Evolution Petroleum Annual Report 2016

Plain-text annual report

EVOLUTION PETROLEUM CORP FORM 10-K (Annual Report) Filed 09/09/16 for the Period Ending 06/30/16 Address Telephone CIK Symbol SIC Code 1155 DAIRY ASHFORD ST. SUITE 425 HOUSTON, TX 77079 713-935-0122 0001006655 EPM 1311 - Crude Petroleum and Natural Gas Industry Oil & Gas Exploration and Production Sector Fiscal Year Energy 06/30 http://www.edgar-online.com © Copyright 2016, EDGAR Online, Inc. All Rights Reserved. Distribution and use of this document restricted under EDGAR Online, Inc. Terms of Use. UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-Ký ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended June 30, 2016o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from to Commission File Number 001-32942EVOLUTION PETROLEUM CORPORATION(Exact name of registrant as specified in its charter)Nevada(State or other jurisdiction ofincorporation or organization) 41-1781991(IRS EmployerIdentification No.)1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079(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 parvalue 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: ýIndicate 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: ýIndicate 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 shorterperiod 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: oIndicate 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 ofRegulation 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: oIndicate 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'sknowledge, 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. o 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", "acceleratedfiler" 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 oIndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: o No: ýThe aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 2015, the last business day of the registrant’s most recently completed second fiscal quarter,based on the closing price on that date of $4.81 on the NYSE MKT was $116,929,484 .The number of shares outstanding of the registrant's common stock, par value $0.001, as of September 7, 2016 , was 32,905,982 .DOCUMENTS INCORPORATED BY REFERENCEPortions of the proxy statement related to the registrant's 2016 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 intoPart III of this report.1EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES2016 ANNUAL REPORT ON FORM 10-KTABLE OF CONTENTS Page PART I Item 1 .Business1 Item 1A.Risk Factors6 Item 1B.Unresolved Staff Comments15 Item 2.Properties15 Item 3.Legal Proceedings21 Item 4.Mine Safety Disclosures21 PART II22 Item 5.Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities22 Item 6.Selected Financial Data24 Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations26 Item 7A.Quantitative and Qualitative Disclosures About Market Risk36 Item 8.Financial Statements and Supplementary Data38 Item 9.Changes In and Disagreements with Accountants on Accounting and Financial Disclosure68 Item 9A.Controls and Procedures68 Item 9B.Other Information69 PART III70 Item 10.Directors, Executive Officers and Corporate Governance70 Item 11.Executive Compensation70 Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters70 Item 13.Certain Relationships and Related Transactions, and Director Independence70 Item 14.Principal Accounting Fees and Services70 PART IV71 Item 15.Exhibits and Financial Statement Schedules71 Glossary of Selected Petroleum Terms72 Signatures75 Exhibit Index76 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 ofplaces and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When consideringany 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-lookingstatement. 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 incommodity 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 ExchangeCommission ("SEC"). 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 andtherefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualifiedin 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-ownedsubsidiaries.PART IItem 1. BusinessNote: See Glossary of Selected Petroleum Industry Terms at the back of this document - refer to Table of ContentsGeneralWe are an independent oil and gas company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and naturalgas, 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. Additional information regarding our operating segment, major customers, revenues and assets can befound in in Item 8. Financial Statements - Notes to Consolidated Financial Statements.Our petroleum operations began in September of 2003. On May 26, 2004, our predecessor, Natural Gas Systems, Inc. (Delaware, "Old NGS"), a private corporation formedin September 2003, merged into a wholly-owned subsidiary of Reality Interactive, Inc. (Nevada, "Reality"), an inactive public company, which was renamed Natural GasSystems, Inc. ("NGS"). The former officers and directors of Reality resigned and the officers, directors and business operations of Old NGS became the Company. Concurrentlywith the listing of NGS shares on the NYSE MKT in July 2006, NGS was renamed Evolution Petroleum Corporation. Our principal executive offices are located at 1155 DairyAshford Road, Suite 425, Houston, Texas 77079, and our telephone number is (713) 935-0122. We maintain a website at www.evolutionpetroleum.com , but informationcontained on our website does not constitute part of this document.Our common stock is traded on the NYSE MKT under the ticker symbol "EPM". We also have preferred stock which trades on the NYSE MKT under the symbol"EPM.A"At June 30, 2016 , we had six full-time employees, not including contract personnel and outsourced service providers. None of the Company’s employees are currentlyrepresented by a union, and the Company believes that it has excellent relations with its employees. 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 other non-core functions.Business StrategyOur business strategy is to acquire known, underdeveloped oil and natural gas resources and exploit them through the application of capital, sound engineering and moderntechnology to increase production, ultimate recoveries, or both.Our principal assets include interests in a CO 2 enhanced oil recovery project in Louisiana’s Delhi field. We are focused on increasing underlying asset values on a pershare 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 - Enhanced Oil Recovery - Onshore LouisianaOur mineral and working interests in the Delhi Holt-Bryant Unit in the Delhi field ("Unit"), located in Northeast Louisiana, are currently our most significant asset. TheUnit is approximately 13,636 acres in size and has had a prolific production history totaling approximately 195 million bbls of oil through primary and limited secondaryrecovery operations since its discovery in the mid-1940s. Since initial enhanced oil recovery ("EOR") production began in March 2010, the Unit has produced over 11 millionbbls of oil. The Unit is currently producing as an EOR project utilizing CO 2 flood technology following the sale of a majority of our working interest to a subsidiary of DenburyResources, Inc., the current operator, in 2006. At the time of our purchase of the field in 2003, the Unit had minimal production.1We own two types of interests in the Unit:•7.4% of overriding royalty interests that are in effect for the life of the Unit and mineral royalty interests, free of all operating and capital cost burdens. EffectiveJuly 1, 2016, our overriding royalty interest was reduced by 0.2226% to 7.2% as part of the litigation settlement with the operator discussed in Note 3 - DelhiLitigation Settlement; and•A 23.9% working interest with an associated 19.0% net revenue interest. The working interest reverted to us effective November 1, 2014. Upon occurrence ofthis contractual payout, we began bearing 23.9% of all operating expenses and capital expenditures and our combined net revenue interests increased to 26.4%through the end of fiscal 2016, and 26.2% thereafter.Our independent reservoir engineers, DeGolyer & MacNaughton, assigned the following estimated reserves net to our interests at Delhi as of June 30, 2016 . Equivalent oilreserves is defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio.•10.8 million bbls of proved oil equivalent reserves, with a Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure") of $78 million,and PV-10* of $101 million•4.5 million bbls of probable** oil equivalent reserves•2.7 million bbls of possible** oil equivalent reserves_______________________________________________________________________________*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 NetRevenues" under Item 2. Properties of this Form 10-K. Both the Standardized Measure and PV-10 are based on the average first day of the month net commodity pricesreceived in the twelve months preceding June 30, 2016, which were $40.91 per barrel of oil and $14.38 per barrel of NGL.**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 andnatural gas that is recoverable from a particular reservoir, Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves butwhich, together with Proved reserves, are as likely as not to be recovered, generally described as having a 50% probability of recovery. Possible reserves are even lesscertain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on productionhistory, results of additional exploration and development, price changes and other factors. Estimates of Probable and Possible reserves are by their nature much morespeculative than estimates of Proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject tosubstantially greater risk. These three reserve categories and net present worth discounted at 10% relating to each category have not been adjusted to different levels ofrecovery risk among these categories and are therefore not comparable and are not meaningfully combined.The operator has planned six primary phases for the installation of the CO 2 flood in the Delhi field. Four of these phases have been completed as of June 30, 2016 and tworemain as undeveloped. One of the remaining two phases is reflected as proved undeveloped in our current reserves report and the other was dropped from proved reserves as itwas not deemed economic under current year pricing guidelines for SEC purposes.Phase I began CO 2 injection in November 2009. First oil production response occurred in March 2010, about three to four months earlier than expected, and production inthe field increased to approximately 2,000 gross BOPD.Implementation of Phase II, which was more than double the size of Phase I, commenced with incremental CO 2 injection at the end of December 2010. First oil productionresponse 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. During early calendar 2013, the operator intensified development in the previouslyredeveloped 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. Grossfield production increased to more than 7,500 BO per day.In June 2013, following a fluid release event that consisted of the uncontrolled release of CO 2, water, natural gas and a small amount of oil from a previously plugged wellin the southwest part of the field, the operator temporarily suspended CO 2 injection in most of the southwestern tip of the field. The operator has fully remediated the affectedarea, but has isolated that2part of the field with a water curtain while continuing production. See discussion below for 2016 developments in this part of the field.The operator took the position that the remediation costs of the June 2013 fluid release event, which totaled over $130 million on a gross basis, could be charged to ourpayout account. Accordingly, this action delayed our working interest reversion by more than one year. We disputed the operator's position on the treatment of these costs, filedsuit against the operator over this matter and other issues related to the original 2006 agreements and subsequently reached a settlement agreement with the operator as describedin Note 3 – Delhi Litigation Settlement.Subsequent to the June 2013 fluids release, the operator delayed further development of the field and stated its intent not to resume significant capital spending untilreversion of our working interest, which became effective on November 1, 2014. In February 2015, subsequent to reversion, we approved an authorization for expenditure("AFE") for the construction of a natural gas liquids ("NGL") recovery plant in the Delhi Field, which will extract NGL's and methane from the field. We expect that the NGL'swill be sold and the recovered methane will be utilized to generate power for the field in order to substantially reduce operating costs, a more cost effective use than selling themethane. In addition to the value of these hydrocarbon products, the increased purity of the CO 2 stream re-injected into the field should result in significant operational benefitsto the CO 2 flood. The estimated gross costs of the plant is approximately $103 million; our net share of these capital expenditures is $24.6 million, of which we have alreadyexpended approximately $21.5 million. The plant is expected to be operational by November 2016.During the fall of 2014, post-reversion, the operator initiated work on the Phase V expansion of the CO 2 flood in the undeveloped eastern part of the field. This project issometimes referred to as Test Site 5. These operations were suspended later that fall when the operator made significant cuts in its capital budget as a result of declining oilprices. While we believe the Phase V expansion is economic at current commodity prices, resumption of this work is likely to be electively delayed due to prevailing oil pricesand the partners' allocation of capital for such projects. Since we believe that the NGL plant and further expansion of the CO 2 flood have favorable economics, even in this lowerprice environment, we expect the expansion of the CO 2 flood to resume within the next few years. The economics of expansion will also be improved subsequent to thecompletion of the NGL recovery plant.During the second calendar quarter of 2016, we authorized expenditures totaling $2.5 million gross ($0.6 million net to Evolution) for a project to restore production in thesouthwestern portion of the field. Following the fluid release event in June 2013, CO 2 injections in this area ceased in order to reduce reservoir pressure and protect the incidentarea. The project includes converting three shut-in wells to water injector wells in order to expand the water curtain barrier to reduce CO 2 migration into this area together withthe installation of three electrical submersible pumps ("ESP") in other shut-in wells in order to increase withdrawal rates and help maintain the targeted reservoir pressure. TheseESP production wells will create a modified waterflood, which is expected to increase gross oil production by an estimated 250 to 300 BOPD. At June 30, 2016 this project wasstill in progress.At June 30, 2016, no proved, probable or possible reserves were attributed to the suspended southwestern tip area of the field, beneath the inhabited Town of Delhi in thenortheast and to one of two development sites on the far eastern side of field (Phase VI) due to the current economics of future development plans. In addition, no probablereserves are currently attributed to three smaller reservoirs within the Unit in similar formations with similar production history due to the lower oil price utilized in our reservescalculation. We do not have proved or probable reserves associated with the Mengel Sand, a separate interval within the Unit that is not currently producing, which was receivedin the litigation settlement in June 2016.At June 30, 2016, 1.4 million bbls of oil equivalent proved undeveloped reserves, 0.5 million bbls of oil equivalent probable reserves, and 0.2 million bbls of oil equivalentpossible reserves were attributed to Phase V of the undeveloped eastern part of the Delhi field. Development of these proved reserves is forecast to begin in fiscal 2018.Artificial Lift Technology (GARP ® )Our artificial lift technology registered as GARP ® (Gas Assisted Rod Pump) was developed internally by our former Senior Vice President of Operations. Its design isintended to increase production and extend the life of horizontal and vertical wells with gas, oil or associated water production with the expectation of recovering additionalreserves at an economically attractive cost per BOE. We received a patent on our GARP ® technology on August 30, 2011, which provides U.S. patent protection for thetechnology through early 2028. We have further filed for a continuation in part to our patent for recent improvements in the technology, including a concentric design whichallows the technology to work in narrower diameter casing.Prior to patent issuance, we tested the GARP ® technology on certain marginal producing wells we owned and operated in the Giddings Field. The tests were successful indemonstrating that the process works; however, these candidates were unable to prove commercial viability due to their low primary recoveries as producers.3Subsequent to receiving our patent, we entered into demonstration joint venture projects with two different industry operators during fiscal 2012 to prove commercialapplication. We further expanded our commercial tests during fiscal 2013 with two additional installations and a third in fiscal 2014. All five of these installations weresuccessful in re-establishing commercial production. During fiscal 2014, we entered into a commercial agreement to install our technology on at least five wells in the GiddingsField. Three installations were completed as of the end of fiscal 2014, two of which were successful. During fiscal 2015, we completed installation of our artificial lift technologyin two additional non-operated wells under this contract. In addition, we restored production in one of our operated wells that had been temporarily abandoned and shut-in sinceMarch 2014. The results from these projects were mixed, with many of the wells successfully establishing or restoring commercial rates of production. However, with thedeclining price environment, many of the wells were not economically successful when including the incremental costs of installing the technology.As a result of the declining commodity price environment and reduced capital spending by the industry, the timing for commercial success of this technology was slowerthan previously anticipated. Based on a strategic review of our GARP ® artificial lift technology operations, we completed the separation and transfer of these operations to a newentity controlled by the inventor of the technology and certain former employees of the Company, effective December 31, 2015. We invested $108,750 in common and preferredstock and retained a minority interest in the new entity, together with a 5% royalty on all future gross revenues derived from the technology. We have the option to convert ourpreferred stock investment into a larger, non-controlling equity stake in the new entity. Consequently, we have retained substantial upside for our shareholders from the potentialfuture success of the technology, while eliminating approximately $1.0 million annually of overhead expense associated with GARP ® . We have also retained the right to use thetechnology in our current wells and any future wells we develop or acquire.Other ProjectsLopez Field —South TexasWe 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 highflow 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 requiredto develop material reserves lowered the attractiveness of this project. Consequently, we elected to sell this asset during fiscal 2013 and completed such monetization in fiscal2014.Mississippi Lime —Kay County, OklahomaIn 2012, we acquired a 45% interest in a joint venture with Orion Exploration, a private company based in Tulsa, Oklahoma. The joint venture was operated by Orion andengaged in the horizontal development of the Mississippi Lime reservoir in Kay County, Oklahoma. Our leasehold position, totaling approximately 6,600 acres, was located inthe eastern, more oil-prone side of the play. We drilled one gross salt water disposal well and reached total depth on two horizontally drilled wells in the Mississippi Limeformation. 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 ofstructure in production, and determined that this play is a structural play requiring substantial geophysical and geological work and expertise in order to be successful, as opposedto a resource play in which engineering is the primary requirement. Accordingly, 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. In October 2014, we closed on the sale of all of our leasehold interests, wells and associatedassets in the Mississippi Lime reservoir to the operator.Markets and CustomersWe 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 readilytransportable and marketable. We do not currently market our share of crude oil production from Delhi. Although we have the right to take our working interest production in-kind, we are currently selling our under the Delhi operator's agreement with Plains Marketing LP for the delivery and pricing of our oil there. The oil from Delhi is currentlytransported from the field by pipeline, which results in better net pricing than the alternative of transportation by truck. Delhi crude oil production sells at Louisiana Light Sweet("LLS") pricing which generally trades at a premium to West Texas Intermediate ("WTI") crude oil pricing. This positive LLS Gulf Coast price differential over WTI Cushingwas approximately $2.19 per barrel during our fiscal year ended June 30, 2016, based on first of the month prices. The differential has narrowed from past years, but we expectthat a positive LLS price differential will continue, at least in the near future.4The following table sets forth purchasers of our oil and natural gas production for the years indicated: Year Ended June 30,Customer2016 2015 2014Plains Marketing L.P. (includes Delhi production)99% 99% 96%Enterprise Crude Oil LLC—% —% 2%Flint Hills—% —% 1%ETC Texas Pipeline, LTD. —% —% 1%All others1% 1% —%Total100% 100% 100%The loss of our purchaser at the Delhi field or disruption to pipeline transportation from the field could adversely affect our net realized pricing and potentially our near-term production levels. The loss of any of our other purchasers would not be expected to have a material adverse effect on our operations.Market ConditionsMarketing of crude oil, natural gas, and natural gas liquids and the prices we receive are influenced by many factors that are beyond our control, the exact effect of which isdifficult to predict. These factors include changes in supply and demand, market prices, government regulation and actions of major foreign producers.Over the past 30 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. Mostrecently, the price of oil per barrel has dropped dramatically, particularly in the fourth quarter 2014 and continuing into 2016, by more than half since its high in June 2014.Worldwide factors such as geopolitical, macroeconomic, supply and demand, refining capacity, petrochemical production and derivatives trading, among others, influence pricesfor crude oil. Local factors also influence prices for crude oil and include increasing or decreasing production trends, quality differences, regulation and transportation issuesunique to certain producing regions and reservoirs.Also over the past 30 years, domestic natural gas prices have been extremely volatile, ranging from $1 to $15 per MMBTU. The spot market for natural gas, changes insupply and demand, derivatives trading, pipeline availability, BTU content of the natural gas and weather patterns, among others, cause natural gas prices to be subject tosignificant 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 crudeoil.CompetitionThe oil and natural gas industry is highly competitive for prospects, acreage and capital. Our competitors include major integrated crude oil and natural gas companies andnumerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies withsubstantially 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 efficientlyconduct operations, achieve technological advantages, identify and acquire economically producible reserves and obtain affordable capital.Government RegulationNumerous 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 oreconomic environment. Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for noncompliance. To the best ofour knowledge, we are in compliance with all laws and regulations applicable to our operations and we believe that continued compliance with existing requirements will nothave 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 severalfactors, including future changes to regulatory requirements which are unpredictable. However, we do not currently anticipate that future compliance with existing laws andregulations 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 thisForm 10-K, for additional information regarding government regulation.5InsuranceWe maintain insurance on our operated and non-operated properties and operations for risks and in amounts customary in the industry. Such insurance includes generalliability, 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 risksof loss through deductibles, limits and self-retentions. We do not carry lost profits coverage and we do not have coverage for consequential damages.Additional InformationWe 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 areavailable 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 practicableafter 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, 1155 DairyAshford Road, Suite 425, Houston, Texas 77079, 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 awebsite 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 FactorsOur business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business,financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which wecurrently consider immaterial also may adversely affect us.Risks related to the oil and gas industry and our CompanyA substantial or extended decline in oil prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditureobligations and financial commitments.The price we receive for our oil significantly influences our revenue, profitability, access to capital and future rate of growth. Oil is a commodity and its price is subjectto wide fluctuations in response to relatively minor changes in supply and demand. For example, average daily prices for WTI crude oil ranged from a high of $111 per barrel toa low of $27 per barrel over the past three fiscal years ending June 30, 2016. Historically, the markets for oil and natural gas have been volatile. These markets will likelycontinue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factorsinclude the following:•worldwide and regional economic conditions impacting the global supply and demand for oil and gas;•actions of OPEC;•the price and quantity of imports of foreign oil and natural gas;•political conditions in or affecting other oil-producing and natural gas-producing countries;•the level of global oil and natural gas exploration and production;•the level of global oil and natural gas inventories;•localized supply and demand fundamentals of regional, domestic and international transportation availability;•weather conditions and natural disasters;•domestic and foreign governmental regulations;•speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;•price and availability of competitors' supplies of oil and natural gas;•technological advances effecting energy consumption; and•the price and availability of alternative fuels.Substantially all of our production is sold to purchasers under short-term (less than twelve-month) contracts at market-based prices. Low oil and natural gas prices willreduce our cash flows, borrowing ability, the present value of our reserves and our ability to develop future reserves. We may be unable to obtain needed capital or financing onsatisfactory terms. Low oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically, which could lead to a decline in our oiland natural gas reserves. Because approximately 79% of our proved reserves at June 30, 2016 are crude oil reserves and 21% are natural gas liquids reserves, and almost 100% ofour current production is crude oil, we are heavily impacted by movements in crude oil prices, which also influence natural gas liquids prices. To the extent that we have not6hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas prices may adversely affect our financialposition.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 operationsand financial results.Over 99% of our revenues come from our royalty, mineral and working interests in the Delhi field in Louisiana and thus our current revenues are highly concentrated inthis field. 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 ourresults of operations and financial results. We are not the operator of the Delhi field, and our revenues and future growth are heavily dependent on the success of operations,which we do not control.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 inorder 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 reservoircharacteristics. Except to the extent we acquire additional properties containing proved reserves or conduct successful development activities, or both, our proved reserves willdecline. Our production is heavily dependent on our interests in EOR production that began during March 2010 in the Delhi field. Although EOR production from provedreserves at Delhi has and is expected to grow over time, environmental or operating problems or lack of future investment at Delhi could cause our net production of oil andnatural gas to 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.Substantially all of our properties, namely our Delhi interests, are operated by other companies and involve third-party working interest owners. As a result, we havelimited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or theamount 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 limitationsand 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 andmaterially and adversely affect our financial conditions and results of operations.We are materially dependent upon our operator with respect to the successful operation of our principal asset, which consists of our interests the Delhi field. A materiallynegative change in our operator’s financial condition could negatively affect operations in the Delhi field, and consequently our income from the field as well as the value ofour interests in the Delhi field.Our royalty, mineral and working interests in the Delhi field, located in Northeast Louisiana, are currently our most significant asset. Over 99% of our revenues come fromthese interests and thus our current revenues are highly concentrated in this field. Any significant downturn in production or other events beyond our control which impact theDelhi field could have a material adverse effect on our results of operations and financial results. We are not the operator of the Delhi field. It is operated by a subsidiary ofDenbury Resources Inc. (“DNR”). Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.Further, our CO 2 - Enhanced Oil Recovery (“CO 2 -EOR”) project in the Delhi field requires significant amounts of CO 2 reserves and technical expertise, the sources ofwhich have been committed by the operator. Additional capital remains to be invested to fully develop this project, further increase production and maximize the value of thisasset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial and logistical matters could cause ultimate enhanced recoveriesfrom the planned CO 2 - EOR project to fall short of our expectations in volume and/or timing. Such occurrences could have a material adverse effect on us, and our results ofoperations and financial condition. Our economic success is thus materially dependent upon the Delhi field operator's ability to: (i) deliver sufficient quantities of CO 2 from its reserves in the Jackson Domesource, (ii) secure its share of capital necessary to fund development and operating commitments with respect to the field and (iii) successfully manage related technical,operating, environmental, strategic and logistical risks, among other things. During the fall of 2014, the operator initiated work on expansion of the CO 2 flood in the undeveloped eastern part of the field. These operations were suspended by theend of 2014 when the operator made significant cuts in its capital budget as a result of declining oil prices. While we believe that expansion remains economic at currentcommodity prices, resumption of7this work could be electively delayed due to prevailing oil prices and the operator’s allocation of capital for such projects, thereby negatively impacting us.We are aware that DNR, which is publicly traded, has disclosed in its public SEC filings certain risks related to its current level of indebtedness and the related financialcovenants. They have stated, for example, that their level of indebtedness could have important consequences, including, among others, requiring dedication of a substantialportion of DNR’s cash flow from operations to servicing their indebtedness. They noted that their ability to meet their obligations under their debt instruments will depend in partupon prevailing economic conditions and commodity prices. DNR also noted that it had deferred development spending for certain projects.Given the current stress in the global commodity markets and oil and gas in particular, our operator could be materially negatively impacted, which could in turnnegatively affect the operator’s ability to operate the Delhi field as well as its financial commitment to the CO 2 -EOR project in the field, and thus our interests in the Delhi fieldcould be materially negatively impacted.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, orrelatively shallow reservoirs. Shallower reservoirs usually have lower pressure, which translates into fewer natural gas volumes in place. Low permeability reservoirs requiremore wells and substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient undepleted fractures to establishcommercial production. Depleted reservoirs require successful application of newer technology to unlock incremental reserves.Our CO 2 -EOR project in the Delhi field, operated by a subsidiary of Denbury Resources Inc., requires significant amounts of CO 2 reserves, development capital andtechnical expertise, the sources of which to date have been committed by the operator. Although initial CO 2 injection began at Delhi in November 2009, initial oil productionresponse began in March 2010 and a large part of the capital budget has already been expended, additional capital remains to be invested to fully develop the EOR project,further increase production and maximize the value of the asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial andlogistical risks may cause ultimate enhanced recoveries from the planned CO 2 -EOR project to fall short of our expectations in volume and/or timing. Such occurrences wouldhave a material adverse effect on the Company, its results of operations and financial condition.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 wellsare 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 involvenumerous 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 issubstantial 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 horizontal drilling or CO 2injection 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 notbe 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 overalldrilling 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 or tertiary injectants, and some of which maybe 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 wellsdiscussed will, if drilled, encounter reservoirs of commercially productive crude oil or natural gas.8The 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, 2016, one purchaser accounted for 99% of our oil and natural gas revenues. We do not currently market our share of crude oil production fromthe Delhi field. Although we have the right to take our working interest production in-kind, we are currently accepting terms under the Delhi operator's agreement with PlainsMarketing L.P. for the delivery and pricing of our oil there. The loss of such large single purchaser for our oil and natural gas production could negatively impact the revenue wereceive. We cannot assure you we could readily find other purchasers for our oil and natural gas production. In addition, the crude oil production from the Delhi field istransported by pipeline and if this pipeline transportation were disrupted and we were forced to use alternative transportation methods, our net realized pricing and potentially ournear-term production levels could be adversely affected.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 beinaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas thatcannot 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 historicalproduction from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future crude oil andnatural 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 factvary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group ofproperties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared by different engineers or by the sameengineers 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 likelyvary 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 thecurrent 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 arebased 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 theend 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 willbe 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 changesin 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 forreporting 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 andnatural gas industry in general. The Standardized Measure and PV-10 do 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 theSEC. 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 futurenet 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 carryingvalue 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 willdepend 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. Ifa 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.Our derivative activities could result in financial losses or could reduce our income.To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enterinto derivative arrangements for a portion of our oil and natural gas production, including costless collars and fixed-price swaps. We have not designated any of our derivativeinstruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments arerecognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Derivative arrangements alsoexpose us to the risk of financial loss in some circumstances, including when:9•production is less than the volume covered by the derivative instruments;•the counterparty to the derivative instrument defaults on its contract obligations; or•there is an increase in the differential between the underlying price in the derivative instrument and actual price received.In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cashmargin requirements.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 CO 2 from its reserves in the Jackson Dome, secure all of the development capital necessaryto fund its and our cost interests and (ii) successfully manage technical, operating, environmental, strategic and logistical development and operating risks, amongother 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 exploitation activities, including meetingpotential 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 carryout our oil and gas acquisitions, exploitation and development activities. Certain of our undeveloped leasehold acreage may be subject to leases that will expire unless productionis 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 toreplace 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 noassurance that additional debt or equity financing will be available to meet these requirements or available to us on favorable terms.We may be subject to risks in connection with acquisitions because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well asuncertainties in forecasting oil and gas prices and future development, production and marketing costs, and the integration of significant acquisitions may be difficult.We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy.The successful acquisition of producing properties requires an assessment of several factors, including:•recoverable reserves•future oil and natural gas prices and their appropriate differentials;•development and operating costs•potential for future drilling and production;•validity of the seller's title to properties, which may be less than expected at closing; and•potential environmental issues, litigation and other liabilities.The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to begenerally consistent with industry practices. Our review will not reveal all existing10or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections maynot always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified,the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification forenvironmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire properties on an “as is” basis. Indemnification from the sellers willgenerally be effective only during the twelve-month period after the closing and subject to certain dollar limitations and minimums. We may not be able to collect on suchindemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations related toacquisitions, which could materially adversely affect our financial condition, results of operations or cash flows. Significant acquisitions and other strategic transactions may involve other risks, including:•our lean management team's capacity could be challenged by the demands of evaluating, negotiating and integrating significant acquisitions and strategic transactions inconcert with the Company's on going business demands.•the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operationswhile carrying on our ongoing business;•difficulty associated with coordinating geographically separate organizations;•an inability to secure, on acceptable terms, sufficient financing that my be required in connection with expanded operations and unknown liabilities; and•the challenge of attracting and retaining personnel associated with acquired operations.The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be requiredto devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able toeffectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. In addition,even if we successfully integrate the assets acquired in an acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, productionvolume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame.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 toregulation 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 actualproduction capacity in order to conserve supplies of crude oil and natural gas. There are federal, state and local laws and regulations primarily relating to protection of humanhealth and the environment applicable to the development, production, handling, storage, transportation and disposal of crude oil and natural gas, by-products thereof and othersubstances and materials produced or used in connection with crude oil and natural gas operations. In addition, we may inherit liability for environmental damages, whetheractual 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 governmentalentities. 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 orregulations 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/ortaxes on carbon that could have the effect of raising prices to the end user.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 canresult 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 toproperty, 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 fullyinsured against all risks incident to our business. Environmental events similar to that experienced in the Delhi field in June 2013 could defer revenue, increase operating costsand maintenance capital expenditures.11The 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 adverseeffect on our operations. In particular, our future success is dependent upon Robert S. Herlin, our Executive Chairman, Randall D. Keys, our President and Chief ExecutiveOfficer, and David Joe, Senior Vice President, Chief Financial Officer and Treasurer, for sourcing, evaluating and closing deals, capital raising, and oversight of developmentand 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 notcontrol. 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 andmaterials. 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 coulddiscontinue 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 materialsincrease, 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 existingproperties. 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.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 forproperties. 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 andincome programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. We may not beable to successfully conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. Specifically, these largercompetitors 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 agreater 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 contractservice providers, obtaining oilfield equipment and acquiring the existing and changing technologies that we believe are and will be increasingly important to attaining success inour industry.We have been, 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 incursubstantial costs in connection with those proceedings.From time to time we may be a defendant or plaintiff in various lawsuits. The nature of our operations exposes us to further possible litigation claims in the future. Thereis risk that any matter in litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on ourfinancial condition, results of operations, and cash flow. Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effecton our financial condition. Adverse litigation decisions or rulings may damage our business reputation.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 ourclaim 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, declining oil and gas prices, geopolitical issues, the availability and cost of credit, the U.S. mortgagemarket, uncertainties with regard to European sovereign debt, the slowdown12in economic growth in large emerging and developing markets, such as China, and other issues have contributed to increased economic uncertainty and diminished expectationsfor the global economy. Concerns about global economic conditions have had a significant adverse impact on domestic and international financial markets and commodity prices.If uncertain or poor economic, business or industry conditions in the United States or abroad remain prolonged, demand for petroleum products could diminish or stagnate, whichcould 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 adverselyimpact our results of operations, liquidity, and financial condition.Risks Associated with Our StockOur stock price has been and may continue to be volatile.Our common stock has relatively low trading volume and the market price has been, and is likely to continue to be, volatile. For example, during the fiscal year endingJune 30, 2016, our stock price as traded on the NYSE MKT ranged from $3.60 to $7.54. The variance in our stock price makes it difficult to forecast with any certainty the stockprice 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 factorsthat 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 2.8 million shares, or approximately 8.5% of our beneficial common stock base. JVLAdvisors LLC controls approximately 4.9 million shares or approximately 14.8% of our outstanding common stock, and Advisory Research controls approximately $3.5 millionshares or 10.6% 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 theeffect of delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover or other business combination involving our company ordiscourage 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 marketprice 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. During the fiscal year ending June 30, 2016, the daily trading volume in our common stock ranged froma low of 14,600 shares to a high of 292,100 shares traded, with average daily trading volume of 69,732 shares. On most days, this trading volume means that there is relativelylimited 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 islimited. 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 doso.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 ourknowledge there are three independent analysts that cover our company. The limited number of published reports by independent securities analysts could limit the interest in ourcommon 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. Ifany 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, wecould 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 offerings13of 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 issueup 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 additionalshares 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 theproportionate 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 andpreferences 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 ofSeptember 1, 2016. Such designation of new series of preferred stock may be made without stockholder approval, and could create additional securities which would havedividend 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;•receiving preferences over the holders of common stock regarding our surplus funds in the event of our dissolution, liquidation or the payment of dividends toPreferred 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 sharesmay 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 APreferred Stock will be limited. We have the right to redeem all shares of Series A Preferred Stock at face value plus accrued dividends 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 theSeries 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 orany 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 Stockwhen payable. In addition, existing or future debt, credit facility arrangements, contractual covenants or arrangements we enter into may restrict or prevent future dividendpayments. 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 ourliquidation, 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 theSeries 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 theSeries 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 existingand 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 onour14Series 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 anypayments could be made to holders of our Series A Preferred Stock.Continued payment of dividends on our Common Stock could be impacted.Our Board of Directors declared cash dividends on our common stock for the first time in December 2013 and we have declared and paid quarterly cash dividends sincethat time. 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 thefuture 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 APreferred Stock and any debt instruments, contractual covenants or arrangements we may enter into, our anticipated capital requirements and other factors that our board ofdirectors may think are relevant. Accordingly, there is no guarantee that we will be able to continue to pay cash dividends on our common stock.Item 1B. Unresolved Staff CommentsNone.Item 2. PropertiesThe information required by Item 2. is contained in Item 1. BusinessOil & Gas PropertiesAdditional 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 RevenuesThe 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 reservesby 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 the12-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 thosetechnologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Subject to limited exceptions, the rules also require that provedundeveloped 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 tosignificant 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 particularreservoir, 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 tobe recovered, generally described as having a 50% probability of recovery. Possible reserves are even less certain and generally require only a 10% or greater probability of beingrecovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and otherfactors. Estimates of Probable and Possible reserves are by their nature much more speculative than estimates of Proved reserves and are subject to greater uncertainties, andaccordingly the likelihood of recovering those reserves is subject to substantially greater risk. These three reserve categories and net present worth discounted at 10% relating toeach category have not been adjusted to different levels of recovery risk among these categories and are therefore not comparable and are not meaningfully combined.Estimated pre-tax 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, andthat 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 basisfor 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 investmentrelated to oil and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company whenestimating 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 oroperating 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 inisolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled herein.15Summary of Oil & Gas Reserves for Fiscal Year Ended 2016Our proved, probable and possible reserves at June 30, 2016 , denominated in equivalent barrels using six MCF of gas and 42 gallons of natural gas liquids to one barrel ofoil 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 totheir expertise in CO 2 -EOR projects and to ensure consistency with the operator who also uses D&M for their reserves estimates in the Delhi field. We also chose to have D&Mestimate our Giddings properties beginning in 2015 in order to simplify and consolidate our reserve reporting. D&M has significant expertise in this region as well. The scopeand 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.The following table sets forth our estimated proved and probable reserves as of June 30, 2016 . See Note 23 to the consolidated financial statements, where additionalunaudited reserve information is provided. The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was$42.91 per barrel of crude oil and $14.38 per barrel of natural gas liquids. The price of natural gas liquids was based on the historical price received, if no historical received priceis available, historical pricing in the area. Pricing differentials were applied to all properties, on an individual property basis. Quality adjustments have been applied based onactual BTU factors for each well and a shrinkage factor has been applied based on production volumes versus actual sales volumes.16Reserves as of June 30, 2016Reserve CategoryOil(MBbls) NGLs(MBbls) Total Reserves(MBOE)*PROVED Developed (66% of Proved)7,168 — 7,168Undeveloped (34% of Proved)1,420 2,235 3,655TOTAL PROVED8,588 2,235 10,823Product Mix79% 21% 100%PROBABLE Developed (69% of Probable)3,092 — 3,092Undeveloped (31% of Probable)471 934 1,405TOTAL PROBABLE3,563 934 4,497Product Mix79% 21% 100%POSSIBLE Developed (72% of Possible)1,964 — 1,964Undeveloped (28% of Possible)187 563 750TOTAL POSSIBLE2,151 563 2,714Product Mix79% 21% 100%*BOE computed on units of production using a six to one conversion ratio of MCF's to barrels.The following tables present a reconciliation of changes in our proved, probable and possible reserves by major property, on the basis of equivalent MBOE quantities.Reconciliation of Changes in Proved Reserves by Major Property DelhiField GiddingsField ProvedTotalProved reserves, MBOE MBOE MBOE MBOEJune 30, 201512,413.8 32.6 12,446.4Production(655.9) (2.9) (658.8)Revisions(934.5) (29.7) (964.2)Sales of minerals in place— — —Improved recovery, extensions and discoveries— — —June 30, 201610,823.4 — 10,823.4Reconciliation of Changes in Probable Reserves by Major Property DelhiField GiddingsField ProbableTotalProbable reserves, MBOE MBOE MBOE MBOEJune 30, 20159,339.4 — 9,339.4Revisions(4,842.1) — (4,842.1)Sales of minerals in place— — —Improved recovery, extensions and discoveries— — —June 30, 20164,497.3 — 4,497.317Reconciliation of Changes in Possible Reserves by Major Property Delhi Field GiddingsField PossibleTotalPossible reserves, MBOEMBOE MBOE MBOEJune 30, 20152,954.4 — 2,954.4Revisions(240.4) — (240.4)Sales of minerals in place— — —Improved recovery, extensions, and discoveries— — —June 30, 20162,714.0 — 2,714.0Reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash FlowsThe following table provides a reconciliation of PV-10 of our proved properties to the Standardized Measure as shown in Note 23 of the consolidated financial statements. For the Years Ended June 30, 2016 2015Estimated future net revenues$187,713,581 $448,113,94310% annual discount for estimated timing of future cash flows86,844,543 229,407,446Estimated future net revenues discounted at 10% (PV-10)100,869,038 218,706,497Estimated future income tax expenses discounted at 10%(22,911,719) (59,509,958)Standardized Measure$77,957,319 $159,196,539The following table provides a reconciliation of PV-10 of each of our proved properties to the Standardized Measure as shown in Note 23 of the consolidated financialstatements. For the Years Ended June 30, 2016 2015Delhi Field$100,869,038 $218,320,579Giddings Field— 385,918Estimated future net revenues discounted at 10% (PV-10)$100,869,038 $218,706,497Estimated future income tax expenses discounted at 10%(22,911,719) (59,509,958)Standardized Measure$77,957,319 $159,196,539Additional 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 ProcessOur policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our ExecutiveChairman, our Chief Executive Officer and our former Senior Vice President of Operations, acting as a consultant to the Company, and to be in compliance with generallyaccepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. Our Executive Chairman holds B.S. and M.E. degrees from RiceUniversity in chemical engineering and earned an M.B.A. from Harvard University. He has over 30 years of experience in engineering, energy transactions, operations andfinance with small independents, larger independents and major integrated oil companies. Our Chief Executive Officer holds a Bachelor of Business Administration degree fromthe University of Texas at Austin. He has over 30 years of experience in the energy industry, encompassing both upstream oil and gas companies and the oilfield service industry.Our Consultant has over 30 years of experience in oil and gas operations and holds a Bachelor of Science in Petroleum Engineering degree from the University of Oklahoma atNorman. The reserve information in this filing is based on estimates prepared by DeGoyler and MacNaughton, our independent engineering firm. The person responsible forpreparing the reserve report is a Registered Professional Engineer in the State of Texas and a Senior Vice President of the firm. He holds a Bachelor of Science degree inGeology in 1973 from Eastern New Mexico University and earned a Master of Science degree in Petroleum Engineering from the University of Texas at Austin in 1975.18He has over 36 years of oil and gas reservoir experience. We provide our engineering firm with property interests, production, current operating costs, current production pricesand other information. This information is reviewed by our Senior Management and outside consultant to ensure accuracy and completeness of the data prior to submission to ourindependent engineering firm. The scope and results of our independent engineering firm's procedures, as well as their professional qualifications, are summarized in the letterincluded as exhibit 99.4 to this Annual Report on Form 10-K.Proved Undeveloped ReservesOur proved undeveloped reserves were 3,655 MBOE at June 30, 2016 with associated future development costs of approximately $14.9 million. During the year endedJune 30, 2016, we incurred $16.5 million of capital spending toward proved undeveloped reserves, primarily related to the NGL plant, but the plant was not complete at the endof the year, so those reserves are still reflected as proved undeveloped. The 1,442 MBOE decrease from 5,097 MBOE at June 30, 2015 is due to a 1,091 MBOE decrease forPhase VI, a portion of the remaining undeveloped eastern area of the Delhi field that presently is uneconomic due to a lower oil price, a 154 MBOE decline in our remainingeastern area reserves and a 197 MBOE decrease in NGL plant reserves. The Phase VI eastern patterns no longer in our proved undeveloped reserves had significantly lessrecoverable reserves and higher future development costs than the Phase V project we continue to carry as proved undeveloped. There were no reclassifications of provedundeveloped reserves to probable or possible reserves.The initial assignment of proved undeveloped reserves in the Delhi field was made on June 30, 2010, which involved a large scale CO 2 enhanced oil recovery project. Theoperator’s development plans for the field have remained essentially unchanged and were originally scheduled to be completed by June 30, 2015, within five years from theinitial recording of such proved reserves. The field is approximately 66% developed as of June 30, 2016. However, as a result of the adverse fluid release event in the field inJune 2013 and the resulting delay in reversion of our working interest, development of the field was not completed as scheduled. Although no unproved reserves were convertedto proved reserves during fiscal 2015 and 2016, development expenditures were ongoing. Expansion of the CO 2 flood to the remaining undeveloped eastern portion of the fieldcommenced subsequent to reversion of our working interest in late calendar 2014. The Company incurred $3.8 million of capital expenditures until the operator suspended thisproject as a result of a significant reduction in its capital spending. During the year ended June 30, 2015 the NGL plant project and began and the Company incurred $5.0 millionof related capital expenditures. In the year ended June 30, 2016, the Company incurred an additional $16.5 million of plant capital expenditures with $3.1 million budgeted for itscompletion expected in the fourth calendar quarter of 2016. At June 30, 2016, $11.6 million of net future capital expenditures also remained for development of the eastern partof the field that was suspended in late 2014 and is now planned to continue over the next two fiscal years and is expected to be completed by December 31, 2018, approximatelyseven and one half years after the initial recording of proved reserves. The 2013 addition of the NGL plant project to recover natural gas liquids and methane required additionalplanning and has resulted in a prudent delay in the full development of the field's proved reserves. Given the nature of CO 2 EOR projects, we believe that the undevelopedreserves in the Delhi field satisfy the conditions to continue to be included as proved undeveloped reserves because (1) we established and continue to follow the previouslyadopted development plan for this project as adjusted to incorporate the completion of the NGL plant in 2016 and delays relating to the 2013 fluid release event; (2) we havesignificant ongoing development activities at this project that, as budgeted and currently being expended, reflect a significant and sufficient portion of remaining capitalexpenditures to convert proved undeveloped reserves to proved developed reserves; and (3) the operator has a historical record of completing the development of comparablelong-term projects.19Sales Volumes, Average Sales Prices and Average Production CostsThe 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, 2016 Year Ended June 30, 2015 Year Ended June 30, 2014ProductVolume Price Volume Price Volume PriceCrude oil (Bbls)658,041 $39.71 450,713 $61.59 169,783 $102.84Natural gas liquids (Bbls)491 $16.06 1,358 $27.41 3,516 $33.32Natural gas (Mcf)1,620 $1.79 7,981 $3.33 26,655 $3.60Average price per BOE*658,802 $39.68 453,401 $61.37 177,742 $99.43 Production costsAmount per BOE Amount per BOE Amount per BOEProduction costs, excluding ad valorem andproduction taxes$8,767,490 $13.31 $9,285,396 $20.48 $1,148,974 $6.46Total production costs, including ad valoremand production taxes$9,062,179 $13.76 $9,335,244 $20.59 $1,193,573 $6.72* BOE computed on units of production using a six to one conversion ratio of MCF's to barrels.Drilling ActivityOur productive drilling activity during the past three fiscal years ended June 30, 2016, was limited to one fiscal 2015 gross (.239 net) development well drilled in the Delhi field.No dry wells were drilled in the past three fiscal year s.Present ActivitiesDuring fiscal year 2015, construction of a natural gas liquids ("NGL") recovery plant commenced in the Delhi field, which will extract and sell NGL's from the field. Inaddition to the value of these hydrocarbon products, the increased purity of the CO 2 stream re-injected into the field should result in significant operational benefits to the CO 2 flood. Project construction continued during fiscal year 2016, with completion expected late in calendar 2016.During the fourth fiscal quarter of fiscal 2016, the operator of the Delhi field commenced a project to restore production in the southwestern portion of the field. Followingthe fluid release event in June 2013, CO 2 injections in this area ceased in order to reduce reservoir pressure and protect the incident area. The project includes converting threeshut-in wells to water injector wells in order to expand the water curtain barrier to reduce CO 2 migration into this area together with the installation of three electricalsubmersible pumps ("ESP") in other shut-in wells in order to increase withdrawal rates and help maintain the targeted reservoir pressure. These ESP production wells will createa modified waterflood, which is expected to increase gross oil production by an estimated 250 to 300 BOPD.For further discussion, see " Highlights for our fiscal year 2016" and "Capital Budget" under Item 7. Management's Discussion and Analysis of Financial Condition andResults of Operations of this Form 10-K.Delivery CommitmentsAs of June 30, 2016, we were not committed to provide a fixed and determinable quantity of oil, NGLs or gas under existing agreements, nor do we currently intend toenter into any such agreements.20Productive WellsThe following table sets forth the number of productive oil and gas wells in which we owned a working interest as of June 30, 2016. See discussion below related to theexpected disposition of our three company operated wells. Company Operated Non-Operated Total Gross Net Gross Net Gross NetCrude oil3 2.9 89 21.3 92 24.2Natural gas— — — — — —Total3 2.9 89 21.3 92 24.2Acreage DataThe following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2016. Developed acreage refers to acreage onwhich wells have been drilled or completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on whichwells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves. FieldDeveloped Acreage Undeveloped Acreage Total Gross Net Gross Net Gross NetDelhi Field, Louisiana*9,126 2,180 4,510 1,077 13,636 3,257Giddings Field, Texas**2,168 2,134 — — 2,168 2,134Total11,294 4,314 4,510 1,077 15,804 5,391When the Company acquired the Delhi field in 2003, the field had been fully developed through primary and secondary recovery and all of such acreage was reflectedas developed acreage. With the addition of a CO 2 -EOR project in the field, certain acreage is now reflected as undeveloped using tertiary recovery operations. We estimate thatour developed acreage currently includes 9,126 gross (2,180 net) acres in the Delhi field, with approximately 4,510 gross (1,077 net) acres attributable to the remainingundeveloped areas in the eastern part of the field. We own a 23.9% working interest in the field. We are not the operator of the EOR project.In addition, our developed acreage includes 2,168 gross (2,134 net) in the Giddings Field comprising of a 100% working interest in two producing wells and a 99%working interest in one well subject to a back-in reversion of 22.5%. None of these wells are currently producing at economic rates in the current price environment. Subsequentto year end, we transferred one well back to the previous operator under our contractual agreement. At this time, we expect to plug and abandon the other two wells.