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Evolution Petroleum 2014 10-K

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



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

For the fiscal year ended June 30, 2014



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

For the transition period from to

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)



Nevada (State or other jurisdiction of incorporation or organization)		41-1781991 (IRS Employer Identification No.)
2500 CityWest Blvd., Suite 1300, Houston, Texas 77042 (Address of principal executive offices and zip code)
(713) 935-0122 (Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



	Title of Each Class		Name of Each Exchange On Which Registered
	Common Stock, $0.001 par value		NYSE MKT
	8.5% Series A Cumulative Preferred Stock, $0.001 par value		NYSE MKT

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

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

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

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: ý No: o

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

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 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. ý

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



Large accelerated filer o	Accelerated filer ý	Non-accelerated filer o	Smaller reporting company o

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $12.34 on the NYSE MKT was $288,090,504.

The number of shares outstanding of the registrant's common stock, par value $0.001, as of September 10, 2014, was 32,793,414.

DOCUMENTS INCORPORATED BY REFERENCE

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TABLE OF CONTENTS

Portions of the proxy statement related to the registrant's 2014 Annual Meeting of Stockholders to be filed within 120 days of the end of the fiscal year covered by this report are incorporated by reference into Part III of this report.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES

2014 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS



		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	6
Item 1B.	Unresolved Staff Comments	14
Item 2.	Properties	14
Item 3.	Legal Proceedings	18
Item 4.	Mine Safety Disclosures	18
PART II		19
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
Item 6.	Selected Financial Data	21
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 8.	Financial Statements and Supplementary Data	33
Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	59
Item 9A.	Controls and Procedures	59
Item 9B.	Other Information	60
PART III		61
Item 10.	Directors, Executive Officers and Corporate Governance	61
Item 11.	Executive Compensation	61
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	61
Item 13.	Certain Relationships and Related Transactions, and Director Independence	61
Item 14.	Principal Accounting Fees and Services	61
PART IV		62
Item 15.	Exhibits and Financial Statement Schedules	62
	Glossary of Selected Petroleum Terms	63
	Signatures	66
	Exhibit Index	67

This Form 10-K and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words "plan," "expect," "project," "estimate," "assume," "believe," "anticipate," "intend," "budget," "forecast," "predict" and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in this Annual Report on Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.

We use the terms, "EPM," "Company," "we," "us" and "our" to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.

PART I

Item 1. Business

Note: See Glossary of Selected Petroleum Industry Terms at the back of this document - refer to Table of Contents

General

We are a petroleum company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas, onshore in the United States. We acquire known crude oil and natural gas resources and exploit them through the application of conventional and specialized technology, with the objective of increasing production, ultimate recoveries, or both. In 2013, our business was modified to include a second focus on applying our proprietary artificial lift technology for recovering incremental oil and gas from existing wells. In this document, we provide additional information about our business operations and plans for commercializing our artificial lift technology, but it is not currently a separate reportable segment of our operations.

Our petroleum operations began in September of 2003. On May 26, 2004, our predecessor, Natural Gas Systems, Inc. (Delaware, "Old NGS"), a private corporation formed in September 2003, merged into a wholly-owned subsidiary of Reality Interactive, Inc. (Nevada, "Reality"), an inactive public company, which was renamed Natural Gas Systems, Inc. The former officers and directors of Reality resigned and the officers, directors and business operations of Old NGS became the Company. Concurrently with the listing of NGS shares on the NYSE MKT (formerly the American Stock Exchange) in July 2006, NGS was renamed Evolution Petroleum Corporation. Our principal executive offices are located at 2500 City West Blvd, Suite 1300, Houston, Texas 77042, and our telephone number is (713) 935-0122. We maintain a website at www.evolutionpetroleum.com, but information contained on our website does not constitute part of this document.

Our stock is traded on the NYSE MKT under the ticker symbol "EPM". We also have preferred stock which trades under the symbol "EPM.A"

At June 30, 2014, we had eight full-time employees, not including contract personnel and outsourced service providers. Our team is broadly experienced in oil and gas operations, development, acquisitions and financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative and non-core functions.

Business Strategy

Our business strategy is to acquire known, underdeveloped oil and natural gas resources and exploit them through the application of capital, sound engineering and modern technology, including our patented artificial lift technology, to increase production, ultimate recoveries, or both. We also provide our artificial lift technology to other operators to improve recovery of long life, low decline production in otherwise mature wells.

Our principal assets include a CO₂ enhanced oil recovery project in Louisiana’s Delhi Field and our patented artificial lift technology. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders.

Delhi Field—Louisiana

Our mineral interests in the Holt Bryant Unit in the Delhi Field, located in Northeast Louisiana, are currently our most significant asset. The Unit has had a prolific production history totaling approximately 190 million bbls of oil through primary and partial secondary recovery operations since its discovery in the mid-1940s. At the time of our $2.8 million purchase in 2003, the Unit had minimal production.

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The Unit is currently producing as an EOR project utilizing CO2 flood technology following the sale of a majority of our interests to a subsidiary of Denbury Resources, Inc., the current operator, in 2006.

We own two types of interests in the Unit:


•	7.4% of overriding and mineral royalty interests that are in effect throughout the life of the project, free of all operating and capital cost burdens.

•

A 23.9% reversionary working interest with an associated 19.1% net revenue interest. The working interest reverts to us when the operator has generated $200 million of net revenue from the 100% working interest less direct operating expenses and the cost of purchased CO2. Upon reversion of the deemed payout, regardless of the operator's actual capital expenditures, we will begin bearing 23.9% of all future operating and capital expense and our net revenue interest will increase from 7.4% to an aggregate 26.5%. Our current independent reserves report dated June 30, 2014 assumes the deemed payout to occur during the fourth calendar quarter of 2014, based on information from and statements by the operator.

Our independent reservoir engineers, DeGolyer & MacNaughton, assigned the following estimated reserves net to our interests at Delhi as of June 30, 2014:


•	13.1 million bbls of proved oil equivalent reserves, with a PV-10* of $318.1 million


•	9.5 million bbls of probable** oil equivalent reserves, with a PV-10* of $135.9 million


•	3.0 million bbls of possible** oil equivalent reserves, with a PV-10* of $20.1 million

_______________________________________________________________________________


*	PV-10 of Proved reserves is a non-GAAP measure, reconciled to the Standardized Measure at "Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues" under Item 2. Properties of this Form 10-K. Probable and Possible reserves are not recognized by GAAP, and therefore the PV-10 of such reserves cannot be reconciled to a GAAP measure.

With respect to the above reserve numbers, estimates of Probable and Possible reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves but which, together with Proved reserves, are as likely as not to be recovered. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of Probable and Possible reserves are by their nature much more speculative than estimates of Proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

The operator has planned multiple phases for the installation of the CO2 flood.

Phase I began CO2 injection in November 2009. First oil production response occurred in March 2010, about three to four months earlier than expected, and production in the field increased to approximately 2,000 gross BO per day.

Implementation of Phase II, which was more than double the size of Phase I, commenced with incremental CO2 injection at the end of December 2010. First oil production response from Phase II occurred during March 2011, three or more months ahead of expectations, and field gross production increased to more than 4,000 BO per day.

Phase III was installed during calendar 2011, and was expanded twice during calendar 2011. Production subsequently increased to more than 6,000 BO per day.

Phase IV was substantially installed during the first six months of calendar 2012. Gross field production increased to more than 7,500 BO per day before the operator temporarily suspended CO2 injection in a portion of the field due to the June 2013 fluid release event described in Item 7. "Management's Discussion and Analysis".

During early calendar 2013, the operator intensified development in the previously redeveloped western side of the field based on production results and new geological mapping that included the results of seismic data acquired over the last few years. During June 2013, a well fluids release occurred at Delhi which resulted in a temporary decline in production from 7,500 BBls/day to approximately 5,700 BBls per day and an attendant near term decrease in revenue from our royalty interests in the Delhi field. The operator has taken the position that these costs can be charged to our payout account and accordingly, this action has delayed our expected working interest reversion by approximately a year. We dispute the operator's position on the treatment of these costs and have filed suit against the operator over this matter and other issues related to the original 2006 agreements.

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Since the June 2013 fluids release, the operator has delayed further development of the field and has stated its intent not to resume significant capital spending until after reversion of our working interest has occurred. We expect that development activities will resume after reversion and that two of the three remaining phases will be installed over the next few years in the eastern part of the field. A third previously planned phase, part of which lies under the town of Delhi (population approximately 3,000), is being re-evaluated by the operator. The reserves in this phase have been reclassified from proved to probable. We further expect that probable reserves associated with three smaller reservoirs within the Unit in similar formations with similar production history will be developed as an additional phase of the EOR project early in the next decade.

During fiscal 2014, we realized an average price of $102.96 per BBL based on Delhi's Louisiana Light Sweet ("LLS") crude oil pricing, a 4% premium over the $99.25 per BBL sales price we received from our Texas production. This positive LLS price differential has narrowed significantly from past years and we do not currently expect a large positive market price differential for LLS going forward.

Artificial Lift Technology (GARP®)

Our artificial lift technology registered as GARP® (Gas Assisted Rod Pump) was developed internally by one of our officers. Its design is intended to extend the life of horizontal and vertical wells with gas, oil or associated water production with the expectation of recovering an additional 10-30% of cumulative recovery at a cost of less than $10 per BOE. We received a patent on our GARP® technology on August 30, 2011, which provides U.S. patent protection for the technology through early 2028. We have further filed for a continuation in part to our patent for recent improvements in the technology.

Prior to patent issuance, we tested the GARP® technology on certain marginal producers we owned and operated in the Giddings Field. The tests were successful in demonstrating that the process works; however, these candidates were unable to prove commercial viability due to their low primary recoveries as producers.

Subsequent to receiving our patent, we entered into demonstration JV projects with two different industry operators during fiscal 2012 to prove commercial application. We further expanded our commercial tests during fiscal 2013 with two additional installations and a third in fiscal 2014. All five of these installations were successful in re-establishing commercial production. One well subsequently ceased oil production when an offset well was hydraulically fractured and the water migrated to our well bore. During fiscal 2014, we entered into a commercial agreement to install our technology on at least five wells in the Giddings Field. Three installations were completed as of the end of fiscal 2014, all three of which were successful in increasing production. One of the three installations is being terminated and our technology removed for installation in another well due to an obstruction in the well bore that prevented economic production. A fourth attempted installation was halted early in the installation process due also to an undisclosed obstruction.

We are in discussions with multiple industry operators to further expand the business to other fields during fiscal 2015. With continued success and industry acceptance, we believe GARP® could be applicable to a large number of late stage horizontal and vertical wells worldwide.

Based on the significant amount of production history, DeGolyer & MacNaughton assigned proved reserves of 172 MBOE to three GARP® installations that we operate with PV-10 of $1.7 million. Recent installations during fiscal 2014 do not yet have sufficient history to estimate expected future performance. Our fees, though based on a percentage of net profits from the wells, will not generally result in the assignment of reserves by our petroleum engineers.

Other Projects

Giddings Field—Central Texas

We began leasing activities in the Giddings Field in December 2006. In late calendar 2007, we initiated a redevelopment drilling program in the Giddings Field targeting the Austin Chalk and Georgetown formations. During fiscal 2013, we began and completed a series of transactions that monetized all of our non-GARP® producing wells and drilling locations.

We retained a 3-5% overriding royalty interest on 2,094 acres on all depths below the base of the Austin Chalk in Brazos, Burleson and Fayette Counties, Texas. We also retained overriding royalty interests of approximately 5% in 900 net acres in the Woodbine formation and a 15% back-in working interest on approximately 258 net acres in Grimes County, Texas. We do not expect to assign any reserves to these residual interests until such time as there are successful drilling results.

Lopez Field—South Texas

We acquired leases covering approximately 782 net acres in the Lopez Field in South Texas as a first effort to test the concept of redeveloping old oil fields utilizing high flow rate production. While our development activity in the Lopez Field confirmed our concept and the potential for developing material oil reserves, the time and effort required to achieve reserves

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has lowered the attractiveness of the potential. Consequently, we elected to monetize this asset during fiscal 2013 and completed such monetization in fiscal 2014.

