our Board, he acts as an advisor to the board of directors of several traditional and green energy companies. Mr. Cerna received a BS 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.

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 Kenneth T. Hern was appointed to our Board of Directors on January 27, 2010. 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 B.A. in Chemistry from Austin College in 1960 and an M.S. 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 our Board of Directors on January 5, 2010. 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 BSc, 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.  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.

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 disclosed above, none of our existing directors or executive officers have 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.

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 Advisory Board

As of January 4, 2010, we established an Advisory Board to advise and make non-binding recommendations to our Board of Directors with respect to matters within the areas of expertise of the Advisory Board’s members, including, but not limited to, the ongoing monitoring of federal and New York State governmental issues that affect or have the potential to affect our oil and gas development and production operations.

Our Advisory Board currently includes Robert C. Avaltroni, Jeffrey A. Chadwick, Arthur J. Pyron and Nicholas A. Spano.

Our Board determined to compensate the Advisory Board members as follows:

· Certain members of the Advisory Board were each granted stock options under our 2009 Equity Incentive Plan to purchase 24,000 shares of our common stock upon appointment to the Advisory Board, which options have an exercise price equal to the fair market value of our common stock on the date of grant, will fully vest in four equal installments with one quarter vesting immediately and one quarter vesting after each subsequent six-month period. All of these options are now fully vested;

· Other members of the Advisory Board each received restricted stock grants under our 2009 Equity Incentive Plan with respect to 24,000 shares of our common stock, with respect to 6,000 of which the restrictions lapse immediately upon appointment to the Advisory Board and with respect to an additional 6,000 shares the restrictions will lapse on each of the six-month, one-year and eighteen-month anniversaries of such appointment. All of these restricted stock grants are now fully vested;

· The prior Chairman of our Advisory Board received options to purchase 226,000 additional shares of our common stock upon his appointment, which options shall have an exercise price equal to the fair market value of our common stock on the date of grant. All of these restricted stock grants are now fully vested; and

· All members of our Advisory Board shall be reimbursed for reasonable out-of-pocket expenses incurred by them in connection with their Advisory Board services.

Certain of these advisors may render additional services to us for which they will be compensated separately.

Board Independence

We are not required to have any independent members of the Board of Directors. The board of directors has determined that (i) Messrs. Griffin 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. Cerna, Hern 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.mesaenergy.us . The membership, principal duties and responsibilities of each committee are set forth below.

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The membership of our Board committees is as follows:

Audit Committee – James J. Cerna, Jr. (Chairman), Kenneth T. Hern and Fred B. Zaziski

Compensation Committee – Fred B. Zaziski (Chairman), Kenneth T. Hern and James J. Cerna, Jr.

Corporate Governance – Kenneth T. Hern (Chairman), Fred B. Zaziski and James J. Cerna, Jr.

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;

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· 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.

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 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.

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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

In December 2011, we adopted a formal Executive Officer Code of Ethics applicable to our principal officers, Randy M. Griffin, our Chief Executive Officer, and Rachel L. Dillard, our Chief Financial Officer, as well as to other persons who may perform similar functions. Our Code of Ethics is available free of charge on our website at www.mesaenergy.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.

Based solely on our review of the copies of such reports received by us and on written representations by our officers and directors regarding their compliance with the applicable reporting requirements under Section 16(a) of the Exchange Act, we believe that with respect to the fiscal year ended December 31, 2012, our directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements.

ITEM 11. EXECUTIVE COMPENSATION 

The following table sets forth information concerning the total compensation paid or accrued by us during the fiscal year ended December 31, 2012, 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, 2012; (ii) our two most highly compensated executive officers other than the principal executive officer who were serving as executive officers at the end of the fiscal year ended December 31, 2012, and who received annual compensation during the fiscal year ended December 31, 2012 in excess of $100,000; and (iii) up to two additional individuals who received annual compensation during the fiscal year ended December 31, 2012 in excess of $100,000 and who were not serving as executive officers of at the end of the fiscal year ended December 31, 2012.

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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)	2012	$	190,000	$	5.000		—	$	68,938		—		—		—	$	263,938
	2011	$	160,000	$	10,000		—	$	68,940		—		—		—	$	238,940
Rachel L. Dillard ,Chief Financial Officer (1)	2012	$	115,250	$	8,000	$	73,846		—		—		—		—	$	197,096
	2011	$	36,855	$	8,000	$	35,194		—		—		—		—	$	80,049
Ray L. Unruh, President (1)	2012		—		—	$	11,250		—		—		—		—	$	11,250
	2011		—		—		2,250		—		—		—		—	$	2,250
David L. Freeman, Executive Vice President – Oil and Gas Operations (1)	2012	$	200,000	$	5,000	$	15,000		—		—		—		—	$	220,000
	2011	$	83,333	$	10,000	$	3,000		—		—		—		—	$	96,333

(1) Value of stock and option awards is the actual amount of stock compensation expense recognized in 2012 for the awards. The fair value of the awards on the date of grant were: Mr. Griffin, $137,878; Ms. Dillard, $180,000; Mr. Unruh, 22,500; Mr. Freeman, $30,000.

(2) Mr. Griffin’s reported salary does not include $120,000 paid to him as part of accrued salary from prior years which is being paid to him in increments of $10,000 per month.

Employment Agreements with Executive Officers

On August 31, 2009, the Company entered into an employment agreement with Randy M. Griffin, its Chief Executive Officer, pursuant to which Mr. Griffin was to receive annual compensation of $120,000 for the first year of employment, $150,000 for the second year and $180,000 for the third year and any years thereafter unless adjusted by the Board of Directors within its sole discretion. Mr. Griffin waived compensation under this agreement for the period January 1, 2010 through June 30, 2010. Compensation for the period September 1, 2009 through July 31, 2011, was accrued.  Beginning January 1, 2011, Mr. Griffin began receiving the accrued compensation at a rate of $10,000 per month, which monthly payment amount will continue until the accrued balance has been fully paid.  In the event that Mr. Griffin terminates the employment agreement for Good Reason (as defined therein) or the Company terminates the employment agreement without Cause (as defined therein), Mr. Griffin 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 one year following the termination of employment.  The term of the employment agreement is for a period of three years and automatically renews for one year periods thereafter unless terminated pursuant to the agreement. On June 8, 2012, Mr. Griffin’s Employment Agreement was amended to increase the annual compensation for the fourth and subsequent years of the agreement to $210,000 per recommendation of the Compensation Committee.

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On September 19, 2011, the Company entered into an employment agreement with Rachel L. Dillard, its Chief Financial Officer.  The employment agreement, as amended, provides for (i) an annual base salary of $112,000 and (ii) a restricted stock award of 1,000,000 shares of its common stock 100,000 shares of which, valued at $15,000, vested on the execution date of the agreement. The remaining shares vest as follows: 200,000 shares on each of April 1, 2012, October 1, 2012 and April 1, 2013, and the remaining 300,000 shares on October 1, 2013.  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 one month following such cessation of employment. The term of the employment agreement is for a period of twelve months and automatically renews for one year periods thereafter unless terminated pursuant to the agreement. Effective October 1, 2012, Ms. Dillard’s Employment Agreement was amended to increase the annual compensation to $125,000 per year, extend the severance period to three months, and provide that any unvested equity compensation will vest upon her death or disability. Effective March 20, 2013, Ms. Dillard’s Employment Agreement was further amended such that the remaining two unvested portions of her restricted stock award were converted to incentive stock options vesting as to 200,000 shares on April 1, 2013 and as to the remaining 300,000 shares on October 1, 2013.  The exercise price for these options was set at $0.131 per share, the closing market price of our common stock on March 20, 2013, and these options expire on March 19, 2018.

Grants of Plan-Based Awards

We have not issued any stock options or maintained any stock option or other incentive plans other than our 2009 Equity Incentive Plan. (See “Market for Common Equity and Related Stockholder Matters – Securities Authorized for Issuance under Equity Compensation Plans,” above). The restricted stock grant to Ms. Dillard in the amount of 1,000,000 shares of our common stock that was subsequently converted into an incentive stock option grant as to 500,000 shares, however, was granted under an employment agreement with her and not under our 2009 Equity Incentive Plan.   

No additional grants were made to executive officers during the year ended December 31, 2012.

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, 2012.

	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	6/30/2011		—		1,000,000		0.15	6/30/2016

The following tables set forth information regarding restricted stock awards held by our Named Executive Officers at December 31, 2012.

	Restricted Stock Awards
Name	Grant Date	Number of Shares or Units of  Stock that  have not Vested		Market Value of Shares or United of Stock that have not Vested  ($)(1)
Rachel L. Dillard	9/19/2011		500,000	$	75,000
	9/30/2011		100,000		15,000
David L. Freeman	9/30/2011		100,000	$	15,000
Ray L. Unruh	9/30/2011		75,000	$	11,250

(1) The market value of restricted stock awards is based on $0.15, the closing market price of our common stock on the dates of grant.

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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, 2012.

	Stock Awards
Name	Number of Shares of  Restricted Stock Acquired on Vesting	Value Realized on Vesting  ($)
Rachel L. Dillard	600,000	$	90,000

(1) The market value of restricted stock awards is based on $0.15, the closing market price of the Company common shares on the dates of grant.

Director Compensation

 The following table sets forth summary information concerning the total compensation paid to our non-employee directors in 2012 for services to us.

	Fees Earned				Restricted
	or Paid in		Stock Option Awards		Stock Awards
Name	Cash($)		($)(1)		($)(2)		Total ($)
James J. Cerna, Jr.	$	18,000	$	9,416	$	3,750	$	31,166
Kenneth T. Hern		12,000		9,416		3,750		25,166
Fred B. Zaziski		12,000		9,416		3,750		25,166
Total:	$	42,000	$	28,248	$	11,250	$	81,498

(1)

On June 8, 2012, each of our non-employee directors was granted restricted stock option awards of 100,000 shares of our common stock vesting over a period of one year as follows:  50,000 shares on June 8, 2012 and 50,000 shares on June 8, 2013.  We determined the fair value of each of these awards on the date of grant to be $12,556; however, 2012 stock compensation expense recognized for these awards was $28,248 in the aggregate.  Options expire on June 7, 2017 and have an exercise price of $0.145 per share.

(2)

On September 30, 2011, each of our non-employee directors was granted a restricted stock award of 50,000 shares of our common stock vesting over a period of two years as follows: 5,000 shares on December 30, 2011, 10,000 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; however, 2012 stock compensation expense recognized for these awards was $11,250 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 27, 2013 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		11,980,341	(4) (9)		11.9	%
Ray L. Unruh		8,071,793	(5) (9)		9.6	%
Rachel L. Dillard		840,000	(6)		1	%
David L. Freeman		8,423,833	(7)		10.0	%
Kenneth T. Hern		285,000	(8)		*
Fred B. Zaziski		285,000	(8)		*
James J. Cerna, Jr.		1,234,554	(8)		1.5	%
All directors and executive officers as a group (7 persons)		31,120,521	(9)		34.0	%
W. Willard Powell		6,288,751			7.5	%

* Indicates beneficial ownership of less than 1%.

1	Unless otherwise noted, the mailing address of each beneficial owner is c/o Mesa Energy Holdings, 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 1, 2013, 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 84,330,477 shares of Common Stock issued and outstanding as of March 27, 2013.

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4 Includes 1,735,740 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 1,904,000 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 1,800,000 shares of common stock that may be purchased from Ray Unruh pursuant to option agreements dated December 17, 2012. Also includes 1,000,000 shares of our common stock issuable upon the exercise of options granted under our 2009 Equity Incentive Plan, which vested on June 30, 2012.