*Includes from the surface of the earth to the top of the Massive Anhydride, less and except the Delhi Holt Bryant CO 2 and Mengel Units. As the Delhi field isa unitized field, undrilled acreage is held by production as long as production is maintained in the unit.**Excludes acreage for small overriding royalty interests retained in various formations in the Giddings Field area.For more complete information regarding current year activities, including crude oil and natural gas production, refer to Item 7. Management's Discussion and Analysis ofFinancial Condition and Results of Operations of this Form 10-K.Item 3. Legal ProceedingsSee Note 18 – Commitments and Contingencies under Item 8. Financial Statements for a description of legal proceedings, which is incorporated herein by reference.Item 4. Mine Safety DisclosuresNot Applicable.21PART IIItem 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity SecuritiesCommon StockOur common stock is currently traded on the NYSE MKT under the ticker symbol "EPM". The following table shows, for each quarter of the fiscal years ended June 30,2016 and 2015, the high and low sales prices for EPM as reported by the NYSE MKT.NYSE MKT: EPM2016:High LowFourth quarter ended June 30, 2016$5.97 $4.45Third quarter ended March 31, 2016$5.12 $3.60Second quarter ended December 31, 2015$7.54 $4.70First quarter ended September 30, 2015$6.70 $4.022015:High LowFourth quarter ended June 30, 2015$7.97 $5.77Third quarter ended March 31, 2015$8.10 $5.68Second quarter ended December 31, 2014$10.25 $6.50First quarter ended September 30, 2014$11.19 $8.95Shares Outstanding and HoldersAs of June 30, 2016, there were 32,907,863 shares of common stock issued and outstanding, held by approximately 218 holders of record.DividendsWe began paying cash quarterly dividends on our common stock in December 2013, at a rate of $0.10 per share and adjusted the rate to $0.05 per share in March 2015. Asof June 30, 2016, we had paid eleven consecutive quarterly dividends on our common stock. All dividends on our Series "A" Perpetual Preferred stock have been timely declaredand paid monthly. 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 futureearnings, financial condition, applicable dividend restrictions and capital requirements and other factors deemed relevant by the Board of Directors. Under our current revolvingcredit facility, exceeding the ratio of trailing twelve month’s EBITDA minus trailing twelve month’s dividends paid to debt service, as defined, would restrict our ability to paycommon stock dividends.Performance GraphThe 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, 2011 toJune 30, 2016 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. Thegraph assumes that $100 was invested on June 30, 2011 in our common stock at the closing market price at the beginning of this period and in each of the other two indices andthe reinvestment of all dividends, if any. The graph is presented in accordance with requirements of the SEC. Shareholders are cautioned against drawing any conclusions fromthe data contained therein, as past results are not necessarily indicative of future financial performance.22Securities Authorized For Issuance Under Equity Compensation PlansPlan categoryNumber ofsecurities tobe issuedupon exerciseof outstandingoptions,warrants andrights(a) Weighted-averageexerciseprice ofoutstandingOptions, warrantsand rights(b) Number of securitiesremainingavailable for futureissuance underequity compensationplans (excludingsecurities reflectedin column (a))(1)Equity compensation plans approved by security holders: Outstanding options35,231 (1) $2.19 Outstanding contingent rights to shares91,172 (1) — Total126,403 $0.61 282,133Equity compensation plans not approved by security holders— — —Total126,403 $0.61 282,133(1)As of June 30, 2016, there were 35,231 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. Under the Plan as of June 30, 2016, 3,904,134 common shares had been issued upon theexercise of stock options, 2,187,330 shares of restricted common stock had been issued (of which 406,848 were unvested as of June 30, 2016), contingent restrictedstock grants of 91,172 shares had been reserved but not issued (all of which are unvested) and 282,133 shares of common stock remain available for future grants.23Issuer Purchases of Equity SecuritiesPeriod(a) Total Number ofShares (or Units)Purchased (1) (2) (b) Average PricePaid per Share (orUnits) (c) Total Number of Shares(or Units) Purchased as Partof Publicly Announced Plansor Programs (d) Maximum Number (orApproximate Dollar Value)of Shares (or Units) thatMay Yet Be PurchasedUnder the Plans orProgramsApril 1, 2016 to April 30, 2016none — — —May 1, 2016 to May 31, 2016none — — —June 1, 2016 to June 30, 2016229 shares of Common Stock $5.70 265,762 Approximately $3.4 million(1)During the fourth fiscal quarter ended June 30, 2016, the Company received 229 shares of common stock from certain of its employees which were surrendered inexchange for their payroll tax liabilities arising from vestings of restricted stock. The acquisition cost per share reflected the weighted-average market price of theCompany's shares at the dates vested.(2)During fiscal 2016, the Company repurchased 202,390 shares for a total cost of $1.17 million, including commissions. Under the program's terms, shares may berepurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases willdepend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and therepurchase program may be suspended or discontinued at any time. Such shares were initially recorded as treasury stock, then subsequently canceled.Item 6. Selected Financial DataThe selected consolidated financial data, set forth below should be read in conjunction with Item 7. "Management's Discussion and Analysis of Financial Condition andResults of Operations" and with the consolidated financial statements and notes to those consolidated financial statements included elsewhere in this report. June 30, 2016 2015 2014 2013 2012Income Statement Data Revenues$26,349,502 $27,841,265 $17,673,508 $21,349,920 $17,962,038Cost of revenues9,133,111 9,355,613 1,193,573 1,780,738 1,774,999Depreciation, depletion, and amortization5,165,120 3,615,737 1,228,685 1,300,207 1,136,974Accretion expense49,054 34,866 41,626 72,312 77,505General and administrative expense9,079,597 6,256,783 8,388,291 7,495,309 6,143,286Restructuring charges1,257,433 (5,431) 1,293,186 — —Income from operations1,665,187 8,583,6975,528,147 10,701,354 8,829,274Other income (expense)32,565,954 (147,619) (38,836) (43,165) 3,778Income tax provision9,570,779 3,444,221 1,891,998 4,029,761 3,700,922Net income attributable to the Company$24,660,362 $4,991,857$3,597,313 $6,628,428 $5,132,130Dividends on Series A Preferred Stock674,302 674,302 674,302 674,302 630,391Net income attributable to common shareholders$23,986,060 $4,317,555$2,923,011 $5,954,126 $4,501,739Earnings per common share: Basic$0.73 $0.13 $0.09 $0.21 $0.16Diluted$0.73 $0.13 $0.09 $0.19 $0.1424 June 30, 2016 June 30, 2015 June 30, 2014 June 30, 2013 June 30, 2012Balance Sheet Data Total current assets$37,086,450 $23,693,048 $26,304,803 $27,436,076 $16,769,789Total assets97,451,051 69,882,727 65,015,752 66,556,296 58,955,486Total current liabilities8,528,908 9,329,257 2,999,726 2,632,750 5,088,917Total liabilities21,129,901 21,306,150 13,138,230 11,720,135 12,332,698Stockholders' equity76,321,150 48,576,577 51,877,522 54,836,161 46,622,788 Number of common shares outstanding32,907,863 32,845,205 32,615,646 28,608,969 27,882,22425Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, Financial Statementsand Supplementary Data. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with RiskFactors under Item 1A of this Form 10-K, along with Forward-Looking Information at the beginning of this report for information on the risks and uncertainties that could causeour actual results to be materially different from our forward-looking statements.Executive OverviewGeneralWe are engaged primarily in the development of oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional andproprietary 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 tomaintain 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 directormaintains a beneficial ownership of our common stock.Our strategy is to grow the value of our Delhi assets to maximize the value realized by our shareholders. In addition, we plan to return cash to the shareholders in the formof quarterly cash dividends and potential stock buybacks under our previously announced share repurchase program.We expect to fund our fiscal 2017 capital program from working capital and net cash flows from our properties.Highlights for our fiscal year 2016Finances•We funded all operations, including $21.1 million of capital spending, from internal resources and remained debt free. All of our capital expenditures anddividends were funded solely by cash flow from operations and working capital and we ended our fiscal year with no funded debt.•We returned $6.6 million to common shareholders in the form of cash dividends during fiscal 2016. We remain committed to our dividend policy and rewardingour long-term shareholders.•We invested $1.2 million in our stock buyback program during fiscal 2016. We have up to $3.4 million remaining under this program.•We increased working capital to $28.6 million at June 30, 2016 compared to $14.3 million at the prior year end. At June 30, 2016, working capital included$34.1 million of cash on hand.•We entered into a new senior secured bank credit facility. The maximum borrowing base is $50.0 million; however the initial borrowing base was set at $10.0million. There are no outstanding borrowings.•Our hedging program resulted in $3.4 million in net gains during fiscal 2016. In fiscal 2016, we used derivative instruments to reduce our exposure to oil pricevolatility in order to support the capital expenditures for the Delhi NGL plant and to protect our dividend policy. We have no hedges in place beyond September 30,2016.Operations•Our fiscal 2016 net income to common shareholders was $24.0 million, a substantial increase from fiscal 2015 net income of $4.3 million. During fiscal 2016,litigation settlement proceeds, insurance proceeds and realized hedging gains contributed to significantly higher net income, offset in part by increased DD&A expenses,litigation expenses and higher income tax expense. This is our fifth consecutive year of reporting net income to common shareholders.•We settled outstanding litigation with the operator of Delhi field. In the settlement, we received $27.5 million in cash and a working interest in the Mengel Sand, aseparate interval within the Delhi field that is not currently producing. We also reached agreement on our ownership of the CO 2 recycle facility and on the long termcosts of purchased CO 2 .•Installation and construction of the NGL recovery plant at Delhi is approximately 90% complete. Technical completion and start-up of the plant is scheduled tobegin in November 2016. Our net share of capital expenditures for26this project is $24.6 million, and has been funded through cash flow from operations and working capital. Approximately $3.1 million remains to be spent as of fiscalyear end 2016.•Our net oil production volumes at Delhi increased by over 46% year over year. Monthly production has been steadily increasing over the past year as a result of aconformance program and greater efficiency with the flood. The majority of the increase in our net production stems from the reversion of our 23.9% working interestand associated 19.0% revenue interest in the Delhi field which became effective on November 1, 2014. We had only eight months of working interest volumes in theprior fiscal year.•We transferred our oilfield technology operations to a new entity and we expect annual cost reductions of approximately $1.0 million. We retained a minorityequity interest in the new Company and will receive a 5% royalty on all future gross revenues from the technology. In addition, we have an option to increase our equityownership and can use the technology in any of our operated wells.Oil & Gas Reserves (based on SEC oil price of $40.91 per barrel in effect as at June 30, 2016)•Delhi proved oil equivalent reserves at June 30, 2016 were 10.8 MMBOE , a 13% decline from the previous year. The Standardized Measure for proved reservesdeclined 51% to $78 million as a result of a 44% drop in the oil price from $72.55 to $40.91 per barrel. Proved reserves are 79% oil and 21% natural gas liquids, and66% of these reserves are developed and producing.•Delhi probable reserves at June 30, 2016 were 4.5 MMBOE , a 52% decrease over the previous year.•Delhi possible reserves at June 30, 2016 were 2.7 MMBOE , a 10% decrease over the previous year.The following table is a summary of our proved, probable and possible reserves for 2016 and 2015: Proved Probable Possible 2016 2015 Change 2016 2015 Change 2016 2015 ChangeReserves MMBOE10.8 12.4 (13)% 4.5 9.3 (52)% 2.7 3.0 (10)%% Developed66% 59% 12 % 69% 43% 60 % 72% 55% 31 %Liquids %100% 100% — % 100% 100% — % 100% 100% — %Standardized Measure$78 $159 (51)% PV-10* ($MM)$101 $219 (54)% ____________________________________________________________________________*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 DiscountedFuture Net Cash Flows ("Standardized Measure"), 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 wideuse 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 andvalue 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 gasproperties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company when estimating the amount offuture 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 operatingperformance 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 inisolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled in Item 2. Properties .ProjectsAdditional property and project information is included under Item 1. Business, Item 2. Properties, Item 8. Financial Statements - Notes to the Financial Statements andExhibit 99.4 of this Form 10-K.Delhi Field EOR—Northeast LouisianaProved reserves volumes totaled 10.8 MMBOE with a Standardized Measure of $78 million and a PV-10* value of $101 million compared to the prior year's 12.4MMBOE with a Standardized Measure of $159 million and a PV-10* value of $21927million. Our reserves quantities in the Delhi field were generally consistent with expectations year over year, especially when applying to our long life production the 44%decline in SEC oil price at Delhi from $72.55 in the prior year to $40.91 in the current year. This decline in price led to a 13% decline in proved reserves volumes reflecting prioryear production and removal of proved undeveloped reserves in Phase VI which were deemed to be uneconomic in the current price environment. Proved undeveloped reservesdeclined 1,422 MBOE to 3,655 MBOE as the result of a 1,091 MBOE negative revision due to the removal of Phase VI, the field's eastern most development site that is notdeemed to be economic at current prices, a 154 MBOE negative revision in our remaining Phase V eastern area site and a 197 MBOE negative revision in NGL plant reserves, allthree due to the reduced SEC oil price applied. The Phase VI eastern development patterns removed from our proved undeveloped reserves had significantly lower recoverablereserves and higher costs than the other Phase V eastern patterns we retained.The reserves report reflects the conveyance, effective July 1, 2016, of a 0.2226% overriding royalty interest to the operator of Delhi as part of the litigation settlementagreement.Our cost of purchased CO 2 in the Delhi field, the largest component of operating costs and the majority of our operating costs, is directly tied to the price of oil sold fromthe field. Therefore this major operating cost has dropped commensurate with the price of crude. Also, we have been successful in realizing a substantial reduction in aggregateCO 2 injection rate without impacting oil production rates. Gross injection rates for the year ended June 30, 2016 averaged 74 MMCF/D, a decline of 30% compared to the 106MMCF/D during fiscal 2015 post-reversion period. We have also seen significant reductions in most categories of lease operating expenses, including decreased workover costs,lower power costs due to lower usage and lower contract labor and chemical costs. The combined effect of this has resulted in six sequential quarters of lower Delhi lifting costsper BOE from approximately $19 per BOE to approximately $12 per BOE.Probable reserve volumes at Delhi were 4.5 MMBOE, compared to 9.3 MMBOE in the prior year. There were a number of projects included in probable reserves in theprior year which are not considered economic in the current price environment. A lesser portion of these revisions resulted from changes to the operators' long-term developmentplans for the field. Possible reserves volumes at Delhi were 2.7 MMBOE, compared to 3.0 MMBOE in the prior year.Gross production at Delhi in the fourth quarter of fiscal 2016 was 6,964 barrels of oil per day (“BOPD”), up 1% from the third fiscal quarter’s 6,918 BOPD. Productionvolumes net to the Company were 1,841 BOPD and 1,829 BOPD, respectively. We expect production from the field to average approximately 7,000 BOPD until potentialadditional volumes are realized from the NGL recovery plant startup in late calendar 2016.The construction and installation of the NGL plant is approximately 90% complete, with the plant startup scheduled to occur in November 2016. The plant has a totalestimated cost of approximately $24.6 million net to Evolution, of which approximately $21.5 million had been incurred as of June 30, 2016. As previously discussed, themethane produced from the plant will be used to generate electricity and other power requirements for the field, which will substantially reduce operating costs. The NGL plantshould also increase the efficiency of the CO 2 flood and is expected to result in incremental production of crude oil.Remaining estimated capital expenditures amount to $8.12 per BOE for Phase V included in proved undeveloped reserves. Given the geology of the Delhi field, noremaining estimated capital expenditures are required to develop our probable or possible reserves as these reserves reflect incremental quantities associated with a greaterpercentage recovery of hydrocarbons in place than the recovery quantities assumed for proved reserves. Looking forward, the timing of plans for continued development of theeastern part of the Delhi field is dependent on the operator’s plans for capital allocation within their portfolio. We continue to believe that this high quality and economicallyviable project will be executed as planned, subject to oil price volatility.GARP ® - Artificial Lift TechnologyAs a result of a strategic review, Company management recommended and the Board approved a transfer of a majority interest in our GARP ® oilfield technologyoperations to a new unaffiliated entity, led by our former SVP of Operations, who invented the technology, effective December 31, 2015. Evolution retained a minority equityinterest in the new company and have the option to convert part of our funding into a substantially increased equity stake in the future. In addition, the Company retains a 5%royalty on all future gross revenues associated with the GARP ® technology. The three Evolution employees who had primary responsibilities for our GARP ® operations,including our former SVP of Operations, a GARP ® sales engineer and a field superintendent, have become full-time employees of the new company and have ceased to beemployees of Evolution. The separation of this operation is expected to reduce the Company's ongoing general and administrative costs by approximately $1 million per year. The combined costs of severance and other related expenses resulted in a one-time restructuring charge in the second fiscal quarter ended December 31, 2015.28Other FieldsDuring fiscal 2016, we operated, produced and sold crude oil, natural gas and natural gas liquids from three legacy wells in the Giddings field area in central Texas. Due todeclining production and depressed commodity prices, two wells have now been temporarily abandoned, and one well bore was returned to the previous operator per contractualagreement, as of August 2016. The financial impact of these wells were immaterial to our full year financial results. There are no current year reserves associated with these wellscompared to 30 MBOE of proved reserves at June 30, 2015.In October 2014, we closed on the sale of all of our remaining noncore mineral interests and assets in the Mississippi Lime project for cash proceeds of approximately$389,165, net of customary closing adjustments. This transaction completes the process of divesting of all of our non-core oil and gas properties. No reserves were associatedwith these assets as of June 30, 2015 or 2014.Liquidity and Capital ResourcesWe have historically funded our operations through cash available from operations. Our primary sources of cash in fiscal 2016 were from funds generated from the sale ofoil and natural gas production and the litigation settlement. A portion of these cash flows were used to fund our capital expenditures. While we will continue to develop ourproperties near term, such development will be more limited while commodity prices remain low and unstable. The Company will manage any development activity in thecontext of its operating cash flow and existing working capital.On April 11, 2016, the Company entered into a new credit agreement with MidFirst Bank (the "Facility"). The Facility replaces the Company’s previous unsecured creditfacility which was set to expire on April 29, 2016 and was terminated in early April. The Facility provides a senior secured revolving credit facility with an initial borrowing baseof $10.0 million (the “Borrowing Base”) and a maximum borrowing amount of $50.0 million. The Facility matures on April 11, 2019, and is secured by substantially all of theCompany’s assets. The Borrowing Base is subject to periodic redeterminations and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on eachMay 15 and November 15, beginning November 15, 2016. The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gasproperties of the Company or its subsidiaries and cancellation of certain hedging positions. With the recent volatility in commodity prices, our borrowing base and relatedcommitments under the Facility could be reduced in the future. The Facility allows for Eurodollar Loans and Base Rate Loans, each as defined in the Facility. The interest rate on each Eurodollar Loan will be the lesser of (1) theadjusted LIBOR for the applicable interest period plus 275 basis points or (2) the Maximum Rate, as defined. The annual interest rate on each Base Rate Loan is the lesser of (1)the Prime Rate plus 100 basis points or (2) the Maximum Rate. The Facility contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a debt servicecoverage ratio of not less than 1.1 to 1.0 and (iii) a consolidated tangible net worth of not less than $40 million, each as defined in the Facility. The Facility also contains otheraffirmative and negative covenants and events of default. As of June 30, 2016, the Company was in compliance with all covenants contained in the Facility, and no amounts wereoutstanding under the Facility.We had $34.1 million and $20.1 million in cash and cash equivalents at June 30, 2016 and June 30, 2015 , respectively.During our fiscal year ended June 30, 2016 , we financed our operations and capital spending with net cash generated from operations and cash on hand. At June 30, 2016 ,our working capital was $28.6 million , compared to working capital of $14.4 million at June 30, 2015 . The $14.2 million working capital increase is primarily due to a $13.9million increase in cash.Cash Flows from Operating ActivitiesFor the year ended June 30, 2016 , cash flows provided by operating activities were $30.7 million , reflecting $28.9 million provided by operations before $1.8 millionprovided by other working capital changes. Of the $28.9 million provided before working capital changes, approximately $24.7 million resulted from net income and $4.2million was attributable to non-cash expenses and gains.For the year ended June 30, 2015, cash flows provided by operating activities were $10.4 million, reflecting $10.9 million provided by operations before $0.5 million usedby other working capital changes. Of the $10.9 million provided before working capital changes, approximately $5.0 million resulted from net income and $5.9 million wasattributable to non-cash expenses.29For 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 millionprovided by other working capital changes. Of the $7.7 million provided before working capital changes, $3.6 million resulted from net income and $4.1 million was attributableto non-cash expenses.Cash Flows from Investing ActivitiesFor the year ended June 30, 2016 , investing activities used $17.6 million of cash, consisting primarily of capital expenditures of approximately $21.1 million for Delhifield partially offset by $3.7 million of derivative settlement payments received.For the year ended June 30, 2015, investing activities used $5.0 million of cash, consisting primarily of capital expenditures of approximately $4.9 million for Delhi field,$0.3 million for artificial lift technology together with $0.2 million of other assets comprised primarily of GARP ® patent costs, partially offset by $0.4 million of proceedsreceived for the sale of properties in the Mississippi Lime project in October 2014.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 Giddingsand continuing costs for wells drilled in the Mississippi Lime during the prior year. We received approximately $0.5 million of proceeds from asset sales, including $0.4 millionfrom the December sale of our South Texas properties, and $0.3 million of cash from the maturity of a certificate of deposit.Oil and gas capital expenditures incurred, which includes accrued expenditures and other noncash items, were $19.7 million, $11.2 million , and $1.2 million , respectively,for the years ended June 30, 2016 , 2015 , and 2014 . These amounts can be reconciled to cash capital expenditures on their respective cash flow statements by adjusting them forrelated non-cash items presented at Note 13 - Supplemental Cash Flow Information.Cash Flows from Financing ActivitiesFor the year ended June 30, 2016, financing activities provided $0.9 million of cash from $9.6 million of tax benefits related to stock-based compensation partially offsetby $7.2 million of dividend payments to common and preferred shareholders and $1.4 million of treasury stock acquisitions primarily attributable to the Company's sharebuyback program. The tax benefits included a $1.5 million cash refund received from the State of Louisiana for carryback of stock-based compensation deductions to previouslyfiled returns.During the year ended June 30, 2015, we used $9.2 million in cash for financing activities, reflecting $9.8 million of common stock dividend payments, $0.7 million ofpreferred stock dividends and $0.3 million of treasury stock acquired through the surrender of shares by certain officers and employees in satisfaction of payroll liabilities relatedto stock-based compensation and open market purchases under our stock repurchase program, partially offset by cash inflows of $1.6 million from a tax benefit related to stock-based compensation and $0.1 million from stock option exercises.