Mississippi Lime—Kay County, Oklahoma

In 2012, we acquired a 45% interest in a joint venture with Orion Exploration, a private company based in Tulsa, OK. The joint venture is operated by Orion and engaged in the horizontal development of the Mississippi Lime reservoir in Kay County, Oklahoma. Our leasehold position is located in the eastern, more oil-prone side of the play. With the objective reservoir less than 4,000 feet in depth, the cost of drilling, fracturing and completing a horizontal well with 4,000 feet of lateral length was estimated to be $3.2 million. The joint venture currently holds approximately 6,600 acres of undeveloped leasehold. To date, we have drilled one gross salt water disposal well and reached total depth on two horizontally drilled wells in the Mississippi Lime formation, the Sneath #1-24 and the Hendrickson #1-1. While both wells produced at the fluid rates expected, the quantities of oil and gas were far less than expected. We subsequently reworked both wells to test the role of structure in production, and have since determined that this play is a structural play requiring substantial geophysical and geological work and expertise in order to be successful, as opposed to a resource play in which engineering is the primary requirement. Since such business is not within our current strategy, we elected in fiscal 2013 to reduce our joint venture interest in undeveloped leases to 33.9%, resulting in a $1.2 million reduction in both our net property and accounts payable. We currently plan to divest of our remaining assets in this venture. Based on our drilling results and divestiture plans, we are no longer carrying any probable reserves for this asset.

Markets and Customers

We market our production to third parties in a manner consistent with industry practices. In the U.S. market where we operate, crude oil and natural gas liquids are readily transportable and marketable. We do not currently market our share of crude oil production from Delhi. Although we have the right to take our current interests in-kind, we are currently accepting terms under the Delhi operator's agreement with Plains Marketing LP for the delivery and pricing of our oil there. The oil from Delhi is currently transported from the field by pipeline, which results in better net pricing than the alternative of transportation by truck.

In January of 2008, we began selling crude oil from our Giddings properties (which includes our GARP® wells) to Enterprise Crude Oil LLC, a crude oil gathering, transportation, storage and marketing company. Our agreements with Enterprise Crude Oil LLC are under a normal "evergreen" sales contracts with a thirty day cancellation provision. In June 2014, we began selling crude oil from our Giddings properties to Sunoco Partners. Oil production from our Lopez Field was sold to Flint Hill Resources. We believe that other crude oil purchasers are readily available.

We sell our natural gas and natural gas liquids from our properties in the Giddings Field under the terms of normal evergreen sales contracts at competitive prices with DCP Midstream, LP, and ETC Texas Pipeline, LTD. Gas sold to DCP and ETC is processed for removal of natural gas liquids, and we receive the proceeds from the sale of the NGL products less a fee and certain operating expenses. We have no other business relationships with our crude oil, natural gas or natural gas liquids purchasers.

The following table sets forth purchasers of our oil and natural gas production for the years indicated:



	Year Ended June 30,
Customer	2014		2013		2012
Plains Marketing LP (includes Delhi production)	96	%	90	%	84	%
Enterprise Crude Oil LLC	2	%	4	%	7	%
Flint Hills Resources	1	%	2	%	1	%
ETC Texas Pipeline, Ltd.	1	%	—	%	3	%
All others	—	%	4	%	5	%
Total	100	%	100	%	100	%

The loss of any single purchaser (which we believe could readily be replaced) would not be expected to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition in the market for our oil and natural gas production, which in turn could negatively impact the prices we receive. Additionally, if Delhi production were unable to be transported from the field by pipeline, our pricing and potentially our near term production levels could be adversely affected.

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Market Conditions

Marketing of crude oil, natural gas, and natural gas liquids is influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, market prices, government regulation and actions of major foreign producers.

Over the past 25 years, crude oil price fluctuations have been extremely volatile, with crude oil prices varying from less than $10 to in excess of $140 per barrel. Worldwide factors such as geopolitical, macroeconomic, supply and demand, refining capacity, petrochemical production and derivatives trading, among others, influence prices for crude oil. Local factors also influence prices for crude oil and include increasing or decreasing production trends, quality differences, regulation and transportation issues unique to certain producing regions and reservoirs. In particular, the price we received for our Delhi oil materially exceeded the price we received for our Texas oil production beginning in the second half of fiscal 2011. This positive price differential narrowed significantly during the past year and we do not currently expect a large positive price differential going forward.

Also over the past 25 years, domestic natural gas prices have been extremely volatile, ranging from $1 to $15 per MMBTU. The spot market for natural gas, changes in supply and demand, derivatives trading, pipeline availability, BTU content of the natural gas and weather patterns, among others, cause natural gas prices to be subject to significant fluctuations. Due to the practical difficulties in transporting natural gas, local and regional factors tend to influence product prices more for natural gas than for crude oil.

Competition

The oil and natural gas industry is highly competitive for prospects, acreage and capital. Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. Competitors are national, regional or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are expertise in given geographical and geological areas and the abilities to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves and obtain affordable capital.

Government Regulation

Numerous federal and state laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for noncompliance. To the best of our knowledge, we are in compliance with all laws and regulations applicable to our operations and we believe that continued compliance with existing requirements will not have a material adverse impact on us. The future annual capital cost of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable. However, we do not currently anticipate that future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.

See "Government regulation and liability for environmental matters that may adversely affect our business and results of operations" under Item 1A. Risk Factors of this Form 10-K, for additional information regarding government regulation.

Insurance

We maintain insurance on our operated properties and operations for risks and in amounts customary in the industry. Such insurance includes general liability, excess liability, control of well, operators extra expense, casualty, fraud and directors & officer's liability coverage. Not all losses are insured, and we retain certain risks of loss through deductibles, limits and self-retentions. Furthermore, we are unable to insure against risks associated with our reversionary working interest until such reversion occurs. We do not carry lost profits coverage and we do not have coverage for consequential damages.

Additional Information

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.evolutionpetroleum.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 2500 City West Blvd, Suite 1300, Houston, Texas 77042, or calling (713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a

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website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

Item 1A. Risk Factors

Risks relating to the Company

Our revenues are concentrated in one asset and declines in production or other events beyond our control could have a material adverse effect on our results of operations.

Over 95% of our revenues come from our royalty interests in the Delhi field in Louisiana and our future revenues will be further concentrated in that field upon reversion of our working interest there, currently expected to occur during the fourth quarter of calendar year 2014. Any significant downturn in production, oil and gas prices, or other events beyond our control which impact the Delhi field could have a material adverse effect on our results of operations. We are not the operator of the Delhi property, and our revenues and future growth are heavily dependent on the success of operations which we do not control. In June 2013, a fluids release from one or more previously plugged wells occurred at the Delhi field that resulted in a significant temporary downturn in the daily oil production at the Delhi field, which has impacted the revenues received from our royalty interest and has delayed the reversion date of our working interest. In addition, the event has prompted the operator to pursue a more conservative development plan for the balance of the field that projects a lower peak production rate occurring at a later date, offset by a lower rate of decline.

Operating results from oil and natural gas production may decline; we may be unable to acquire and develop the additional oil and natural gas reserves that are required in order to sustain our business operations.

In general, the volumes of production from crude oil and natural gas properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we acquire properties containing proved reserves or conduct successful development activities, or both, our proved reserves will decline. In the near term, our production is heavily dependent on our 7.4% of royalty interests and the pending reversion to us of a 23.9% working interest in EOR production that began during March 2010 in the Delhi Field. In addition, our production will be impacted by the results of wells in which we have installed our GARP® technology and any future installations in which we are compensated with production or its equivalent. Although EOR production from proved reserves at Delhi has and is expected to grow over time and we expect to grow the number of GARP® installations, environmental or operating problems or lack of future investment at Delhi, lack of success in adding GARP® installations or a change in our GARP® compensation model without further development activities in new or existing projects or without acquisitions of producing properties, our net production of oil and natural gas could decline significantly over time, which could have a material adverse effect on our financial condition.

We have limited control over the activities on properties we do not operate.

Some of our properties, including our Delhi interests, are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Operators of these properties may act in ways that are not in our best interest. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production and materially and adversely affect our financial conditions and results of operations.

The types of resources we focus on have substantial operational risks.

Our business plan focuses on the acquisition and development of known resources in partially depleted reservoirs, naturally fractured or low permeability reservoirs, or relatively shallow reservoirs. Shallower reservoirs usually have lower pressure, which translates into fewer natural gas volumes in place. Low permeability reservoirs require more wells and substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient undepleted fractures to establish commercial production. Depleted reservoirs require successful application of newer technology to unlock incremental reserves.

Our CO2-EOR project in the Delhi Field, operated by a subsidiary of Denbury Resources Inc., requires significant amounts of CO2 reserves, development capital and technical expertise, the sources of which to date have been committed by the operator. Although initial CO2 injection began at Delhi in November 2009, initial oil production response began in March 2010 and a large part of the capital budget has already been expended, substantial capital remains to be invested to fully develop the EOR project and further increase production. The operator's failure to manage these and other technical, environmental, operating, strategic, financial and logistical risks may cause ultimate enhanced recoveries from the planned

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CO2-EOR project to fall short of our expectations in volume and/or timing. Such occurrences would have a material adverse effect on the Company and its results of operations.

The existing well bores in which we are installing GARP® were originally drilled years or decades earlier. As such, they contain older casing or debris that could be more subject to failure, or the well files, if available, may be incomplete or incorrect. Such problems can result in the complete loss of a well or much higher costs. Expected results are based on theoretical estimates using historical data, which may not be complete or accurate, and thus such estimates may not prove accurate. Terms of compensation for installing GARP® may well change over time based on results achieved, industry acceptance, marketing efforts and other factors.

Our projects generally require that we acquire new leases in and around established fields or other known resources, and drill and complete wells, some of which may be horizontal, as well as negotiate the purchase of existing well bores and production equipment or install our proprietary artificial lift technology that has yet to be universally proven. Leases may not be available and required oil field services may not be obtainable on the desired schedule or at the expected costs. While the projected drilling results may be considered to be low to moderate in risk, there is no assurance as to what productive results may be obtained, if any.

Crude oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production and drilling and completing new wells are speculative activities and involve numerous risks and substantial uncertain costs.

Our growth will be materially dependent upon the success of our future development program. Drilling for crude oil and natural gas and re-working existing wells involve numerous risks, including the risk that no commercially productive crude oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:


•	unexpected drilling conditions;


•	pressure fluctuations or irregularities in formations;


•	equipment failures or accidents;


•	environmental events;


•	inability to obtain or maintain leases on economic terms, where applicable;


•	adverse weather conditions;


•	compliance with governmental requirements; and


•	shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.

Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion techniques such as hydraulic fracturing, horizontal drilling or CO2 injection or other injectants do not guarantee that we will find and produce crude oil and/or natural gas in our wells in economic quantities. Our future drilling activities may not be successful and, if unsuccessful, such failure would have an adverse effect on our future results of operations and financial condition. We cannot assure you that our overall drilling success rate or our drilling success rate for activities within a particular geographic area will not decline.

We may also identify and develop prospects through a number of methods, some of which do not include horizontal drilling, hydraulic fracturing or tertiary injectants, and some of which may be unproven. The drilling and results for these prospects may be particularly uncertain. We cannot assure you that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive crude oil or natural gas.

The loss of a large single purchaser of our oil and natural gas could reduce the competition of our production.

For the year ended June 30, 2014, seven purchasers accounted for all of our oil and natural gas revenues, with one purchaser accounting for over 95% of our sales. The loss of a large single purchaser for our oil and natural gas production could negatively impact the revenue we receive.

Our patented GARP® technology may not achieve acceptance or widespread adoption by industry.

We have developed, field tested and initiated commercialization of our artificial lift technology, GARP® (Gas Assisted Rod Pump), though it may not generate substantial value. Our further success in commercializing the technology will depend upon additional positive field tests, additional customers, acceptance by industry and our ability to defend the technology from competitors through confidentiality, trade secret and patent protection.

We may be unable to continue licensing from third parties the technologies that we use in our business operations.