5 Includes 770,830 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 and 5,395,963 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 1,800,000 shares owned by Ray Unruh that may be purchased by Randy Griffin pursuant to option agreements dated December 17, 2012.  Also includes 30,000 of our restricted common stock issuable under our 2009 Equity Incentive Plan within 60 days.  Does not include 45,000 shares of our restricted common stock issuable under our 2009 Equity Incentive Plan which vest on September 30, 2013.

6 Includes 40,000 shares of our restricted common stock issuable upon the exercise of options granted under our 2009 Equity Incentive Plan and an additional 200,000 shares of our restricted common stock issuable upon the exercise of options granted under Ms. Dillard’s employment agreement, both issuable within 60 days. Does not include (i) 60,000 shares of our restricted common stock issuable upon the exercise of options granted under our 2009 Equity Incentive Plan which vest on September 30, 2013 and (ii) 300,000 shares of our restricted common stock issuable upon the exercise of options granted under Ms. Dillard’s employment agreement which vest on October 1, 2013.

7 Includes 3,471,480 shares owned by Freeman Energy LLC and 1,350,020 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. Includes 40,000 shares of our restricted common stock issuable under our 2009 Equity Incentive Plan within 60 days. Does not include 60,000 shares of our restricted common stock issuable under our 2009 Equity Incentive Plan which vest on September 30, 2013.

8 Includes 250,000 shares of our common stock that may be issued upon exercise of non-incentive stock options granted under our 2009 Equity Incentive Plan. Includes 10,000 shares of our restricted common stock issuable under our 2009 Equity Incentive Plan within 60 days. Does not include 50,000 shares of our restricted common stock issuable under our 2009 Equity Incentive Plan which vest on June 7, 2013; 50,000 shares of our restricted common stock issuable under our 2009 Equity Incentive Plan which vest on June 7, 2014, or 15,000 shares of our restricted common stock issuable under our 2009 Equity Incentive Plan which vest on September 30, 2013.

9 As Mr. Griffin has an option to purchase an aggregate of 1,800,000 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 1,800,000 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.

  Equity Compensation Plan Information

On August 20, 2009, our Board of Directors adopted, and on August 21, 2009, our stockholders approved, the 2009 Equity Incentive Plan (the “2009 Plan”), which reserves a total of 5,000,000 shares of our Common Stock for issuance under the 2009 Plan. If an incentive award granted under the 2009 Plan expires, terminates, is unexercised or is forfeited, or if any shares are surrendered to us in connection with an incentive award, the shares subject to such award and the surrendered shares will become available for further awards under the 2009 Plan.

In addition, the number of shares of Common Stock subject to the 2009 Plan, any number of shares subject to any numerical limit in the 2009 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.

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 2009 Plan. Subject to the terms of the 2009 Plan, the Compensation Committee would have complete authority and discretion to determine the terms of awards under the 2009 Equity Incentive Plan.

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Grants

The 2009 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 2009 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 2009 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 2009 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 2009 Plan would terminate ten years after it is adopted.

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, 2012, 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

On August 31, 2009, the Company entered into an employment agreement with Randy M. Griffin, its Chief Executive Officer, pursuant to which Mr. Griffin was to receive annual compensation of $120,000 for the first year of employment, $150,000 for the second year and $180,000 for the third year and any years thereafter unless adjusted by the Board of Directors within its sole discretion. Mr. Griffin waived compensation under this agreement for the period January 1, 2010 through June 30, 2010. Compensation for the period September 1, 2009 through July 31, 2011, was accrued.  Beginning January 1, 2011, Mr. Griffin began receiving the accrued compensation at a rate of $10,000 per month, which monthly payment amount will continue until the accrued balance has been fully paid.  In the event that Mr. Griffin terminates the employment agreement for Good Reason (as defined therein) or the Company terminates the employment agreement without Cause (as defined therein), Mr. Griffin 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 one year following the termination of employment.  The term of the employment agreement is for a period of three years and automatically renews for one year periods thereafter unless terminated pursuant to the agreement. On June 8, 2012, Mr. Griffin’s Employment Agreement was amended to increase the annual compensation for the fourth and subsequent years of the agreement to $210,000 per recommendation of the Compensation Committee.

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On September 19, 2011, the Company entered into an employment agreement with Rachel L. Dillard, its Chief Financial Officer.  The employment agreement, as amended, provides for (i) an annual base salary of $112,000 and (ii) a restricted stock award of 1,000,000 shares of its common stock 100,000 shares of which, valued at $15,000, vested on the execution date of the agreement. The remaining shares vest as follows: 200,000 shares on each of April 1, 2012, October 1, 2012 and April 1, 2013, and the remaining 300,000 shares on October 1, 2013.  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 one month following such cessation of employment. The term of the employment agreement is for a period of twelve months and automatically renews for one year periods thereafter unless terminated pursuant to the agreement. Effective October 1, 2012, Ms. Dillard’s Employment Agreement was amended to increase the annual compensation to $125,000 per year, extend the severance period to three months, and provide that any unvested equity compensation will vest upon her death or disability.  Effective March 20, 2013, Ms. Dillard’s Employment Agreement was further amended such that the remaining two unvested portions of her restricted stock award were converted to incentive stock options vesting as to 200,000 shares on April 1, 2013 and as to the remaining 300,000 shares on October 1, 2013.  The exercise price for these options was set at $0.131 per share, the closing market price of our common stock on March 20, 2013, and these options expire on March 19, 2018.

Option Grants

On June 30, 2011, we issued to Randy M. Griffin, our Chief Executive Officer, an incentive stock option to purchase 1,000,000 shares of our common stock under our 2009 Plan.  This option has an exercise price of $0.15 per share, became fully vested on June 30, 2012 and expires on June 30, 2016.

On March 20, 2012, we converted the remaining 100,000 share portion of a restricted stock grant to Rachel L. Dillard, our Chief Financial Officer, into an incentive stock option vesting as to 40,000 shares on March 30, 2013 and as to 60,000 shares on September 30, 2013, all at an exercise price of $0.131 per share.  These stock options expire on March 30, 2018.

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. Cerna, Hern and Zaziski qualifies as independent under the requirements of the NASDAQ listing standards.

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, 2012 and 2011 are set forth in the table below:

Fee Category	2012		2011
Audit fees (1)	$	195,000	$	125,310
Audit-related fees (2)		30,650		99,737
Tax fees (3)		—		—
All other fees (4)		—		—
Total fees	$	225,650	$	225,047

(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.

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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, 2012. 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	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. (1)
2.2	2.2	Articles of Merger (1)
2.3	--	Asset Purchase Agreement and Plan of Reorganization dated as of November 14, 2012, as amended by Amendment No. 1 thereto dated as of February 19, 2013, among Armada, Mesa and MEI (13)
2.4	--	Form of Assignment and Assumption Agreement between Mesa and MEI entered into on March [___], 2013 (14)
3.1	3.1	Certificate of Incorporation of the Registrant (2)
3.2	3.1	Certificate of Amendment to Certificate of Incorporation of the Registrant (3)
3.3	3.3	Restated Bylaws of the Registrant (1)
4.1	10.7	Form of Secured Convertible Promissory Note of Mesa Energy Holdings, Inc. (1)
4.2	10.02	Form of Convertible Debenture issued June 16, 2011 to Whalehaven Capital Fund Ltd.(4)
10.1	10.1	Split-Off Agreement, dated as of August 31, 2009, by and among Mesa Energy Holdings, Inc., Mesquite Mining Group, Inc., and Beverly Frederick (1)
10.2	10.2	General Release Agreement, dated as of August 31, 2009, by and among Mesa Energy Holdings, Inc., Mesquite Mining Group, Inc., and Beverly Frederick (1)
10.3	10.6	Form of Subscription Agreement between Mesa Energy Holdings, Inc. and the investors party thereto (1)
10.4	10.4	Form of Omnibus Waiver and Modification Agreement dated May 11, 2011 relating to the Secured Convertible Promissory Note of Mesa Energy Holdings, Inc. (11)
10.5	10.8	Form of Subsidiary Guaranty among Mesa Energy, Inc., Mesa Energy Operating, LLC and the investors party thereto (1)
10.6	10.9	Security Agreement, dated as of August 31, 2009, among Mesa Energy Holdings, Inc., Mesa Energy, Inc., Mesa Energy Operating, LLC, the investors party thereto and Collateral Agents, LLC (1)
10.7	10.26	Collateral Agent Agreement, dated as of August 31, 2009, among Mesa Energy Holdings, Inc., Mesa Energy, Inc., Mesa Energy Operating LLC, the investors party thereto and Collateral Agents, LLC (1)
10.8	10.17	Spring Valley Center Office Lease, dated June 1, 2007, between Spring Valley Center, LLP and Mesa Energy, Inc. (1)
10.9	10.21	Letter Agreement, dated March 17, 2009, between Mesa Energy,  Inc. and Robert Thomasson (1)
10.10	10.22	Purchase and Sale Agreement, dated June 17, 2009, between Hydrocarbon Generation, Inc. and Sycamore Resources, Inc. (1)
10.11	10.23	Assignment of Purchase and Sale Agreement, dated as of August 25, 2009, from Sycamore Resources, Inc. to Mesa Energy, Inc. (1)
10.12	10.24	Employment Agreement dated August 31, 2009, between Mesa Energy Holdings, Inc. and Randy M. Griffin (1)
10.13	10.01	Exchange Agreement, dated as of June 16, 2011, by and between Mesa Energy Holdings, Inc. and Whalehaven Capital Fund Ltd. (4)
10.14	10.01	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 (5)
10.15	10.15	Employment Services Agreement dated September 19, 2011, between Mesa Energy Holdings, Inc. and Rachel L. Dillard (11)
10.16	10.16	Amendment dated October 17, 2011 Employment Services Agreement dated September 19, 2011, between Mesa Energy Holdings, Inc. and Rachel L. Dillard (11)
10.17	10.25	Mesa Energy Holdings, Inc. 2009 Equity Incentive Plan (1)
10.18	10.01	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 (6)
10.19	10.02	Security Agreement dated July 22, 2011 by TNR Natural Resources, LLC for the benefit of F&M Bank & Trust Company (6)
10.20	10.03	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 (6)
10.21	10.04	Pledge and Security Agreement dated July 22, 2011 by Mesa Energy, Inc. for the benefit of F&M Bank & Trust Company (6)

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10.22	10.05	Unlimited Guaranty dated July 22, 2011 by Mesa Energy Holdings, Inc. for the benefit of F&M Bank & Trust Company (6)
10.23	10.06	Unlimited Guaranty dated July 22, 2011 by Mesa Gulf Coast, LLC for the benefit of F&M Bank & Trust Company (6)
10.24	10.07	Unlimited Guaranty dated July 22, 2011 by Tchefuncte Natural Resources, LLC for the benefit of F&M Bank & Trust Company (6)
10.25	10.09	Amendment to Membership Interest Purchase Agreement, dated as of July 13, 2011, by and among Mesa Energy Holdings, Inc., Mesa Energy, Inc., Tchefuncte Natural Resources, LLC, Carolyn M. Greer, Willie Willard Powell and David L. Freeman. (6)
10.26	10.01	Letter Agreement and Bill of Sale between the Registrant and Wentworth Operating Co., dated September 8, 2011 (7)
10.27	10.03	Voting Agreement, dated as of November 14, 2012, between Stockholder of Mesa Energy Holdings, Inc. and Armada Oil, Inc. (12)
10.28	*	Second Amendment to Employment Services Agreement dated as of October 1, 2012 between Mesa Energy Holdings, Inc. and Rachel L. Dillard
10.29	*	Third Amendment to Employment Services Agreement dated as of March 20, 2013 between Mesa Energy Holdings, Inc. and Rachel L. Dillard
16.1	16.1	Letter regarding change in certifying accountant dated September 21, 2009 (8)
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	99.1	Audited financial statements of TNR for the period from inception (June 10, 2010) to December 31, 2010, including the related report of the independent registered public accounting firm, and the unaudited interim financial statements for the period from inception (June 10, 2010) to June 30, 2010 and the six months ended June 30, 2011 (9)
99.2	99.2	Audited statements of revenues and direct operating expenses of certain oil and gas properties of Samson Properties for the years ended December 31, 2010 and 2009 and the unaudited interim statements of revenues and direct operating expenses for the six month periods ended June 30, 2011 and 2010  (9)
99.3	99.3	Unaudited pro forma consolidated financial information and accompanying notes of Mesa Energy Holdings, Inc. as of and for the six months ended June 30, 2011 and for the year ended December 31, 2010, together with unaudited pro forma consolidated supplemental oil and gas information  (9)
99.4	99.4	Letter from Collarini Associates dated October 17, 2011 relating to its reserve estimates dated January 1, 2011 (9)
99.5	99.5	Letter from Collarini Associates dated October 17, 2011 relating to its reserve estimates dated April 1, 2011 (9)
99.6	99.1	Reserve Report of Chadwick Energy Consulting, Inc. (10)
99.7	99.7	Letter from Collarini Associates dated March 6, 2012 relating to its reserve estimates dated January 1, 2012 (11)
99.7	*	Letter from Collarini Associates dated February 28, 2013, relating to its reserve estimates dated January 1, 2013
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 of 1933, as amended, except as shall be expressly set forth by specific reference in such filing or document.