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 ofpreferred 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 relatedto 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.Capital BudgetDelhi FieldDuring fiscal 2016, our net share of capital expenditures was approximately $19.0 million, all which was incurred at Delhi and primarily for the NGL plant. There havebeen and will continue to be recurring maintenance capital expenditures required for a field of this size. These expenditures are generally for testing and strengthening of wellbore integrity, including previously plugged wells, drilling and completion of monitoring wells and larger projects to recomplete or workover wells which may be capitalizedinstead of being charged to operating expenses.Known capital expenditures over the next fiscal year are expected to total approximately $3.1 million, net to our working interest, primarily for the remaining costs of theNGL plant. There will likely be additional maintenance capital expenditures, but the amount of these is not expected to be material to our financial position and cannot beestimated accurately at this time.After completion of the NGL plant, there are two remaining capital projects to exploit the eastern part of the Delhi field. The first phase of this project was underway in thefall of 2014, immediately after reversion of our working interest. However, based on the decline in oil prices, the operator significantly reduced its capital budget and suspendedwork on this phase. The resumption of this project is dependent on prevailing oil prices, the availability of capital for such projects and the relative30economics of this project versus other projects in the operator's portfolio. We believe this Phase V project, which has an estimated cost of $11.5 million net to our workinginterest, has favorable economics, even in this lower price environment, and expect the expansion of the CO 2 flood to resume within the next two years. Phase VI has lessfavorable economics and will require a significant increase in oil prices or other improvements to the economics of the project before it is expected to move forward. Theeconomics of both projects will be improved subsequent to the completion and startup of the NGL recovery plant in late calendar 2016.Liquidity OutlookOur current liquidity position is very strong, with $28.6 million of working capital, which is significantly in excess of our expected capital needs and we also expectpositive cash flow in the future. Our future liquidity will be impacted by changes in the realized prices we receive for the oil, natural gas and natural gas liquids we produce andthe costs associated with that production. Commodity prices are market driven and historically volatile, and they are likely to continue to be volatile. In June 2015, the Companybegan using derivative instruments to reduce its exposure to oil price volatility for a portion of its near-term forecasted production in order to achieve a more predictable level ofcash flows to support the Company’s capital expenditure and dividend programs. Costless collars and swaps used by the Company to manage risk are designed to establish floorprices on anticipated future oil production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit futurerevenues from favorable price movements. Our future revenues, cash flow, profitability, access to capital and future rate of growth are significantly impacted by the prices wereceive for our production.Funding for our anticipated capital expenditures over the next two fiscal years is expected to be met from cash flows from operations and current working capital. Ourpreference is to remain debt free under our current operating plans, but we have access to a senior secured credit facility for oil and gas development as required. In addition wehave an effective shelf registration statement with Securities and Exchange Commission. We may choose to evaluate new growth opportunities through acquisitions or othertransactions. In that event, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be advantageousfor us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do so at this time.The Board of Directors instituted a cash dividend on our common stock in December 2013 and have since paid eleven consecutive quarterly dividends and have declaredthe twelfth dividend for payment on September 30, 2016. In addition, in May 2015, we established a stock repurchase plan to allow us acquire up to $5.0 million of our commonstock over time. During fiscal 2016, we spent $1.2 million on stock repurchases. Return of free cash flow in excess of our operating and capital requirements to our shareholdersthrough cash dividends and repurchases of our common stock remains a priority of our financial strategy, and it is our near term goal to increase our dividends over time asappropriate.31Results of OperationsThe following table sets forth certain financial information with respect to our oil and natural gas operations: Year Ended June 30, 2016 2015 2014Oil and gas production: Crude oil revenues$26,130,762 $27,761,291 $17,460,392NGL revenues7,885 37,227 117,166Natural gas revenues2,895 26,601 95,950Total revenues$26,141,542 $27,825,119 $17,673,508 Crude oil volumes (Bbl)658,041 450,713 169,783NGL volumes (Bbl)491 1,358 3,516Natural gas volumes (Mcf)1,620 7,981 26,655Equivalent volumes (BOE)658,802 453,401 177,742 Equivalent volumes per day (BOE/D)1,800 1,242 487 Crude oil price per Bbl$39.71 $61.59 $102.84NGL price per Bbl16.06 27.41 33.32Natural gas price per Mcf1.79 3.33 3.60Equivalent price per BOE$39.68 $61.37 $99.43 Production costs (a)$9,062,179 $9,335,244 $1,193,573Production costs per BOE$13.76 $20.59 $6.72 Oil and gas DD&A (b)$4,906,123 $3,220,990 $1,192,370Oil and gas DD&A per BOE$7.45 $7.10 $6.71 Artificial lift technology services: Services revenues$207,960 $16,146 $—Cost of service70,932 20,369 —Depreciation and amortization expense$238,475 $374,371 $—(a) Includes ad valorem and production taxes of $294,689 , $49,848 , and $44,599 in for the years ended June 30, 2016 , 2015 , and 2014 , respectively.(b) Excludes depreciation and amortization expense of artificial lift technology services below and excludes non-operating asset depreciation of $20,522 , $20,376 , and $36,315 for the yearsended June 30, 2016 , 2015 , and 2014 , respectively.Year ended June 30, 2016 compared with the Year ended June 30, 2015Net Income Available to Common Stockholders . For the year ended June 30, 2016, we generated net income to common shareholders of $24.0 million, or $0.73 per dilutedshare, on total revenues of $26.3 million. This compares to net income of $4.3 million, or $0.13 per diluted share, on total revenues of $27.8 million for the year-ago period. The$19.7 million earnings increase resulted from $28.1 million from the Delhi field litigation settlement, $1.1 million from an insurance recovery, and $3.5 million of derivativegains, partially offset by $6.1 million of higher income taxes, $1.5 million of lower revenue, and $5.4 million of higher operating expenses (which includes a $1.3 million non-recurring restructuring charge).Oil and Gas Production . Revenues decreased $1.7 million to $26.1 million primarily as a result of a 35% decline in realized prices from $61.37 per equivalent barrel in the year-ago period to $39.68 per barrel in the current period, partially offset by a 45% increase in production volumes. The year-ago period did not include a full twelve months of netproduction and revenues or production costs as reversion of our working interest did not occur until November 1, 2014. Delhi oil production and32revenues comprise virtually all of our revenues. Delhi gross production of 6,778 BOPD was 12% higher that the average gross production of 6,038 BOPD in the year-ago periodas a result of production enhancement and conformance operations in the field.Production Costs. Production costs for the current period decreased $0.2 million to $9.1 million from $9.3 million in the prior year period due to a $0.6 million decrease for theCompany's operated wells as a result of workover expense in the prior year, partially offset by $0.4 million increase at the Delhi field. The year-ago period did not include a fulltwelve months of net production costs as reversion of our Delhi working interest did not occur until November 1, 2014. Delhi production costs for the current period were $8.9million of which $4.1 million was for CO 2 costs, compared to $8.5 million, of which $5.1 million was for CO 2 costs, in the year-ago period. Average gross injection volumesdecreased from 105,848 Mcf per day in the post-reversion prior year period to 73,762 Mcf per day for the year ended June 30, 2016. For the year ended June 30, 2016,production costs were $13.76 per BOE on total production volumes. Production costs were $18.90 per BOE calculated solely on our Delhi working interest volumes, whichincludes $8.66 per working interest BOE for CO 2 costs. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, whichbear no production costs, and are therefore higher than the rates per BOE on our total production volumes.Artificial Lift Technology Services . Service revenues were $0.2 million for the year ended June 30, 2016 as a result of current year installations at third party wells. Prior yearservice revenues and costs were negligible.Cost of Artificial Lift Technology Services. Cost of technology services were $0.1 million for the year ended June 30, 2016 as a result of current year project activity.General and Administrative Expenses (“G&A”) . G&A expenses increased $2.8 million, or 45%, to $9.1 million for the year ended June 30, 2016 from the year-ago period, as aresult of a $1.7 million increase in litigation costs and $0.8 million of stock compensation expense. Total litigation costs for the current year were approximately $2.7 million. InJune, 2016, we relocated our office to substantially smaller and less expensive premises. This cost savings will be reflected in future operations.Restructuring charge . Effective December 31, 2015, we recognized a $1.3 million restructuring charge related to the separation of our GARP® artificial lift technologyoperations. Approximately $0.6 million of the charge consists of the impairment of assets used in that operation and $0.6 million was associated with accrued personneltermination costs to be paid from January 2016 through June 2017. Such termination costs also include approximately $0.1 million of non-cash stock compensation expense fromthe accelerated vesting of restricted stock. As a result of the restructuring, future annual overhead cost savings are estimated to be approximately $1.0 million per year.Other Income and Expenses . During the year ended June 30, 2016, the Company realized gains of $28.1 million from the Delhi field litigation settlement, $3.4 million of gainson derivatives and $1.1 million from an insurance recovery at the Delhi field.Depletion & Amortization Expense (“DD&A”) . DD&A increased $1.5 million, or 43% to $5.2 million for the current period compared to $3.6 million for the year-ago period asa result of $1.7 million of higher amortization of the full cost pool, partially offset by $0.1 million of lower depreciation on artificial lift technology. Compared to the prior year,production volumes increased 45% to 0.7 million BOE and the amortization rate increased 5% to $7.45 per BOE. Compared to the prior year, the higher amortization rate wasdue to an 18% decrease in our pool of unamortized costs, partially offset by a 13% decline in proved reserves BOE.Year ended June 30, 2015 compared with the Year ended June 30, 2014Net Income Available to Common Shareholders . For the year ended June 30, 2015, we generated net income of $4.3 million or $0.13 per diluted share on total revenues of$27.8 million. This compares to net income of $2.9 million, or $0.09 per diluted share, on total revenues of $17.7 million for the prior fiscal year. Earnings increased by $1.4million, reflecting $10.2 million of higher revenue together with $2.1 million of lower G&A and $1.3 million of restructuring expenses in the prior year, partially offset by $8.1million of higher production costs, $2.4 million of increased DD&A and $1.6 million of higher income taxes.Oil and Gas Production . Revenues increased to $27.8 million primarily as a result of a 155% increase in production volumes from the prior fiscal year due to the November 1,2014 reversion of our Delhi working interest, partially offset by a 38% decline in realized prices from $99.43 per equivalent barrel to $61.37 per barrel in the current period.Delhi oil production and revenues comprise virtually all of our fiscal 2015 revenues. The $10.2 million revenue increase was due to a $10.7 million increase at Delhi, offset by a$0.5 million decline at our operated properties reflecting previous Mississippi Lime and South Texas divestitures. Delhi gross production decreased 0.6% from 6,078 BOPD inthe prior year to 6,038 BOPD in the current year.33Production Costs . Production costs for the current period increased $ 8.1 million to $9.3 million from $1.2 million in the prior year period due to a $8.5 million increase at theDelhi field, partially offset by a $0.4 million decrease for the Company's operated wells reflecting the divestitures of non core properties. There were no Delhi production costs inthe prior fiscal year as those revenues were derived solely from our mineral and overriding royalty interests, which bear no operating expenses. The current period does notinclude a full twelve months of net production costs as reversion of our Delhi working interest did not occur until November 1, 2014. Of the $8.5 million of Delhi productioncosts incurred in the current year, $5.1 million was for CO2 costs. For the year end June 30, 2015, production costs were $20.59 per BOE on total production volumes. From ourNovember 1, 2014 working interest reversion to June 30, 2015, production costs were $29.89 per BOE calculated solely on our Delhi working interest volumes, which includes$17.72 per working interest BOE for CO 2 costs. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, which bear noproduction costs, and are therefore higher than the rates per BOE on our total production volumes.General and Administrative Expenses (“G&A”) . G&A expenses decreased $2.1 million, or 25%, to $6.3 million during the year ended June 30, 2015 from $8.4 million in theprior year primarily due to fiscal 2014 non-recurring charges of $0.8 million related to stock option exercises and $0.6 million related to the retirement of our chief financialofficer, a $0.6 million decrease in personnel-related costs as a result of our December 2013 restructuring, and a $0.7 million decline in accrued incentive compensation, partiallyoffset by $0.4 million of higher legal expenses. This fiscal 2014 restructuring charge of $1.3 million consisted of $0.9 million of termination benefits and $0.4 million non-cashcharge for accelerated restricted stock vesting for terminated employees.Restructuring Charges. The Company recorded $1.3 million of restructuring expense in December 2013 primarily reflecting $956,000 of termination benefits to be paid fromJanuary to December 2014 and $376,000 of non-cash stock compensation expense for accelerated restricted stock vesting for terminated employees. All restructuring obligationshad been satisfied by December 31, 2014. See Note 8 - Restructuring.Depletion & Amortization Expense (“DD&A”) . DD&A increased $2.4 million, or 194%, to $3.6 million for the year ended June 30, 2015 from $1.2 million for the prior yeardue to $2.0 million increase in amortization of our full cost oil and gas property cost pool and a $0.3 million impairment charge for GARP® equipment installations on threeunder performing wells of a third party customer. The remaining expense increase was primarily the result of higher depreciation of artificial lift equipment placed in serviceduring fiscal 2015. The $2.0 million increase in full cost pool depletion was primarily due to higher volume generated from the reversionary working interest. For fiscal 2015 thedepletion rate was $7.10 per BOE compared to $6.71 in the prior year. The increase in rate was impacted by a higher estimated cost for the Delhi field NGL plant at June 30,2015.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 inrecent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfieldservices, oilfield equipment, tubulars, labor, expertise and other services greatly impact our lease operating expenses and our capital expenditures. During fiscal 2016, we haveseen some declines in operating and capital costs as a result of lower demand and excess supply of good and services in the industry. Product prices, operating costs anddevelopment costs may not always move in tandem. Known Trends and Uncertainties. General worldwide economic conditions, as well as economic conditions for the oil and gas industry specifically, continue to beuncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which impact demand for crude oiland natural gas. If demand for oil gas decreases or there is a continuing excess supply in the future, it may put downward pressure on crude oil and natural gas prices, therebylowering our revenues and working capital going forward. Seasonality. Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of ourpetroleum products. Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, drivenby summer cooling and driving, winter heating, and extremes in seasonal weather including hurricanes that may substantially affect oil and natural gas production and imports.34Contractual Obligations and Other CommitmentsThe table below provides estimates of the timing of future payments that, as of June 30, 2016 , we are obligated to make under our contractual obligations andcommitments. We expect to fund these contractual obligations with cash on hand and cash generated from operations. Payments Due by Period Total Less than1 Year 1 - 3 Years 3 - 5 Years More than 5 YearsContractual Obligations Operating lease$220,292 $80,235 $140,057 — —Other Obligations Asset retirement obligations962,196 201,896 — — 760,300Total obligations$1,182,488 $282,131 $140,057 $— $760,300As discussed at Note 6 – Property and Equipment, we have a $3.1 million capital expenditure commitment related to the completion of the NGL plant at the Delhi Fieldwhich we expect to fund in the first quarter of fiscal 2017.Critical Accounting Policies and EstimatesThe preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certainaccounting 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 thedate 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 significanteffect on our consolidated financial statements. Our significant accounting policies are included in Note 2 to the consolidated financial statements. Following is a discussion ofour 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 gasindustry. 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, thecosts of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directlyrelated to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gainor 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 andproved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded representinvestments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and explorationdrilling 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, 2016, we hadno 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. Theestimated 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 indetermining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in theevaluation of all available geological, geophysical, engineering and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based onthe 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 everyreasonable effort is made to ensure that the reported reserve estimates represent the most accurate assessments possible, including the hiring of independent engineers to prepareour reserve estimates, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in ourfinancial statements. Material revisions to reserve estimates and / or significant changes in commodity prices could substantially affect our estimated future net cash flows of ourproved reserves, affecting our quarterly ceiling test calculation and could significantly affect our depletion rate. A 10% decrease in commodity prices used to determine ourproved reserves and Standardized Measure as of June 30, 2016 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, 2016 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately$248,000, $524,000 and $831,000, respectively.35On 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 inevaluating 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 todisclose 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 arithmeticaverage 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 oncapitalized 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 estimatesand 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 financialreporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared or filed; therefore, weestimate 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 carryforwards. 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 likelihoodthat 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 suchdeferred 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, 2016, we have recorded avaluation allowance for the portion of our net operating loss that is limited by IRS Section 382.Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making the assessment of theultimate 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 taxassets 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 ourestimates 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 notprobable.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 methodrequires the input of certain assumptions, including expected stock price volatility, expected term of the award, the expected risk-free interest rate, and the expected dividendyield 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 ourlimited 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 baseour 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 whileoperating 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 theamount of expense we recognize for our stock-based compensation awards.Off Balance Sheet ArrangementsThe Company has no off-balance sheet arrangements as of June 30, 2016 .Item 7A. Quantitative and Qualitative Disclosures About Market RisksInterest Rate RiskWe 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 useinterest rate derivative instruments to manage exposure to interest rate changes.Commodity Price RiskOur 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 declinesignificantly, 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 accountingrules 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 borrowand raise additional capital, as, if and when needed. We use derivative instruments to36manage our exposure to commodity price risk from time to time based on our assessment of such risk. We primarily utilize swaps and costless collars to reduct the effect of pricechanges on a portion of our future oil production. We do not enter into derivative instruments for trading purposes.37Item 8. Financial StatementsIndex to Consolidated Financial Statements Reports of Independent Registered Public Accounting Firm39 Consolidated Balance Sheets as of June 30, 2016 and 201541 Consolidated Statements of Operations for the Years ended June 30, 2016, 2015, and 201442 Consolidated Statements of Cash Flows for the Years ended June 30, 2016, 2015, and 201443 Consolidated Statements of Stockholders' Equity for the Years ended June 30, 2016, 2015, and 201444 Notes to Consolidated Financial Statements4538REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and StockholdersEvolution Petroleum Corporation We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and subsidiaries (the “Company”) as of June 30, 2016 and 2015, and therelated consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the three years in the period ended June 30, 2016. These financialstatements 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 andperform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made bymanagement, 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 andsubsidiaries as of June 30, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2016, in conformity withU.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, 2016, based on criteria established in Internal Control - Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission in 2013, and our report dated September 9, 2016 expressed an unqualified opinion on the effectiveness of Evolution PetroleumCorporation’s internal control over financial reporting.Hein & Associates LLPHouston, TexasSeptember 9, 201639REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Board of Directors and StockholdersEvolution Petroleum CorporationWe have audited Evolution Petroleum Corporation's internal control over financial reporting as of June 30, 2016, based on criteria established in Internal Control - IntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Evolution Petroleum Corporation’s management is responsible formaintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanyingManagement’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting basedon 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 performthe audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining anunderstanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness ofinternal 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 auditprovides 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 offinancial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes thosepolicies 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 thecompany; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally acceptedaccounting 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 materialeffect 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 tofuture 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 maydeteriorate. In our opinion, Evolution Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of June 30, 2016, based on criteriaestablished in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of EvolutionPetroleum Corporation and subsidiaries as of June 30, 2016 and 2015, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows foreach of the three years in the period ended June 30, 2016 and our report dated September 9, 2016 expressed an unqualified opinion.Hein & Associates LLPHouston, TexasSeptember 9, 201640Evolution Petroleum Corporation and SubsidiariesConsolidated Balance Sheets June 30, 2016 June 30, 2015Assets Current assets Cash and cash equivalents$34,077,060 $20,118,757Receivables2,638,188 3,122,473Deferred tax asset105,321 82,414Derivative assets, net14,132 —Prepaid expenses and other current assets251,749 369,404Total current assets37,086,450 23,693,048Property and equipment, net of depreciation, depletion, and amortization Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization59,970,463 45,186,886Other property and equipment, net28,649 276,756Total property and equipment, net59,999,112 45,463,642Other assets365,489 726,037Total assets$97,451,051 $69,882,727Liabilities and Stockholders' Equity Current liabilities Accounts payable$5,809,107 $8,173,878Accrued liabilities and other2,097,951 855,373Derivative liabilities, net— 109,974State and federal taxes payable621,850 190,032Total current liabilities8,528,908 9,329,257Long term liabilities Deferred income taxes11,840,693 11,242,551Asset retirement obligations760,300 715,767Deferred rent— 18,575Total liabilities21,129,901 21,306,150Commitments and contingencies (Note 18) 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, 317,319shares issued and outstanding at June 30, 2016 and 2015, respectively, with a total liquidation preference of $7,932,975 ($25.00 per share)317 317Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,907,863 and 32,845,205 shares as of June 30, 2016 and2015, respectively32,907 32,845Additional paid-in capital47,171,563 36,847,289Retained earnings29,116,363 11,696,126Total stockholders' equity76,321,150 48,576,577Total liabilities and stockholders' equity$97,451,051 $69,882,727 See accompanying notes to consolidated financial statements.41Evolution Petroleum Corporation and SubsidiariesConsolidated Statements of Operations Years Ended June 30, 2016 2015 2014Revenues Crude oil$26,130,762 $27,761,291 $17,460,392Natural gas liquids7,885 37,227 117,166Natural gas2,895 26,601 95,950Artificial lift technology services207,960 16,146 —Total revenues26,349,502 27,841,265 17,673,508Operating costs Production costs9,062,179 9,335,244 1,193,573Cost of artificial lift technology services70,932 20,369 —Depreciation, depletion and amortization5,165,120 3,615,737 1,228,685Accretion of discount on asset retirement obligations49,054 34,866 41,626General and administrative expenses*9,079,597 6,256,783 8,388,291Restructuring charges1,257,433 (5,431) 1,293,186Total operating costs24,684,315 19,257,568 12,145,361Income from operations1,665,187 8,583,697 5,528,147Other Gain on settled derivative instruments, net3,315,123 — —Gain (loss) on unsettled derivative instruments, net124,106 (109,974) —Delhi field litigation settlement28,096,500 — —Delhi field insurance recovery related to pre-reversion event1,074,957 — —Interest and other income26,211 35,991 30,256Interest (expense)(70,943) (73,636) (69,092)Income before income tax provision34,231,141 8,436,078 5,489,311Income tax provision9,570,779 3,444,221 1,891,998Net income attributable to the Company24,660,362 4,991,857 3,597,313Dividends on preferred stock674,302 674,302 674,302Net income attributable to common shareholders$23,986,060 $4,317,555 $2,923,011Earnings per common share Basic$0.73 $0.13 $0.09Diluted$0.73 $0.13 $0.09Weighted average number of common shares outstanding Basic32,810,375 32,817,456 30,895,832Diluted32,861,231 32,924,018 32,564,067_______________________________________________________________________________*General and administrative expenses for the years ended June 30, 2016, 2015 and 2014 included non-cash stock-based compensation expense of $1,750,209 , $943,653 ,and $1,352,322 , respectively. These years also included litigation expenses of $2,729,755 , $1,015,105 , and $300,564 , respectively.See accompanying notes to consolidated financial statements.42Evolution Petroleum Corporation and SubsidiariesConsolidated Statements of Cash Flows Years Ended June 30, 2016 2015 2014Cash flows from operating activities Net income attributable to the Company$24,660,362 $4,991,857 $3,597,313Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization5,211,494 3,664,373 1,272,778Impairments included in restructuring charge569,228 — —Stock-based compensation1,750,209 943,653 1,352,322Stock-based compensation related to restructuring59,339 — 376,365Accretion of discount on asset retirement obligations49,054 34,866 41,626Settlement of asset retirement obligations— (223,564) (315,952)Deferred income taxes575,235 1,422,489 1,344,812Deferred rent— (17,145) (17,145)(Gain) loss on derivative instruments, net(3,439,229) 109,974 —Noncash (gain) on Delhi field litigation settlement(596,500) — —Write-off of deferred loan costs50,414 — —Changes in operating assets and liabilities: Receivables484,285 (1,665,261) 507,592Prepaid expenses and other current assets24,754 378,049 (480,899)Accounts payable and accrued expenses822,730 551,452 663,645Income taxes payable431,818 190,032 (233,548)Net cash provided by operating activities30,653,193 10,380,775 8,108,909Cash flows from investing activities Derivative settlements received3,633,831 — —Proceeds from asset sales— 398,242 542,347Development of oil and natural gas properties(21,095,901) (4,890,909) (966,931)Acquisitions of oil and natural gas properties— — (59,315)Capital expenditures for technology and other equipment(6,883) (313,059) (312,890)Maturities of certificates of deposit— — 250,000Other assets(161,345) (236,559) (202,017)Net cash used by investing activities(17,630,298) (5,042,285) (748,806)Cash flows from financing activities Proceeds from the exercise of stock options51,000 141,600 3,252,801Acquisitions of treasury stock(1,357,185) (333,841) (1,655,251)Common stock dividends paid(6,565,823) (9,833,642) (9,723,833)Preferred stock dividends paid(674,302) (674,302) (674,302)Deferred loan costs(168,972) (94,075) (63,535)Tax benefits related to stock-based compensation9,650,657 1,633,946 509,096Other33 67 6,850Net cash provided (used) by financing activities935,408 (9,160,247) (8,348,174)Net increase (decrease) in cash and cash equivalents13,958,303 (3,821,757) (988,071)Cash and cash equivalents, beginning of year20,118,757 23,940,514 24,928,585Cash and cash equivalents, end of year$34,077,060 $20,118,757 $23,940,514See accompanying notes to consolidated financial statements.43Evolution Petroleum Corporation and SubsidiariesConsolidated Statement of Changes in Stockholders' EquityFor the Years Ended June 30, 2016 , 2015 and 2014 Preferred Common Stock AdditionalPaid-inCapital RetainedEarnings TreasuryStock TotalStockholders'Equity Shares Par Value Shares Par Value Balance, June 30, 2013317,319 $317 28,608,969 $29,410 $31,813,239 $24,013,035 $(1,019,840) $54,836,161Issuance of restricted common stock— — 39,732 40 (40) — — —Exercise of warrants— — 905,391 905 (905) — — —Exercise of stock options— — 3,299,367 3,299 3,868,108 — — 3,871,407Forfeitures of restricted stock— — (51,099) (51) 51 — — —Acquisition of treasury stock— — (186,714) — — — (2,273,857) (2,273,857)Retirements of treasury stock— — — (988) (3,292,709) — 3,293,697 —Stock-based compensation— — — — 1,728,687 — — 1,728,687Tax benefits related to stock-based compensation— — — — 509,096 — — 509,096Net income— — — — — 3,597,313 — 3,597,313Common stock cash dividends— — — — — (9,723,833) — (9,723,833)Preferred stock cash dividends— — — — — (674,302) — (674,302)Recovery of short swing profits— — — — 6,850 — — 6,850Balance, June 30, 2014317,319 317 32,615,646 32,615 34,632,377 17,212,213 — 51,877,522Issuance of restricted common stock— — 213,466 214 (147) — — 67Exercise of stock options— — 87,000 87 141,513 — — 141,600Acquisition of treasury stock— — (70,907) — — — (504,124) (504,124)Retirements of treasury stock— — — (71) (504,053) — 504,124 —Stock-based compensation— — — — 943,653 — — 943,653Tax benefits related to stock-based compensation— — — — 1,633,946 — — 1,633,946Net income— — — — — 4,991,857 — 4,991,857Common stock cash dividends— — — — — (9,833,642) — (9,833,642)Preferred stock cash dividends— — — — — (674,302) — (674,302)Balance, June 30, 2015317,319 317 32,845,205 32,845 36,847,289 11,696,126 — 48,576,577Issuance of restricted common stock— — 272,098 272 (239) — — 33Exercise of stock options— — 50,000 50 127,450 — — 127,500Forfeitures of restricted stock— — (40,758) (41) 41 — — —Acquisition of treasury stock— — (218,682) — — — (1,263,402) (1,263,402)Retirements of treasury stock— — — (219) (1,263,183) — 1,263,402 —Stock-based compensation— — — — 1,809,548 — — 1,809,548Tax benefits related to stock-based compensation— — — — 9,650,657 — — 9,650,657Net income attributable to the Company— — — — — 24,660,362 — 24,660,362Common stock cash dividends— — — — — (6,565,823) — (6,565,823)Preferred stock cash dividends— — — — — (674,302) — (674,302)Balance, June 30, 2016317,319 $317 32,907,863 $32,907 $47,171,563 $29,116,363 $— $76,321,150 See accompanying notes to consolidated financial statements.44Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNote 1 – Organization and Basis of PreparationNature of Operations. Evolution Petroleum Corporation ("EPM") and its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleum companyheadquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the development of oil and gas reserves within known oiland gas resources utilizing conventional and proprietary technology.Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significantintercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made toconform to the current presentation. Such reclassifications have no impact on previously reported net income or stockholders' equity. As a result of the separation of our GARP ®artificial lift technology operations discussed in Note 8, previously reported revenues for the Delhi field and our artificial lift technology operations have been reclassified asappropriate to crude oil, natural gas liquids, natural gas and artificial lift technology service revenues. Before the reclassification, artificial lift technology revenues includedcrude oil, natural gas liquids and gas revenues produced by certain of the Company’s operated wells that utilized the technology, together with service revenues derived from theuse of the Company’s technology in third party wells. Previously reported production costs for our artificial lift technology operations have been reclassified as appropriate to oiland gas production costs and cost of artificial lift technology services.Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts ofassets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reservequantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gasproperties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historicalexperience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financialstatements are appropriate, actual results could differ from those estimates.Note 2 – Summary of Significant Accounting PoliciesCash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents.Account Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of joint interest owner obligations due within 30 days of the invoice date,accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivables if it is determined thatcollection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using thespecific identification method. As of June 30, 2016 and 2015 , no allowance for doubtful accounts was considered necessary.Oil and Natural Gas Properties. We use the full cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, allcosts incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs thatare directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similaractivities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship betweencapitalized costs and proved reserves.Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluatedproperties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude thesecosts until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment hasoccurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized.45Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit onthe book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and relateddeferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion and amortization oras a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase theCeiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent , and assuming continuation of existing economic conditions, of 1) estimated futuregross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price foreach month within the 12 -month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangementsincluding hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the provedreserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven propertiesincluded in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties. Our CeilingTests did not result in an impairment of our oil and natural gas properties during the years ended June 30, 2016 , 2015 or 2014 .Other Property and Equipment. Other property and equipment includes leasehold improvements, data processing and telecommunications equipment, office furnitureand equipment, and oilfield service equipment related to our artificial lift technology operations. These items are recorded at cost and depreciated over expected lives of theindividual assets or group of assets, which range from three to seven years . The assets are depreciated using the straight-line method, except for oilfield service equipmentrelated to our artificial lift technology operations, which is depreciated using a method which approximates the timing and amounts of expected revenues from the contract.Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carryingamount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset,including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carryingamount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred.Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company'sconsolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the periodincurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the assetretirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a level 3 fair value measurement.The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligationdiscounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If theestimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimatedasset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, certificates of deposit, accounts receivable, accounts payable andderivative instruments. Except for derivatives, the carrying amounts of these approximate fair value due to the highly liquid nature of these short-term instruments. The fairvalues of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources,including quoted forward prices for oil and gas, discount rates and volatility factors.Stock-based Compensation. Estimated grant date fair value of stock-based compensation awards is determined to provide the basis for future compensation expense.Service-and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. For market-based awards, which reflect future returns of our common stock, the fair value and expected vesting period are determined using a Monte Carlo simulation based on the historicalvolatility of the Company's total return compared to the historical volatilities of the other companies comprising a benchmark index. We used the Black-Scholes option-pricingmodel to determine grant date fair value of our past Stock Option and Incentive Warrant awards. For service-based awards stock-based compensation equal to grant date fairvalue46Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)is recognized ratably over the requisite service period as the award vests. A performance-based award vests upon attaining the award's operational goal and requires that therecipient remain an employee of the Company upon vesting. Stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vestingperiod when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be deemed to be shorter than theremainder of the award’s term. For a market-based award stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period,so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination ofservice.Revenue Recognition - Oil and Gas. We recognize oil and natural gas revenue from our interests in producing wells at the time that title passes to the purchaser. As aresult, we accrue revenues related to production sold for which we have not received payment.Revenue Recognition - Artificial Lift Technology. Our artificial lift technology operations have generated revenues under contractual arrangements. Under thesecontracts, we were required to bear part or all of the incremental installation and capital costs for the technology. We evaluated the substance of each contractual arrangement andrecognized revenues over the life of the contract as the earnings process is determined to be complete. We likewise charge our costs, including both capital expenditures andoperating expenses, to operating costs in a manner which either matches these costs to the timing of expected revenues, where appropriate, or charges these costs to theaccounting period in which they were incurred where it is not appropriate to capitalize or defer them to match with revenues.Derivative Instruments. The Company uses derivative transactions to reduce its exposure to oil price volatility. All derivative instruments are recorded on the consolidatedbalance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant toa ISDA master agreement, which provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivativeinstruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company elected not to meet the criteria to qualify its derivativeinstruments for hedge accounting treatment, net gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain or (loss) on derivatives inthe consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from the counterparty as aresult of derivative settlements are classified as cash flows from investing activities. The Company does not intend to enter into derivative instruments for speculative or tradingpurposes.Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimatedfuture development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and naturalgas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold improvements, office and computerequipment, vehicles and artificial lift equipment is depreciated as described above in Other Property and Equipment.Intangible Assets - Intellectual Property. The Company has capitalized the external costs, consisting primarily of legal costs, related to securing its patents andtrademarks. The costs related to patents were amortized over the remaining patent life which was less than the expected useful life of each patent. Trademarks have a perpetuallife and were not amortized.Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in thefinancial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance basedupon management's assessment of available evidence if it is deemed more likely than not some or all of the deferred tax assets will not be realizable. We recognize a tax benefitfrom an uncertain position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position and will record thelargest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penaltiesassociated with income taxes as income tax expense.Earnings (loss) per share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss by the weighted-average number of common sharesoutstanding. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional commonshares that would have been outstanding if potential dilutive common shares had been issued. Our potential dilutive common shares are our outstanding stock options, warrants,and contingent restricted common stock. The dilutive effect of our potential dilutive common shares is reflected in diluted EPS by application of the treasury stock method.Under the treasury stock method, exercise of stock options and warrants shall be assumed at the beginning of the period (or at time of issuance, if later) and common shares shallbe47Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)assumed to be issued; the proceeds from exercise shall be assumed to be used to purchase common stock at the average market price during the period; and the incrementalshares (the difference between the number of shares assumed issued and the number of shares assumed purchased) shall be included in the denominator of the diluted EPScomputation. Potentially dilutive common shares are excluded from the computation if their effect is anti-dilutive.Recent Accounting Pronouncements.In August 2015, the FASB issued Accounting Standards Update 2015-14, which defers the effective date of ASU 2014-09 Revenue from Contracts with Customers (Topic606) (" ASU 2014-09") one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requiresthat revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which theentity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-09 would have been effective for fiscal years, and interim periods withinthose years, beginning after December 15, 2017. The standard provided for either the retrospective or cumulative effect transition method. The Company is currently assessingthe impact of the adoption of ASU 2014-09 will have on its consolidated financial statements, if any.In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes” as part of their simplification initiatives. The standard requiresthat deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The update is effective for public company annual reportingperiods beginning after December 15, 2016, and may be adopted prospectively or retrospectively with early adoption permitted. The Company plans to early adopt this standardthe first quarter of year ended June 30, 2017 and does not believe that adoption of this update will have a material impact on our results of operations, financial position or cashflows.On February 25, 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”), which relates to the accounting for leasing transactions. This standard requires a lessee torecord on the balance sheet the assets and liabilities for the rights and obligations created by leases with lease terms of more than 12 months. In addition, this standard requiresboth lessees and lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning after December 15, 2018, includinginterim periods within those fiscal years. We are evaluating the impact the adoption of ASU 2016-02 will have on our condensed consolidated financial statements.On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) , which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions,including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. This standard will beeffective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company plans to early adopt this standard during the firstquarter of the year ended June 30, 2017. The adoption of this standard will result in all excess tax benefits or deficiencies being recognized as tax expense or benefit in thereporting period they occur regardless of whether the benefit reduces taxes payable in the current period. On the statement of cash flows excess tax benefits or deficiencies willbe classified along with other income tax as an operating activity and cash paid by the Company when directly withholding shares for tax withholding purposes will continue tobe classified as a financing activity. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements, but does notexpect the impact of adoption to be material.Note 3 – Delhi Field Litigation SettlementOn June 24, 2016, Evolution Petroleum Corporation, together with its subsidiaries NGS Sub Corp. and Tertiaire Resources Company (collectively, “Evolution”), enteredinto a settlement agreement with Denbury Resources, Inc. and Denbury Onshore, LLC, a subsidiary of Denbury Resources Inc. (together with Denbury Onshore, "Denbury"), toresolve all outstanding disputes and claims between the parties, including claims related to the litigation between Evolution and Denbury with respect to the Delhi field innortheastern Louisiana. The Delhi field litigation between the parties has been dismissed by the Court with prejudice. In connection with this settlement, the Company recognizeda $28.1 million settlement gain consisting48Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)of a $27.5 million cash payment made by Denbury together with its conveyance to Evolution of a 23.9% working interest in the Mengel Sand Interval, a separate interval withinthe boundaries of the Delhi field which is not currently producing and for which we estimated a Level 2 fair value of $596,500 . In addition, effective July 1, 2016, Denbury willbe credited with an additional 0.2226% overriding royalty interest in the Delhi field to remedy a previous dispute regarding the interests conveyed in the original transactionbetween the parties. See Note 18 — Commitments and Contingencies.Note 4 – ReceivablesAs of June 30, 2016 and June 30, 2015 our receivables consisted of the following: June 30, 2016 June 30, 2015Receivables from oil and gas sales$2,637,593 $3,122,155Other595 318Total receivables$2,638,188 $3,122,473Note 5 – Prepaid Expenses and Other Current AssetsAs of June 30, 2016 and June 30, 2015 our prepaid expenses and other current assets consisted of the following: June 30, 2016 June 30, 2015Prepaid insurance$168,681 $178,994Prepaid federal and state income taxes— 22,542Equipment inventory (a)— 81,538Retainers and deposits30,568 26,978Other prepaid expenses52,500 59,352Prepaid expenses and other current assets$251,749 $369,404(a) As discussed in Note 8, our equipment inventory was determined to have no future value in use for our operations and negligible market value and was charged torestructuring costs as part of the separation of our artificial lift technology operations.Note 6 – Property and EquipmentAs of June 30, 2016 and June 30, 2015 , our oil and natural gas properties and other property and equipment consisted of the following: June 30, 2016 June 30, 2015Oil and natural gas properties: Property costs subject to amortization$77,408,353 $57,718,653Less: Accumulated depreciation, depletion, and amortization(17,437,890) (12,531,767)Unproved properties not subject to amortization— —Oil and natural gas properties, net59,970,463 45,186,886Other property and equipment: Furniture, fixtures and office equipment, at cost228,752 287,680Artificial lift technology equipment, at cost7,000 319,994Less: Accumulated depreciation(207,103) (330,918)Other property and equipment, net$28,649 $276,756As of June 30, 2016 and 2015 , all oil and gas property costs were being amortized.49Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)During the year ended June 30, 2016 , the Company incurred capital expenditures of $19.0 million for the Delhi field, including approximately $16.4 million for the NGLplant project which is currently under construction. We have incurred $21.5 million on a cumulative basis for the NGL plant out of a total authorized commitment of $24.6million , with a remaining balance of approximately $3.1 million .As described in Note 3 – Delhi Field Litigation Settlement, we received a 23.9% working interest in the Mengel Interval (currently non-producing) having an estimatedfair value of $596,500 .On December 31, 2015, as described in Note 8 — Restructuring, we transferred our residual artificial lift technology equipment to new entity not controlled by theCompany. We recorded a charge of $210,392 to expense most of the remaining capitalized costs of artificial lift equipment installed in the wells of a third-party customer. Underour installation contracts, we had funded the majority of the incremental equipment and installation costs in exchange for 25% of the net profits from production, as defined, foras long as the technology remains in the wells. During the year ended ended June 30, 2015, we incurred $217,733 of costs related to installing our artificial lift technology onthird party wells and recorded an impairment charge of $275,682 reflecting the unrecovered installation costs, net of estimated salvage value. During the year ended June 30,2014, we incurred $377,943 of installation costs. Impairment charges are included in depreciation, depletion and amortization expense on the consolidated statement ofoperations.On October 24, 2014, we sold all of our remaining mineral interest and assets in the Mississippi Lime project for proceeds of $389,165 and the buyer's assumption of allabandonment liabilities. On December 1, 2013, we sold our producing assets and undeveloped reserves in the Lopez Field in South Texas in return for proceeds of $402,500 andthe buyer's assumption of all abandonment liabilities. The net proceeds from these sales of our properties, including the reduction of asset retirement obligations, were recognizedas a reduction of the cost of oil and gas properties.Note 7 – Other AssetsAs of June 30, 2016 and June 30, 2015 our other assets consisted of the following: June 30, 2016 June 30, 2015Royalty rights108,512 —Less: Accumulated amortization of royalty rights(6,782) —Investment in Well Lift Inc., at cost108,750 —Deferred loan costs168,972 337,078Less: Accumulated amortization of deferred loan costs(13,963) (147,057)Trademarks— 44,803Patent costs— 538,276Less: Accumulated amortization of patent costs— (47,063)Other assets, net$365,489 $726,037During the year ended June 30, 2016 , our previous negotiations to obtain a new expanded secured credit facility were curtailed due to market conditions. As a result, theCompany determined that $50,414 of deferred legal fees related to the proposed facility were unlikely to be utilized and were charged to expense. In addition, $107,196 ofdeferred costs incurred for title work in the Delhi field was charged to capitalized costs of oil and gas properties. Our existing unsecured credit facility expired in April 2016 andits associated deferred loan costs of $179,468 had been completely amortized. Contemporaneous with that facility's expiration, we entered into a secured credit facility providedby another financial institution, incurring $168,972 of deferred loan costs. Total amortization of costs related to our credit facilities for the year ended June 30, 2016 was $46,374.See Note 8 – Restructuring for discussion of transactions associated with the separation of our artificial lift technology operations.The company accounts for its investment in Well Lift Inc. ("WLI") using the cost method under which any return of capital reduces cost and any dividends paid arerecorded as income. This investment is considered a level 3 fair value50Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)measurement and its value will be evaluated for impairment periodically and when management identifies any events or changes in circumstances that might have a significantadverse effect on the fair value of the investment.Note 8 – RestructuringSeparation of GARP ® Artificial Lift Technology OperationsDuring the quarter ended December 31, 2015, we conducted a strategic review of our GARP ® artificial lift technology operations and consummated a plan to separate andtransfer these operations to a new entity controlled by the inventor of the technology, our former Senior Vice President of Operations, and certain former employees of theCompany. We invested $108,750 in common and preferred stock of the new entity, WLI. We own 17.5% of WLI and our former employees that previously had primaryresponsibility for our GARP ® operations own the balance of the common stock. Our preferred stock is convertible at our option into common stock which would result in ourownership of 42.5% of WLI, based on the current capital structure of WLI. The company has no contractual exposure to losses of WLI, nor does it have any obligation oragreement to provide additional funding or support to WLI if it is needed. In connection with this transaction, three employees of the Company were terminated. We accrued arestructuring charge based on agreements with the employees covering salary and benefit continuation and an acceleration of vesting of equity awards in exchange for releasefrom liabilities and other provisions including agreements not to compete. At December 31, 2015, we recorded a personnel restructuring charge of $688,205 consisting of$59,339 in stock-based compensation and $628,866 of accrued separation and benefits expense. Our current estimate of remaining restructuring obligations as of June 30, 2016 isas follows:Type of CostDecember 31, 2015 Payments Adjustments to Cost June 30, 2016Salary expense$530,387 $(176,796) $— $353,591Payroll taxes and benefits expense98,479 (32,582) — 65,897Accrued liability for restructuring costs$628,866 $(209,378) $— $419,488Other Restructuring ImpairmentsAlso in connection with the December 2015 separation of GARP ® , we and WLI entered into an agreement under which we transferred our technology assets, includingour patents and trademarks, to WLI in exchange for a perpetual royalty of 5% on all future gross revenues associated with the GARP ® technology. We reduced the carryingvalue of these exchanged technology assets to our estimate of their expected discounted net present value, which was $108,512 . This estimate was based on the recent financialresults from our artificial lift technology operations and the current depressed state of the oil and gas industry and the potential upside cases were assigned relatively lowprobabilities for accounting purposes. This resulted in an impairment charge of $469,395 . In addition, we transferred certain inventory and minor fixed assets to WLI which hadno further use in our operations and were deemed to have negligible market or salvage value. This resulted in impairments of $92,901 to equipment inventory and $6,932 to fixedassets, respectively. These impairments total $569,228 and are included in restructuring charges.Restructuring of Oil and Gas OperationsOn November 1, 2013, we undertook an initiative to refocus our business that resulted in an adjustment of our workforce with less emphasis on engineering and greateremphasis on sales and marketing. In exchange for severance and non-compete agreements with the terminated employees, we recorded a restructuring charge of $1,332,186representing $376,365 of stock-based compensation from the accelerated vesting of equity awards and $955,821 of estimated severance compensation and benefits to be paidduring the twelve months ended December 31, 2014. All of the Company's obligations under these agreements had been fulfilled at December 31, 2014, extinguishing theliability. Our disposition of the accrued restructuring charges is reflected in the following schedule:51Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Type of CostBalance atDecember 31, 2013 Payments Adjustment toCost June 30, 2015Salary expense$615,721 $(615,721) $— $—Incentive compensation costs185,525 (185,525) — —Payroll taxes and benefits expense154,575 (110,144) (44,431) —Accrued liability for restructuring costs$955,821 $(911,390) $(44,431) $—Note 9 – Accrued Liabilities and Other As of June 30, 2016 and June 30, 2015 our other current liabilities consisted of the following: June 30, 2016 June 30, 2015Accrued incentive and other compensation$999,172 $578,910Accrued restructuring charges419,488 —Asset retirement obligations due within one year201,896 57,223Accrued royalties, including suspended accounts49,580 75,164Accrued franchise taxes62,834 94,885Payable for settled derivatives318,708 —Accrued - other46,273 49,191Accrued liabilities and other$2,097,951 $855,373 Note 10 –Asset Retirement ObligationsOur asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end oftheir productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the years ended June 30,2016 and 2015 : Years Ended 2016 2015Asset retirement obligations—beginning of period$772,990 $352,215Liabilities incurred (a)28,505 564,019Liabilities settled— (137,604)Liabilities sold— (52,526)Accretion of discount49,054 34,866Revisions to previous estimates111,647 12,020Asset retirement obligations — end of period962,196 772,990Less: current asset retirement obligations(201,896) (57,223)Long-term portion of asset retirement obligations$760,300 $715,767(a) Liabilities incurred during fiscal 2015 relate to our share of the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our workinginterest.52Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)Note 11 – Stockholders' EquityCommon StockCommencing in December 2013, the Board of Directors initiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share and subsequentlyadjusted this rate to $0.05 per share during the quarter ended March 31, 2015. We paid cash dividends of $6,565,823 , $9,833,642 and $9,723,833 from retained earnings to ourcommon shareholders during the years ended June 30, 2016 , 2015 and 2014 , respectively.On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Since commencement in June2015, we have repurchased 265,762 shares at an average price of $6.05 per share, for total cost of $1,609,008 . This includes 202,390 shares purchased during the year endedJune 30, 2016, at an average price of $5.80 , for total cost of $1,173,899 . Under the program's terms, shares are repurchased only on the open market and in accordance with therequirements of the Securities and Exchange Commission. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchasesdepends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and it may besuspended or discontinued at any time. We have not repurchased any shares since December 2015.During the year ended June 30, 2014, we issued (i) 1,568,832 shares of our common stock upon the exercise of incentive stock options (ISOs), receiving cash proceedstotaling $3,252,801 , and (ii) 2,635,696 of our common shares upon cashless exercises of nonqualified stock options ("NQSOs") and incentive warrants, all being exercised on anet basis, except for 50,956 of previously acquired shares owned by option holders that were swapped in payment of the exercise price. The weighted average cost of theseswapped shares was $12.14 .In fiscal 2014, we retired 801,889 shares of treasury stock acquired in previous fiscal years at a cost of $1,019,840 and 186,714 treasury shares acquired during fiscal 2014from employees and directors at an average cost of $12.18 per share or $2,273,857 . The shares acquired in 2014 were received in satisfaction of payroll tax liabilities from theexercise of stock options and vesting of restricted stock (requiring cash outlays by us) and 50,956 shares were received from option holders in cashless stock option exercises,using stock previously owned by the option holder.Series A Cumulative Perpetual Preferred StockAt June 30, 2016 , there were 317,319 shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock outstanding. The Series A Cumulative PreferredStock cannot be converted into our common stock and there are no sinking fund or redemption rights available to the holders thereof. Effective July 1, 2014, we can redeem thispreferred stock at any time for the stated liquidation value of $25.00 per share plus accrued dividends. With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common stockholders, but subordinate to any of our existing and future debt. Dividends on the Series ACumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as,if and when declared by our Board of Directors through its Dividend Committee. We paid dividends of $674,302 to holders of our Series A Preferred Stock during each of theyears ended June 30, 2016 , 2015 , and 2014 .Tax Treatment of Dividends to RecipientsBased on our current projections for the fiscal year ending June 30, 2016 , we expect all preferred and common dividends for this fiscal year will be treated for taxpurposes as qualified dividend income to the recipients. For the fiscal year ended June 30, 2015 , 100% of cash dividends on preferred stock were treated as qualified dividendincome. For the same period, approximately 86% of cash dividends on common shares were treated as a return of capital to stockholders and the remainder of 14% were treatedas qualified dividend income. For fiscal year ended June 30, 2014 , all cash dividends on preferred and common stock were treated for tax purposes as a return of capital to ourshareholders.Note 12—Stock-Based Incentive PlanUnder the terms of the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "Plan"), we have granted option awards to purchase common stock(the "Stock Options"), restricted common stock awards ("Restricted Stock"), contingent restricted common stock awards ("Contingent Restricted Stock") and/or unrestricted fullyvested common stock, to employees, directors, and consultants of the Company. The Plan authorizes the issuance of 6,500,000 shares of common stock prior to its expiration onOctober 24, 2017 and 282,133 shares remain available for grant as of June 30, 2016 .53Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)Stock Options and Incentive WarrantsNo Stock Options have been granted since August 2008 and all compensation costs attributable to Stock Options have been recognized in prior periods. No IncentiveWarrants have been granted since February 2006. All compensation costs attributable to these awards have been recognized in prior periods and all remaining awards wereexercised in November 2013. The following summary presents information regarding outstanding Stock Options as of June 30, 2016 , and the changes during the period: Number of StockOptions WeightedAverageExercisePrice AggregateIntrinsic Value(1) WeightedAverageRemainingContractualTerm (inyears)Stock Options outstanding at July 1, 201591,061 $2.50 Exercised(50,000) 2.55 Expired(5,830) 4.02 Stock Options outstanding at June 30, 201635,231 $2.19 $115,558 1.2Vested at June 30, 201635,231 $2.19 $115,558 1.2Exercisable at June 30, 201635,231 $2.19 $115,558 1.2(1)Based upon the difference between the market price of our common stock on the last trading date of the period ( $5.47 as of June 30, 2016 ) and the Stock Optionexercise price of in-the-money Stock Options.For the year ended June 30, 2016 , there were 50,000 Stock Options exercised with an aggregate intrinsic value of $131,000 . For the year ended June 30, 2015, there were87,000 Stock Options exercised, with an aggregate intrinsic value of $501,810 . For the year ended June 30, 2014, there were 4,644,759 Stock Options and Incentive Warrantsexercised with an aggregate intrinsic value of $47,504,114 .No stock options vested during the years ended June 30, 2016 , 2015 , and 2014 .Restricted Stock and Contingent Restricted StockPrior to August 28, 2014, all Restricted Stock grants contained a four -year vesting period based solely on service. Restricted Stock which vests based solely on service isvalued at the fair market value on the date of grant and are amortized over the service period.In August 2014 and in December 2015, the Company awarded grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan.Such grants, which expire after four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying theRestricted Stock grants were issued on the date of grant, whereas the Contingent Restricted Stock are reserved from the Plan, but will be issued only upon the attainment ofspecified performance-based or market-based vesting provisions.Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee of the Companythrough the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fairvalue when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the four-year term. As of June 30, 2016 , certain performance-based awards were not considered probable of vesting for accounting purposes and no compensation expense has beenrecognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense would be recorded at that time andamortization would continue over the remaining expected vesting period.Market-based awards entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds thecorresponding total returns of various quartiles of companies comprising the SIG Exploration and Production Index (NASDAQ EPX) during defined measurement periods. Thefair value and expected vesting period of these awards were determined using a Monte Carlo simulation based on the historical volatility of the Company's total54Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)return compared to the historical volatilities of the other companies in the index. During the fiscal year ended June 30, 2016 , we granted market-based awards with fair valuesranging from $2.93 to $5.07 , all with an expected vesting period of 3.83 years, based on the various quartiles of comparative market performance. During the fiscal year endedJune 30, 2015, we granted market-based awards with fair values ranging from $4.26 to $8.40 and with expected vesting periods of 3.30 years to 2.55 years, based on the variousquartiles of comparative market performance. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, solong as the award holder remains an employee of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent ofvesting or expiration of the awards, except for termination of service.In December 2015, one employee resigned and three others left the Company when we restructured our artificial lift technology operations. As a result 31,467 restrictedshares and 14,212 contingent restricted shares were forfeited. Also in connection with the restructuring, at the Company’s request in February 2016, certain employees agreed tovoluntarily relinquish 31,307 restricted performance-based shares and 15,654 contingent performance-based shares in exchange for 22,016 shares of service-based restrictedstock subject to vesting in three annual tranches ending on August 28, 2018.Unvested Restricted Stock awards at June 30, 2016 consisted of the following:Award TypeNumber of Restricted Shares Weighted Average Grant-Date Fair ValueService-based awards224,515 $7.08Performance-based awards89,079 7.17Market-based awards93,254 5.50Unvested at June 30, 2016406,848 $6.74The following table sets forth the Restricted Stock transactions for the year ended June 30, 2016 : Number ofRestrictedShares WeightedAverageGrant-DateFair Value UnamortizedCompensationExpense at June 30,2016 Weighted AverageRemainingAmortization Period(Years)Unvested at July 1, 2015262,227 $9.37 $— Service-based awards granted164,610 5.84 Performance-based awards granted64,752 6.09 Market-based awards granted64,752 4.58 Vested(86,719) 8.73 Forfeited(62,774) 9.72 Unvested at June 30, 2016406,848 $6.74 $1,536,125 2.6During the years ended June 30, 2016 , 2015 , and 2014 , there were 86,719 , 91,306 , and 277,198 shares of Restricted Stock that vested with a total grant date fair valueof $757,229 , $766,970 , and $1,796,243 , respectively.55Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)Unvested Contingent Restricted Stock awards at June 30, 2016 consisted of the following:Award Type Number of Contingent Restricted Shares Weighted Average Grant-Date Fair ValuePerformance-based awards 44,542 $7.17Market-based awards 46,630 3.34Unvested at June 30, 2016 91,172 $5.21The following table summarizes Contingent Restricted Stock activity: Number of Restricted Stock Units Weighted Average Grant-Date Fair Value UnamortizedCompensationExpense at June 30,2016 (1) Weighted AverageRemainingAmortization Period(Years)Unvested at July 1, 201556,286 $8.20 Performance-based awards granted32,376 6.09 Market-based awards granted32,376 2.93 Forfeited(29,866) $9.33 Unvested at June 30, 201691,172 $5.21 $107,219 2.8(1) Excludes $122,268 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accountingpurposes.Stock-based Compensation ExpenseFor the years ended June 30, 2016 , 2015 , and 2014 , we recognized stock-based compensation expense related to Restricted Stock, Contingent Restricted Stock grants,and Stock Option grants of $1,809,548 , $943,653 , and $1,728,687 , respectively. Included in these amounts are stock-based compensation expense of $59,339 for the year endedJune 30, 2016 and $376,365 for the year ended June 30, 2014 that were reflected in restructuring charges.56Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)Note 13 – Supplemental Disclosure of Cash Flow InformationOur supplemental disclosures of cash flow information for the years ended June 30, 2016 , 2015 , and 2014 are as follows: June 30, 2016 2015 2014Income taxes paid$540,000 $220,000 $755,941Income tax refunds1,556,999 331,733 —Non-cash transactions: Increase (decrease) in accrued purchases of property and equipment(2,250,048) 5,422,566 (183,766)Deferred loan costs charged to oil and gas property costs107,196 — —Oil and natural gas property costs attributable to the recognition of asset retirement obligations140,151 576,039 66,976Mengel working interest acquired in Delhi Field litigation settlement596,500 — —Royalty rights acquired through non-monetary exchange of patent and trademark assets108,512 — —Previously acquired Company shares swapped by holders to pay stock option exercise price$76,500 $— $618,606Accrued purchases of treasury stock(170,283) 170,283 —Note 14 – Income TaxesWe file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended June 30, 2016 , 2015 and2014 . We believe that we have appropriate support for the income tax positions taken and to be taken on the Company's tax returns and that the accruals for tax liabilities areadequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company'stax returns are open to audit under the statute of limitations for the years ending June 30, 2013 through June 30, 2015 for federal tax purposes and for the years ended June 30,2011 through June 30, 2015 for state tax purposes.The components of our income tax provision (benefit) are as follows: June 30, 2016 June 30, 2015 June 30, 2014Current: Federal$8,731,290 $1,413,296 $386,018State264,254 608,436 161,168Total current income tax provision8,995,544 2,021,732 547,186Deferred: Federal541,891 1,282,059 1,319,727State33,344 140,430 25,085Total deferred income tax provision575,235 1,422,489 1,344,812 $9,570,779 $3,444,221 $1,891,998The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate, currently 34% , to the income tax provision in our financialstatements. The effective tax rate for 2016 is less than the statutory rate primarily due to the benefit derived from statutory depletion in excess of tax basis. The effective tax ratesfor 2015 and 2014 exceed the statutory rate as a result of state income taxes, primarily in the state of Louisiana, with smaller adjustments related to stock-based compensationand other permanent differences.57Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) June 30, 2016 June 30, 2015 June 30, 2014Income tax provision (benefit) computed at the statutory federal rate$11,638,588 $2,868,267 $1,866,366Reconciling items: Depletion in excess of basis(2,242,620) — —State income taxes, net of federal tax benefit196,415 595,708 189,081Permanent differences related to stock-based compensation— — (155,817)Other permanent differences(21,604) (19,754) (7,632)Income tax provision$9,570,779 $3,444,221 $1,891,998Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposesand the amounts used for income tax purposes. Deferred tax assets and liabilities are classified as either current or noncurrent on the balance sheet based on the classification ofthe related asset or liability for financial reporting purposes. Deferred tax assets and liabilities not related to specific assets or liabilities on the financial statements are classifiedaccording to the expected reversal date of the temporary difference or the expected utilization date for tax attribute carryforwards. Asset (Liability) June 30, 2016 June 30, 2015 June 30, 2014Deferred tax assets: Non-qualified stock-based compensation$553,182 $173,647 $134,469Net operating loss carry-forwards386,808 400,288 427,249AMT credit carry-forward*— 701,254 701,254Other130,947 91,113 165,775Gross deferred tax assets1,070,937 1,366,302 1,428,747Valuation allowance(292,446) (292,446) (292,446)Total deferred tax assets778,491 1,073,856 1,136,301Deferred tax liability: Oil and natural gas properties(12,513,863) (12,233,993) (10,873,949)Total deferred tax liability(12,513,863) (12,233,993) (10,873,949)Net deferred tax liability$(11,735,372) $(11,160,137) $(9,737,648)_______________________________________________________________________________*In fiscal 2016 we used our total AMT credit carry-forward of $901,545 . Our previous deferred tax asset above did not include $200,291 of AMT credit carry-forwardassociated with the tax benefit related to stock-based compensation.The above assets and liabilities are present on the balance sheet as follows: June 30, 2016 June 30, 2015 June 30, 2014Current deferred tax asset$105,321 $82,414 $159,624Non-current deferred tax liability11,840,693 11,242,551 9,897,272Net liability11,735,372 11,160,1379,737,64858Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)As of June 30, 2016 , we had a federal tax loss carryforward of approximately $1.2 million that we acquired through the reverse merger in May 2004. The majority of thetax loss carryforwards from the reverse merger expired without being utilized. We will be able to utilize a maximum of $0.3 million of these carryforwards in equal annualamounts of $39,648 through 2023 and the balance is not able to be utilized based on the provisions of IRC Section 382. We have recorded a valuation allowance for the portionof our net operating loss that is limited by IRC Section 382.During fiscal 2016 we utilized the remaining amount of $25.3 million of net operating losses ("NOL's") created primarily from tax deductions in excess of book deductionsrelated to the exercise of non-qualified stock options and incentive warrants in fiscal 2014. NOL's related to such stock-based awards had not affected our future tax provision forfinancial reporting purposes, nor had it been recognized as a deferred tax asset for these future benefits. In fiscal 2016, 2015 and 2014, we recognized a tax benefit for utilizationof these NOL's to offset cash taxes that would otherwise have been payable as an increase in additional paid in capital, in amounts of $9,650,657 , $1,633,946 and $509,096respectively.In late September 2015, we received a $1.5 million refund payment of cash taxes paid to the State of Louisiana over a three-year period ended June 30, 2014. We alsoreceived $57,467 from the State of Louisiana for interest on the refund and recorded it as a reduction of current income tax expense. This carryback of tax losses resulted fromthe exercise of stock options and incentive warrants in fiscal 2014 and, accordingly, we recognized this benefit as an increase in additional paid-in capital for financial reportingpurposes. This carryback utilized approximately $19.1 million of an estimated $24.2 million net loss for state tax purposes. The remaining balance of this net loss carryforward inLouisiana was utilized in the tax return for the year ended June 30, 2015.In addition, as of June 30, 2016, the Company has an estimated carryforward of percentage depletion in excess of basis of approximately $5.0 million . These futuredeductions are limited to 65% of taxable income in any period.Note 15 – Related Party TransactionsOn June 30, 2011, we entered into a Technology Assignment Agreement with the Company’s Senior Vice President of Operations to acquire exclusive, perpetual, non-cancelable rights to the patented artificial lift technology he developed while employed by the Company. Under the agreement, he was paid a fee when the technology wasemployed. For the years ended June 30, 2016, 2015 and 2014, we made payments of $0 , $26,579 and $10,113 , respectively, under the agreement, while he served as an officerof the Company. Our obligations with respect to this agreement were terminated in December 2015 in connection with the transfer of our artificial lift technology operations toWell Lift Inc.Note 16 – Net Income Per ShareThe following table sets forth the computation of basic and diluted net income per share: June 30, 2016 2015 2014Numerator Net income attributable to common shareholders$23,986,060 $4,317,555 $2,923,011Denominator Weighted average number of common shares – Basic32,810,375 32,817,456 30,895,832Effect of dilutive securities: Contingent restricted stock grants9,378 4,422 —Stock Options41,478 102,140 1,668,235Total weighted average dilutive securities50,856 106,562 1,668,235Weighted average number of common shares and dilutive potential common shares used in diluted EPS32,861,231 32,924,018 32,564,067Net income per common share – Basic$0.73 $0.13 $0.09Net income per common share – Diluted$0.73 $0.13 $0.0959Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)The following were reflected in the calculation of diluted earnings per share as of June 30, 2016 :Outstanding Potential Dilutive SecuritiesWeightedAverageExercise Price Outstanding at June 30, 2016Contingent Restricted Stock grants$— 91,172Stock Options2.19 35,231Total$0.61 126,403The following were reflected in the calculation of diluted earnings per share as of June 30, 2015 :Outstanding Potential Dilutive SecuritiesWeightedAverageExercise Price Outstanding at June 30, 2015Contingent Restricted Stock grants$— 56,286Stock Options$2.50 91,061Total$1.55 147,347The following were reflected in the calculation of diluted earnings per share as of June 30, 2014 :Outstanding Potential Dilutive SecuritiesWeightedAverageExercise Price Outstanding at June 30, 2014Stock Options$2.08 178,061Note 17 – Credit AgreementsSenior Secured Credit AgreementOn April 11, 2016, the Company entered into a new three -year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million . The Facilityreplaces the Company's previous unsecured credit facility which was set to expire on April 29, 2016 and was terminated in early April. The initial borrowing base under theFacility was set at $10 million and the Company has no outstanding borrowings. Proceeds from the Facility may be used for the acquisition and development of oil and gasproperties and for letters of credit and other general corporate purposes. Availability of borrowings under the Facility is subject to semi-annual borrowing base redeterminations.The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000 , and carries a commitment fee of 0.25% per annum on the undrawnportion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either Libor plus 2.75% or the Prime Rate, as defined, plus1.00% . The Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratioof not more than 3.00 to 1.00 , (b) a debt service coverage ratio of not less than 1.10 to 1.00 , and (c) a consolidated tangible net worth of not less than $40 million , all as definedunder the Facility.In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized toexpense. The unamortized balance in debt issuance costs related to the Facility was $155,009 as of June 30, 2016.Unsecured Revolving Credit AgreementOn February 29, 2012, the Company and a commercial bank entered into an unsecured credit agreement with a four year term. The agreement had provided $5 million ofavailability, which the Company never utilized. The original expiration date was extended to April 29, 2016. In connection with this agreement, the Company had incurred$179,468 of debt issuance costs. Such costs had been capitalized in Other Assets and have been completely amortized to expense.Note 18 – Commitments and ContingenciesOn December 13, 2013, Evolution Petroleum Corporation and its wholly-owned subsidiaries, Tertiaire Resources Company and NGS Sub. Corp. (collectively,“Evolution”) filed a lawsuit in the 133 rd Judicial District Court of Harris County,60Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)Texas, against Denbury Onshore, LLC (“Denbury”) alleging breaches of certain 2006 agreements between the parties regarding the Delhi field in northeast Louisiana. On June24, 2016, Evolution entered into a settlement agreement with Denbury to resolve all outstanding disputes and claims between the parties, including claims related to the pendinglitigation between Evolution and Denbury with respect to the Delhi field. Pursuant to the settlement, the parties dismissed with prejudice all such claims between them withrespect to such litigation. In addition to clarifying certain aspects of the parties' ongoing relationship, the settlement resolves (a) claims by Evolution in connection with the June2013 incident at the Delhi field involving a release of well fluids (the “June 2013 Incident”); (b) disputes regarding the occurrence, determination, timing, nature and terms of“payout” and Evolution's related reversionary interest in the Delhi Field; and (c) any claims by Denbury related to the purchase by Denbury of its original Delhi field interestfrom the Company. Under the terms of the settlement, Evolution retains any and all rights under its existing agreements with Denbury regarding indemnification for any costswhich are asserted or arise subsequent to the effective date of the settlement and which relate to periods prior to reversion of its working interest, including any such costs relatedto the June 2013 Incident. See Note 3 — Delhi Field Litigation Settlement.On December 3, 2013, our wholly owned subsidiary, NGS Sub Corp., was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by CecilM. Brooks and Brandon Hawkins, residents of Louisiana, alleging that in 2006 a former subsidiary of NGS Sub Corp. improperly disposed of water from an off-lease well into awell located on the plaintiffs’ lands in Winn Parish. The plaintiffs requested monetary damages and other relief. NGS Sub Corp. divested its ownership of the property inquestion along with its ownership of the subsidiary in 2008 to a third party. The district court granted our exception of no right of action and dismissed certain claims againstNGS Sub Corp. The plaintiffs subsequently filed an amended petition naming NGS Sub Corp. and the Company as defendants. NGS Sub Corp. and the Company have denied theplaintiffs’ claims. Various pretrial motions filed on behalf of multiple parties were recently decided by the court and discovery is in process. We will continue to vigorouslydefend all claims by plaintiffs and consider the likelihood of a material loss to the Company in this matter to be remote.Lease Commitments. We had a non-cancelable lease for office space that expired on July 31, 2016. Late in fiscal 2016, the Company entered into a new non-cancelableoffice space with a three year term ending on May 31, 2019. Future minimum lease commitments as of June 30, 2016 under these operating leases are as follows:For the fiscal year ended June 30, 2017$80,235201873,073201966,984Total$220,292Rent expense for the years ended June 30, 2016 , 2015 , and 2014 was $182,626 , $175,103 , and $174,229 , respectively.Capital Expenditures. See Note 6 for discussion of capital projects in progress and expected remaining capital commitments.Note 19 – Concentrations of Credit RiskMajor Customers. We market all of our oil and natural gas production from the properties we operate. We do not currently market our share of crude oil production fromDelhi. Although we have the right to take our working interest production at Delhi in-kind, we are currently selling our oil under the Delhi operator's agreement with PlainsMarketing L.P. for the delivery of our oil to a pipeline at the field. The majority of our operated gas, oil and condensate production is sold to purchasers under short-term (lessthan 12 months) contracts at market-based prices. The following table identifies customers from whom we derived 10 percent or more our net oil and natural gas revenues duringthe years ended June 30, 2016 , 2015 , and 2014 . The loss of our purchaser at the Delhi field or disruption to pipeline transportation from the field could adversely affect our netrealized pricing and potentially our near-term production levels. The loss of any of our other purchasers would not be61Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)expected to have a material adverse effect on our operations. Year Ended June 30,Customer2016 2015 2014Plains Marketing L.P. (includes Delhi production)99% 99% 96%Enterprise Crude Oil LLC—% —% 2%Flint Hills—% —% 1%ETC Texas Pipeline, LTD. —% —% 1%All others1% 1% —%Total100% 100% 100%Accounts Receivable. Substantially all of our accounts receivable result from oil and natural gas sales to third parties in the oil and natural gas industry. Ourconcentration of customers in this industry may impact our overall credit risk.Cash and Cash Equivalents and Certificates of Deposit. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attemptto minimize by maintaining our cash and cash equivalents in high quality money market funds. At times, cash balances may exceed limits federally insured by the FederalDeposit Insurance Corporation ("FDIC"). Our certificates of deposit are below or at the maximum federally insured limit set by the FDIC.Note 20 – Retirement PlanWe have a Company sponsored 401(k) Retirement Plan ("Plan") which covers all full-time employees. We currently match 100% of employees' contributions to the Plan,to a maximum of the first 6% of each participant's eligible compensation, with Company contributions fully vested when made. Our matching contributions to the Plan totaled$88,348 , $85,676 , and $116,873 for the years ended June 30, 2016 , 2015 , and 2014 , respectively.Note 21 – DerivativesIn early June 2015, the Company began using derivative instruments to reduce its exposure to crude oil price volatility for a substantial portion of its near-term forecastedproduction. The Company's objectives for this program were to achieve a more predictable level of cash flows to support the Company’s capital expenditure program and toprovide better financial visibility for the payment of dividends on common stock. The Company uses both fixed price swap agreements and costless collars to manage itsexposure to crude oil price risk. While these derivative instruments are intended to limit the downside risk of adverse price movements, they may also limit future revenues fromfavorable price movements. The Company does not intend to enter into derivative instruments for speculative or trading purposes.The Company accounts for derivatives under the provisions of ASC 815 Derivatives and Hedgin g ("ASC 815") under which the Company records the fair value of theinstruments on the balance sheet at each reporting date, with changes in fair value recognized in income. Given cost and complexity considerations, the Company did not elect touse cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, the effective portion of the change in fair value of the derivative instrumentswould be deferred in other comprehensive income and not recognized in earnings until the underlying hedged item impacts earnings.These derivative instruments can result in both fair value asset and liability positions held with each counterparty. These positions are offset to a single net fair value assetor liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA masteragreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value derivative instruments wherethe Company is in a net asset position with its counterparty as of June 30, 2016 totaled $14,132 . Refer to Note 22–Fair Value Measurement for derivative asset and derivativeliability balances before offsetting.The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require ourcounterparties to post collateral to support the net asset positions of our derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformanceby the counterparties to its derivative instruments.For the year ended June 30, 2016, the Company recorded in the consolidated statement of operations a gain on derivative62Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)instruments of $3,439,229 consisting of a realized gain of $3,315,123 on settled derivatives and an unrealized gain of $124,106 on unsettled derivatives. For the year endedJune 30, 2015 , the Company recorded in the consolidated statement of operations a net unrealized loss on unsettled derivatives of $109,974 .The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of June 30, 2016 .Period Type of Contract Volumes (in Bbls./day) Weighted Average FloorPrice per Bbl. Weighted AverageCeiling Price per Bbl. Weighted AverageCollar Spread per Bbl.Months of July 2016 throughSeptember 2016 Costless Collar 600 $45.00 $55.00 $10.00Subsequent to June 30, 2016 , the Company's July and August collars expired without settlement as the respective NYMEX prices for those months fell between the floorand ceiling prices.Note 22 – Fair Value MeasurementAccounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizesassets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.The three levels are defined as follows:Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.Level 2—Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly orindirectly, for substantially the full term of the asset or liability.Level 3—Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants wouldprice the assets and liabilities.Fair Value of Derivative Instruments. The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on arecurring basis as presented in the consolidated balance sheets as of June 30, 2016 . All items included in the tables below are Level 2 inputs within the fair value hierarchy: June 30, 2016Asset (Liability) Gross AmountsRecognized Gross AmountsOffset in theConsolidated BalanceSheet Net Amounts Presentedin the ConsolidatedBalance SheetsCurrent derivative assets $45,263 $(31,131) $14,132Current derivative liabilities (31,131) 31,131 —Total $14,132 $— $14,132The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-partysources, including quoted forward prices for oil and gas, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparty forreasonableness and are adjusted for the counterparties credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments forcredit quality have not had a material impact on the fair values.63Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)Note 23 – Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited)Costs incurred for oil and natural gas property acquisition, exploration and development activitiesThe following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costsare those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas thatmay warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells,geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling.Exploration and development costs also include amounts incurred due to the recognition of asset retirement obligations of $140,151 , $576,039 and $66,976 during the yearsended June 30, 2016 , 2015 , and 2014 , respectively. For the Years Ended June 30, 2016 2015 2014Oil and Natural Gas Activities Property acquisition costs: Proved property$— $— $—Unproved property (a)596,500 — 47,344Exploration costs— — 757,423Development costs19,093,200 10,975,637 18,566Total costs incurred for oil and natural gas activities$19,689,700 $10,975,637 $823,333(a) As described in Note 3 — Delhi Field Litigation Settlement, we received a 23.9% working interest in the non-producing Mengel Interval with an estimated fair value of$596,500 . This cost is included in properties subject to amortization.Estimated Net Quantities of Proved Oil and Natural Gas ReservesThe following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based onevaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30,2016 , 2015 , and 2014 , which requires the application of the previous 12 months unweighted arithmetic average first-day-of-the-month price, and current costs held constantthroughout the projected reserve life, when estimating whether reserve quantities are economical to produce.Proved oil and natural gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate withreasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves arereserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities ofproved oil and natural gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities ofoil and natural gas that are ultimately recovered.64Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated wereas follows: Crude Oil(Bbls) Natural GasLiquids(Bbls) Natural Gas(Mcf) BOEProved developed and undeveloped reserves: June 30, 201312,782,755 979,885 22,797 13,766,440Revisions of previous estimates (a)(1,919,052) 1,269,588 2,412,677 (247,350)Improved recovery, extensions and discoveries17,146 32,731 498,044 132,884Sales of minerals in place(184,722) — — (184,722)Production (sales volumes)(169,783) (3,516) (26,655) (177,742)June 30, 201410,526,344 2,278,688 2,906,863 13,289,510Revisions of previous estimates (b)(64,074) 156,195 (2,894,703) (390,330)Improved recovery, extensions and discoveries— — — —Sales of minerals in place— — — —Production (sales volumes)(450,294) (1,288) (7,221) (452,786)June 30, 201510,011,976 2,433,595 4,939 12,446,394Revisions of previous estimates (c)(765,385) (198,233) (3,319) (964,171)Improved recovery, extensions and discoveries— — — —Sales of minerals in place— — — —Production (sales volumes)(658,041) (491) (1,620) (658,802)June 30, 20168,588,550 2,234,871 — 10,823,421Proved developed reserves: June 30, 201310,077,522 8,539 22,797 10,089,861June 30, 20147,858,224 32,164 481,042 7,970,562June 30, 20157,347,231 1,572 4,939 7,349,626June 30, 20167,168,249 — — 7,168,249Proved undeveloped reserves: June 30, 20132,705,233 971,346 — 3,676,579June 30, 20142,668,120 2,246,524 2,425,821 5,318,948June 30, 20152,664,745 2,432,023 — 5,096,768June 30, 20161,420,301 2,234,871 — 3,655,172(a) Significant reserve revisions occurred in the Delhi field during fiscal 2014. As a result of a fluid release event in the field, 1,817,224 BBLs of oil reserves werereclassified from proved to probable category based on the operator's decision to defer CO 2 injections in certain parts of the field. There was a positive revision of1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the NGL plant inthe Delhi field. The plant was expected to significantly increase recoveries of these products, particularly natural gas, which were not previously planned to be extractedfrom the injection volumes.