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As is customary in the crude oil and natural gas industry, we utilize a variety of widely available technologies in the crude oil and natural gas development and drilling process. We do not have any patents or copyrights for the technology we currently utilize, except for the registered trademark and issued patent on our GARP® artificial lift technology that is in the process of commercialization. We generally license or purchase services from the holders of such technology, or outsource the technology integral to our business from third parties. Our commercial success will depend in part on these sources of technology and assumes that such sources will not infringe on the proprietary rights of others. We cannot be certain whether any third-party patents will require us to utilize or develop alternative technology or to alter our business plan, obtain additional licenses, or cease activities that infringe on third-parties' intellectual property rights. Our inability to acquire any third-party licenses, or to integrate the related third-party products into our business plan, could result in delays in development unless and until equivalent products can be identified, licensed, and integrated. Existing or future licenses may not continue to be available to us on commercially reasonable terms or at all. Litigation, which could result in substantial cost to us, may be necessary to enforce any patents licensed to us or to determine the scope and validity of third-party obligations or to protect our patent rights on GARP®.

Our crude oil and natural gas reserves are only estimates and may prove to be inaccurate.

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. Our reserves are only estimates that may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors, such as historical production from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas product prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from prepared by different engineers or by the same engineers but at different times, may vary substantially.

Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the crude oil and natural gas industry in general. PV-10 does not necessarily correspond to market value.

Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.

We review on a periodic basis the carrying value of our crude oil and natural gas properties under the applicable rules of the various regulatory agencies, including the SEC. Under the full cost method of accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this "ceiling" test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write down of the carrying value for accounting purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our crude oil and natural gas properties when crude oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will depend in part on the prices for crude oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period. If a write down is required, it would result in a current charge to our earnings but would not impact our current cash flow from operating activities.

Crude oil and natural gas prices are highly volatile in general and low prices will negatively affect our financial results.

Our revenues, operating results, profitability, cash flow, future rate of growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of crude oil and natural gas. Lower crude oil and natural gas prices also may reduce the amount of crude oil and natural gas that we can produce economically. Historically, the markets for crude oil and natural gas have been very volatile, and such markets are likely to continue to be volatile in the future. Prices for crude oil and natural gas are subject to wide fluctuation in response to

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relatively minor changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, including:


•	worldwide and domestic supplies of crude oil, natural gas and NGLs;


•	the level of consumer product demand;


•	weather conditions;


•	domestic and foreign governmental regulations;


•	the price and availability of alternative fuels;


•	political instability or armed conflict in oil-producing regions;


•	the price and level of foreign imports; and


•	overall domestic and global economic conditions.

It is extremely difficult to predict future crude oil and natural gas price movements with any certainty. Declines in crude oil and natural gas prices may materially adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Further, crude oil and natural gas prices do not move in tandem. Because approximately 79% of our proved reserves at June 30, 2014 are crude oil reserves and 17% are natural gas liquids reserves, we are heavily impacted by movements in crude oil prices, which also influence natural gas liquids prices. To the extent that we have not hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas prices may adversely affect our financial position.

We may have difficulty managing future growth and the related demands on our resources and may have difficulty in achieving future growth.

Although we hope to experience growth through acquisitions and development activity, any such growth may place a significant strain on our financial, technical, operational and administrative resources. Our ability to grow will depend upon a number of factors, including:


•	our ability to identify and acquire new development or acquisition projects;


•	our ability to develop existing properties;


•	our ability to continue to retain and attract skilled personnel;


•	the results of our development program and acquisition efforts;


•	the success of our technologies;


•	hydrocarbon prices;


•	drilling, completion and equipment prices;


•	our ability to successfully integrate new properties;


•	our access to capital; and


•	the Delhi Field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome, secure all of the development capital necessary to fund its and our cost interests and (ii) to successfully manage technical, operating, environmental, strategic and logistical development and operating risks, among other things.

We cannot assure you that we will be able to successfully grow or manage any such growth.

Our operations require significant amounts of capital and additional financing may be necessary in order for us to continue our exploration activities, including meeting potential future drilling obligations.

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and gas acquisitions, exploitation and development activities. Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production is established. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available to us on favorable terms.

Government regulation and liability for environmental matters may adversely affect our business and results of operations.

Crude oil and natural gas operations are subject to extensive federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are federal,

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state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of crude oil and natural gas, by-products thereof and other substances and materials produced or used in connection with crude oil and natural gas operations. In addition, we may inherit liability for environmental damages, whether actual or not, caused by previous owners of property we purchase or lease or nearby properties. As a result, we may incur substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us, such as diminishing the demand for our products through legislative enactment of proposed new penalties, fines and/or taxes on carbon that could have the effect of raising prices to the end user.

For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:

•

Taxes. President Obama's Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted , make significant changes to U.S. tax laws. These changes include, but are not limited to (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for certain domestic production activities, (iii) an extension of the amortization period for certain geological and geophysical expenditures, and (iv) the repeal of the percentage depletion allowance for oil and natural gas properties; and

•

Hydraulic Fracturing. The U.S. Congress, the EPA and various states are currently considering legislation that could adversely affect the use of the hydraulic-fracturing process. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. Any proposed legislation, if adopted, could establish an additional level of regulation, permitting and restrictions at the federal level that could adversely affect the development of unconventional oil and natural gas resources.

Our insurance may not protect us against all of the operating risks to which our business is exposed.

The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, hurricanes, flooding, pollution, releases of toxic gas and other environmental hazards and risks, which can result in (i) damage to or destruction of wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or (v) damage to property, the environment or natural resources. While we carry general liability, control of well, and operator's extra expense coverage typical in our industry, we are not fully insured against all risks incident to our business. Environmental events similar to that experienced in the Delhi Field in June 2013 could defer revenue, postpone the payout of our reversionary working interest or increase operating costs and maintenance capital expenditures. Due to their characteristics, we have been unable to insure our reversionary working interest and royalty interests against operating risks of the type experienced in June 2013.

The loss of key personnel could adversely affect us.

We depend to a large extent on the services of certain key management personnel, including our executive officers, the loss of any of whom could have a material adverse effect on our operations. In particular, our future success is dependent upon Robert S. Herlin, our Chairman and Chief Executive Officer, Randall D. Keys, our President, Chief Financial Officer and Treasurer, and Daryl V. Mazzanti, our Vice President of Operations, for sourcing, evaluating and closing deals, capital raising, and oversight of development and operations. Presently, the Company is not a beneficiary of any key man insurance.

Oil field service and materials' prices may increase, and the availability of such services and materials may be inadequate to meet our needs.

Our business plan to develop or redevelop crude oil and natural gas resources requires third party oilfield service vendors and various material providers, which we do not control. We also rely on third-party carriers for the transportation and distribution of our production. As our production increases, so does our need for such services and materials. Generally, we do not have long-term agreements with our service and materials providers. Accordingly, there is a risk that any of our service providers could discontinue servicing our crude oil and natural gas fields for any reason or we may not be able to source the materials we need. Any delay in locating, establishing relationships, and training our sources could result in production shortages and maintenance problems, with a resulting loss of revenue to us. In addition, if costs for such services and materials increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may have assumed when deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelop plans.

We cannot market the crude oil and natural gas that we produce without the assistance of third parties.

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The marketability of the crude oil and natural gas that we produce depends upon the proximity of our reserves to, and the capacity of, facilities and third-party services, including crude oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities necessary to make the products marketable for end use. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in or delay or discontinuance could adversely affect our financial condition.

We face strong competition from larger oil and gas companies.

Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. We may not be able to successfully conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive crude oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment and acquiring the existing and changing technologies that we believe are and will be increasingly important to attaining success in our industry.

We are, and in the future may become, involved in legal proceedings related to our Delhi interest or other properties or operations and, as a result, may incur substantial costs in connection with those proceedings.

On August 23, 2012, we, and our wholly owned subsidiary NGS Sub Corp and Robert S. Herlin, our President, were served with a lawsuit filed in federal court by James H. and Kristy S. Jones. The plaintiffs allege primarily that the defendants wrongfully purchased the plaintiffs' 0.048119 overriding royalty interest in the Delhi Unit in January 2006 by failing to divulge the existence of an alleged previous agreement to develop the Delhi Field for EOR. Although we believe that the claims are without merit and not timely, and intend to vigorously defend against the claims, an adverse resolution of this proceeding could subject us to significant monetary damages and other penalties, which could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

In December 2013 we filed a lawsuit against the operator of the Delhi Field alleging that the operator improperly charged the payout account for capital expenditures and costs of capital, failed to adhere to preferential rights to participate in acquisitions within the defined area of mutual interest, breached the promises to assume environmental liabilities and fully indemnify us from such costs, and other breaches. We are seeking declaration of the validity of the 2006 agreements and recovery of damages and attorneys’ fees. The operator subsequently filed counterclaims, including the assertion that we owed it additional revenue interests pursuant to the 2006 agreements and that the transfer of our reversionary working interest from our wholly owned subsidiary to our parent corporation and subsequently to another wholly owned subsidiary breached their preferential right to purchase. We have denied their counterclaims as being without merit and not timely. We may incur significant legal costs in this matter and the outcome is uncertain.

Ownership of our oil, gas and mineral production depends on good title to our property.

Good and clear title to our oil, gas and mineral properties is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, gas and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim which could result in a reduction or elimination of the revenue received by us from such properties.

Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.

During the last few years, concerns over inflation, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market, uncertainties with regard to European sovereign debt, and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices. If the economic recovery in the United States or abroad remains prolonged, demand for petroleum products could diminish or stagnate, which could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors', suppliers' and customers' ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition.

Risks Associated with Our Stock

Our stock price has been and may continue to be volatile.

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Our common stock is relatively thinly traded and the market price has been, and is likely to continue to be, volatile. For example, during the year prior to June 30, 2014, our stock price as traded on the NYSE MKT ranged from $13.83 to $9.92. The variance in our stock price makes it difficult to forecast with any certainty the stock price at which an investor may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as:


•	actual or anticipated variations in our results of operations;


•	naked short selling of our common stock and stock price manipulation;


•	changes or fluctuations in the commodity prices of crude oil and natural gas;


•	general conditions and trends in the crude oil and natural gas industry;


•	redemption demands on institutional funds that hold our stock; and


•	general economic, political and market conditions.

Our executive officers, directors and affiliates may be able to control the election of our directors and all other matters submitted to our stockholders for approval.

Our executive officers and directors, in the aggregate, beneficially own approximately 3.1 million shares, or approximately 10% of our beneficial common stock base. JVL Advisors LLC controls approximately 5.0 million shares or approximately 15% of our outstanding common stock. As a result, these holders could exercise significant influence over matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.

The market for our common stock is limited and may not provide adequate liquidity.

Our common stock is relatively thinly traded on the NYSE MKT. In the year prior to June 30, 2014, the actual daily trading volume in our common stock ranged from 12,700 shares of common stock to a high of 2,254,100 shares of common stock traded. On most days, this trading volume means there is limited liquidity in our shares of common stock. Selling our shares is more difficult because smaller quantities of shares are bought and sold and news media coverage about us is limited. These factors result in a limited trading market for our common stock and therefore holders of our stock may be unable to sell shares purchased, should they desire to do so.

If securities or industry analyst do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.

Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge there are four independent analysts that cover our company. The limited number of published reports by independent securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.

The issuance of additional common stock and preferred stock could dilute existing stockholders.

We currently have in place a registration statement which allows the Company to publicly issue up to $500 million of additional securities, including debt, common stock, preferred stock, and warrants. At any time we may make private offerings of our securities. The shelf registration is intended to provide greater flexibility to the company in financing growth or changing our capital structure. We are authorized to issue up to 100,000,000 shares of common stock. To the extent of such authorization, our board of directors has the ability, without seeking stockholder approval, to issue additional shares of common stock in the future for such consideration as our board may consider sufficient. The issuance of additional common stock in the future would reduce the proportionate ownership and voting power of the common stock now outstanding. We are also authorized to issue up to 5,000,000 shares of preferred stock , the rights and preferences of which may be designated in series by our board of directors, of which, at least 317,319 shares of Series A Preferred Stock are issued and outstanding as of September 10, 2014. Such designation of new series of preferred stock may be made without stockholder approval, and could create additional securities which would have dividend and liquidation preferences over the common stock now outstanding. Preferred stockholders could adversely affect the rights of holders of common stock by:


•	exercising voting, redemption and conversion rights to the detriment of the holders of common stock;

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•	receiving preferences over the holders of common stock regarding our surplus funds in the event of our dissolution, liquidation or the payment of dividends to Preferred stockholders;


•	delaying, deferring or preventing a change in control of our company; and


•	discouraging bids for our common stock.