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(1) Incorporated by reference the Exhibit numbered as indicated above to the Registrant’s Current Report on Form 8-K (File No. 333-149338), filed with the SEC on September 3, 2009.

(2) Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Registration Statement on Form S-1 (File No. 333-149338), filed with the SEC on February 21, 2008.

(3) Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Form 8-K (File No. 333-149338), filed with the SEC on June 25, 2009.

(4) Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Form 8-K (File No. 000-53972), filed with the SEC on July 7, 2011.

(5) Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Form 8-K (File No. 000-53972), filed with the SEC on June 6, 2011.

(6) Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Form 8-K (File No. 000-53972), filed with the SEC on July 28, 2011.

(7)  Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Form 8-K (File No. 000-53972), filed with the SEC on October 17, 2011.

(8) Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Amendment No. 1 to Current Report on Form 8-K/A (File No. 333-149338), filed with the SEC on September 22, 2009.

(9) Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Form 8-K (File No. 000-53972), filed with the SEC on January 11, 2012.

(10)   Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Amendment No. 1 to its Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 000-53972), filed with the SEC on July 22, 2011.

(11) Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Form 10-K (File No. 000-53972), filed with the SEC on April 13, 2012.

(12) Incorporated by reference to the Exhibit numbered as indicated above to the Registrant’s Form 8-K (File No. 000-53972), filed with the SEC on November 20, 2012.

(13) Incorporated by reference to Appendix A to the Registrant’s Definitive Proxy Statement dated March 15, 2013 (File No. 000-53972), filed with the SEC on March 15, 2013.

(14) Incorporated by reference to Appendix B to the Registrant’s Definitive Proxy Statement dated March 15, 2013 (File No. 000-53972), filed with the SEC on March 15, 2013.

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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.

MESA ENERGY HOLDINGS, INC.

Dated:  April 1, 2013	By:	/s/ RANDY M. GRIFFIN
		Randy M. Griffin, Chief Executive Officer
Dated:  April 1, 2013	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	April 1, 2013
Randy M. Griffin	Officer (principal executive officer)
/s/ RAY L. UNRUH	Director, President, Secretary
Ray L. Unruh		April 1, 2013
/s/ JAMES J. CERNA, JR.	Director
James J. Cerna, Jr.		April 1, 2013
/s/ KENNETH T. HERN	Director
Kenneth T. Hern		April 1, 2013
/s/ FRED B. ZAZISKI	Director
Fred B. Zaziski		April 1, 2013

60

MESA ENERGY HOLDINGS, INC.

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2012 and 2011	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2012 and 2011	F-4
Consolidated Statement of Changes in Stockholders’ Equity (Deficit) for the Years Ended December 31, 2012 and 2011	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012 and 2011	F-6
Notes to Consolidated Financial Statements	F-7

F-1

Report of Independent Registered Public Accounting Firm

To the Shareholders

Mesa Energy Holdings, Inc.

Dallas, Texas

We have audited the accompanying consolidated balance sheets of Mesa Energy Holdings, Inc. as of December 31, 2012 and 2011, and the related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows for the years ended December 31, 2012 and 2011. 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 Mesa Energy Holdings, Inc. as of December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for the years ended December 31, 2012 and 2011, in conformity with accounting principles generally accepted in the United States of America.

/s/ GBH CPAs, PC

GBH CPAs, PC

www.gbhcpas.com

Houston, Texas

April 1, 2013

F-2

MESA ENERGY HOLDINGS, INC.

CONSOLIDATED BALANCE SHEETS

	December 31, 2012		December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	5,884,649	$	3,182,392
Accounts receivable – oil and gas		1,593,258		2,460,260
Accounts receivable – other		280,430		58,818
Derivative assets, commodity contracts – current		83,298		656,413
Deferred financing costs, net – current		22,563		51,507
Deferred tax assets – current		38,325		—
Prepaid expenses		117,678		3,971
TOTAL CURRENT ASSETS		8,020,201		6,413,361
Oil and gas properties, successful efforts accounting:
Properties subject to amortization, net		9,082,526		6,727,027
Properties not subject to amortization		759,133		—
Support facilities and equipment, net		2,075,563		2,076,777
Land		48,345		48,345
Net oil and gas properties		11,965,567		8,852,149
Property and equipment, net		241,627		31,834
Derivative assets, commodity contracts		—		282,537
Deferred financing costs, net		13,162		28,431
Deferred tax assets		3,126,478		3,088,740
Deposits on asset retirement obligations		609,421		640,000
Other assets		4,013		5,000
TOTAL ASSETS	$	23,980,469	$	19,342,052
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable – trade	$	1,045,918	$	1,518,603
Revenue payable		334,433		796,221
Accrued expenses		753,961		259,808
Accrued expenses – related parties		54,840		54,840
Deferred tax liabilities – current		—		212,781
Notes payable – current		90,417		466,655
Other current liabilities		91,000		—
TOTAL CURRENT LIABILITIES		2,370,569		3,308,908
Notes payable		9,195,963		5,162,018
Convertible notes payable, net of discount of $0 and $4,279, respectively		—		461,740
Derivative liability – convertible debt		—		113,083
Derivative liability – commodity contracts		58,519		—
Deferred tax liabilities		678,782		—
Asset retirement obligations		3,507,798		3,450,252
TOTAL LIABILITIES		15,811,631		12,496,001
Commitments and contingencies
Stockholders’ equity:
Preferred stock, par value $0.0001, 10,000,000 shares authorized, 0 shares issued and outstanding		—		—
Common stock, par value $0.0001, 300,000,000 shares authorized, 84,330,477 and 79,531,324 shares issued and outstanding, respectively		8,433		7,953
Additional paid-in capital (deficiency)		829,273		(633,745	)
Retained earnings		7,331,132		7,471,843
TOTAL STOCKHOLDERS’ EQUITY		8,168,838		6,846,051
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	23,980,469	$	19,342,052

See accompanying notes to consolidated financial statements.

F-3

MESA ENERGY HOLDINGS, INC.

 CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2012			2011
Revenues	$	14,865,169		$	6,960,597
Operating expense:
Lease operating expense		7,062,611			2,849,484
Environmental remediation expense		244,237			—
Exploration cost		115,276			129,478
Depletion, depreciation, amortization, accretion and impairment		1,832,537			1,429,100
Loss on settlement of asset retirement obligations		116,394			—
General and administrative expense		3,636,010			1,855,282
Gain on sale of oil and gas properties		—			(22,396	)
Total operating expense		13,007,065			6,240,948
Income from operations		1,858,104			719,649
Other income (expense):
Interest income		8,602			2,886
Interest expense		(503,638	)		(549,512	)
Realized gain on commodity contracts		440,699			137,358
Unrealized gain on change in derivatives – commodity contracts		(912,963	)		938,950
Gain on change in derivative values – convertible debt		(534,989	)		(113,083	)
Gain on settlement of accounts payable with common stock		—			286,041
Loss on conversion of debt – related party		—			(62,306	)
Loss on extinguishment of debt		—			(17,620	)
Other income (expense)		(7,261	)		25,803
Total other income (expense)		(1,509,550	)		648,517
Income before income taxes		348,554			1,368,166
Income tax benefit (expense)		(489,265	)		2,783,792
Net income (loss)	$	(140,711	)	$	4,151,958
Net income (loss) per common share:
Basic	$	(0.00	)	$	0.07
Diluted	$	(0.00	)	$	0.06
Weighted average number of common shares outstanding:
Basic		83,985,678			61,494,530
Diluted		83,985,678			67,905,495

See accompanying notes to consolidated financial statements.

F-4

MESA ENERGY HOLDINGS, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)

For the Years Ended December 31, 2012 and 2011

	Common Stock				Additional
					Paid-In			Retained
	Shares		Par		Capital			Earnings			Total
Balances at December 31, 2010		40,231,729	$	4,023	$	(6,786,915	)	$	3,319,885		$	(3,463,007	)
Shares issued for cash to related parties		320,000		32		39,968			—			40,000
Share-based compensation		816,967		83		324,242			—			324,325
Shares issued to settle accounts payable		1,250,000		125		177,195			—			177,320
Conversion of debt and accrued interest to stock		14,646,628		1,464		2,463,624			—			2,465,088
Common shares issued to induce debt conversion		1,036,000		103		111,871			—			111,974
Shares issued for acquisition of Tchefuncte Natural Resources, LLC		21,200,000		2,120		2,965,880			—			2,968,000
Shares issued in exchange for personal guarantees on debt		30,000		3		4,647			—			4,650
Debt discount		—		—		5,743			—			5,743
Related party forgiveness of debt		—		—		60,000			—			60,000
Net income		—		—		—			4,151,958			4,151,958
Balances at December 31, 2011		79,531,324	$	7,953	$	(633,745	)	$	7,471,843		$	6,846,051
Share-based compensation		1,071,000		107		303,876			—			303,983
Conversion of notes payable and accrued interest to stock		3,728,153		373		465,646			—			466,019
Transfer of derivative liability from liability classification to equity classification		—		—		648,072			—			648,072
Warrant expense		—		—		45,424			—			45,424
Net loss		—		—		—			(140,711	)		(140,711	)
Balances at December 31, 2012		84,330,477	$	8,433	$	829,273		$	7,331,132		$	8,168,838

See accompanying notes to consolidated financial statements.