(b) The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi field NGL plant together with a 452,786MCF negative revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision during the current fiscalyear to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revisionprimarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision due to the lostGiddings well.65Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)(c) The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which weredeemed uneconomic under the lower SEC price case utilized at the end of the period.Standardized Measure of Discounted Future Net Cash FlowsFuture oil and natural gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, as requiredby ASC 932, Extractive Activities - Oil and Gas ("ASC 932"). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs arecomputed by estimating the expenditures to be incurred in developing and producing our proved oil and natural gas reserves assuming continuation of existing economicconditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil andnatural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general andadministrative costs of ongoing operations relating to the Company's proved oil and natural gas reserves. Changes in the demand for oil and natural gas, inflation, and otherfactors make such estimates inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the current market value of ourproved reserves.The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2016 , 2015 , and 2014 are as follows: For the Years Ended June 30, 2016 2015 2014Future cash inflows$383,491,193 $807,030,282 $1,193,515,075Future production costs and severance taxes(179,182,565) (309,225,333) (475,387,931)Future development costs(16,595,047) (49,691,006) (46,154,178)Future income tax expenses(45,713,438) (123,888,665) (195,581,510)Future net cash flows142,000,143 324,225,278 476,391,45610% annual discount for estimated timing of cash flows(64,042,824) (165,028,739) (250,313,784)Standardized measure of discounted future net cash flows$77,957,319 $159,196,539 $226,077,672Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmeticaverage first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content and regional price differentials. Year Ended June 30, 2016 2015 2014 Oil(Bbl) Gas(MMBtu) Oil(Bbl) Gas(MMBtu) Oil(Bbl) Gas(MMBtu)NYMEX prices used indetermining future cashflows$42.91 n/a $71.88 $3.44 $100.37 $4.10There were no natural gas reserves in 2016. The NGL prices utilized for future cash inflows were based on historical prices received, where available. For the Delhi NGLplant, we utilized historical prices for the expected mix and net pricing of natural gas liquid products projected to be produced by the plant.A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves is asfollows:66Table of ContentsEVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) For the Years Ended June 30, 2016 2015 2014Balance, beginning of year$159,196,539 $226,077,672 $307,220,699Net changes in sales prices and production costs related to future production(120,832,747) (88,043,095) (73,439,526)Changes in estimated future development costs74,991 (9,585,405) 9,848,614Sales of oil and gas produced during the period, net of production costs(17,079,363) (18,538,016) (16,479,934)Net change due to extensions, discoveries, and improved recovery— — 775,574Net change due to revisions in quantity estimates(18,821,014) (9,391,321) (23,757,788)Net change due to sales of minerals in place— — (3,150,277)Development costs incurred during the period16,327,883 7,785,095 —Accretion of discount21,870,650 31,974,540 45,896,187Net change in discounted income taxes36,598,239 34,157,767 58,073,450Net changes in timing of production and other (a)622,141 (15,240,698) (78,909,327)Balance, end of year$77,957,319 $159,196,539 $226,077,672(a) Due to the June 2013 fluid release event in the Delhi field, the operator expressed plans to produce the Delhi field at lower production rates. The decision to produce thesereserves at lower rates over a longer period of time did not materially change the total quantities expected to be recovered, but resulted in a significant reduction in the discountedvalue of these reserves as of June 30, 2014.Note 24 – Selected Quarterly Financial Data (Unaudited)The following table presents summarized quarterly financial information for the years ended June 30, 2016 and 2015 :2016First Second (1) Third Fourth (2)Revenues$7,379,406 $6,622,927 $5,106,735 $7,240,434Operating income (loss)1,846,498 (454,987) (681,147) 954,823Net income (loss) available to common shareholders$2,923,652 $654,697 $(298,183) $20,705,894Basic net income (loss) per share$0.09 $0.02 $(0.01) $0.63Diluted net income (loss) per share$0.09 $0.02 $(0.01) $0.632015First Second (3) Third FourthRevenues$4,004,827 $7,708,067 $7,064,689 $9,063,682Operating income1,840,866 2,162,294 1,245,990 3,334,547Net income available to common shareholders$960,435 $1,071,342 $566,011 $1,719,767Basic net income per share$0.03 $0.03 $0.02 $0.05Diluted net income per share$0.03 $0.03 $0.02 $0.05(1) Includes $1.3 million restructuring charge.(2) Includes gain on settlement of Delhi field litigation of $28.1 million .(3) Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi field.67Item 9. Changes In and Disagreements with Accountants on Accounting and Financial DisclosureNone.Item 9A. Controls and ProceduresDisclosure Controls and ProceduresWe maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed,summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms and that such information is accumulated andcommunicated to this Company's management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely decisions regarding requireddisclosure.As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company'smanagement, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as ofthe end of the period covered by this report. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls andprocedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarizedand reported within the time periods specified in the Securities and Exchange Commission rules and forms.Management's Report on Internal Control Over Financial ReportingThe Company's management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f)of the Exchange Act) as a process designed by, or under the supervision of, the company's principal executive and principal financial officers and effected by the Company'sboard of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:•Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;•Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generallyaccepted in the United States of America and that receipts and expenditures of the company are being made only in accordance with authorizations of management anddirectors of the company; and•Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a materialeffect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to beeffective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to futureperiods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures maydeteriorate. Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, an evaluation was conductedon the effectiveness of the Company's internal control over financial reporting based on criteria established in the Internal Control-Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission in 2013. Management concluded that the Company maintained effective internal control over financialreporting as of June 30, 2016.The effectiveness of our internal control over financial reporting at June 30, 2016 has been audited by Hein & Associates LLP, the independent registered publicaccounting firm that also audited our financial statements. Their report is included in Item 8. "Financial Statements" of this Annual Report on form 10-K under the headingReport of Independent Registered Public Accounting Firm on internal control over financial reporting.68Changes in Internal Control Over Financial ReportingThere has been no change in the Company's internal control over financial reporting during the fourth quarter ended June 30, 2016 that has materially affected, or isreasonably likely to materially affect, the Company's internal control over financial reporting.Item 9B. Other InformationNone.69PART IIIItem 10. Directors, Executive Officers And Corporate GovernanceIncorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's2016 fiscal year.Item 11. Executive CompensationIncorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's2016 fiscal year.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder MattersIncorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's2016 fiscal year.Item 13. Certain Relationships and Related Transactions, Director IndependenceIncorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's2016 fiscal year.Item 14. Principal Accountant Fees and ServicesIncorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's2016 fiscal year.70PART IV.Item 15. Exhibits and Financial Statement SchedulesThe following documents are filed as part of this report:1. Financial Statements.Our consolidated financial statements are included in Part II, Item 8 of this report:Report of Independent Registered Public Accounting FirmConsolidated Balance SheetsConsolidated Statements of OperationsConsolidated Statements of Cash FlowsConsolidated Statements of Stockholders' EquityNotes to the Consolidated Financial Statements2. Financial Statements Schedules and supplementary information required to be submitted:None.3. ExhibitsA list of the exhibits filed or furnished with this report on Form 10-K (or incorporated by reference to exhibits previously filed or furnished by us) is provided in theExhibit Index of this report. Those exhibits incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. Otherwise,the exhibits are filed herewith.71GLOSSARY OF SELECTED PETROLEUM TERMSThe following abbreviations and definitions are terms commonly used in the crude oil and natural gas industry and throughout this form 10-K:"BBL." A standard measure of volume for crude oil and liquid petroleum products; one barrel equals 42 U.S. gallons."BCF." Billion Cubic Feet of natural gas at standard temperature and pressure."BOE." Barrels of oil equivalent. BOE is calculated by converting 6 MCF of natural gas to 1 BBL of oil."BOPD." Barrels of oil per day."BTU" or "British Thermal Unit." The standard unit of measure of energy equal to the amount of heat required to raise the temperature of one pound of water 1 degreeFahrenheit. One Bbl of crude is typically 5.8 MMBTU, and one standard MCF is typically one MMBTU."CO 2 ." Carbon dioxide, a gas that can be found in naturally occurring reservoirs, typically associated with ancient volcanoes, and also is a major byproduct frommanufacturing and power production also utilized in enhanced oil recovery through injection into an oil reservoir."Developed Reserves." Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or inwhich the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operationalat the time of the reserves estimate if the extraction is by means not involving a well."EOR." Enhanced Oil Recovery projects involve injection of heat, miscible or immiscible gas, or chemicals into oil reservoirs, typically following full primary andsecondary waterflood recovery efforts, in order to gain incremental recovery of oil from the reservoir."Field." An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geologic structural feature and/or stratigraphicfeature.*"Farmout." Sale or transfer of all or part of the operating rights from the working interest owner (the assignor or farm-out party), to an assignee (the farm-in party) whoassumes all or some of the burden of development, in return for an interest in the property. The assignor may retain an overriding royalty or any other type of interest. ForFederal tax purposes, a farm-out may be structured as a sale or lease, depending on the specific rights and carved out interests retained by the assignor."Gross Acres or Gross Wells." The total acres or number of wells participated in, regardless of the amount of working interest owned."Horizontal Drilling." Involves drilling horizontally out from a vertical well bore, thereby potentially increasing the area and reach of the well bore that is in contactwith the reservoir."Hydraulic Fracturing." Involves pumping a fluid with or without particulates into a formation at high pressure, thereby creating fractures in the rock and leaving theparticulates in the fractures to ensure that the fractures remain open, thereby potentially increasing the ability of the reservoir to produce oil or gas."LOE." Means lease operating expense(s), a current period expense incurred to operate a well."MBO." One thousand barrels of oil"MBOE." One thousand barrels of oil equivalent."MCF." One thousand cubic feet of natural gas at standard conditions, being approximately sea level pressure and 60 degrees Fahrenheit temperature. Standard pressurein the state of Louisiana is deemed to be 15.025 psi by regulation, but varies in other states."MMBOE." One million barrels of oil equivalent."MMBTU." One million British thermal units."MMCF." One million cubic feet of natural gas at standard temperature and pressure.72"Mineral Royalty Interest." A royalty interest that is retained by the owner of the minerals underlying a lease. See "Royalty Interest"."Net Acres or Net Wells." The sum of the fractional working interests owned in gross acres or gross wells."NGL." Natural gas liquids, being the combination of ethane, propane, butane and natural gasoline that can be removed from natural gas through processing, typicallythrough refrigeration plants that utilize low temperatures, or through J-T plants that utilize compression, temperature reduction and expansion to a lower pressure."NYMEX." New York Mercantile Exchange."OOIP." Original Oil in Place. An estimate of the barrels originally contained in a reservoir before any production therefrom."Operator." An oil and gas joint venture participant that manages the joint venture, pays venture costs and bills the venture's non-operators for their share of venturecosts. The operator is also responsible to market all oil and gas production, except for those non-operators who take their production in-kind."Overriding Royalty Interest or ORRI." A royalty interest that is created out of the operating or working interest. Unlike a royalty interest, an overriding royalty interestterminates with the operating interest from which it was created or carved out of. See "Royalty Interest"."Permeability." The measure of ease with which a fluid can move through a reservoir. The unit of measure is a darcy, or any metric derivation thereof, such as amillidarcy, where one darcy equals 1,000 millidarcys. Extremely low permeability of 10 millidarcys, or less, are often associated with source rocks, such as shale, makingextraction of hydrocarbons more difficult, than say sandstone traps, where permeability can be one to two darcys or more."Porosity." (of sand or sandstone). The relative volume of the pore space (or open area) compared to the total bulk volume of the reservoir, stated in percent. Higherporosity rocks provide more storage space for hydrocarbon accumulations than lower porosity rocks in a given cubic volume of reservoir.“Possible Reserves.” Additional unproved reserves that analysis of geological and engineering data suggests are less likely to be recoverable than Probable Reserves,but have at least a ten percent probability of being recovered.*"Probable Developed Producing Reserves." Probable Reserves that are Developed and Producing.*"Probable Reserves." Additional reserves that are less certain to be recovered than Proved Reserves but which, together with Proved Reserves, are as likely as not to berecovered.*"Producing Reserves." Any category of reserves that have been developed and production has been initiated.*"Proved Developed Reserves." Proved Reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or inwhich the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operationalat the time of the reserves estimate if the extraction is by means not involving a well."Proved Developed Nonproducing Reserves ("PDNP")." Proved Reserves that have been developed and no material amount of capital expenditures are required to bringon production, but production has not yet been initiated due to timing, markets, or lack of third party completed connection to a gas sales pipeline.*"Proved Developed Producing Reserves ("PDP")." Proved Reserves that have been developed and production has been initiated.*"Proved Reserves." Estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty tobe recoverable in future years from known reservoirs under existing economic, operating methods, and government regulations prior to the time at which contracts providingthe right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for theestimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonabletime.*"Proved Undeveloped Reserves ("PUD")." Proved Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where arelatively major expenditure is required for recompletion.*73(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unlessevidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilledwithin five years, unless the specific circumstances, justify a longer time.(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improvedrecovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by otherevidence using reliable technology establishing reasonable certainty."PSI," or pounds per square inch, a measure of pressure. Pressure is typically measured as "psig", or the pressure in excess of standard atmospheric pressure."Present Value." When used with respect to oil and gas reserves, present value means the estimated future net revenues computed by applying current prices of oil andgas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as ofthe date of the latest balance sheet presented, less estimated future expenditures (based on current costs to be incurred in developing and producing the proved reserves)computed using a discount factor and assuming continuation of existing economic conditions."Productive Well." A well that is producing oil or gas or that is capable of production."PV-10." Means the present value, discounted at 10% per annum, of future net revenues (estimated future gross revenues less estimated future costs of production,development, and asset retirement costs) associated with reserves and is not necessarily the same as market value. PV-10 does not include estimated future income taxes.Unless otherwise noted, PV-10 is calculated using the pricing scheme as required by the Securities and Exchange Commission ("SEC"). PV-10 of proved reserves iscalculated the same as the standardized measure of discounted future net cash flows, except that the standardized measure of discounted future net cash flows includes futureestimated income taxes discounted at 10% per annum. See the definition of standardized measure of discounted future net cash flows."Royalty" or "Royalty Interest." 1) The mineral owner's share of oil or gas production (typically between 1 / 8 and 1 / 4 ), free of costs, but subject to severance taxesunless the lessor is a government. In certain circumstances, the royalty owner bears a proportionate share of the costs of making the natural gas saleable, such as processing,compression and gathering. 2) When a royalty interest is coterminous with and carved out of an operating or working interest, it is an "Overriding Royalty Interest," whichalso may generically be referred to as a Royalty."Shut-in Well." A well that is not on production, but has not yet been plugged and abandoned. Wells may be shut-in in anticipation of future utility as a producing well,plugging and abandonment or other use."Standardized Measure." The standardized measure of discounted future net cash flows (the "Standardized Measure") is an estimate of future net cash flows associatedwith proved reserves, discounted at 10% per annum. Future net cash flows is calculated by reducing future net revenues by estimated future income tax expenses anddiscounting at 10% per annum. The Standardized Measure and the PV-10 of proved reserves is calculated in the same exact fashion, except that the Standardized Measureincludes future estimated income taxes discounted at 10% per annum. The Standardized Measure is in accordance with accounting standards generally accepted in theUnited States of America ("GAAP")."SWIW." Salt water injection well."Undeveloped Reserves." Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relativelymajor expenditure is required for recompletion.*"Working Interest." The interest in the oil and gas in place which is burdened with the cost of development and operation of the property. Also called the operatinginterest."Workover." A remedial operation on a completed well to restore, maintain or improve the well's production.______________________________________________________________________________* This definition may be an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X.74SIGNATURESIn accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereuntoduly authorized in the City of Houston, Texas, on the date indicated. Evolution Petroleum Corporation By: /s/ RANDALL D. KEYSRandall D. KeysPresident and Chief Executive Officer(Principal Executive Officer)Date: September 9, 2016 In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and onthe dates indicated.Date Signature Title September 9, 2016 /s/ ROBERT S. HERLINRobert S. Herlin Executive Chairman of the BoardSeptember 9, 2016 /s/ RANDALL D. KEYSRandall D. Keys President and Chief Executive Officer (Principal Executive Officer)September 9, 2016 /s/ DAVID JOE David Joe Senior Vice President, Chief Financial Officer and Treasurer (PrincipalFinancial Officer)September 9, 2016 /s/ RODERICK SCHULTZ Roderick Schultz Chief Accounting Officer (Principal Accounting Officer)September 9, 2016 /s/ EDWARD J. DIPAOLOEdward J. DiPaolo Lead DirectorSeptember 9, 2016 /s/ GENE STOEVERGene Stoever DirectorSeptember 9, 2016 /s/ WILLIAM DOZIERWilliam Dozier DirectorSeptember 9, 2016 /s/ KELLY W. LOYDKelly W. Loyd Director75INDEX OF EXHIBITSMASTER EXHIBIT INDEXEXHIBITNUMBERDESCRIPTION3.1Articles of Incorporation (Previously filed as an exhibit to the Company's Current Report on Form 8-K on February 7, 2002)3.2Certificate of Amendment to Articles of Incorporation (Previously filed as an exhibit to the Company's Current Report on Form 8-K on February 7, 2002)3.3Certificate of Amendment to Articles of Incorporation (Previously filed as an exhibit to Form SB 2/A on October 19, 2005)3.4Certificate of Designation of Rights and Preferences for 8.5% Series A Cumulative Preferred Stock (Previously filed as an exhibit to the Company's CurrentReport of Form 8-K on June 29, 2011)3.5Bylaws (Previously filed as an exhibit to the Company's Current Report on Form 8-K on February 7, 2002)3.6Amended Bylaws (Previously filed as an exhibit to Form 10KSB on March 31, 2004)4.1Specimen form of the Company's Common Stock Certificate (Previously filed as an exhibit to Form S-3 on June 19, 2013)4.2Specimen form of the Company's 8.5% Series A Cumulative Preferred Stock Certificate (Previously filed as an exhibit to Form 8-A on June 29, 2011)4.32004 Stock Plan (Previously filed as an exhibit to the Company's Definitive Information Statement on Schedule 14C on August 9, 2004)4.4Amended and Restated 2004 Stock Plan, adopted December 4, 2007 (previously filed as an exhibit to the Company's Definitive Information Statement onSchedule 14A on October 29, 2007)4.5Amendment to Amended and Restated 2004 Stock Plan, adopted December 5, 2011 (previously filed as an exhibit to the Company's Definitive InformationStatement on Schedule 14A on October 28, 2011)4.6Form of Stock Option Agreement for the Natural Gas Systems 2004 Stock Plan (Previously filed as an exhibit to the Current Report on Form 8-K on April 8,2005)4.7Form of Restricted Stock Agreement (Previously filed as an exhibit to Form 8-K on May 15, 2009)4.8Form of Contingent Performance Stock Grant under the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (Previously filed as anexhibit to the Company's Quarterly Report on Form 10-Q on November 7, 2014 )4.9Majority Voting Policy for Directors (Previously filed as an exhibit to the Company's Current Report on Form 8-K on October 31, 2012)10.1Executive Employment Agreement of Robert S. Herlin, dated April 4, 2005 (Previously filed as an exhibit to Form 8-K on April 8, 2005)10.2Executive Employment Agreement of Daryl V. Mazzanti, dated June 23, 2005 (Previously filed as an exhibit to Form 8-K on June 29, 2005)10.3Purchase and Sale Agreement I, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, 2006 (Previously filed as an exhibit to Form 8-K onJune 16, 2006)10.4Purchase and Sale Agreement II, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, 2006 (Previously filed as an exhibit to Form 8-K onJune 16, 2006)10.5Conveyance, Assignment and Bill of Sale Agreement, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, 2006 (Previously filed as anexhibit to Form 8-K on June 16, 2006)10.6Unit Operating Agreement, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, 2006 (Previously filed as an exhibit to Form 8-K onJune 16, 2006)10.7Settlement Agreement, dated June 24, 2016, by and among Denbury Onshore, LLC, Denbury Resources Inc., NGS Sub Corp., Tertiaire Resources Company,and the Company (Filed herein)10.8Form of Indemnification Agreement for Officers and Directors, as adopted on September 20, 2006 (Previously filed as an exhibit to Form 8-K on September 22,2006)10.9Technology Assignment Agreement dated June 30, 2011 between Evolution Petroleum Corporation and Daryl Mazzanti (Previously filed as an exhibit to Form10-K on September 11, 2015)10.10Credit Agreement dated April 11, 2016 between Evolution Petroleum Corporation and MidFirst Bank (Previously filed as an exhibit to Form 8-K on April 15,2016)76EXHIBITNUMBERDESCRIPTION14.1Code of Business Conduct and Ethics for Natural Gas Systems, Inc. (Previously filed as an exhibit to Form 8-K on May 4, 2006)21.1List of Subsidiaries of Evolution Petroleum Corporation (Filed herein)23.1Consent of Hein & Associates, LLP (Filed herein)23.2Consent of DeGolyer and MacNaughton (Filed herein)23.3Consent of W.D. Von Gonten & Co. (Filed herein)31.1Certification of Chief Executive Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to Section 302 ofthe Sarbanes-Oxley Act of 2002 (Filed herein)31.2Certification of President and Chief Financial Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant toSection 302 of the Sarbanes-Oxley Act of 2002 (Filed herein)32.1Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Filedherein)32.2Certification of President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of2002 (Filed herein)99.1Audit Committee Charter of the Board of Directors of Natural Gas Systems, Inc. (Previously filed as an exhibit to Form 8-K on May 4, 2006)99.2Compensation Committee Charter of the Board of Directors of Natural Gas Systems, Inc. (Previously filed as an exhibit to Form 8-K on May 4, 2006)99.3Nominating Committee Charter of the Board of Directors of Natural Gas Systems, Inc. (Previously filed as an exhibit to Form 8-K on May 4, 2006)99.4The summary of DeGolyer and MacNaughton's Report as of June 30, 2016, on oil and gas reserves (SEC Case) dated August 26, 2016 and certificate ofqualification (Filed herein)101.INSXBRL Instance Document101.SCHXBRL Taxonomy Extension Schema Document101.CALXBRL Taxonomy Extension Calculation Linkbase Document101.DEFXBRL Taxonomy Extension Definition Linkbase