Our Series A Preferred Stock is thinly traded and has no stated maturity date.

The shares of Series A Preferred Stock were listed for trading on the NYSE MKT under the symbol "EPM.PR.A" on July 5, 2011 and are thinly traded on the NYSE MKT. Since the securities have no stated maturity date, investors seeking liquidity will be limited to selling their shares in the secondary market. An active trading market for the shares may not develop or, even if it develops, may not last, in which case the trading price of the shares could be adversely affected and your ability to transfer your shares of Series A Preferred Stock will be limited. We have the right to redeem all shares of Series A Preferred Stock at face value at any time.

The market value of our Series A Preferred Stock could be adversely affected by various factors.

The trading price of the shares of Series A Preferred Stock may depend on many factors, including:


•	market liquidity;


•	prevailing interest rates;


•	optional redemption by us;


•	the market for similar securities;


•	general economic conditions; and


•	our financial condition, performance and prospects.

For example, higher market interest rates could cause the market price of the Series A Preferred Stock to decrease.

We could be prevented from paying dividends on our Series A Preferred Stock.

Although dividends on the Series A Preferred Stock are cumulative and arrearages will accrue until paid, preferred stockholders will only receive cash dividends on the Series A Preferred Stock if we have funds legally available for the payment of dividends and such payment is not restricted or prohibited by law, the terms of any senior shares or any documents governing our indebtedness. Our business may not generate sufficient cash flow from operations to enable us to pay dividends on the Series A Preferred Stock when payable. In addition, existing or future debt, credit facility arrangements, contractual covenants or arrangements we enter into may restrict or prevent future dividend payments. Accordingly, there is no guarantee that we will be able to pay any cash dividends on our Series A Preferred Stock.

Furthermore, in some circumstances, we may pay dividends in stock rather than cash, and our stock price may be depressed at such time.

Our Series A Preferred Stock has not been rated and will be subordinated to all of our existing and future debt.

Our Series A Preferred Stock has not been rated by any nationally recognized statistical rating organization. In addition, with respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock will be subordinated to any existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock. We may also incur additional indebtedness in the future to finance potential acquisitions or the development of new properties and the terms of the Series A Preferred Stock do not require us to obtain the approval of the holders of the Series A Preferred Stock prior to incurring additional indebtedness. As a result, our existing and future indebtedness may be subject to restrictive covenants or other provisions that may prevent or otherwise limit our ability to make dividend or liquidation payments on our Series A Preferred Stock. Upon our liquidation, our obligations to our creditors would rank senior to our Series A Preferred Stock and would be required to be paid before any payments could be made to holders of our Series A Preferred Stock.

We could be prevented from continuing to pay dividends on our Common Stock.

Our board of directors declared dividends on our common stock for the first time in November 2013 and we have paid a total of three quarterly cash dividends on our common stock. However, there is no certainty that dividends will be declared by the board of directors in the future. Any payment of cash dividends on our common stock in the future will be dependent upon the amount of funds legally available, our earnings, if any, our financial condition and business plan, restrictions contained in our Series A preferred stock and any debt instruments, contractual covenants or arrangements we may enter into, our anticipated capital requirements and other factors that our board of directors may think are relevant. Accordingly, there is no guarantee that we will be able to continue to pay any cash dividends on our common stock.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Company Location

Our corporate headquarters are located at 2500 CityWest Boulevard, Suite 1300, Houston, Texas. We entered into a sublease agreement, effective on March 1, 2007, to rent approximately 8,400 square feet of Class "A" office space in the Westchase District area in West Houston. The current monthly base rent is $13,251, having escalated from a monthly base rate of $11,507 in August 2011. The sublease expires by its term on July 1, 2016.

Oil & Gas Properties

Additional detailed information describing the types of properties we own can be found in "Business Strategy" under Item 1. Business of this Form 10-K.

Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues

The SEC sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These rules require disclosure of oil and gas proved reserves by significant geographic area, using the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.

There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.

Estimates of Probable and Possible reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves but which, together with Proved reserves, are as likely as not to be recovered. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of Probable and Possible reserves are by their nature much more speculative than estimates of Proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

Estimated future net revenues discounted at 10% or PV-10 is a financial measure that is not recognized by GAAP. We believe that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by analysts and investors in evaluating oil and natural gas companies, and that it is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. Further, analysts and investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. We also use this pre-tax measure when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled herein.

Summary of Oil & Gas Reserves for Fiscal Year Ended 2014

Our proved and probable reserves at June 30, 2014, denominated in equivalent barrels using six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio, were estimated by our independent petroleum engineer, DeGolyer and MacNaughton ("D&M"). D&M was selected for our interests in the Delhi Field due to their expertise in CO2-EOR projects and to ensure consistency with the operator who has utilized D&M for their reserves estimates in the Delhi Field. We also chose to have D&M estimate our Giddings properties in 2014 in order to simplify and consolidate our reserve reporting. D&M has significant expertise in this region as well. The scope and results of their procedures are summarized in a letter from the firm, which is included as exhibit 99.4 to this Annual Report on Form 10-K.

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The following table sets forth our estimated proved and probable reserves as of June 30, 2014. See Note 18 to the consolidated financial statements, where additional unaudited reserve information is provided. The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $100.37 per barrel of crude oil and $4.10 per MMbtu of natural gas. The price of natural gas liquids was based on the historical price received, if no historical received price is available, historical pricing in the area. Pricing differentials were applied to all properties, on an individual property basis. Quality adjustments have been applied based on actual BTU factors for each well and a shrinkage factor has been applied based on production volumes versus actual sales volumes.

June 30, 2014



Reserve Category	Oil (MBbls)		NGLs (MBbls)		Natural Gas (MMcf)		Total Reserves (MBOE)		PV-10
PROVED
Developed (60% of Proved)	7,858		32		481		7,970		$	257,954,613
Undeveloped (40% of Proved)	2,668		2,247		2,426		5,319		61,790,784
TOTAL PROVED	10,526		2,279		2,907		13,289		$	319,745,397
Product Mix	79	%	17	%	4	%	100	%
PROBABLE
Developed (43% of Probable)	4,039		—		—		4,039		$	79,823,271
Undeveloped (57% of Probable)	3,381		1,735		1,873		5,428		56,106,975
TOTAL PROBABLE	7,420		1,735		1,873		9,467		$	135,930,246
Product Mix	79	%	18	%	3	%	100	%

The following tables present a reconciliation of changes in our proved and probable reserves by major property, on the basis of equivalent MBOE quantities.

Reconciliation of Changes in Proved Reserves by Major Property



	Delhi Field		Giddings Field		Lopez Field		Oklahoma		Proved Total
Proved reserves, MBOE	MBOE		MBOE		MBOE		MBOE		MBOE
June 30, 2013	13,545.5		35.1		185.8		—		13,766.4
Production	(164.2	)	(12.0	)	(1.1	)	(0.4	)	(177.7	)
Revisions	(263.9	)	16.2		—		0.4		(247.3	)
Sales of minerals in place	—		—		(184.7	)	—		(184.7	)
Improved recovery, extensions and discoveries	—		132.8		—		—		132.8
June 30, 2014	13,117.4		172.1		—		—		13,289.5

Reconciliation of Changes in Probable Reserves by Major Property



	Delhi Field	Giddings Field	Lopez Field		Oklahoma		Probable Total
Probable reserves, MBOE	MBOE	MBOE	MBOE		MBOE		MBOE
June 30, 2013	7,412.3	—	530.8		3,281.0		11,224.1
Revisions	2,054.6	—	—		(3,281.0	)	(1,226.4	)
Sales of minerals in place	—	—	(530.8	)	—		(530.8	)
Improved recovery, extensions and discoveries	—	—	—		—		—
June 30, 2014	9,466.9	—	—		—		9,466.9

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Reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash Flows

The following table provides a reconciliation of PV-10 of our proved properties to the Standardized Measure as shown in Note 18 of the consolidated financial statements.



	For the Years Ended June 30,
	2014			2013
Estimated future net revenues	$	671,972,966		$	865,335,587
10% annual discount for estimated timing of future cash flows	352,227,569			406,373,713
Estimated future net revenues discounted at 10% (PV-10)	319,745,397			458,961,874
Estimated future income tax expenses discounted at 10%	(93,667,725		)	(151,741,175		)
Standardized Measure	$	226,077,672		$	307,220,699

The following table provides a reconciliation of PV-10 of each of our proved properties to the Standardized Measure as shown in Note 18 of the consolidated financial statements.



	For the Years Ended June 30,
	2014			2013
Delhi Field	$	318,076,654		$	455,297,781
Giddings Field	1,668,743			513,816
Lopez Field	—			3,150,277
Estimated future net revenues discounted at 10% (PV-10)	$	319,745,397		$	458,961,874
Estimated future income tax expenses discounted at 10%	(93,667,725		)	(151,741,175		)
Standardized Measure	$	226,077,672		$	307,220,699

Additional information about the properties we own can be found in Item 1. Business.

Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company's Overall Reserve Estimation Process

Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief Executive Officer and Vice President of Operations and to be in compliance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. We provide our engineering firm with property interests, production, current operating costs, current production prices and other information. This information is reviewed by our Vice President of Operations and our Chief Executive Officer to ensure accuracy and completeness of the data prior to submission to our independent engineering firm. The scope and results of our independent engineering firm's procedures, as well as their professional qualifications, are summarized in the letter included as exhibit 99.4 to this Annual Report on Form 10-K.

Proved Undeveloped Reserves

Our proved undeveloped reserves were 5,319 MBOE at June 30, 2014 with associated future development costs of approximately $41.7 million. The 1,643 MBOE increase in proved undeveloped reserves from 3,676 MBOE as of June 30, 2013 is attributable to a 1,791 MBOE increase in reserves associated with the planned Delhi gas plant, partially offset by the sale of 148 MBOE of our Lopez Field properties.

At June 30, 2014, none of our proved undeveloped reserves, which are all at Delhi, have remained undeveloped for five years from the date of initial recognition and disclosure as proved undeveloped reserves. The operator has indicated spending plans related to development of these proved undeveloped reserves over the next three to four years, including installation of a gas processing plant. According to the operator, such spending will commence after our working interest reversion occurs.

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Sales Volumes, Average Sales Prices and Average Production Costs

The following table shows the Company's sales volumes and average sales prices received for crude oil, natural gas liquids, and natural gas for the periods indicated:



	Year Ended June 30, 2014				Year Ended June 30, 2013				Year Ended June 30, 2012
Product	Volume		Price		Volume		Price		Volume		Price
Crude oil (Bbls)	169,783		$	102.84	196,379		$	105.34	151,081		$	109.53
Natural gas liquids (Bbls)	3,516		$	33.32	7,272		$	34.81	12,611		$	49.18
Natural gas (Mcf)	26,655		$	3.60	139,006		$	2.95	266,777		$	2.98
Average price per BOE*	177,742		$	99.43	226,819		$	94.13	208,156		$	86.29

Production costs	Amount		per BOE		Amount		per BOE		Amount		per BOE
Production costs, excluding ad valorem and production taxes	$	1,156,011	$	6.50	$	1,713,833	$	7.56	$	1,708,235	$	8.21
Total production costs, including ad valorem and production taxes	$	1,193,573	$	6.72	$	1,780,738	$	7.85	$	1,774,999	$	8.53

* BOE computed on units of production using a six to one conversion ratio of MCF's to barrels.

Drilling Activity

The following table sets forth our drilling activity during the past three fiscal years. During fiscal year 2014, we did not drill any new wells. During fiscal 2013, we completed 2 gross and 0.8 net wells in Kay County, Oklahoma. During fiscal 2012, we drilled and completed one gross and net well in the Lopez Field and declared dry two wells in Wagoner County, Oklahoma. One well drilled in the Lopez Field was temporarily inactive pending permitting.