F-5

MESA ENERGY HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2012 and 2011

	Year Ended December 31,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(140,711	)	$	4,151,958
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization, accretion and impairment		1,832,537			1,429,100
Deferred income taxes		389,938			(2,875,959	)
Share-based compensation		349,407			324,325
Gain on sale of oil and gas properties		—			(22,396	)
Loss on settlement of asset retirement obligations		116,394			—
Amortization of debt discount charged to interest expense		4,279			1,464
Amortization of deferred financing costs		44,213			140,871
Common shares issued to induce debt conversion		—			111,974
Shares issued for continuation of loan guarantees charged to interest expense		—			4,650
Unrealized loss (gain) on change in derivatives – commodity contracts		912,963			(938,950	)
Gain on change in derivative values – convertible debt		534,989			113,083
Gain on settlement of accounts payable with common stock		—			(286,041	)
Loss on conversion of debt – related party		—			62,306
Loss on extinguishment of debt		—			17,620
Changes in operating assets and liabilities:
Accounts receivable – oil and gas		867,002			(450,172	)
Accounts receivable – other		(221,612	)		(50,470	)
Prepaid expenses		(24,076	)		11,669
Accounts payable and accrued expenses		(638,919	)		904,849
Revenue payable		(461,788	)		663,747
Accrued expenses – related parties		—			50,823
CASH PROVIDED BY OPERATING ACTIVITIES		3,564,616			3,364,451
CASH FLOWS FROM INVESTING ACTIVITIES
Cash received for sale of oil and gas properties		—			17,960
Cash paid for acquisition and development of oil and gas properties		(3,795,819	)		(5,379,057	)
Cash paid for settlement of asset retirement obligations		(225,172	)		—
Cash paid for support facilities and equipment		(277,813	)		(246,214	)
Cash paid for property and equipment		(86,132	)		(6,319	)
Installment payment on software		(45,500	)		—
CASH USED IN INVESTING ACTIVITIES		(4,430,436	)		(5,613,630	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of stock		—			40,000
Proceeds from borrowings on line of credit, net of financing costs		4,000,000			5,693,086
Proceeds from borrowings on debt, net of financing costs		79,419			20,000
Proceeds from borrowings on debt – related party		—			72,000
Principal payments on long-term notes payable		(511,342	)		(306,611	)
Principal payments on debt – related party		—			(93,000	)
CASH PROVIDED BY FINANCING ACTIVITIES		3,568,077			5,425,475
NET CHANGE IN CASH		2,702,257			3,176,296
CASH AT BEGINNING OF YEAR		3,182,392			6,096
CASH AT END OF YEAR	$	5,884,649		$	3,182,392
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest	$	479,494		$	210,495
Cash paid for income taxes	$	77,000		$	—
NON-CASH INVESTING AND FINANCING TRANSACTIONS
Prepaid insurance financed with notes payable	$	89,631		$	—
Software purchased with installment payments	$	136,500		$	—
Transfer of derivative liability from liability classification to equity classification	$	648,072		$	—
Fair value of derivative liability on convertible debt	$	—		$	136,404
Accrued oil and gas development cost	$	—		$	36,364
Common stock issued for purchase of Tchefuncte Natural Resources, LLC	$	—		$	2,968,000
Common stock issued for the conversion of notes payable and accrued interest	$	466,019		$	2,465,088
Promissory note and accrued interest exchanged for convertible note	$	—		$	41,019
Debt discount on convertible note	$	—		$	5,743
Common stock issued to settle accounts payable	$	—		$	177,320
Forgiveness of accrued salary by CEO recorded as contributed capital	$	—		$	60,000

See accompanying notes to consolidated financial statements. 

F-6

MESA ENERGY HOLDINGS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Organization

Mesa Energy, Inc. (“MEI”) is a wholly owned subsidiary of Mesa Energy Holdings, Inc. (referred to individually or in conjunction with one or more of its subsidiaries as the “Company”). MEI’s predecessor entity, Mesa Energy, LLC, was formed in April 2003 as an exploration and production company in the oil and gas industry. MEI’s oil and gas operations are conducted through itself and its wholly owned subsidiaries. MEI acquired Tchefuncte Natural Resources, LLC (“TNR”) in July 2011. TNR owns interests in 80 wells and related surface production equipment in five fields located in Plaquemines and Lafourche Parishes in Louisiana. Mesa Gulf Coast Operating, LLC, a wholly owned subsidiary of the Company, became the operator of all operated properties in Louisiana in October 2011. Mesa Midcontinent, LLC is a qualified operator in the state of Oklahoma and operates our properties in Garfield and Major Counties, Oklahoma. MEI is a qualified operator in the State of New York and operates the Java Field. The Company’s operating entities have historically employed, and will continue in the future to employ, on an as-needed basis, the services of drilling contractors, other drilling related vendors, field service companies and professional petroleum engineers, geologists and land men as required in connection with future drilling and production operations.

Basis of Presentation 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 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 for the basis for making judgments that are not readily apparent from other sources.   Actual results could differ from these estimates and changes in these estimates are recorded when known.

Reclassifications

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

Cash, 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 write-offs 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.

F-7

The Company routinely assesses the collectibility of all material trade and other receivables. The Company's oil and gas receivables consist primarily of 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 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 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.

F-8

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.

F-9

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, 2012 and 2011:

	Carrying Value at				Fair Value Measurement at
	December 31, 2012				December 31, 2012
					Level 1			Level 2				Level 3
Derivative assets, commodity contracts		$	83,298			$	—		$	83,298		$	—
Derivative liabilities, commodity contracts			(58,519	)			—			(58,519	)		—

	Carrying Value at		Fair Value Measurement at
	December 31, 2011		December 31, 2011
			Level 1		Level 2		Level 3
Derivative liability, convertible debt	$	113,083	$	—	$	—	$	113,083
Derivative assets, commodity contracts		938,950		—		938,950		—

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

		Significant Unobservable Inputs
		(Level 3)
		Years Ended December 31,
		2012			2011
Beginning balance	$	(113,083	)	$	—
Gain on change in derivative values		(534,989	)		(113,083	)
Transfer of derivative liability from liability classification to equity classification		648,072			—
Initial derivative valuation		—			—
Transfers		—			—
Ending balance	$	—		$	(113,083	)
Change in gains (losses) included in earnings relating to derivatives still held at year end		N/A		$	(113,083	)

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

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 the derivative instruments are recorded as unrealized gains or losses in the Statement of Operations.

F-10

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 within the related full cost pool. 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.

F-11

Earnings Per Common Share

The Company’s earnings per share are computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflects the potential dilution of securities, if any, that could share in the earnings of the Company and 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,
	2012			2011
Numerator:
Net income (loss) available to stockholders	$	(140,711	)	$	4,151,958
Basic net income allocable to participating securities (1)		—			(37,306	)
Basic net income available to stockholders		(140,711	)		4,114,652
Impact of assumed conversions-interest expense, net of income taxes		—			56,223
Income available to stockholders assuming conversion of convertible debentures	$	(140,711	)	$	4,170,875
Denominator:
Weighted average number of common shares-Basic		83,985,678			61,494,530
Effect of dilutive securities (2) :
Options and warrants		—			—
Convertible promissory notes		—			6,410,965
Weighted average number of common shares-Diluted		83,985,678			67,905,495
Net income per share:
Basic	$	0.00		$	0.07
Diluted	$	0.00		$	0.06

(1)

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

(2)

For the year ended December 31, 2012, “out of the money” stock options representing 2,525,879 shares and warrants representing 500,000 shares were antidilutive and, therefore, excluded from the diluted share calculation. For the year ended December 31, 2011, “out of the money” stock options representing 2,228,000 shares were antidilutive and, therefore, excluded from the diluted share calculation. There were no warrants outstanding at December 31, 2011.

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. 

F-12

NOTE 2 – ACQUISITION OF TCHEFUNCTE NATURAL RESOURCES, LLC.

On July 22, 2011, the Company acquired 100% of the membership interests in Tchefuncte Natural Resources, LLC (“TNR”), and TNR became a wholly-owned subsidiary of the Company. Assets acquired comprise five oil and gas fields in Plaquemines and Lafourche Parishes in Louisiana. In exchange for their members’ interests, the selling members of TNR received an aggregate of 21.2 million shares of the Company’s common stock valued at $2,968,000 based on the closing price of the Company’s common stock on July 22, 2011, as follows:

a) in exchange for all of the issued and outstanding members’ interests of TNR (20 million shares),

b) for the retirement of notes payable in the amount of $150,000 (1.2 million shares).

The selling members retained an overriding royalty interest on each lease owned by TNR equal to the difference between a 75% net revenue interest (“NRI”) (on an 8/8ths basis) and the current NRI, not to exceed 3%.

Immediately prior to the acquisition of TNR, on July 22, 2011, TNR completed the acquisition of properties in four fields in south Louisiana (the “Samson Properties”) from Samson Contour Energy E&P, LLC (“Samson”) for a total purchase price, net of post-closing adjustments, of $4,936,231. TNR used net cash of $5,371,525 from MEI’s Loan Agreement with F&M Bank & Trust Company and $300,000 provided by the selling members of TNR and Mesa’s CEO to fund the initial purchase price for the Samson Properties of $5,071,525 and to fund $600,000, representing a portion of the obligations for the Site Specific Trust Accounts (“SSTAs”), for asset retirement liability on wells owned and operated by Samson. TNR received a post-closing payment from Samson of $735,294 for adjustments to the purchase price resulting in a net purchase price of $4,936,231.

In addition, on July 26, 2011, the selling members agreed to continue to provide personal guarantees on the notes for the boat and camp (see Note 5 –Debt) in exchange for an additional 30,000 shares of the Company’s common stock valued at $4,650 based on the closing price of the Company’s common stock on July 26, 2011.

The acquisition price of TNR, including the Samson Properties acquired by TNR, 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	$	562,157
Receivables		2,010,088
Other current assets		16,890
Total current assets		2,589,135
Oil and gas properties		9,275,472
Properties and equipment		28,368
Deposit on asset retirement obligations		600,000
Total assets acquired		12,492,975
Liabilities assumed:
Accounts payable and accrued liabilities		751,969
Notes payable		139,321
Asset retirement obligations		3,262,160
Total liabilities assumed		4,153,450
Net assets acquired	$	8,339,525
Consideration paid:
Common stock issued valued at $0.14 per share		2,968,000
Note payable – F&M Bank		5,371,525
Total consideration paid	$	8,339,525

F-13

The following unaudited pro forma information assumes the acquisition of TNR occurred as of January 1, 2011. 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.  Pro forma information for 2012 is not included, as the Company benefitted the entire year from the acquisition.

	Year ended December 31,
	2011
Revenues	$	12,794,679
Net income	$	7,277,898
Net income per common share – basic	$	0.10
Net income per common share – diluted	$	0.09
Weighted average common shares outstanding – basic		73,227,133
Weighted average common shares outstanding – diluted		79,638,098

NOTE 3 – COMMODITY DERIVATIVE INSTRUMENTS

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

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

The Company has commodity derivative instruments with a single counterparty for which it determined the fair value using period-end closing oil and gas prices, interest rates and volatility factors for the periods under each contract as of December 31, 2012 and 2011.

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

Costless Gas Collars

		Weighted
		Average
Production Period	Total Volumes	Floor/Ceiling				Fair Value
Jan 2013-Dec 2013 (1)	230,000 MMBtu	$	2.50	/	4.50	$	(24,185	)

F-14

Gas Fixed Price Swaps

		Average
Production Period	Total Volume	Fixed Price		Fair Value
Jan 2013-Jul 2013 (2)	70,000 MMBtu	$	4.00	$	45,142

Oil Fixed Price Swaps

		Average
Production Period	Total Volumes	Fixed Price		Fair Value
Jan 2013-Jul 2013 (3)	18,900 Bbls	$	114.90	$	161,311

Average Price Oil Collar

		Average
Production Period	Total Volume	Floor / Ceiling				Fair Value
Jan 2013-Jun 2013 (4)	24,708 Bbls	$	80	/	100	$	(23,017	)
Jul 2013-Dec 2013	40,908 Bbls	$	80	/	100	$	(75,953	)
Jan 2014-Jul 2014	39,424 Bbls	$	80	/	100	$	(58,519	)

(1)	Costless gas collar entered into on June 26, 2012.
(2)	Fixed price swap is the remaining put of July 25, 2011 costless gas collar unwound on June 26, 2012.
(3)	Crude oil swap entered into on January 6, 2012.
(4)	Average price collar entered into on July 19, 2012.