	Year Ended June 30,
	2014		2013		2012
	Gross	Net	Gross	Net	Gross	Net
Productive wells drilled
Development	—	—	—	—	—	—
Exploratory	—	—	2.0	0.8	1.0	1.0
Total	—	—	2.0	0.8	1.0	1.0
Nonproductive dry wells drilled
Development	—	—	1.0	0.2	—	—
Exploratory	—	—	—	—	—	—
Total	—	—	1.0	0.2	—	—

Present Activities

As of June 30, 2014, we had completed installation of our artificial lift technology in three non-operated wells, with at least two more wells scheduled in early fiscal 2015 under our contract with a large independent operator.

For further discussion, see "Highlights for our fiscal year 2014" and "Capital Budget" under Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

Delivery Commitments

As of June 30, 2014, we had no delivery or hedging commitments.

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Productive Wells and Developed Acreage



			Gross (Net)
Area	Gross Developed Acres	Net Developed Acres	Producing Wells			Inactive Producing Wells
Giddings - GARP®	2,168	2,134	3.0	(2.9	)	1.0	(0.9	)
Giddings - Other	-	-	-	-		3.0	(3.0	)
Mississippi Lime	1,399	630	1.0	(0.5	)	3.0	(0.4	)
Total	3,567	2,764	4.0	(3.4	)	7.0	(4.3	)

Our developed acreage at June 30, 2014 totaled 2,764 net acres, of which 2,134 net acres were in the Giddings Field comprising a 100% working interest in two producing wells, 99% working interest in one well subject to a back-in reversion of 22.5%, and a 90.5% working interest in one inactive well subject to a back-in reversion of 22.5%. We also have three shut-in wells in which we have a 100% working interest, all of which were plugged and abandoned subsequent to fiscal year end. We also own mineral and overriding royalty interests aggregating 7.4% in our CO2-EOR project in the Delhi Field. We do not recognize net acres associated with our royalty interests in the EOR project at Delhi.

Undeveloped Acreage

As of June 30, 2014, we held approximately 20,279 gross and 5,522 net undeveloped acres in the Gulf Coast and Mid-Continent regions of the United States, as follows:

Undeveloped Acreage



Field/Area	Gross Acreage	Net Acreage
Kay County, Oklahoma	6,643	2,257
Delhi Field, Louisiana*	13,636	3,265
Total	20,279	5,522

_______________________________________________________________________________

Includes from the surface of the Earth to the top of the Massive Anhydride, less and except the Delhi Holt Bryant CO2 and Mengel Units. With respect to the Delhi Holt Bryant Unit, currently being redeveloped using CO2-EOR operations within this same acreage, we currently own royalty interests aggregating approximately 7.4%. Separately, we own a 23.9% reversionary working interest (19.1% net revenue interest) that will revert to us, as, if and when payout occurs, as defined. We are not the operator of the Delhi CO2-EOR project.

Our net undeveloped acreage in the Delhi Field is held by production and does not expire so long as production is maintained in the unit. Our acreage in Oklahoma is all subject to expiration in fiscal 2015, if not renewed or extended.

For more complete information regarding current year activities, including crude oil and natural gas production, refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

Item 3. Legal Proceedings

See Note 15—Commitments and Contingencies under Item 8. Financial Statements for a description of legal proceedings.

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

Common Stock

Our common stock is currently traded on the NYSE MKT under the ticker symbol "EPM".

We initiated trading of our common stock on the OTC Bulletin Board in May 2004, under the symbol "NGSY". On July 17, 2006 we qualified for trading on the American Stock Exchange. The American Stock Exchange was acquired by the NYSE Euronext (NYX) in 2008 and is now known as NYSE MKT. The following table shows, for each quarter of the fiscal years ended June 30, 2014 and 2013, the high and low sales prices for EPM as reported by the NYSE MKT.

NYSE MKT: EPM



2014:	High		Low
Fourth quarter ended June 30, 2014	$	13.15	$	9.92
Third quarter ended March 31, 2014	$	13.83	$	11.56
Second quarter ended December 31, 2013	$	12.77	$	11.01
First quarter ended September 30, 2013	$	12.59	$	10.68



2013:	High		Low
Fourth quarter ended June 30, 2013	$	11.50	$	9.60
Third quarter ended March 31, 2013	$	11.09	$	8.06
Second quarter ended December 31, 2012	$	8.40	$	7.48
First quarter ended September 30, 2012	$	8.99	$	7.70

Shares Outstanding and Holders

As of June 30, 2014, there were 32,615,646 shares of common stock issued and outstanding, held by approximately 350 holders of record.

Dividends

We we began paying cash dividends on our common stock in December 2013, at a rate of $0.10 per share. As of June 30, 2014, we had paid three quarterly dividends on our common stock. All dividends on our Series "A" Perpetual Preferred stock have been timely declared and paid. Any future determination with regard to the payment of dividends will be at the discretion of the board of directors and will be dependent upon our future earnings, financial condition, applicable dividend restrictions and capital requirements and other factors deemed relevant by the board of directors. Under our current revolving credit facility, an existing loan balance and/or letter of credit commitment would restrict our ability to pay common stock dividends.

Performance Graph

The following graph presents a comparison of the yearly percentage change in the cumulative total return on our Common Stock over the period from June 30, 2009 to June 30, 2014 with the cumulative total return of the S&P 500 Index and the SIG Oil Exploration and Production Index of publicly traded companies over the same period. The graph assumes that $100 was invested on June 30, 2009 in our common stock at the closing market price at the beginning of this period and in each of the other two indices and the reinvestment of all dividends, if any. The graph is presented in accordance with requirements of the SEC. Shareholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.

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Securities Authorized For Issuance Under Equity Compensation Plans



Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)			Weighted-average exercise price of outstanding Options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(1)
Equity compensation plans approved by security holders	178,061	(1	)	$	2.08	812,281
Equity compensation plans not approved by security holders	—			$	—	—
Total	178,061			$	2.08	812,281

_______________________________________________________________________________

(1)

As of June 30, 2014, there were 178,061 shares of common stock issuable upon exercise of outstanding stock options. The Amended and Restated 2004 Stock Plan (the "Plan") provides for the issuance of a total of 6,500,000 common shares. As of June 30, 2014, 3,767,134 common shares had been issued upon the exercise of stock options, 1,742,524 shares of restricted common stock had been issued under the Plan (of which 140,067 were unvested as of June 30, 2014) and 812,281 shares of common stock were available for future grants under the Plan.

Issuer Purchases of Equity Securities

During the fourth fiscal quarter ended June 30, 2014, the Company received shares of common stock from certain of its employees and directors which were surrendered in exchange for their payroll tax liabilities arising from vestings of restricted stock. The acquisition cost per share reflected the weighted-average market price of the Company's shares at the dates vested. Such shares were initially recorded as treasury stock, then subsequently canceled.

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Period	(a) Total Number of Shares (or Units) Purchased	(b) Average Price Paid per Share (or Units)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1, 2014 to April 30, 2014	99 shares of Common Stock	$	12.73	Not applicable	Not applicable
May 1, 2014 to May 31, 2014	none	—		—	—
June 1, 2014 to June 30, 2014	5,590 shares of Common Stock	$	11.15	Not applicable	Not applicable

Item 6. Selected Financial Data

The selected consolidated financial data, set forth below should be read in conjunction with Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" and with the consolidated financial statements and notes to those consolidated financial statements included elsewhere in this report.



	June 30,
	2014			2013			2012		2011			2010
Income Statement Data
Revenues	$	17,673,508		$	21,349,920		$	17,962,038	$	7,530,875		$	5,021,901
Artificial lift technology costs	609,221			390,238			124,703		—			—
Production costs - other properties	584,352			1,390,500			1,650,296		1,379,327			1,665,079
Depreciation, depletion, and amortization	1,228,685			1,300,207			1,136,974		563,104			1,818,110
Accretion expense	41,626			72,312			77,505		59,913			61,054
General and administrative expense	8,388,291			7,495,309			6,143,286		5,335,384			5,092,243
Restructuring charges	1,293,186			—			—		—			—
Income (loss) from operations	5,528,147			10,701,354			8,829,274		193,147			(3,614,585		)
Other income (expense)	(38,836		)	(43,165		)	3,778		14,214			55,054
Income tax provision (benefit)	1,891,998			4,029,761			3,700,922		448,914			(1,171,824		)
Net income (loss) attributable to the Company	$	3,597,313		$	6,628,428		$	5,132,130	$	(241,553	)	$	(2,387,707	)
Dividends on Series A Preferred Stock	674,302			674,302			630,391		—			—
Net income (loss) attributable to common shareholders	$	2,923,011		$	5,954,126		$	4,501,739	$	(241,553	)	$	(2,387,707	)
Earnings per share:
Basic	$	0.09		$	0.21		$	0.16	$	(0.01	)	$	(0.09	)
Diluted	$	0.09		$	0.19		$	0.14	$	(0.01	)	$	(0.09	)



	June 30, 2014		June 30, 2013		June 30, 2012		June 30, 2011		June 30, 2010
Balance Sheet Data
Total current assets	$	26,304,803	$	27,436,076	$	16,769,789	$	6,357,840	$	6,229,351
Total assets	65,015,752		66,556,296		58,955,486		39,951,953		37,195,075
Total current liabilities	2,999,726		2,632,750		5,088,917		2,211,932		1,287,699
Total liabilities	13,138,230		11,720,135		12,332,698		6,487,196		5,717,882
Stockholders' equity	51,877,522		54,836,161		46,622,788		33,464,757		31,477,193
Common stock outstanding	32,615,646		28,608,969		27,882,224		27,612,916		27,061,376

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

Executive Overview

General

We are engaged primarily in the development of incremental oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional and proprietary technology. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain control of our assets for the benefit of our shareholders, including a substantial ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership of our common stock.

Our strategy is to grow the value of our Delhi asset to maximize the value realized by our shareholders while commercializing our patented GARP® artificial lift technology for recovering incremental oil and gas reserves in mature fields.

We expect to fund our fiscal 2015 capital program from working capital and net cash flows from our properties.

Highlights for our fiscal year 2014

Finances


•	We initiated a common stock dividend in fiscal 2014. We paid a total of $9.7 million in common stock dividends during the fiscal year.


•	Working capital was $23.3 million at June 30, 2014 compared to $24.8 million at the prior year end. At June 30, 2014, working capital included $24.0 million of cash.


•	We remained debt free. All of our expenditures were funded solely by working capital and we ended our fiscal year with no funded debt.

•

Stock option exercises raised $3.3 million in cash proceeds, and resulted in a tax loss carryforward of $27.6 million which can be used to offset future income tax payments. The tax benefits related to stock-based compensation will not reduce our future income tax expenses for financial reporting purposes, but will instead increase our stockholders' equity. In addition, we have percentage depletion carryforwards of $9.1 million.


•	Dividend distributions to preferred and common shareholders will be characterized as return of capital and not taxable dividends for the fiscal 2014. The loss carryforwards from stock option exercises caused a deficit in our current year tax earnings and profits, as defined, making cash dividends a return of capital to our shareholders.

Operations

•

Our fiscal 2014 net income was $2.9 million, a 51% decline from fiscal 2013 net income of $6.0 million. During fiscal 2014, we incurred pre-tax restructuring expenses and other non-recurring charges of $2.7 million in connection with our new corporate strategy, the retirement of a corporate officer and the exercise of substantially all of our outstanding stock options. We expect to see reduced corporate overhead going into fiscal 2015.

•

Total revenues were $17.7 million, a 17% decrease from $21.3 million in fiscal 2013. During fiscal 2014, we completed the divestiture of substantially all of our non-core oil and gas properties, causing a drop of $1.6 million in revenue. Our production and revenues from the Delhi Field were also down $2.3 million as a result of the June 2013 fluids release (the “June 2013 Event” discussed below).


•	Artificial lift technology revenues were $0.6 million in fiscal 2014, a 66% increase from $0.4 million in fiscal 2013.

Oil & Gas Reserves


•	Combined Delhi Proved and Probable oil equivalent volumes at June 30, 2014 increased to 22.6 MMBOE, an 8% increase over the previous year;


•	Reserves volumes in the immediate area of the June 2013 Event and within the Delhi town limits were re-categorized from Proved Reserves to Probable Reserves, due to the operator’s current forecast of deferred CO2 injection;


•	Combined Proved and Probable future net revenues remain essentially unchanged, despite a lower trailing average oil price than that used in 2013, while the combined PV‑10* of $454 million is 20% lower than the previous year, due

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primarily to a more conservative operating plan that defers a portion of forecast production into later periods and a lower peak production rate;


•	Reserve Life Index** for Proved Oil Reserves at Delhi is approximately 18 years;


•	The operator has elected to pursue a more conservative development and operating plan at Delhi, resulting in growing annual production volumes through 2022 with a projected peak rate expected to be 20% lower than forecasts from the previous year; and


•	Proved Reserves of 13.3 MMBOE are 79% oil, 17% natural gas liquids and 4% natural gas.



	Proved								Probable
	2014			2013			Change		2014			2013			Change
Reserves MMBOE	13.3			13.8			(4	)%	9.5			11.2			(15	)%
% Developed	60		%	73		%	(18	)%	43		%	32		%	34	%
Liquids %	96		%	100		%	(4	)%	97		%	80		%	21	%
PV-10* ($MM)	$	320		$	459		(30	)%	$	136		$	135		1	%

_______________________________________________________________________________

PV-10 of Proved reserves is a pre-tax non-GAAP measure. We have included a reconciliation of PV-10 to the unaudited after-tax Standardized Measure of Discounted Future Net Cash Flows, which is the most directly comparable financial measure calculated in accordance with GAAP, in Item 2. "Properties." We believe that the presentation of the non-GAAP financial measure of PV-10 provides useful and relevant information to investors because of its wide use by analysts and investors in evaluating the relative monetary significance of oil and natural gas properties, and as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. We also use this pre-tax measure when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled below. Probable and Possible reserves are not recognized by GAAP, and therefore the PV-10 of Probable and Possible reserves cannot be reconciled to a GAAP measure.

** Reserve Life Index is a relative measure of the average life of a Company’s reserves calculated as the remaining reserves divided by the current rate of production. In our calculation we have used total Proved oil reserves divided by expected oil production in the first 12 months of the reserve report, calculated on a gross basis so as not to be affected by the timing of the working interest reversion. Natural gas and NGL reserves and production were not considered material or relevant for the purpose of this calculation as they are currently undeveloped. We believe that this measure is relevant to understanding and analyzing our reserve base and is useful to investors and analysts in comparing our company to others in the industry. This measure is not an absolute measure of the expected life of our reserves, nor is it intended to convey information about any specific event or time in the future.

Projects

Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.4 of this Form 10-K.

Delhi Field EOR—Northeast Louisiana

Our reserves in the Delhi Field were impacted by the June 2013 Event, which consisted of the uncontrolled release of CO2, water, natural gas and a small amount of oil from one or more previously plugged wells in the southwest part of the Field. The operator has fully remediated the affected area, but that portion of the Field has been converted for the foreseeable future from CO2 flood to water flood. This has also prompted the operator to pursue a more conservative development plan for the balance of the field. The operational effects include:


•	Reducing reservoir pressure that will result in production over a longer period of time than previously forecast and a lower peak production rate;


•	Deferring CO2 injection in the immediate area of the June 2013 Event in favor of a water flood; and

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•	Deferring CO2 injection in the immediate area of the town of Delhi in the eastern, currently undeveloped portion of the project.

Reducing reservoir pressure by slowing the pace of CO2 injection is expected to lower and delay the projected peak oil production rate, but results in a much flatter decline curve. Deferring CO2 injection in two areas of the field has also resulted in the reclassification of related developed and undeveloped reserves from the Proved category to Probable category, primarily as a result of CO2 injections currently projected to occur beyond the SEC’s five-year limitation for Proved Reserves development projects. There is uncertainty as to when CO2 injections may be re-established or initiated in the affected areas, which may be sooner or later than currently projected.

The decline in Proved Reserves resulting from reduced injection pressure and deferred development was partially offset, in volumes, by the addition of incremental proved gas plant volumes, with forecasts of a more robust natural gas liquids (“NGL”) recovery than projected in the previous year’s estimate. The combined impacts on PV-10* of the lower peak production rate, later date of peak rate and re-categorization of reserves resulted in a decrease of our Proved PV-10* by 30% to $318 million. Due to the re-categorization, Probable volumes and related PV-10* increased 28% and 24%, respectively, to 9.5 MMBOE and $136 million, respectively. Consequently, the aggregate impact on Proved and Probable reserves was an 8% increase in combined volumes to 22.6 MMBOE and a 20% decrease in combined PV-10* to $454 million.

Possible reserves volumes at Delhi decreased by 20% to 3.0 MMBOE and PV-10* declined by 38% to $20 million, both primarily due to the incremental recovery factor being reduced from 3% to 2% of original oil in place and the projected slower production pace.

Gross production at Delhi in the fourth quarter of fiscal 2014 was 5,956 BOPD, down slightly from the third fiscal quarter’s 6,172 BOPD due primarily to normal plant maintenance during the fourth quarter and no material development capital expenditures since early calendar 2013. The reduction in production from the 7,188 BOPD rate in the fourth fiscal quarter of 2013 is primarily attributable to the June 2013 Event. In addition, the operator’s current plans are to produce the Field at a lower CO2 injection pressure, which is expected to reduce peak production rates, but extend production over a longer life.

The operator has better defined its plans to process recycled gas to recover substantially all of the natural gas liquids and methane beginning in the second half of calendar 2015. Our previous report was based on a more limited recovery of only heavier C5+ liquids. This new plan should substantially increase recovery volumes and improve the gas plant economics while simultaneously improving CO2 flood efficiency.

Looking forward, the operator has said that it will not commence material new capital expenditures until reversion of our working interest, which they expect to occur in the fourth quarter of calendar 2014. We now expect Delhi production to peak in 2021-2022. Consequently, our Delhi PV-10* is now expected to increase over time to its maximum value around the first quarter of calendar 2018, about two years later than previously forecast. At that point, we are projected to have generated approximately $120 million of net cash flow from the Field after capital expenditures.

GARP® - Artificial Lift Technology

For the first time we are separately disclosing reserves associated with wells equipped with our GARP® technology. Proved Reserves attributable to Company-operated GARP® installations completed during the past three years include 172 thousand barrels of oil equivalent (“MBOE”) of Proved Reserves with PV-10* of $1.7 million. Based on Proved Reserves and cumulative production to date only, our GARP® technology has added reserves at a cost of less than $4.00 per barrel of oil equivalent (“BOE”).

With respect to the previously announced contract to install GARP® for a third party operator, we have successfully completed installations on a total of three wells and we expect to continue installations on another two wells in the near future. Two of the three wells are producing at commercial rates which are more than double the rates prior to installation, but have not yet fully stabilized. One of the three wells, which was not producing at commercial rates prior to installation, appears to have an obstruction in the lateral or a depleted reservoir which is severely restricting fluid production. We intend to pull the GARP® equipment out of that well and use it in a future installation. We attempted installation on a fourth well, but encountered an obstruction in the horizontal section of the wellbore and abandoned the operation.

Other Fields

During the year we divested noncore properties in the South Texas Lopez Field and scheduled for divestment our Mississippi Lime properties in Oklahoma. Approximately 0.2 MMBOE of Proved Reserves and 3.8 MMBOE of Probable Reserves were associated with these assets as of June 30, 2013 and are no longer included in our year-end reserves. Consequently, all of our Probable and Possible Reserves are located in the Delhi Field.

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Liquidity and Capital Resources

At June 30, 2014, our working capital was $23.3 million compared to $24.8 million at June 30, 2013. The $1.5 million working capital decrease was due primarily to $1.2 million of lower cash and certificates of deposit and $0.4 million of increased current liabilities impacted by accruals for restructuring and an officer retirement. During our fiscal year ended June 30, 2014, we incurred oil and gas capital expenditures of $0.8 million and capital expenditures of $0.4 million for artificial lift technology equipment. Principal development activities related to GARP® wells at Giddings and expenditures on existing Mississippi Lime wells. During the year, we realized $3.3 million of proceeds from stock option and warrant exercises as well as $0.5 million of proceeds primarily from the sale of our non-core Lopez properties.

Cash Flows from Operating Activities

For the year ended June 30, 2014, cash flows provided by operating activities were $8.1 million, reflecting $7.7 million provided by operations before $0.4 million provided by other working capital changes. Of the $7.7 million provided before working capital changes, $3.6 million was due to net income and $4.1 million was attributable to non-cash expenses.

For the year ended June 30, 2013, cash flows provided by operating activities were $11.9 million, reflecting $6.6 million of net income together with $5.3 million provided by non-cash expenses, including $2.5 million from deferred income taxes, $1.5 million from stock compensation, and $1.3 million from depreciation, depletion and amortization.

Cash flows provided by operating activities for the year ended June 30, 2012 were $10.4 million, reflecting $5.2 million of net income and $5.2 million provided by noncash expenses. Working capital items were essentially unchanged from the prior year. Included in noncash expenses were $1.2 million of depreciation, depletion and amortization, $1.5 million of stock-based compensation, and $2.5 million of deferred income taxes.

Cash Flows from Investing Activities

For the year ended June 30, 2014, cash paid for oil and gas capital expenditures was $1.3 million, primarily for development activities related to GARP® wells in Giddings and continuing costs for the Sneath and Hendrickson wells drilled in the Mississippi Lime during the prior year. We received approximately $542,000 of proceeds from asset sales, including $402,500 from the December sale of our South Texas properties, and $250,000 of cash from the maturity of a certificate of deposit.

Cash paid for oil and gas capital expenditures during the year ended June 30, 2013 was $4.9 million. Of these expenditures, $0.7 million was for leasehold acquisitions, principally in the Mississippi Lime, and $4.2 million was for development activities. Development activities were predominantly in the Mississippi Lime, where one salt water disposal well and two wells were drilled. In Giddings, expenditures were centered on adding three new GARP® wells. An inflow of $3.5 million was received for proceeds from the sales of a portion of our Giddings exploration and production properties. In December 2012, an expiring $250,000 certificate of deposit was rolled over beginning a new annual term.

Cash paid for oil and gas capital expenditures during the year ended June 30, 2012 was $7.0 million. Of these expenditures, $3.7 million was for leasehold acquisitions, principally in the Mississippi Lime in Oklahoma, and $3.3 million was for development activities. Development expenditures were primarily in the Lopez Field where four wells were drilled with remaining expenditures made in the Mississippi Lime and the Giddings Field in Texas.

At June 30, 2012, we had advanced $224,206 of cash for its share of development costs to be incurred by its joint venture partner in the Mississippi Lime play and recorded a $1,142,715 advance to be paid subsequent to June 30, 2012. During the year ended June 30, 2012, we received $0.8 million for the sale of a portion of our Woodbine lease rights.

Oil and gas capital expenditures incurred, which includes accrued expenditures, were $0.9 million, $3.4 million, and $8.9 million, respectively, for the years ended June 30, 2014, 2013, and 2012. These amounts can be reconciled to cash capital expenditures on their respective cash flow statements by adjusting them for related non-cash items presented at Note 10—"Supplemental Cash Flow Information".

Cash Flows from Financing Activities

During the year ended June 30, 2014, we used $8.3 million in cash for financing activities, reflecting $9.7 million of common stock dividend payments, $0.7 million of preferred stock dividends and $1.7 million of treasury stock acquired through the surrender of shares by certain officers and employees in satisfaction of payroll liabilities related to stock-based compensation, partially offset by cash inflows of $0.5 million from a tax benefit related to stock-based compensation and $3.3 million from stock option exercises.

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During the year ended June 30, 2013, we paid preferred dividends of $0.7 million and acquired $0.1 million of treasury stock through the surrender of shares by certain officers and employees in satisfaction of payroll liabilities related to stock-based compensation, as described at Note 8—"Stockholders' Equity." A tax benefit related to stock-based compensation provided $0.8 million.

During the year ended June 30, 2012, we received $6.9 million of net proceeds from the issuance of 317,319 shares of our 8.5% Series A perpetual preferred stock after all offering costs and we paid $0.6 million of dividends thereon. We incurred deferred loan costs of $0.2 million during 2012 in connection with an unsecured revolving credit agreement, which has current availability of $5.0 million.