At December 31, 2012, the Company recognized a short-term derivative asset of $206,453, a short term derivative liability of $123,155, and a long-term derivative liability of $58,519, with the change in fair value of $912,963 reflected in unrealized loss on derivative instruments. Realized gains of $440,699 from settlements of these derivatives have been reported in other income as realized gain on commodity contracts.

F-15

The details of the commodity derivatives at December 31, 2011, are summarized below:

Costless Gas Collars

		Weighted
		Average
Production Period	Total Volumes	Floor/Ceiling				Fair Value
Jan 2012-Jul 2013	217,500 MMBtu	$	4.00	/	5.75	$	155,411

Oil Fixed Price Swaps

		Average
Production Period	Total Volumes	Fixed Price		Fair Value
Jan 2012-Dec 2012	42,000 Bbls	$	114.50	$	420,578
Jan 2013-Jul 2013	18,900 Bbls	$	114.90	$	249,553

Oil Basis Swaps

Production Period	Total Volumes	Basis Price		Fair Value
Jan 2012-Sep 2012	9,000 Bbls	$	20.00	$	113,408

At December 31, 2011, the Company had recognized a short-term derivative asset of $656,413 and a long-term derivative asset of $282,537, with the change in fair value of $938,950 reflected in unrealized gain on derivative instruments. Realized gains of $137,358 from settlements of those derivatives were reported in other income as realized gain on commodity contracts.

NOTE 4 – PROPERTY AND EQUIPMENT

Oil and Gas Properties

The Company’s oil and gas properties at December 31, 2012 and 2011 are located in the United States.

F-16

The carrying values of the Company’s oil and gas properties, net of depletion, depreciation, amortization, and impairment at December 31, 2012 and 2011 were:

	December 31,
Property	2012		2011
Lake Hermitage Field	$	3,568,957	$	2,494,003
Valentine Field		1,995,406		1,668,172
Larose Field		1,435,549		1,528,908
Bay Batiste Field		1,050,390		1,035,944
Turkey Creek Field		1,791,357		—
Total	$	9,841,659	$	6,727,027

Net oil and gas properties at December 31, 2012 and 2011 were as follows:

			Exploration								Depletion,
			and								Amortization
Year	Acquisition		Development		Dry Hole			Disposition			and
Incurred	Costs		Costs		Costs			of Assets			Impairment			Total
2010 and prior	$	754,878	$	2,947,554	$	(466,066	)	$	(2,090,383	)	$	(1,145,983	)	$	—
2011		7,334,184		606,053		—			—			(1,213,210	)		6,727,027
2012		759,133		3,807,248		—			—			(1,451,749	)		3,114,632
Total	$	8,848,195	$	7,360,855	$	(466,066	)	$	(2,090,383	)	$	(3,810,942	)	$	9,841,659

The Company holds oil and gas leasehold interests in Louisiana, Oklahoma, and New York.   The Company evaluates each of its properties upon completion of drilling and assessment of reserves to determine which, if any, are subject to impairment.

During the year ended December 31, 2012, the Company plugged and abandoned two wells, the Southdown 2D in Valentine field and the LLDSB #7 in Lake Hermitage field, retiring their costs comprising, solely, asset retirement costs for the Southdown 2D well and asset retirement costs and intangible drilling costs for the LLDSB #7. Costs of the LLDSB #7 well were retired after an unsuccessful attempt to convert it to a salt water disposal well resulted in an oil spill for which the Company incurred $244,237 of environmental remediation expense in addition to the expense of plugging and abandoning the well and recognized a loss on the settlement of the asset retirement obligation of $116,394.

Additional information about our properties is below:

Lake Hermitage Field – Plaquemines Parish, Louisiana

The Company owns 100% working interests in eighteen wells in the Lake Hermitage Field, of which seven are producing, ten wells are currently shut-in pending evaluation for workover or recompletion and one well is awaiting conversion to a salt water disposal well. During the year ended December 31, 2012, the Company spent $1,546,723 on development of the Lake Hermitage field which included recompletion of four wells. During the year ended December 31, 2011, the Company spent $605,053 on development of the Lake Hermitage field. Lake Hermitage field also includes three processing facilities and tank batteries.

F-17

Valentine Field – Lafourche Parish, Louisiana

The Company owns an average 90% working interest, some of which is non-operated, in forty-one wells in the Valentine Field, of which twelve are currently producing, three are salt water disposal, and twenty-six are shut-in pending evaluation for future workover or recompletion.

During the year ended December 31, 2012, the Company spent $859,316 on development of the Valentine Field, of which $743,292 was spent on the PPCO #1 Sidetrack.  Due to technical problems with equipment, the sidetrack was abandoned in late December 2012.  We believe the sidetrack was a geological success but a mechanical failure as a significant indication of natural gas was encountered during drilling.  Costs for the sidetrack remain capitalized as the Company evaluates the feasibility of participating in a subsequent sidetracking of this well.

Larose Field – Lafourche Parish, Louisiana

Various working interests, some of which are non-operated, are owned by the Company in eight wells in the Larose Field. There are two salt water disposal wells in the field and two wells are currently shut-in pending evaluation for future workover or recompletion.  During the year ended December 31, 2012, the Company spent $149,970 to upgrade its processing facility to better enable gas lift of the M.R.Fee 852 #1 well as well as to provide excess capacity for processing of third party production.

Bay Batiste Field, Plaquemines Parish, Louisiana

The Company owns an average 61% working interest in seven wells in the Bay Batiste Field, although only one well is currently producing. There is one salt water disposal well in the field.  The other five wells are currently shut-in pending evaluation for future workover or recompletion.  During the year ended December 31, 2012, the Company spent $94,634 on the State Lease 9570 #3 well, to replace a large compressor for a smaller, more efficient compressor.

Turkey Creek Field – Garfield and Major Counties, Oklahoma

During the year ended December 31, 2012, the Company acquired leasehold interests comprising 3,745 gross/3,105 net acres in Garfield and Major Counties, Oklahoma, spending $602,377; entered into a Farmout Agreement spending $140,000 and an additional $30,000 in leasehold costs; and spudded the Thomas Unit #6H well spending $936,488 and an additional $78,846 on the Thomas #5 water disposal well. Under the terms of the Farmout Agreement we may acquire approximately 1,760 net acres of leasehold should we meet certain obligations set forth therein, the most significant of which is a requirement to drill two wells over a thirty-six month period, one of which has already been drilled.

SE Manila Village Field – Plaquemines Parish, Louisiana

The Company owns a non-operated working interest in two wells which are shut-in.

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

On August 31, 2009, we 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. In late 2009, we evaluated a number of the existing wells in order to determine the viability of the re-entry of existing wellbores for plug-back and recompletion of the wells in the Marcellus Shale. As a result of this evaluation, we selected the Reisdorf Unit #1 and the Ludwig #1 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 data that supports further development of the Marcellus in western New York. 

F-18

As of December 31, 2010, the State of New York had placed a moratorium on high volume frac stimulation in order to develop new permitting rules. The new permitting rules have not been completed and there can be no assurance when such permitting rules will be issued or what restrictions such permits might impose on producers. Accordingly, we are unable to continue with our development plans in New York for the time being. Unless the moratorium is removed and new permitting rules provide for the economic development of these properties, production on these properties will remain marginally economic.  

During the year ended December 31, 2012, there has been no change in the status of the moratorium, and the wells continue to produce on a marginally economic basis.

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,
	Lives	2012			2011
Tank batteries	7-12	$	789,043		$	646,214
Production equipment	7		1,001,943			950,000
Production facilities	7		55,544			-
Field offices	20		267,089			267,089
Crew boat	7		66,313			57,835
Construction in progress (not depreciated)	N/A		19,019			-
Asset retirement cost	7		256,363			256,363
Subtotal			2,455,314			2,177,501
Accumulated depreciation			(379,751	)		(100,724	)
Total support facilities and equipment, net		$	2,075,563		$	2,076,777

In August 2012, the Lake Hermitage field office/camp was seriously damaged by Hurricane Isaac.  The Company is in process of repairing and renovating it. Its net book value at December 31, 2012, was $109,467.  The Company recognized depreciation expense of $279,027 and $100,724 during the years ended December 31, 2012 and 2011, respectively.

Property and Equipment  

		December 31,
	Lives	2012			2011
Office equipment, computer equipment, purchased software, and leasehold improvements	3	$	203,972		$	16,388
Furniture and fixtures	10		53,346			18,300
Subtotal			257,318			34,688
Accumulated depreciation			(15,691	)		(2,854	)
Total property and equipment, net		$	241,627		$	31,834

During the year ended December 31, 2012, property and equipment increased by $222,630 compared with the year ended December 31, 2011. The increase was the result of software purchased with installment payments of $136,500; cash payments of $77,271 for office furniture and equipment and computer equipment; and cash payments of $8,859 for leasehold improvements.  The Company recognized depreciation expense of $12,838 and $2,854 during the years ended December 31, 2012 and 2011, respectively.

F-19

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.

NOTE 5 – DEBT

Convertible Promissory Notes

In 2009 and 2010, the Company commenced a series of private placements (the “PPO”) of 10% Secured Convertible Promissory Notes of the Company (the “Convertible Notes”), at a purchase price of 100% of face value, which, at the option of the respective holders, were convertible into shares of common stock at a conversion price of $0.25 per share, subject to adjustment in certain circumstances. Each of the Convertible Notes issued are due 24 months from issuance (or earlier upon certain events of default) and bear interest at 10% per annum, payable semi-annually on December 31 and June 30 in each year. Interest will be paid in shares of the common stock valued for this purpose at 90% of the volume weighted average price of the common stock for the ten trading days preceding but not including the relevant interest payment date. The Company shall have the right to redeem from time to time, upon prior notice, all or any portion of the outstanding principal amount of the Convertible Notes, without penalty, for 100% of the principal being redeemed plus accrued and unpaid interest.

The Convertible Notes contain a standard “blocker” provision so that no holder shall have the right to convert any portion of its Convertible Notes to the extent that, after giving effect to such conversion, the holder and its affiliates would beneficially own in excess of 4.99% of the number of shares of common stock outstanding immediately after giving effect to such conversion. By written notice to the Company, a holder may increase or decrease such percentage to any other percentage, provided that any such increase will not be effective until the sixty-first (61st) day after such notice is delivered and such percentage may not, in any event, exceed 9.99%. All convertible notes above are secured by the assets of the Company.

The Company determined that the Convertible Notes issued in the 2009 and 2010 Private Placements contained provisions that protect holders from declines in the Company’s stock price that could result in modification of the exercise price under the conversion feature based on a variable that is not an input to the fair value of a “fixed-for-fixed” option as defined under FASB ASC Topic No. 815–40. As a result, the exercise price is not indexed to the Company’s own stock. The fair value of the conversion feature was recognized as an embedded derivative instrument and will be measured at fair value at each reporting period. The Company measured the fair value of these instruments as of the date of issuance and recorded an initial derivative liability of $9,383,380 during the year ended December 31 2009 and $3,311,820 during the year ended December 31, 2010. The fair values of these instruments are re-measured each reporting period and a gain or loss is recorded for the change in fair value.

During the year ended December 31, 2011, convertible notes with accrued interest totaling $2,465,088 were converted into 14,646,628 common shares of the Company at $0.125 per share.  As of December 31, 2011, the balance on the convertible notes was $461,740.