Capital Budget

Delhi Field

With reversion of our 23.9% working interest in Delhi expected to occur during the fourth quarter of calendar 2014, we will begin funding our share of capital expenditures in the Field. Projected capital expenditures over the next two fiscal years are currently expected to total approximately $25-27 million. This timing of this spending is dependent on the date of reversion of our working interest and the pace of project development by the operator of the Field. Of this total, approximately $15-17 million is for the gas processing plant and approximately $10 million is for the roll-out of the next phase of the CO2 project. We expect these costs to be incurred over portions of the next two fiscal years. Total spending based on proved reserves in the reserve report, net to our interest, is forecast to be approximately $45 million over the next four years, which includes the projects above plus further expansion of the CO2 flood pattern. We expect that cash flows from the our interests in the Field will be significantly in excess of the net capital expenditures required.

GARP® - Artificial Lift Technology

Our marketing and business plans for commercializing this artificial lift technology continue to evolve. During the early stages of commercializing the technology, we used it for our own account in operated wells and under farm-outs from other operators. During 2014, we entered into a risk-sharing contract under which we were responsible for funding the majority of the equipment and installation costs in exchange for fees based on the net profits from the wells. Going forward, we may continue to install the technology for our own account and under risk-sharing arrangements. However, we currently expect a greater percentage of our future revenues to result from contracts where we are paid on a fee basis, rather than under risk-sharing arrangements or in our own wells. Accordingly, we currently expect that our capital requirements for artificial lift technology operations will be relatively modest.

Liquidity Outlook

Funding for all capital expenditures is expected to be met from current working capital and cash flows from operations. Our preference is to remain debt free, but we do have access to a $5 million unsecured revolving line of credit and are in discussions to convert this line to a senior secured facility with up to $30 million of capacity. This facility is intended primarily to provide a standby source of liquidity to meet future capital expenditures at Delhi or other future capital needs or opportunities.

Payment of cash dividends on our common stock remains an important aspect of our financial strategy and it is our goal to maintain or increase our dividends. We expect that the excess cash flow from the Delhi Field, after reversion of our working interest, will permit the Board of Directors to consider prudent increases in the level of our dividend payout.

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Results of Operations

The following table sets forth certain financial information with respect to our oil and natural gas operations:



	Year Ended June 30,
	2014		2013		2012
Delhi field:
Crude oil revenues	$	16,908,666	$	19,219,036	$	15,143,770
Crude oil volumes (Bbl)	164,224		180,658		136,074
Average price per Bbl	$	102.96	$	106.38	$	111.29

Artificial lift technology:
Crude oil revenues	$	414,270	$	323,488	$	113,430
NGL revenues	115,172		16,661		15,148
Natural gas revenues	93,890		34,914		3,766
Total revenues	$	623,332	$	375,063	$	132,344

Crude oil volumes (Bbl)	4,115		3,476		1,199
NGL volumes (Bbl)	3,460		432		304
Natural gas volumes (Mcf)	26,105		10,531		1,543
Equivalent volumes (BOE)	11,927		5,664		1,760

Crude oil price per Bbl	$100.67		$93.06		$94.60
NGL price per Bbl	$33.29		$38.57		$49.83
Natural gas price per Mcf	$3.60		$3.32		$2.44
Equivalent price per BOE	$52.26		$66.22		$75.20

Artificial lift production costs	$	609,221	$	390,238	$	124,703
Production costs per BOE	51.08		68.90		70.85

Other properties:
Revenues	$	141,510	$	1,755,821	$	2,685,924
Equivalent volumes (BOE)	1,591		40,497		70,322
Equivalent price per BOE	$	88.94	$	43.36	$	38.19

Production costs	$	584,352	$	1,390,500	$	1,650,296
Production costs per BOE	$	367.29	$	34.34	$	23.47

Combined:
Oil and gas DD&A (a)	$	1,192,370	$	1,255,209	$	1,087,020
Oil and gas DD&A per BOE	$	6.71	$	5.53	$	5.22

(a) Excludes totals of depreciation of office equipment, furniture and fixtures, and amortization of other assets of $36,315 and $44,998 and $49,954 for the years ended June 30, 2014, 2013, and 2012, respectively.

Year ended June 30, 2014 compared with the Year ended June 30, 2013

Net Income Available to Common Shareholders. For the year ended June 30, 2014, we generated net income of $2.9 million or $0.09 per diluted share, (which includes a $1.3 million restructuring charge, $1.4 million of non-recurring charges related to stock option exercises and the retirement of the Company’s chief financial officer) on total oil and natural gas revenues of $17.7 million. For the year ended June 30, 2014, non-cash stock compensation expense was $1.7 million of which $203,861 related to the retirement charge. This compares to a net income of $6.0 million, or $0.19 per diluted share, (which includes $1.5 million of non-cash stock-based compensation expense) on total oil and natural gas revenues of $21.3 million for the

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corresponding year-ago period. The earnings decline is due to lower revenue, higher G&A, and a current year restructuring charge, partially offset by lower lease operating expense and income taxes. Additional details of the components of net income are explained in greater detail below.

Delhi Field. Revenue decreased 12% to $16.9 million primarily because of a 9% volume decline attributable to the June 2013 Event, together with a 3% lower price per BOE.

Artificial Lift Technology. Revenue increased 66% to $0.6 million reflecting a 110% BOE volume increase, primarily due to the new Philip well, partially offset by a 21% decrease in price per BOE primarily influenced by a higher percentage of natural gas production.

Other Properties. Revenue decreased by 92% to $0.1 million due to the prior fiscal year sales of non-core Giddings Field properties and the sale of Lopez Field properties in December 2013.

Artificial Lift Production Costs. Expenses increased 56% to $0.6 million due to the new Philip and Appelt wells.

Other Properties Production Costs. Expenses decreased 58% to $0.6 million due the prior fiscal year sales of Giddings Field properties and the December 2013 sale of our South Texas Lopez Field. We had continuing workover and testing costs on our Mississippi Lime project during 2014 which have now been terminated.

General and Administrative Expenses (“G&A”). G&A expenses, including $1.4 million of one-time charges, increased 12% to $8.4 million during the year ended June 30, 2014 from $7.5 million in the prior year. The $0.9 million increase was primarily due to approximately $672,000 of higher compensation and benefits impacted by an officer's retirement, $146,000 of higher transaction expenses, $121,000 of lower absorption to drilling projects and $90,000 in higher consulting expense, partially offset by lower stock compensation expense of $179,000. Stock-based compensation was $1.4 million (16% of total G&A) for the year ended June 30, 2014 compared to $1.5 million (21% of total G&A) for the year ended June 30, 2013.

Restructuring Charges. The Company recorded $1.3 million of restructuring expense in December 2013 primarily reflecting $956,000 of termination benefits to be paid from January to December 2014 and $376,000 of non-cash stock compensation expense for accelerated restricted stock vesting for terminated employees. See Note 5 — Restructuring.

Oil and Gas Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A decreased by 5% to $1.2 million for the year ended June 30, 2014, compared to $1.3 million for the prior year. This change was principally due to a 21% increase in depletion rate to $6.71 per BOE, partially offset by a 22% volume decrease.

Year ended June 30, 2013 compared with the Year ended June 30, 2012

Net income attributable to common shareholders. For the year ended June 30, 2013, we reported net income of $6.0 million or $0.19 income per diluted share (which includes $1.5 million of non-cash stock-based compensation expense) on total oil and natural gas revenues of $21.3 million. This compares to net income of $4.5 million, or $0.14 income per diluted share (which includes $1.5 million of non-cash stock-based compensation expense) on total oil and natural gas revenues of $18.0 million for the year ended June 30, 2012. The difference was primarily due to an increase in revenues of $3.4 million partially offset by $1.5 million of increased operating expenses. Additional details of earnings components are explained in greater detail below.

Delhi Field. Revenue increased 27% to $19.2 million because of a 33% volume increase partially offset by a 4% price per bbl decline.

Artificial Lift Technology. Revenue increased 183% to $0.4 million due to a 222% BOE volume increase, primarily due to a full year of production from the Morgan Kovar well completed during the prior fiscal year, partially offset by a 12% decrease in price per BOE impacted by an increase in the percentage of natural gas production.

Other Properties. Revenue decreased by 35% to $1.8 million for the year ended June 30, 2013 due to the December 2012 sale of Giddings Field properties.

Artificial Lift Production Costs. Expenses increased 213% to $0.4 million for fiscal 2013 reflecting a full year of operations for the Selected Lands #1 and #2 wells, which were completed in the fourth calendar quarter of 2011.

Other Properties Production Costs. Expenses decreased 16% to $1.4 million for the year ended June 30, 2013 principally due to the December 2012 sale of Giddings Field properties.

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General and Administrative Expenses ("G&A"). G&A expenses increased 22% to $7.5 million for the year ended June 30, 2013, compared to $6.1 million for the year ended June 30, 2012. The increase was due principally to $361,000 for higher bonus expense, $287,000 for higher legal expense (principally litigation), $232,000 for salaries and benefits, $124,000 for compliance costs, $87,000 for divestiture transaction fees, and $73,000 for board of director fees. Stock-based compensation was $1.5 million (21% of total G&A) and $1.4 million (24% of total G&A) for the years ended June 30, 2013 and 2012, respectively, is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and, as a result, will likely continue to be a significant component of our G&A costs.

Oil and Gas Depreciation, Depletion & Amortization Expense (“DD&A”). DD&A increased by 14% to $1.3 million for the year ended June 30, 2013, compared to $1.1 million for the prior year. The increase is primarily due to a 9% increase in volumes, and a 6% higher annual depletion rate of $5.53 per BOE. The higher depletion rate is primarily due to higher Delhi future development costs partially offset by lower future development costs due to Giddings properties divested during the current year.

Other Economic Factors

Inflation. Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services greatly impact our lease operating expenses and our capital expenditures. During fiscal 2014, we saw modest cost increases in certain oilfield services and materials compared to prior years. Product prices, operating costs and development costs may not always move in tandem.

Known Trends and Uncertainties. General worldwide economic conditions continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which impact demand for crude oil and natural gas. If demand decreases in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues and working capital going forward. In addition, our lease operating expenses and their percentage of our revenues are likely to increase as reversion of our back-in interest at Delhi or other additions to our working interest production that would dilute extraordinary margins we have enjoyed from our mineral and overriding royalty interests at Delhi.

Seasonality. Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products. Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather including hurricanes that may substantially affect oil and natural gas production and imports.

Contractual Obligations and Other Commitments

The table below provides estimates of the timing of future payments that, as of June 30, 2014, we are obligated to make under our contractual obligations and commitments. We expect to fund these contractual obligations with cash on hand and cash generated from operations.



	Payments Due by Period
	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
Contractual Obligations
Operating lease	331,273		159,011		159,011		13,251		—
Other Obligations
Asset retirement obligations	352,215		146,703		—		—		205,512
Total obligations	$	683,488	$	305,714	$	159,011	$	13,251	$	205,512

We have entered into employment agreements with two of the Company's senior executives. The employment contracts provide for severance payments in the event of termination by the Company for any reason other than cause or permanent disability, or in the event of a constructive termination, as defined. The agreements provide for the payment of base pay and certain medical and disability benefits for periods ranging form 6 months to 1 year after termination. The total contingent obligations under the employment contracts as of June 30, 2014 was approximately $591,000.

Critical Accounting Policies and Estimates

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The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets and liabilities and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates have a significant effect on our consolidated financial statements. Our significant accounting policies are included in Note 2 to the consolidated financial statements. Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our consolidated financial statements.

Oil and Natural Gas Properties. Companies engaged in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and gas industry. We apply the full cost accounting method for our oil and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 2014, we had no unevaluated properties costs.

Estimates of Proved Reserves. The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense, and the estimated future net cash flows associated with those proved reserves is the basis in determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including reservoir performance, additional development activity, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates represent the most accurate assessments possible, including the hiring of independent engineers to prepare our reserve estimates, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial statements. Material revisions to reserve estimates and / or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves, affecting our quarterly ceiling test calculation and could significantly affect our depletion rate. A 10% decrease in commodity prices used to determine our proved reserves and Standardized Measure as of June 30, 2014 would not have resulted in an impairment of our oil and natural gas properties. Holding all other factors constant, a reduction in the Company's proved reserve estimates at June 30, 2014 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $53,000, $116,000 and $186,000, respectively.

On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and gas reserves. The rule allows consideration of new technologies in evaluating reserves, generally limits the designation of proved reserves to those projects forecast to be commenced within five years of the end of the period, allows companies to disclose their probable and possible reserves to investors, requires reporting of oil and gas reserves using an average price based on the previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices, revises the disclosure requirements for oil and gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.

Valuation of Deferred Tax Assets. We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared or filed; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carry backs and carry forwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our net operating loss). If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of June 30, 2014, we have recorded a valuation allowance for the portion of our net operating loss that is limited by IRS Section 382.

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Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making the assessment of the ultimate realization of deferred tax assets. Based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible, as of end of the current fiscal year, we believe that it is more likely than not that the Company will realize the benefits of its net deferred tax assets. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would increase in the period it is determined that recovery is not probable.

Stock-based Compensation. We estimate the fair value of stock option awards on the date of grant using the Black-Scholes option pricing model. This valuation method requires the input of certain assumptions, including expected stock price volatility, expected term of the award, the expected risk-free interest rate, and the expected dividend yield of the Company's stock. The risk-free interest rate used is the U.S. Treasury yield for bonds matching the expected term of the option on the date of grant. Because of our limited trading experience of our common stock and limited exercise history of our stock option awards, estimating the volatility and expected term is very subjective. We base our estimate of our expected future volatility on peer companies whose common stock has been trading longer than ours, along with our own limited trading history while operating as an oil and natural gas producer. Future estimates of our stock volatility could be substantially different from our current estimate, which could significantly affect the amount of expense we recognize for our stock-based compensation awards.

Off Balance Sheet Arrangements

The Company has no off-balance sheet arrangements as of June 30, 2014.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risks

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Commodity Price Risk

Our most significant market risk is the pricing for crude oil, natural gas and NGLs. We expect energy prices to remain volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline. In addition, a non-cash write-down of our oil and gas properties could be required under full cost accounting rules if future oil and gas commodity prices sustained a significant decline. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as, if and when needed. Although our current production base may not be sufficient enough to effectively allow hedging, we may use derivative instruments to hedge our commodity price risk.

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Item 8. Financial Statements

Index to Consolidated Financial Statements



	Reports of Independent Registered Public Accounting Firm	34
	Consolidated Balance Sheets as of June 30, 2014 and 2013	36
	Consolidated Statements of Operations for the Years ended June 30, 2014, 2013 and 2012	37
	Consolidated Statements of Cash Flows for the Years ended June 30, 2014, 2013 and 2012	38
	Consolidated Statements of Stockholders' Equity for the Years ended June 30, 2014, 2013 and 2012	39
	Notes to Consolidated Financial Statements	40

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Evolution Petroleum Corporation

We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and subsidiaries as of June 30, 2014 and 2013, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended June 30, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 about whether the financial statements are free of material misstatement. 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 financial position of Evolution Petroleum Corporation and subsidiaries as of June 30, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2014, in conformity with U.S. generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Evolution Petroleum Corporation and subsidiaries’ internal control over financial reporting as of June 30, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 1992, and our report dated September 12, 2014 expressed an unqualified opinion on the effectiveness of Evolution Petroleum Corporation’s internal control over financial reporting.

Hein & Associates LLP

Houston, Texas

September 12, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Evolution Petroleum Corporation

We have audited Evolution Petroleum Corporation’s internal control over financial reporting as of June 30, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 1992. Evolution Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Evolution Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of June 30, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 1992.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Evolution Petroleum Corporation and subsidiaries as of June 30, 2014 and 2013, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended June 30, 2014, and our report dated September 12, 2014, expressed an unqualified opinion.

Hein & Associates LLP

Houston, Texas

September 12, 2014

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Evolution Petroleum Corporation and Subsidiaries

Consolidated Balance Sheets



	June 30, 2014		June 30, 2013
Assets
Current assets
Cash and cash equivalents	$	23,940,514	$	24,928,585
Certificates of deposit	—		250,000
Receivables
Oil and natural gas sales	1,456,146		1,632,853
Joint interest partner	—		49,063
Income taxes	—		281,970
Other	1,066		918
Deferred tax asset	159,624		26,133
Prepaid expenses and other current assets	747,453		266,554
Total current assets	26,304,803		27,436,076
Property and equipment, net of depreciation, depletion, and amortization
Oil and natural gas properties—full-cost method of accounting, of which $4,112,704 was excluded from amortization at June 30, 2013	37,822,070		38,789,032
Other property and equipment	424,827		52,217
Total property and equipment	38,246,897		38,841,249
Advances to joint interest operating partner	—		26,059
Other assets	464,052		252,912
Total assets	$	65,015,752	$	66,556,296
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable	$	441,722	$	769,099
State and federal taxes payable	—		233,548
Accrued liabilities and other	2,558,004		1,630,103
Total current liabilities	2,999,726		2,632,750
Long term liabilities
Deferred income taxes	9,897,272		8,418,969
Asset retirement obligations	205,512		615,551
Deferred rent	35,720		52,865
Total liabilities	13,138,230		11,720,135
Commitments and contingencies (Note 15)
Stockholders' equity
Preferred stock, par value $0.001; 5,000,000 shares authorized: 8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at June 30, 2014 and 2013, respectively, with a total liquidation preference of $7,932,975 ($25.00 per share)	317		317
Common stock; par value $0.001; 100,000,000 shares authorized; issued 32,615,646 shares at June 30, 2014, and 29,410,858 at June 30, 2013; outstanding 32,615,646 shares and 28,608,969 shares as of June 30, 2014 and 2013, respectively	32,615		29,410
Additional paid-in capital	34,632,377		31,813,239
Retained earnings	17,212,213		24,013,035
	51,877,522		55,856,001
Treasury stock, at cost, no shares and 801,889 shares as of June 30, 2014 and 2013, respectively	—		(1,019,840		)
Total stockholders' equity	51,877,522		54,836,161
Total liabilities and stockholders' equity	$	65,015,752	$	66,556,296

See accompanying notes to consolidated financial statements.

Table of Contents

Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Operations



	Years Ended June 30,
	2014			2013			2012
Revenues
Delhi field	$	16,908,666		$	19,219,036		$	15,143,770
Artificial lift technology	623,332			375,063			132,344
Other properties	141,510			1,755,821			2,685,924
Total revenues	17,673,508			21,349,920			17,962,038
Operating costs
Artificial lift technology	609,221			390,238			124,703
Production costs - other properties	584,352			1,390,500			1,650,296
Depreciation, depletion and amortization	1,228,685			1,300,207			1,136,974
Accretion of discount on asset retirement obligations	41,626			72,312			77,505
General and administrative expenses*	8,388,291			7,495,309			6,143,286
Restructuring charges**	1,293,186			—			—
Total operating costs	12,145,361			10,648,566			9,132,764
Income from operations	5,528,147			10,701,354			8,829,274
Other
Interest income	30,256			22,580			25,728
Interest (expense)	(69,092		)	(65,745		)	(21,950		)
Income before income tax provision	5,489,311			10,658,189			8,833,052
Income tax provision	1,891,998			4,029,761			3,700,922
Net income attributable to the Company	3,597,313			6,628,428			5,132,130
Dividends on preferred stock	674,302			674,302			630,391
Net income attributable to common shareholders	$	2,923,011		$	5,954,126		$	4,501,739
Earnings per common share
Basic	$	0.09		$	0.21		$	0.16
Diluted	$	0.09		$	0.19		$	0.14
Weighted average number of common shares outstanding
Basic	30,895,832			28,205,467			27,784,298
Diluted	32,564,067			31,975,131			31,609,929

_______________________________________________________________________________


*	General and administrative expenses for the years ended June 30, 2014, 2013 and 2012 included non-cash stock-based compensation expense of $1,352,322, $1,531,745 and $1,475,995, respectively.


**	Restructuring charges for the year ended June 30, 2014 included non-cash stock-based compensation expense of $376,365.

See accompanying notes to consolidated financial statements.

Table of Contents

Evolution Petroleum Corporation and Subsidiaries

Consolidated Statements of Cash Flows



	Years Ended June 30,
	2014			2013			2012
Cash flows from operating activities
Net income attributable to the Company	$	3,597,313		$	6,628,428		$	5,132,130
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,272,778			1,341,055			1,150,454
Stock-based compensation	1,352,322			1,531,745			1,475,995
Stock-based compensation related to restructuring	376,365			—			—
Accretion of discount on asset retirement obligations	41,626			72,312			77,505
Settlement of asset retirement obligations	(315,952		)	(90,531		)	(61,936		)
Deferred income taxes	1,344,812			2,512,978			2,549,592
Deferred rent	(17,145		)	(17,146		)	(15,401		)
Changes in operating assets and liabilities:
Receivables from oil and natural gas sales	176,707			(289,506		)	216,057
Receivables from income taxes and other	281,822			(189,813		)	(64,194		)
Due from joint interest partners	49,063			47,088			(10,046		)
Prepaid expenses and other current assets	(480,899		)	(33,121		)	(165,581		)
Accounts payable and accrued expenses	663,645			278,436			80,986
Income taxes payable	(233,548		)	141,581			9,845
Net cash provided by operating activities	8,108,909			11,933,506			10,375,406
Cash flows from investing activities
Proceeds from asset sales	542,347			3,479,976			799,610
Development of oil and natural gas properties	(966,931		)	(4,163,080		)	(3,291,921		)
Acquisitions of oil and natural gas properties	(59,315		)	(755,194		)	(3,768,162		)
Capital expenditures for other equipment	(312,890		)	—			(61,176		)
Advances to joint venture operating partner	—			—			(224,206		)
Maturities of certificates of deposit	250,000			—			—
Other assets	(202,017		)	(32,160		)	(35,056		)
Net cash used in investing activities	(748,806		)	(1,470,458		)	(6,580,911		)
Cash flows from financing activities
Proceeds from the exercise of stock options	3,252,801			70,719			—
Proceeds from issuance of preferred stock, net	—			—			6,930,535
Acquisitions of treasury stock	(1,655,251		)	(137,818		)	—
Common stock dividends paid	(9,723,833		)	—			—
Preferred stock dividends paid	(674,302		)	(674,302		)	(630,391		)
Deferred loan costs	(63,535		)	(16,211		)	(163,257		)
Tax benefits related to stock-based compensation	509,096			794,569			249,728
Other	6,850			32			—
Net cash provided (used) by financing activities	(8,348,174		)	36,989			6,386,615
Net increase (decrease) in cash and cash equivalents	(988,071		)	10,500,037			10,181,110
Cash and cash equivalents, beginning of period	24,928,585			14,428,548			4,247,438
Cash and cash equivalents, end of period	$	23,940,514		$	24,928,585		$	14,428,548

See accompanying notes to consolidated financial statements.

Table of Contents

Evolution Petroleum Corporation and Subsidiaries

Consolidated Statement of Changes in Stockholders' Equity

For the Years Ended June 30, 2014, 2013 and 2012



	Preferred			Common Stock
	Preferred			Common Stock			Additional Paid-in Capital			Retained Earnings		Treasury Stock			Total Stockholders' Equity
	Shares	Par Value		Shares	Par Value		Additional Paid-in Capital			Retained Earnings		Treasury Stock			Total Stockholders' Equity
Balance, June 30, 2011	—	$	—	27,612,916	$	28,400	$	20,761,209		$	13,557,170	$	(882,022	)	$	33,464,757
Issuance of preferred stock	317,319	317		—	—		7,932,658			—		—			7,932,975
Preferred stock issuance costs	—	—		—	—		(1,002,440		)	—		—			(1,002,440		)
Issuance of restricted common stock	—	—		196,106	196		(162		)	—		—			34
Exercise of stock warrants	—	—		65,261	66		(66		)	—		—			—
Exercise of stock options	—	—		7,941	8		(8		)	—		—			—
Stock-based compensation	—	—		—	—		1,475,995			—		—			1,475,995
Tax benefits related to stock-based compensation	—	—		—	—