During the year ended December 31, 2012, convertible notes with face values of $425,000 on the dates of settlement were converted into 3,400,000 common shares of the Company at $0.125 per share. The derivative liability of $648,072 associated with these convertible debts was eliminated to the paid in capital component of stockholders’ equity.  An additional note converted to 328,153 common shares of the company at $0.125 per share, with a face value of $41,019, contained no derivative feature.  In all, 3,728,153 shares of the Company’s common stock were issued upon conversion of notes during 2012.

F-20

The assumptions used to determine fair value of the conversions during the years ended December 31, 2012 and 2011 were:

	December 31, 2012					December 31, 2011
Common stock issuable upon conversion				3,400,000			3,400,000
Market price of common stock on measurement date	$	0.18	–	0.27		$	0.14
Conversion price				0.12		$	0.12
Conversion period in years		0.86	–	1.33			1.58
Expected volatility		157.74	–	159.16	%		163.11	%
Expected dividend yield				—	%		—	%
Risk free interest rate		0.35	–	0.56	%		0.74	%

The Company had $0 and $461,740 of convertible promissory notes outstanding at December 31, 2012 and 2011, net of unamortized debt discount of $0 and $4,279, respectively.

The fair value of the embedded derivative at December 31, 2012 and 2011 was $0 and $113,083, respectively.  For the years ended December 31, 2012 and 2011, the Company recognized losses on the convertible debt derivative of $534,989 and $113,083, respectively.

The Company determined the fair values of these derivatives using a binomial valuation model that utilizes the Cox-Ross-Rubenstein method of formulating the Black-Scholes equation for determining the theoretical value of convertible notes that contain options of the underlying common stock of the Company.  Assumptions used to determine the fair values are found below the tables representing activity for derivative instruments during the years ended December 31, 2012 and 2011 immediately below

Activities for derivative instruments during the years ended December 31, 2012 and 2011 were as follows:

	January 1, 2012 Derivative Liability		Derivative Liability for Convertible Debt Settled by Conversion			Change in Fair Value of Derivative Liability at Settlement		December 31, 2012 Derivative Liability
Derivative conversion feature	$	113,083	$	(648,072	)	$	534,989	$	—

	January 1, 2011 Derivative Liability		2011 Activity		Change in Fair Value		December 31, 2011 Derivative Liability
Derivative conversion feature	$	—	$	—	$	113,083	$	113,083

F-21

The Company’s notes payable consisted of the following at December 31, 2012 and 2011:

	December 31,
	2012			2011
Credit Facility	$	9,195,963		$	5,495,963
Term notes		90,417			132,710
Notes payable outstanding		9,286,380			5,628,673
Less:  current maturities		(90,417	)		(466,655	)
Notes payable – noncurrent	$	9,195,963		$	5,162,018

Credit Facility and Notes Payable

On July 22, 2011, MEI entered into a $25 million senior secured revolving line of credit (“Credit Facility") with F&M Bank and Trust Company (“F&M Bank”) that, under its original terms, was to mature on July 22, 2013. The interest rate is the F&M Bank Base Rate plus 1% subject to a floor of 5.75%, payable monthly. During the year ended December 31, 2012, the maturity was extended to July 22, 2014. At December 31, 2012 and 2011, the interest rate was 5.75%. A 2.00% annual fee is applicable to letters of credit drawn under the Credit Facility.

The Credit Facility provided financing for the 2011 acquisition of TNR, working capital for field enhancements, and general corporate purposes. The Credit Facility was originally subject to an initial borrowing base of $10,500,000 which was fully utilized by the Company with the completion of the acquisition of TNR. The Company obtained letters of credit in the amount of $4,704,037 that were provided to the State of Louisiana to secure asset retirement obligations associated with the properties. $5,693,106 was funded to MEI to complete the transaction, provide working capital for field enhancements and for general corporate purposes. In addition, MEI paid a $102,857 loan origination fee which is being amortized over the life of the loan. The borrowing base is subject to two scheduled redeterminations each year. Loans made under this credit facility are secured by TNR’s proved developed producing reserves (“PDP”) as well as guarantees provided by the Company, MEI, and the Company’s other wholly-owned subsidiaries. Monthly Commitment Reductions were initially set at $150,000 beginning November 22, 2011 and continuing until the first redetermination on or about April 1, 2012. At the first redetermination, the Company was relieved of its obligation to make Monthly Commitment Reductions, and its borrowing base was increased from $10,500,000 to $13,500,000.  The redetermination also lifted the Company’s obligation to make the $150,000 Monthly Commitment Reduction payments. Future principal reduction requirements, if any, will be determined concurrently with each semi-annual redetermination. In September 2012, F&M performed a second redetermination and increased the Company’s borrowing base from $13,500,000 to $14,500,000.  In addition, the term of the note was extended from July 22, 2013 to July 22, 2014.  During the year ended December 31, 2012, the Company drew an additional $4 million from its Credit Facility, resulting in a principal balance of $9,195,963, and letters of credit drawn under the facility decreased by $100,912 to $4,603,125.

At December 31, 2012 and 2011, the Company recognized interest expense on the Credit Facility of $315,628 and $137,651, respectively.  At December 31, 2012 and 2011, the Company recognized interest expense on the amortization of the deferred financing cost of $44,214 and $22,939, respectively. Unamortized deferred financing cost at December 31, 2012 and 2011 were $35,725 and $79,938, respectively.  Fees for letters of credit were $114,149 and $47,695 during the years ended December 31 2012 and 2011, respectively.

At December 31, 2012 and 2011, the Company’s borrowing base was $14,500,000 and $10,500,000, respectively.  The Company had $675,912 and $750,000 available to draw from the borrowing base of the Credit Facility as of December 31, 2012 and 2011, respectively.

The Company was in compliance with all of the debt covenants as of December 31, 2012 and 2011.

The Credit Facility requires that 50% of the projected production from the acquired properties be hedged for 24 months at $100 per barrel or above. The Company entered into various commodity derivate contracts with a single counterparty.  For more information see Note 3 – Commodity Derivative Instruments.

F-22

Boat and Camp Loans

On April 21, 2011, TNR issued a note pursuant to a Business Loan Agreement with Resource Bank for the purchase of a boat to transport work crews (“Boat Loan”). On May 18, 2011, TNR issued a note pursuant to a Multiple Indebtedness Mortgage Agreement with Resource Bank for land and building (“Land & Building Loan”) to use as a field operations facility. These notes were personally guaranteed by the former members of TNR. On July 22, 2011, the Company assumed the Boat Loan and Land & Building Loan in conjunction with the Company’s acquisition of TNR.

Terms of the Boat Loan and Land & Building Loan were as follows:

Loan	Maturity	Rate			Balance at December 31, 2012	Balance at December 31, 2011
Boat	April 21, 2014	6.50	%	$	—	$	34,155
Land & Building	May 18, 2014	6.25	%		—		98,553

During the year ended December 31, 2012, the Company paid off these notes in full.

Premium Financed Insurance Notes

During the year ended December 31, 2012, the Company entered into two notes payable with AFCO in the principal amounts of $89,631 and $68,195 for property specific insurance policies.  Both notes are for terms of less than one year and bear an interest rate of 4.39%.  At December 31, 2012, outstanding balances on these notes were $44,638 and $43,711, respectively.  The Company had no such notes at December 31, 2011.

F-23

Debt Maturities

Scheduled maturities for all long-term debt, including convertible and related party debt, are as follows at December 31, 2012:

	Maturity
Year ending December 31,	Amounts
2013	$	90,417
2014 and thereafter		9,195,963
Total	$	9,286,380

NOTE 6 – RELATED PARTY TRANSACTION

On June 14, 2011, the Company executed an agreement with Cherokee Financial Corp. (owned by the Company’s President) wherein Cherokee agreed to accept payment in common stock for the outstanding balance of principal and accrued interest on its long-term note receivable from the Company. A total of 2,249,722 shares, with a fair market value of $314,961, were issued in full payment of outstanding principal of $213,400 and accrued interest of $67,815, resulting in a loss on conversion of debt of $33,746. Also on June 14, 2011, the Company executed an agreement with Sycamore Resources, Inc. (owned by our CEO) to convert the note payable owed to Sycamore to common stock. A total of 1,904,000 shares, with a fair market value of $266,560, were issued in full payment of the outstanding principal of $238,000 owed to Sycamore Resources, Inc., resulting in a loss on conversion of debt of $28,560.

From January 2011 through June 2011, the Company received loan proceeds of $72,000 from its CEO. In July 2011, the Company made payments totaling $93,000 to its CEO as payment in full of the principal balance of all outstanding notes payable to him. Accrued interest of $3,155 was paid to the Company’s CEO on November 18, 2011. After a payment of $20,000 for accrued interest on December 30, 2011, $54,840 of accrued interest remains outstanding on a note payable to Sycamore Resources, Inc., an entity controlled by the CEO.

The Company did not have any related party transaction during 2012.

NOTE 7 – 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, 2012 and 2011.

	For the Year Ended December 31,
	2012			2011
Beginning asset retirement obligations	$	3,450,252		$	80,217
Obligations assumed from acquisition (1)		—			3,262,160
Accretion expense		196,903			112,311
Sale of properties		—			(4,436	)
Settlement of asset retirement obligations		(139,357	)		—
Ending asset retirement obligations	$	3,507,798		$	3,450,252

(1) ARO of properties acquired from TNR.

During the year ended December 31, 2012, the Company plugged and abandoned two wells, the Southdown 2D and the LLDSB #7, recognizing a loss on settlement of asset retirement obligations of $116,394. During the year ended December 31, 2011, the Company was required to provide letters of credit in the aggregate amount of $4,704,037 from its credit facility with F&M Bank supporting these obligations in addition to a $600,000 deposit placed with the State of Louisiana Department of Natural Resources, Office of Conservation.  During the year ended December 31, 2012, the Company was refunded $30,579 of the deposit in place with the State of Louisiana Department of Natural Resources, Office of Conservation, and its letter of credit requirement by the State of Louisiana was reduced by $100,912 to $4,603,125. However, the Company was required by the Oklahoma Corporation Commission to provide a $25,000 letter of credit in conjunction with our 2012 drilling activity there.  At December 31, 2012, the Company provided $4,268,125 in letters of credit.

F-24

NOTE 8 – INCOME TAXES

The components and allocation of current and noncurrent deferred income taxes/valuation allowance are:

	December 31,
Current Deferred Tax Assets/(Liabilities)	2012		2011
Imputed interest	$	6,315	$	6,321
Derivatives		32,010		(219,102	)
Net current deferred tax assets/(liabilities)	$	38,325	$	(212,781	)

	December 31,
Noncurrent Deferred Tax Assets/(Liabilities)	2012		2011
Difference in depreciation, depletion, and capitalization methods – oil and natural gas properties	$	693,710	$	574,760
Net operating losses		1,873,634		2,161,829
Share based compensation		511,306		432,710
Derivatives		—		(94,307	)
Tax credits		—		13,748
Other		47,828		—
Total noncurrent deferred tax asset	$	3,126,478	$	3,088,740
Difference in depreciation, depletion, and intangible drilling costs - oil and natural gas properties	$	668,254	$	—
Other		10,528		—
Total noncurrent deferred tax liabilities	$	678,782	$	—

The Company has US net operating loss carry forwards of approximately $5.2 million which begin to expire in 2028.

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 believes that it is more likely than not that its deferred tax asset will 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.

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, 2012 and 2011. There were no interest and penalties related to unrecognized tax positions for the years ended December 31, 2012 and 2011. The tax years subject to examination by tax jurisdictions in the United States are 2009 through 2012.

F-25

As of December 31, 2012 and 2011, the Company recorded deferred tax assets, net of deferred tax liabilities, of $2,486,021 and $2,875,959, respectively.

NOTE 9 – COMMITMENTS AND CONTINGENCIES

Contractual Obligations

The Company leases its corporate office in Dallas, Texas, as well as a field office in Covington, Louisiana, at monthly rental amounts of $4,345 and $3,851, respectively. The Dallas office lease, extended on February 28, 2012, for a term of three years, expires on June 30, 2015.  The Covington office lease was to have expired on March 31, 2013; however, on January 25, 2013, the Company and its landlord amended the lease whereby the Company elected not to exercise its option to extend the lease for an additional two years beyond April 13, 2013, but instead extended the lease for one year from April 1, 2013 through March 31, 2014, under the same terms and conditions of the lease agreement of March 16, 2011.  During the year ended December 31, 2012, the Company paid rent totaling $51,585 and $43,809 for its Dallas and Covington offices, respectively.

The Company also leases four trucks that are used in its field operations in Louisiana.  The leases for these trucks qualify as operating leases.  During the year ended December 31, 2012, the Company made total payments of $26,274 for the trucks.

During 2012, the Company’s rental expense was $125,256 for all operating leases.

During the year ended December 31, 2011, the Company leased its Covington, Louisiana office and office equipment for that office. These leases were assumed upon acquisition of TNR in July 2011. The Louisiana office has a monthly rental payment of $3,851 and was to expire in March 2013. Total 2011 rental expense also included $27,510 for its corporate offices in Dallas, TX, which was paid pursuant to a month-to-month lease.  The Company also held four trucks under leases.

During 2011, the Company’s rental expense was $202,471 for all operating leases.

Information regarding all the Company’s contractual lease obligations, at December 31, 2012, is set forth in the following table.

	Operating
	Leases
2013	$	124,928
2014		77,201
2015 and thereafter		26,070
Total	$	228,199

On August 31, 2012, the Company entered into a contract with a software vendor for an enterprise resource planning (ERP) system with terms that provide for the payment of $136,500 software license fee in monthly installments over the course of twelve months. The contract specifies twelve equal monthly payments of $11,375 beginning September 2012. The balance owed to the vendor under the contract at December 31, 2012, was $91,000.

The software license has been capitalized and will be amortized over three years beginning at such time as it has been implemented and made ready for its intended use, which will occur in January 2013.

F-26

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.

NOTE 10 – COMMON STOCK

The following table shows the Company’s common stock activities for the year ended December 31, 2012:

	Common
	Shares
	Issued
Shares issued as compensation (See Note 11) (1)		1,071,000
Shares issued to notes payable and accrued interest (See Note 5) (2)		3,728,153
Total shares issued during the year ended December 31, 2012		4,799,153

(1)	Restricted common stock with fair value of $174,346 which vested pursuant to grants awarded in 2011 to employees pursuant to our 2009 Equity Incentive Plan (671,000 shares) and an Employment Services Agreement (400,000 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.
(2)	Restricted common stock issued upon conversion of notes payable and accrued interest with fair value of $466,019 determined on date of conversion as set forth in Note 5.

The following table shows the Company’s common stock activities for the year ended December 31, 2011:

	Common
	Shares
	Issued
Shares issued for cash to related parties		320,000
Shares issued as compensation		816,967
Shares issued to vendors to settle accounts payable		1,250,000
Shares issued to convert related party debt and accrued interest		4,153,722
Shares issued to convert debt and accrued interest		10,492,906
Shares issued to induce debt conversion		1,036,000
Shares issued for acquisition of TNR		21,200,000
Shares issued to TNR sellers to continue guarantee on debt		30,000
Total shares issued during the year ended December 31, 2011		39,299,595

F-27

In June 2011, the Company issued 320,000 shares of common stock to two related parties for cash of $40,000.

During 2011, the Company issued 816,967 shares of common stock to its employees, consultants and vendors for their services. These shares were recorded at their fair value of $324,325 based on the closing price of the Company’s common stock on the grant date.

In June 2011, the Company issued 1,250,000 shares of common stock, valued at their fair value of $177,320, based on the closing price of the Company’s common stock on the grant date, to two vendors to settle the outstanding accounts payable.

During 2011, 4,153,722 and 10,492,906 shares of common stock were issued to related parties and third parties, respective, to convert notes payable and accrued interest. These shares were recorded at their fair value of $2,465,088 based on the closing price of the Company’s common stock on the grant date. To induce the debt conversion, the Company also issued 1,036,000 shares of common stock, valued at their fair value of $111,974 based on the closing price of the Company’s common stock on the grant date, to several creditors.

In July 2011, the Company issued 21,200,000 shares of common stock to acquire 100% of the membership interests in TNR and these shares were recorded at their fair value of $2,968,000 based on the closing price of the Company’s common stock on the acquisition date. The Company also issued additional 30,000 shares of common stock, valued at their fair value of $4,650, to the selling members of TNR as they agreed to continue to provide personal guarantees on the Boat and Camp Loans.

NOTE 11 – SHARE-BASED COMPENSATION

Stock Options

The Board of Directors of the Company previously adopted the 2009 Equity Incentive Plan (the “2009 Plan”), which provides for the issuance of incentive awards of up to 5,000,000 shares of common stock to officers, key employees, consultants and directors of the Company and its subsidiaries.  As of December 31, 2011, options to purchase 2,228,000 shares of our common stock had been granted; additional options to purchase 640,000 were granted during the year ended December 31, 2012.

The following table summarizes the Company’s stock option activities for the years ended December 31, 2012 and 2011: 

	Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
Outstanding at December 31, 2010		1,048,000		$	0.25	2.5 years	$	—
Issued		1,180,000			0.15
Exercised		—			—
Cancelled/Expired		—			—
Outstanding at December 31, 2011		2,228,000			0.20	3.6 years	$	—
Issued		640,000			0.18
Exercised		—			—
Cancelled/Expired/Forfeited		(21,000	)		0.17
Outstanding at December 31, 2012		2,847,000			0.19	3.0 years	$	1,630
Exercisable at December 31, 2012		2,138,000		$	0.22	3.0 years	$	751

During the year ended December 31, 2012, stock options to purchase 640,000 shares of the Company common stock were granted to the Company’s employees. These stock options have a grant date fair value of $102,487.

During the year ended December 31, 2011, stock options to purchase 1,180,000 shares of the Company common stock were granted to the Company’s employees. These stock options have a grant date fair value of $160,922.

F-28

The following tables summarize the values from and assumptions for the Black-Scholes option pricing model for stock options granted during the years ended December 31, 2012 and 2011:

	2012
Weighted average grant date fair value	$	0.19
Weighted average grant date	April 10, 2012
Weighted average risk-free interest rate		0.54	%
Expected life (in years)	4.8 years
Weighted average volatility		146.8	%
Expected dividends	$	-

	2011
Weighted average grant date fair value	$	0.15
Weighted average grant date	July 14, 2011
Weighted average risk-free interest rate		0.19	%
Expected life (in years)	5.0 years
Weighted average volatility		163.7	%
Expected dividends	$	-

Share-based compensation expense of $129,638 and $181,625 related to stock options was recognized for 2012 and 2011, respectively. As of December 31, 2012 and 2011, the Company had $61,950 and $88,801 of unrecognized share-based compensation related to stock options remaining to be amortized. No stock options were exercised during 2012 and 2011.

Restricted Stock

The following table summarizes the Company’s restricted stock activity for the years ended December 31, 2012 and 2011, including activities for awards not granted under the 2009 Plan:

	Shares
Unvested Restricted Shares at December 31, 2010		36,000
Granted		2,221,967
Vested		(316,967	)
Cancelled/Expired		—
Unvested Restricted Shares at December 31, 2011		1,941,000
Granted		200,000
Vested		(1,071,000	)
Cancelled/Forfeited		(200,000	)
Unvested Restricted Shares at December 31, 2012		870,000

During the year ended December 31, 2012, 200,000 shares of the Company restricted stock were granted to the Company’s employees. These shares have a grant date fair value of $36,000.

During the year ended December 31, 2011, 2,221,967 shares of the Company restricted stock were granted to the Company’s employees. These shares have a grant date fair value of $333,295.

These restricted stock grants have various vesting terms. The Company recognizes share-based compensation according to the vesting terms. All of the Company’s outstanding restricted stocks at December 31, 2012 will vest in 2013.

F-29

The Company had, at December 31, 2012 and 2011, respectively, $104,400 and $272,476, of unrecognized compensation expense related to outstanding restricted stock which is expected to be recognized in share-based compensation expense in the next nine months. Compensation expense related to restricted stock grants of $174,346 and $54,200 was recognized in the years ended December 31, 2012 and 2011, respectively.

Warrants

On June 15, 2012, the Company terminated a consulting agreement in consideration for which the Company issued 500,000 cashless warrants which vested immediately and are exercisable at $1 per share for a period of five years. Each warrant entitles the holder to one share of the Company’s common stock in the event of exercise.

The following table summarizes the Company’s warrant activities for the year ended December 31, 2012:

	Warrants		Exercise Price		Remaining Contractual Life	Aggregate Intrinsic Value
Outstanding at December 31, 2011		—	$	—	—		—
Granted		500,000		1.00
Exercised		—		—
Cancelled/Expired		—		—
Outstanding at December 31, 2012		500,000		1.00	4.5 years	$	—
Exercisable at December 31, 2012		500,000	$	1.00	4.5 years	$	—

The following summarizes the values from and assumptions for the Black-Scholes option pricing model for warrants issued during year ended December 31, 2012.  The Company had not issued warrants during the year ended December 31, 2011.

Grant date fair value	$	45,423
Grant date		June 26, 2012
Weighted average risk-free interest rate		0.75	%
Expected life (in years)		5
Weighted average volatility		136.27	%
Expected dividends	$	—

The Company had not issued warrants during the year ended December 31, 2011.

Share-based compensation expense of $45,423 and $0 related to the warrants was recognized during the years ended December 31, 2012 and 2011, respectively. At December 31, 2012 and 2011, the Company had no unrecognized share-based compensation related to outstanding warrants. No warrants have been exercised during 2012. 

NOTE 12 – SUBSEQUENT EVENTS

In January 2013, stock options to purchase 100,000 shares of the Company’s restricted common stock with a fair value of $14,035 were awarded to an employee pursuant to the Company’s 2009 Equity Incentive Plan.

The assumptions used to calculate the fair value of the stock options are as follows:

Exercise price	$	15
Vesting period in years (1)		2
Term of options in years		5
Expected volatility		191.05	%
Expected dividend yield		0	%
Risk free interest rate		0.76	%

(1) Vesting schedule – March 30, 2013: 10%; September 30, 2013, March 30, 2014, and September 30, 2014: 20% each; December 30, 2014: 30%.

F-30

On January 8, 2013, the Company entered into a lease agreement, commencing March 1, 2013, for a term of one year for new living quarters for our crews working in the Lake Hermitage field in Louisiana.  The Company’s Lake Hermitage Camp, the facility used to house the crews, was substantially damaged during Hurricane Isaac in August 2012.  Monthly payment under the lease agreement is $1,800, for total rent payments of $21,600 per year.  Because the leased living quarters are more conveniently located to the Company’s Lake Hermitage properties, the Company began, in 2013, to consider either the sale or leasing of our Lake Hermitage field office/camp once repairs and renovations on it have been completed.

On January 25, 2013, the Company entered into an Amendment of Lease with the Lessor of its Covington, Louisiana, field office whereby the Company elected not to exercise its option to extend the lease for an additional two years beyond April 13, 2013, but instead extended the lease for one year from April 1, 2013 through March 31, 2014, under the same terms and conditions of the lease agreement of March 16, 2011.

On January 30, 2013, the Company made a decision to abandon its development drilling of the Thomas Unit #6H (“#6”) and to defer drilling of the Thomas Unit #5 (a proposed water disposal well).  After successfully drilling, logging, pressure testing and coring the pilot hole for the #6, the Company had two directional drilling motor failures while drilling “the curve” in preparation for horizontal drilling.  As a result of those mechanical failures and a variety of other well bore issues, the Company determined that the resulting negative impact to the geometry of the curve would have resulted in the horizontal lateral being too deep and elected to abandon the well bore.  The Company is optimistic about the data gathered in the pilot hole and expects to redrill the well at an offset location on the same drilling pad at a later date.  Total costs incurred on the project through December 31, 2012, were $1,015,334. Total costs incurred for the project through abandonment were $2,577,081.  The Company evaluated this subsequent event and determined this to be a non-recognized subsequent event. The mechanical failures did not exist at December 31, 2012 but arose subsequent to the yearend; therefore, the event should not result in adjustment to the Company’s 2012 consolidated financial statements.

On March 8, 2013, the Company entered into two additional commodity derivative contracts with the same counterparty to those set forth in NOTE 3 – COMMODITY DERIVATIVE INSTRUMENTS as follows:

Costless Gas Collars

		Weighted
		Average
Production Period	Total Volumes	Floor/Ceiling				Fair Value (1)
Jan 2014-Oct 2014	130,000 MMBtu	$	3.75	/	4.25	$	(14,164	)
Nov 2014-Dec 2014	26,000 MMBtu	$	3.75	/	4.50		(7,060	)

Oil Fixed Price Swaps

		Average
Production Period	Total Volumes	Fixed Price		Fair Value (1)
Jan 2014-Dec 2014	60,000 Bbls	$	95.75	$	(200,296	)
Jan 2015-Mar 2015	11,049 Bbls	$	92.50	$	(21,775	)

(1)   Fair value date is March 8, 2013.

On the same date, the Company unwound the crude oil average price collar for the January 2014 through July 2014 settlement periods.  Volumes unwound were 39,424 barrels with a fixed price of $100 per barrel.  The Company incurred a loss of $8,144 in unwinding these positions.

F-31

On March 20, 2013, the Company’s Board of Directors approved the termination of the remaining 500,000 shares of the restricted stock grant to Rachel L. Dillard pursuant to her Employment Services Agreement of September 19, 2011, as amended on October 17, 2011, and October 1, 2012, and approved an amendment to the Company’s Employment Services Agreement with Ms. Dillard to grant stock options to purchase 500,000 shares of the Company’s restricted common stock pursuant to the March 20, 2013 amendment to her Employment Services Agreement.  The Board also approved the termination of the remaining 100,000 shares of the restricted stock grant to Rachel L. Dillard pursuant to the Company’s 2009 Equity Incentive Plan and the issuance to her of a grant of stock options to purchase 100,000 shares of the Company’s restricted common stock pursuant to the Company’s 2009 Equity Incentive Plan.  The fair value of the unvested restricted stock award terminated is $75,000. The fair value was determined by multiplying the unvested number of shares by the closing stock price on the date of grant. $72,000 of expense associated with the terminated grants remained to be recognized as of December 31, 2012.  The fair value of the stock options granted is $75,283, calculated in accordance with the assumptions set forth below, will be amortized to stock compensation expense in the first three quarters of 2013.

Exercise price	$	.131
Vesting period in years (1)		.53
Term of options in years		5
Expected volatility		180.89	%
Expected dividend yield		0	%
Risk free interest rate		0.88	%

(1) Vesting schedule – March 30, 2013: 6.67%; April 1, 2013: 33.33%; September 30, 2013: 10%; October 1, 2013: 50%.

On March 28, 2013, the Company closed (the “Closing”) the sale to Armada Oil, Inc. (“Armada”) of 100% of the issued and outstanding shares of MEI, constituting substantially all of the Company’s assets (the “Acquisition”).  MEI is now a wholly-owned subsidiary of Armada.  In connection with the consummation of the Acquisition, and immediately prior to the Closing, the Company and MEI entered into an Assignment and Assumption Agreement (the “Assignment and Assumption Agreement”), as contemplated by the Acquisition Agreement, pursuant to which the Company assigned to MEI and MEI assumed all of the Company’s assets and liabilities.

As consideration for the Acquisition, the Company received and will distribute to its stockholders 0.40 shares of Armada common stock (the “Acquisition Consideration”) for each share of the Company’s common stock that a stockholder of the Company owned as of the close of business on March 27, 2013, the business day immediately preceding the closing date of the Acquisition.  As of the Closing, and as a result of the Acquisition, each outstanding share of the common stock of the Company was converted into the right to receive the Acquisition Consideration.  In accordance with the Acquisition Agreement, after the distribution of the Acquisition Consideration, the Company will be wound up and dissolved and we will cease its corporate existence.

NOTE 13 – SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT, AND PRODUCTION ACTIVITIES (UNAUDITED)

The Company’s oil and gas properties and proved reserves are located in the United States.

F-32

Capital Costs

Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2012 and 2011 are summarized below:  

	2012			2011
Undeveloped properties not being amortized	$	759,133		$	1,145,983
Proved properties being amortized		12,893,468			7,940,237
Accumulated depreciation, depletion and impairment		(3,810,942	)		(2,359,193	)
Net capitalized costs	$	9,841,659		$	6,727,027

Acquisition, Exploration, and Development Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities for the years ended December 31, 2012 and 2011 are summarized below:

	2012		2011
Proved acreage	$	—	$	7,334,184
Undeveloped acreage		759,133		—
Development costs		3,691,975		606,053
Exploration expense		115,276		129,478
	$	4,566,384	$	8,069,715

Results of Operations

	2012 Quarter Ended
	March 31		June 30			September 30		December 31
Net revenues from production:
Sales of oil and gas production	$	4,394,812	$	3,847,090		$	3,235,366	$	3,357,901
Production Expenses:
Oil and gas operating expense		1,982,964		1,640,004			1,548,851		1,890,792
Environmental remediation expense		216,214		28,023			--		--
Exploration expenses		52,312		43,867			137,090		(117,993	)
Depreciation, depletion, and amortization		420,340		435,094			361,484		615,619
Results of operations before income tax expense:	$	1,722,982	$	1,700,102		$	1,187,941	$	969,483
Income tax expense		353,848		(821,862	)		195,850		(217,101	)
Results of operations	$	2,076,830	$	878,240		$	1,383,791	$	752,382

F-33

Results of operations for producing activities comprise all activities associated with our exploration for and production of oil and gas.  Net revenues from production include only the revenues from the production and sale of natural gas, oil, and NGLs. Gains (losses) on property dispositions represent net gains or losses on sales of oil and gas properties.  Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Exploration expenses include dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining unproved leaseholds. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion, and amortization allowances, after giving effect to permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas activities.  

Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows

Supplemental Oil and Gas Reserve and Standardized Measure Information

The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available. All of the Company’s reserves are located in the United States.

Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.

The standardized measure of discounted future net cash flows is computed by applying the average first day of the month price of oil and gas during the 12 month period before the end of the year (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.

The reserve estimates set forth below were prepared by third party engineering firms using reserve definitions and pricing requirements prescribed by the SEC. Collarini Associates (“Collarini”).  Collarini is an independent consultant, does not own any interest in the Company’s properties, and is not engaged contingent upon the value of the Company’s properties.  Collarini prepared reserves estimates for our Louisiana properties by performance methods, volumetric methods, analogy, or a combination of methods.  Performance methods generally included decline-curve analysis and material balance analysis where representative data was available.  Volumetric estimates generally included a combination of geological and engineering interpretations, while analogy methods included reserve estimates from historical performance of similar wells and reservoirs in the field or nearby fields. The data utilized were furnished to Collarini by the Company or obtained from public data sources.  Chadwick Energy Consulting, Inc. (“Chadwick”) prepared reserves estimates for our New York properties. Collarini and Chadwick are professional engineering firms specializing in the technical and financial evaluation of oil and gas assets. Chadwick’s report was conducted under the direction of Jeffrey A. Chadwick, President of Chadwick. As of the date the consolidated financial statements were issued, Jeffrey Chadwick serves as a member of the Company’s Advisory Board, which serves in an advisory capacity and is not part of the Company’s Board of Directors. Chadwick used a combination of production performance, offset analogies, seismic data and their interpretation, subsurface geologic data and core data, along with estimated future operating and development costs as provided by the Company and based upon historical costs adjusted for known future changes in operations or development plans, to estimate our reserves.

F-34

Estimated quantities of oil and natural gas reserves

The following table sets forth certain data pertaining to changes in reserve quantities of the proved, proved developed, and proved undeveloped reserves for the year ended December 31, 2012 and 2011.

	December 31,
	2012						2011
	Oil			Gas			Oil			Gas
	(Bbls)			(Mcf)			(Bbls)			(Mcf)
Total proved reserves
Beginning of year		2,200,300			7,933,297			—			122,986
Extensions and discoveries (1)		546,800			361,100			—			—
Revisions of previous estimates (2)		(494,735	)		(1,989,422	)		88,194			638,245
Purchases of minerals in place		—			—			2,164,481			7,450,645
Production		(112,165	)		(742,091	)		(52,375	)		(278,579	)
End of year proved reserves		2,140,200			5,562,884			2,200,300			7,933,297
End of year proved developed reserves		488,000			2,211,000			599,300			3,509,297
End of year proved undeveloped reserves		1,652,000			3,351,884			1,601,000			4,424,000

(1)   The 2012 extensions and discoveries were primarily related to our decision in some of our Lake Heritage proved undeveloped properties to shift activity level to a different zone development.

(2)   The 2012 revisions of previous estimates were primarily associated with our determination to increase the acreage spacing in the Lake Hermitage field to 160 acres from 80 acres which reduced the number of wells to be drilled into proved undeveloped reserves from our 2011 reserve estimate.

The standardized measure of discounted future net cash flows relating to the proved oil and gas reserves is computed using average first-day-of the-month prices for oil and gas during the 12-month periods ended December 31, 2012 and 2011 (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated related future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation of existing economic conditions.

Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of continuing operations including property acquisitions and exploration. The estimated future cash flows are then discounted using a rate of ten percent a year to reflect the estimated timing of the future cash flows.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows relating to the proved crude oil and natural gas reserves as of December 31, 2012 and 2011 is presented below.

Net cash flows at December 31,	2012			2011
Future net cash flow	$	251,927,900		$	271,969,719
Future production cost		(58,224,400	)		(56,852,360	)
Future development cost		(35,690,300	)		(55,894,900	)
Future income tax		(49,824,667	)		(50,133,525	)
Future net cash flows		108,188,533			109,088,934
10% annual discount for timing of cash flow		(42,390,895	)		(35,332,097	)
Standard measure of discounted future net cash flow relating to the proved oil and gas reserves	$	65,797,638		$	73,756,837

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The principal sources of changes in the standardized measure of the future net cash flows for each of the two years in the period ended December 31, 2012 and 2011 are:

	2012			2011
Beginning of the year	$	73,756,837		$	149,356
Sales of oil and gas produced, net of production costs		(7,468,883	)		(4,111,116	)
Net change in sales price, net of production costs		(9,105,410	)		7,408,760
Purchases of reserves in place		—			95,845,954
Extensions and discoveries net of future production and development costs		20,157,700			—
Net changes in future development costs		15,765,181			605,951
Development costs incurred during the year that reduced future development costs		(2,345,055	)		606,053
Revisions of previous quantity estimates		(32,772,963	)		4,598,979
Other		(2,921,362	)		(530,639	)
Accretion of discount		10,537,613			2,407,731
Change in income tax expense		193,980			(33,224,192	)
End of the year	$	65,797,638		$	73,756,837

F-36