Document101.LABXBRL Taxonomy Extension Label Linkbase Document101.PREXBRL Taxonomy Extension Presentation Linkbase Document77Exhibit 10.7 SETTLEMENT AGREEMENTTHIS SETTLEMENT AGREEMENT (“ Agreement ”) is made and entered into effective as of June 24, 2016 (the “ Effective Date ”),by and among Denbury Onshore, LLC (“ Denbury Onshore ”), Denbury Resources Inc. (“ DRI ” and, collectively with Denbury Onshore, “Denbury ”), NGS Sub Corp. (“ NGS ”), Tertiaire Resources Company (“ TRC ”), and Evolution Petroleum Corporation (“ EPM ” and,collectively with NGS and TRC, “ Evolution ”) (Denbury and Evolution collectively are referred to as the “ Parties ” or, individually, as a “Party ”).RECITALS:On or about May 8, 2006, NGS and Denbury Onshore entered into a Purchase and Sale Agreement that set forth an agreement forDenbury Onshore to acquire certain Working Interests (“ WI ”) with certain Net Revenue Interests (“ NRI ”) in the unitized Holt-Bryantintervals (the “ Holt-Bryant Intervals ”) in the Delhi Unit located in Richland, Franklin and Madison Parishes, Louisiana (the “ Unit ”) fromNGS. NGS and Denbury Onshore subsequently entered into two bifurcated Purchase and Sale Agreements (collectively, the “ PSA ”) settingforth the details of the transaction, including certain rights and obligations of NGS and Denbury Onshore that would survive the closing of thetransaction. NGS and Denbury Onshore closed on the PSA on or about June 12, 2006. The actual transfer of interests between NGS andDenbury Onshore was covered by a Conveyance, Assignment, and Bill of Sale (“ Conveyance ”). To the extent any agreement herein addressesa provision in one of the PSA or the Conveyance, but relates to a right or obligation in both the PSA and the Conveyance, this Agreement shallapply to both contracts.Also on or about June 12, 2006, NGS and Denbury Onshore entered into a Unit Operating Agreement (the “ 2006 UOA ”) governingrights and duties of the Parties concerning the operation of the Unit. As part of the 2006 UOA, the parties agreed that, as between NGS andDenbury Onshore, the 1984 COPAS accounting standards would govern the accounting of Unit operations. As recognized in the 2006 UOA, aseparate 1952 Unit Operating Agreement governs the Unit as approved by the Louisiana Department of Natural Resources Office ofConservation (the “ 1952 UOA ”).From and after June 1, 2006 or about that date, Denbury Onshore has been the operator of the Unit.Certain disputes have arisen between the Parties concerning (i) the Parties’ performance under the PSA and Conveyance, (ii) the Parties’performance under the 2006 UOA, (iii) Denbury Onshore’s operation of the Unit, and (iv) certain other issues. The Parties have brought claimsagainst each other in a lawsuit styled NGS et al v. Denbury Onshore et al, Cause No. 2013-74863 in the 133rd Judicial District Court of HarrisCounty, Texas (the “ Lawsuit ”).1Without admitting any wrongdoing, fault, or liability of any kind, the Parties desire to resolve the Lawsuit and any and all claims theyhave or may have against each other, and further desire to clarify certain aspects of their ongoing relationship, on the terms and conditions setout below.AGREEMENTS:NOW, THEREFORE, in consideration of the mutual promises and obligations contained herein, and subject to the terms and conditionshereof, the Parties, intending to be legally bound, agree as follows:1. Payment by Denbury . On or before the fourth business day after the Effective Date, Denbury will pay to EPM the sum ofTwenty-Seven Million Five Hundred Thousand dollars ($27,500,000.00), by wire transfer to:Wells Fargo Bank1000 Louisiana St., 7th FloorHouston, Texas 77002Routing No. [intentionally omitted]Account No. [intentionally omitted]2. Assignment of Interests by Denbury . Within three business days following the Effective Date, (a) Denbury Onshore will assignto TRC, effective as of July 1, 2016, 25% of all interests assigned to Denbury Onshore and its affiliates in the Mengel interval of the Unit (the “Mengel Interval ”) by executing an Assignment in substantially the form attached hereto as Exhibit A, and (b) the parties will amend the 2006UOA to govern all depths in the Unit, including the Mengel Interval, by executing an Amendment in substantially the form attached hereto asExhibit B. Except as explicitly agreed herein, the Parties’ rights and obligations in the Mengel Interval shall be governed by the 2006 UOA, asamended. Evolution agrees that the entity that owns the working interest in the Holt-Bryant Intervals shall be the same entity to own the workinginterest transferred by this paragraph in the Mengel Interval. Evolution further agrees that it will not separate these working interests bytransferring either interest to another entity independently of the other interest without the prior written consent of Denbury. Nothing herein shallprevent Evolution from simultaneously transferring both of such interests to another single entity, so long as such transfer is otherwisepermissible under, and made in accordance with and subject to, the terms of the 2006 UOA, the PSA and the Conveyance.3. Adjustment of Interests in the Holt-Bryant Intervals . Evolution acknowledges and agrees that, as a result of the settlement andcompromise reflected in this Agreement, Denbury Onshore shall be entitled to adjust the interests in the Holt-Bryant Intervals credited onDenbury Onshore’s ownership decks to Evolution and Denbury Onshore, respectively, effective as of July 1, 2016. This adjustment will result inDenbury Onshore increasing the NRI in the Holt-Bryant2Intervals credited to Denbury Onshore by inclusion of a 0.222595% overriding royalty interest in the Holt-Bryant Intervals to Denbury Onshoreand decreasing the overriding royalty interest in the Holt-Bryant Intervals subject to that certain Act of Sale and Assignment executed onJanuary 31, 2006, but effective as of December 1, 2005, by and between James H. Jones and Kristi S. Jones, as Vendors and NGS Sub Corp., asVendee (the “ Jones ORRI ”) credited to EPM by the same amount. Specifically, the Jones ORRI is to be reduced from 4.811195% to 4.5886%.Without limiting the generality of the releases contained in this Agreement, Denbury specifically releases, discharges, and dismisses withprejudice its claims relating to the working and/or net revenue interests in the Holt-Bryant Intervals conveyed by NGS to Denbury Onshoreunder the PSA and/or Conveyance (the “ NRI Dispute ”).4. Resulting Ownership in the Unit . Following the assignment set forth in paragraph 2 of this Agreement and the adjustment setforth in paragraph 3 of this Agreement, Evolutions’ interests in the Holt-Bryant Intervals and the Mengel Interval that were affected, conveyed,or retained pursuant to the PSA, Conveyance, and/or this Agreement shall be as follows:a. Post-Agreement Ownership Interests in the Holt-Bryant Intervals :Denbury Onshore : NRI increased by 0.222595% (.00222595)TRC : Working Interest 23.8879375%TRC : Net Revenue Interest 19.0361517%EPM : Royalty Interests 0.4979160%EPM : Jones ORRI 4.5886000%EPM : Other ORRI 2.0960900%b. Post-Agreement Ownership Interests in the Mengel Interval :Denbury Onshore : Working Interest 71.8283420%Net Revenue Interest 51.5023620%TRC : Working Interest 23.9427800%Net Revenue Interest 17.1674540%By stating these percentages above, the Parties are making no warranties of title and no guarantees except as are explicitly made elsewhere inthis Agreement or as made in prior conveyances. The Parties further agree that, if Denbury Onshore, in its reasonable judgment as a prudentoperator, ever recognizes any working interest owner(s) or revenue interest owner(s) in either the Holt-Bryant3Intervals or the Mengel Interval unaccounted for in the ownership figures given in this paragraph 4 of this Agreement, then Denbury Onshore’sand Evolution’s interests shall be proportionately reduced such that both Denbury Onshore and Evolution (or the successors or assigns of theseparties) proportionately share the burden of the reduction in ownership caused by the recognition of the previously unrecognized interests.5. Agreements about CO 2 Pipelines .a. The Parties agree that Denbury Gulf Coast Pipelines, LLC owns all of the CO 2 pipelines upstream of the Delhi Holt Bryant UnitCO 2 purchase meter, including the trunk pipeline and the lateral pipeline to the meter which is located upstream of the CO 2 recycle plant(collectively the “ Upstream Pipelines ”).b. The Amendment to the 2006 UOA attached hereto as Exhibit B contains provisions under which Evolution will pay DenburyOnshore transportation fees for CO2 transported through the Upstream Pipelines to the Delhi Holt-Bryant Unit, which provisions are an integralpart of this Agreement. Evolution acknowledges that, as a result of the settlement and compromise reflected in this Agreement, thetransportation fees described and set forth in the 2006 UOA, as amended, may be below market rates.c. The Parties agree that, as of the Effective Date, the working interest owners in the Unit own all CO2 piping downstream of theDelhi Holt Bryant Unit CO2 purchase meter to the CO2 recycling plant and all Unit CO2 infrastructure piping, including piping to the Unit testsites, and to and from the Unit’s CO2 recycle plant (collectively, the “ Downstream Pipelines ”). The Parties agree that, as of the EffectiveDate, notwithstanding Evolution’s prior interpretation of Article 1.9(d)(3) of the PSA and Article II(d)(iii) of the Conveyance, the cost ofoperating and maintaining the Downstream Pipelines shall be proportionately borne by the working interest owners in accordance with theirworking interest ownership in the Holt-Bryant Intervals and pursuant to the 2006 UOA, as amended. Without limiting the generality of thereleases contained in this Agreement, Evolution specifically releases, discharges, and dismisses with prejudice its pending legal and audit claimsconcerning costs incurred to operate and/or maintain the Downstream Pipelines, including, but not limited to, any and all pending complaints byEvolution concerning either (1) Denbury’s treatment of costs related to the Unit’s “CO2 Flowlines” or (2) Denbury’s treatment of the Unit’s“CO2 Plant Electric” costs. Evolution agrees to accept all past charges to the joint account for these and any other costs to operate and/ormaintain the Downstream Pipelines.6. Plugging and Abandoning Costs . The Parties agree that, notwithstanding Evolution’s prior interpretation of the PSA andConveyance, all costs incurred to plug and/or abandon any wells within the Unit Area (as that term is defined in the 2006 UOA) will beproportionately borne by the Unit’s working interest owners and pursuant to the 2006 UOA, as amended. Without limiting the generality of thereleases contained in this Agreement, Evolution specifically releases,4discharges, and dismisses with prejudice its pending legal and audit claims concerning costs incurred to plug and/or abandon any wells withinthe Unit Area. 7. CO2 Recycling Facility .a. The Parties agree that following Reversion TRC owns an interest in the CO 2 Recycling Facility, including all related real property(the “ Facility ”), equal to its working interest percentage in the Holt-Bryant Intervals. As of July 1, 2016, such ownership shall be equal to theworking interest percentage of TRC in the Holt-Bryant Intervals as stated in paragraph 4 of this Agreement, and as may be adjusted from time totime as provided in paragraph 4 of this Agreement. Without limiting the generality of the releases contained in this Agreement, Denburyspecifically releases, discharges, and dismisses with prejudice its claims relating to the costs of the Facility and the Facility Usage Fee, asdefined in Denbury’s Second Amended Answer and Counterclaims.b. Except for costs incurred prior to Reversion, TRC will pay its proportionate working interest share of all operating and capital costsattributable to the Facility in proportion to its working interest percentage in the Holt-Bryant Intervals. TRC specifically disclaims its rights toany beneficial interest in the Facility Usage Fee attributable to other working interest owners in the Unit.8. Area of Mutual Interest . The Parties agree that the provision in the PSA providing for an area of mutual interest is no longerbinding on the Parties. Without limiting the generality of the releases contained in this Agreement, Evolution releases, discharges, and dismisseswith prejudice its claims related to the area of mutual interest in the PSA (the “ AMI Dispute ”).9. Preferential Right . The Parties agree that Article 19.1 in the PSA and Article VI of the Conveyance are still binding and valid.However, Denbury hereby definitively consents to and ratifies the assignment of EPM’s working interest (reversionary or otherwise) in the Unitto TRC that was effected by that certain Act of Assignment by and between EPM, as Assignor, and TRC, as Assignee, effective May 16, 2008and recorded at File No. 342603, Conveyance Book 469, in the Records of Richland Parish, Louisiana and in the Records of Franklin andMadison Parishes, Louisiana. Without limiting the generality of the releases contained in this Agreement, Denbury specifically releases,discharges, and dismisses with prejudice its claims that any transfers made prior to the Effective Date of this Agreement by any of EPM, TRC,or NGS violated Article 19.1 of the PSA and/or Article VI of the Conveyance (the “ Pref Right Dispute ”).10. Timing of Payout . The Parties agree that Payout, as that term is defined in the PSA and Conveyance, occurred during October2014 and that TRC reverted to its proportionate share of the working interest effective November 1, 2014 (the “ Reversion ”) as set forth in thatcertain Conveyance and Assignment, dated December 31, 2014. Without limiting the generality of the5releases contained in this Agreement, the Parties release, discharge and dismiss with prejudice any and all claims and counterclaims relating tothe timing of Payout or Reversion, including any and all disputes related to costs charged to the Payout account prior to Reversion. No Partyretains any claim for damages related to the timing, nature, or terms of Payout or the Reversion.11. Audit Exceptions . The Parties intend for this Agreement to resolve any and all exceptions, claims, or disputes in connection withEvolution’s right to audit the Payout account pursuant to Section 1.9(d)(6) of the PSA or the joint account pursuant to Section 5.3 of the 2006UOA for the period through and including March 31, 2015 (the period of the most recently completed audit) (the “ Audits ”). Any and allexceptions that Evolution has made or could have made in the Audits are hereby resolved and waived, including, but not limited to, exceptionsregarding:a. a fee for the Delhi CO2 facility, raised in exception no. 1 in the 2008-2010 audit, exception no. 1 in the 2010-2011 audit, exceptionno. 1 in the 2011-2012 audit, exception no. 1 in the 2013-2014 audit, exception no. 17 in the 2014-2015 audit, all JADE lines referenced orincorporated into those exceptions, and any related exceptions from any of the Audits (the “ Facility Usage Fee ”);b. the cost of plugging and abandoning wells, raised in exception no. 12 in the 2006-2008 audit, exception no. 11 in the 2008-2010audit, exception no. 37 in the 2011-2012 audit, exception no. 21 in the 2013-2014 audit, exception no. 15 in the 2014-2015 audit, all JADE linesreferenced or incorporated into those exceptions, and any related exceptions from any of the Audits (“ P&A Costs ”);c. the cost of remediation, clean-up, and restoration, raised in exception no. 22 in the 2013-2014 audit, exception no. 14 in the 2014-2015 audit, preliminary exception no. 2 in the 2015-2016 audit, all JADE lines referenced or incorporated into those exceptions, and any similarexceptions from any of the Audits, whether or not such exceptions are specifically related to the June 2013 Environmental Incident (the “Environmental Remediation Costs ”);d. the cost of operating and maintaining CO2 flowlines, raised in exception nos. 26 and 35 in the 2011-2012 audit, exception no. 20 inthe 2013-2014 audit, exception no. 16 in the 2014-2015 audit, all JADE lines referenced or incorporated into those exceptions, and any relatedexceptions from any of the Audits (the “ Flowlines Costs ”); ande. the cost of electricity used on the Delhi CO2 facility, raised in exception no. 17 in the 2014-2015 Audit, all JADE lines referencedor incorporated into that exception, and any related exceptions from any of the Audits (the “ Electricity Costs ”).Evolution agrees not to make an exception to the Facility Usage Fee, P&A Costs, the Environmental Remediation Costs, the Flowlines Costs, orthe Electricity Costs in the audit that is currently6underway for the period from April 2015 through March 2016, or in any future audit, absent manifest error in the relevant calculations.12. Post Reversion Indemnity Obligations . Evolution agrees that it has no further claims against Denbury related to claims or costsarising from the incident at the Unit that occurred on or about June 13, 2013 (the “ June 2013 Environmental Incident ”) and that have beendisclosed to Evolution or of which Evolution is aware, and that Denbury has no further obligation to Evolution for such claims or costs.Notwithstanding anything herein to the contrary, the Parties agree that for any other costs or claims which are asserted or arise subsequent to theEffective Date of this Agreement and which relate to events that occurred prior to Reversion, including the June 2013 Environmental Incident,the rights and obligations set forth in Article 17 of the PSA and Articles II, IV and V of the Conveyance shall continue to apply.13. Insurance Proceeds . Evolution waives and releases any claim to any insurance proceeds that Denbury may receive related toclaims made before the Effective Date concerning the June 2013 Environmental Incident. Evolution agrees that Denbury may keep any suchproceeds in their entirety. Evolution shall have no right to obtain any portion of such proceeds by reason of its proportionate working interestownership in the Unit. Notwithstanding anything to the contrary, nothing contained herein shall affect Evolution’s rights to obtain insuranceproceeds received after the Effective Date that do not relate to the June 2013 Environmental Incident.14. Geological, Geophysical, and Technical Information .a. To the extent it is legally permitted to do so, Denbury will make certain geological, geophysical and technical informationconcerning the Unit that is in existence as of the Effective Date accessible to TRC on a workstation at the headquarters of DRI. The informationmade available to TRC pursuant to this subparagraph (the “ Existing Data ”) shall be limited to raw geological, geophysical, and technical dataand shall not include any analysis, interpretation, or other derivative Denbury work product derived from or based upon such data. TRC’s accessto the Existing Data shall be limited to (i) normal working hours of Denbury Onshore, (ii) 150 combined hours per year at a workstation at theheadquarters of DRI, and (iii) a single, contiguous four-week period per year. TRC agrees to hold the Existing Data strictly confidential. TRCagrees that it will not, directly or indirectly, disclose the Existing Data to anyone, except as required by applicable law or a court of competentjurisdiction, or to TRC’s outside reserves engineer (who shall also agree to keep such data confidential) for purposes of compiling TRC’s annualreserves report. Denbury makes no warranty or representation, express or implied, with respect to the accuracy, completeness, or materiality ofthe Existing Data, except that Denbury will not knowingly provide inaccurate data to TRC. The Existing Data shall be made available to TRC asa convenience only and any reliance on or use of same is at TRC’s sole risk. TRC will indemnify Denbury against any and all claims, demands,losses, damages, causes of action, or judgments of any kind or character arising out of TRC’s use of the Existing Data. Notwithstandinganything in paragraph 23 (or any other paragraph7or section) of this Agreement, TRC’s rights under this paragraph of this Agreement shall be strictly non-transferable and non-assignable andshall not inure to the benefit of TRC’s successors, heirs, or assigns. Denbury further agrees that it will not raise an objection if TRC uses anindependent reservoir engineer to review or prepare its reserves estimates that is also used by Denbury for this same purpose.b. In its capacity as a working interest owner, TRC shall be given the opportunity to participate, proportionate to its working interestownership in the Unit, in the cost of acquiring geological, geophysical and technical information concerning the Unit not in existence as of theEffective Date. To the extent TRC elects to participate in such costs, and solely to such extent, Denbury will provide TRC with copies of suchgeological, geophysical and technical information concerning the Unit for purposes of TRC’s annual reserves report and other analysis.1.5 Confidentiality; Prior Approval of Press Releases . Denbury will not (i) make any statement to the public concerning thisAgreement or settlement or dismissal of the Lawsuit or (ii) issue any press release concerning same, without first obtaining express writtenapproval of the statement or press release from Evolution. Likewise, Evolution will not (i) make any statement to the public concerning thisAgreement or settlement or dismissal of the Lawsuit or (ii) issue any press release concerning same, without first obtaining express writtenapproval of the statement or press release from Denbury. Such approvals will not be unreasonably withheld and neither Party shall be restrictedfrom providing timely disclosures to the public as required by federal and state securities laws and any other applicable rules and regulations.The Parties agree that certain information contained in this Agreement is confidential, and further agree to take reasonable steps to avoiddisclosure or dissemination of the complete text of this Agreement to third parties (excluding the Parties’ respective officers, employees,directors, attorneys, accountants and tax or financial advisors), except for summary disclosure of relevant provisions as deemed necessary oradvisable for public reporting purposes, subject in all respects to the foregoing provisions of this paragraph 15.16. Dismissal of the Lawsuit . The Parties agree to take all necessary and appropriate efforts to dismiss the Lawsuit with prejudice,including by filing the Joint Agreed Motion to Dismiss and Order of Dismissal with Prejudice in the forms attached hereto as Exhibit C andExhibit D, respectively.17. Release by Denbury .a. Denbury releases and discharges Evolution, together with all of Evolution’s past, present and future direct and indirect parents,owners, subsidiaries, affiliates, divisions, and related entities, and any of those entities’ past, present and future employees, officers, directors,shareholders, fiduciaries, agents, insurance carriers, predecessors, successors, assigns, executors, administrators, and legal representatives(collectively, the “ Released Evolution Parties ”) from any8and all claims, causes of action, complaints, liabilities, and theories of recovery of whatever nature, against any of the Released EvolutionParties, whether known or unknown, whether recognized by the law or equity of any jurisdiction, and whether for direct, consequential, orspecial damages, losses, costs, expenses, specific performance, or equitable relief arising from and relating to the pending disputes concerningthe Facility Usage Fee, P&A Costs, the June 2013 Environmental Incident, Environmental Remediation Costs, Flowline Costs, Electricity Costs,the NR1 Dispute, the AMI Dispute and/or the Pref Right Dispute, as defined above, and any other matter whatsoever to the extent that it is basedon acts or omissions that have occurred prior to the Effective Date (collectively, “ Claims Released by Denbury ”), except as set forth inparagraph 17(c) below.b. Denbury agrees not to bring, join, or accept relief from any lawsuit in which Denbury asserts any of the Claims Released byDenbury against any of the Released Evolution Parties in any court or other forum, except that Denbury may file suit solely as necessary toprotect its rights under this Agreement.c. Exclusions from the Release . Notwithstanding paragraph 17(a) above: (i) none of the rights and obligations created by thisAgreement are waived or released; and (ii) Denbury retains all rights and obligations under the PSA, Conveyance, the 2006 UOA, and the 1952UOA except to the extent such rights and obligations were modified or released pursuant to this Agreement, including specifically the ClaimsReleased by Denbury in paragraph 17(a), above; provided that, and notwithstanding anything to the contrary contained herein, Denbury retainsthe rights and obligations specifically retained in paragraph 12.18. Release by Evolution .a. Evolution releases and discharges Denbury, together with all of Denbury’s past, present and future direct and indirect parents,owners, subsidiaries, affiliates, divisions, and related entities, and any of those entities’ past, present and future employees, officers, directors,shareholders, fiduciaries, agents, insurance carriers, predecessors, successors, assigns, executors, administrators, and legal representatives(collectively, the “ Released Denbury Parties ”) from any and all claims, causes of action, complaints, liabilities, and theories of recovery ofwhatever nature, whether known or unknown, and whether recognized by the law or equity of any jurisdiction from any and all claims, causes ofaction, complaints, liabilities, and theories of recovery of whatever nature, against any of the Released Denbury Parties, whether known orunknown, whether recognized by the law or equity of any jurisdiction, and whether for direct, consequential, or special damages, losses, costs,expenses, specific performance, or equitable relief arising from and relating to the pending disputes concerning the Facility Usage Fee, P&ACosts, the June 2013 Environmental Incident, Environmental Remediation Costs, Flowline Costs, Electricity Costs, the NRI Dispute, the AMIDispute and/or the Pref Right Dispute, as defined above, and any other matter whatsoever to the extent that it is based on acts or omissions thathave occurred prior to the Effective Date (collectively, “ Claims Released by Evolution ”), except as set forth in paragraph 18(c).9b. Evolution agrees not to bring, join, or accept relief from any lawsuit in which Evolution asserts any of the Claims Released byEvolution against any of the Released Denbury Parties in any court or other forum, except that Evolution may file suit solely as necessary toprotect its rights under this Agreement.c. Exclusions from the Release . Notwithstanding paragraph 18(a) above: (i) none of the rights and obligations created by thisAgreement are waived or released and (ii) Evolution retains all rights and obligations under the PSA, Conveyance, the 2006 UOA, and the 1952UOA except to the extent such rights and obligations were modified or released pursuant to this Agreement, including specifically the ClaimsReleased by Evolution in paragraph 18(a), above; provided that, and notwithstanding anything to the contrary contained herein, Evolutionretains the rights and obligations specifically retained in paragraph 12.19. No Admission of Liability . Nothing contained in this Agreement or the settlement among the Parties, or any act performed ordocument executed pursuant to or in furtherance of this Agreement or such settlement, is, may be deemed, may be used as, or shall be construedas an admission by any of the Parties of wrongdoing, fault, or liability of any kind with respect thereto, and all such liability is expressly denied.20. Representations and Warranties . The Parties represent and warrant as follows:a. Each Party hereto represents and warrants that it has entered into and executed this Agreement voluntarily, knowingly, and with thebenefit of advice of legal counsel of its choosing.b. Each Party hereto represents and warrants that it has not relied upon the representation of any person in entering into thisAgreement but has entered into this Agreement based on its own knowledge and investigation of the facts. In executing this Agreement, noParty did rely or has relied upon any representation or statement made by any other Party, or by any agents, representatives, or attorneys of anyother Party, with regard to the subject matter, basis, or effect of this Agreement.c. Evolution represents and warrants that it has not sold, transferred, pledged, or assigned to any other person or entity all or anyportion of the Claims Released by Evolution (or any claim that would be released by this Agreement but for such a sale, transfer, pledge, orassignment) or any rights or entitlements with respect thereto, and that the execution and delivery of this Agreement does not violate or conflictwith the terms of any contract, agreement, or other instrument.d. Denbury represents and warrants that it has not sold, transferred, pledged, or assigned to any other person or entity all or anyportion of the Claims Released by Denbury (or any claim that would be released by this Agreement but for such a sale, transfer, pledge, orassignment) or10any rights or entitlements with respect thereto, and that the execution and delivery of this Agreement does not violate or conflict with the termsof any contract, agreement, or other instrument.e. Each Party represents that it has full authority and approval to execute and perform this Agreement.21. Waiver of Breach . The failure by any Party to insist upon the performance of any one or more terms, covenants, or conditions ofthis Agreement shall not be construed as a waiver or relinquishment of any right granted hereunder or of the future performance of any suchterm, covenant or condition.22. Severability . Should any court of competent jurisdiction declare any provision of this Agreement to be illegal. invalid, orunenforceable, the offending provision shall be stricken, and all remaining provisions shall remain in full force and effect.23. Interpretation . Each of the Parties hereto has jointly participated in the negotiation and drafting of this Agreement. In the eventany ambiguity or question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by each of the Parties hereto,and no presumptions or burdens of proof shall arise favoring any Party by virtue of the authorship of any of the provisions of this Agreement.24. Binding Effect . This Agreement shall inure to the benefit of and be binding upon the Parties hereto and their respective parents,subsidiaries, agents, officers, directors, employees, representatives, successors, heirs, assigns, attorneys, and insurers. The signatories to thisAgreement represent and warrant that they have the authority to execute this Agreement on behalf of the Parties that they purport to represent.25. Execution . This Agreement may be executed in counterpart signature pages or in any number of counterparts, all of which takentogether shall constitute one and the same instrument, and any of the Parties may execute this Agreement by signing any such counterpartsignature page or such counterpart. Electronic copies of signature pages shall be deemed valid.26. Texas Law and Venue . This Agreement shall be governed by and construed in accordance with the laws of the State of Texas,without regard to its conflict of law principles. Each Party submits to the jurisdiction of any courts of the State of Texas in the County of Harris,or of the United States District Court for the Southern District of Texas (Houston Division). Each Party hereby (a) irrevocably waives anyobjection that it may now or hereafter have to the laying of venue in the courts referred to in this paragraph, (b) irrevocably waives and agreesnot to plead or claim in any such court that any such action or proceeding brought therein has been brought in an inconvenient forum, and (c)irrevocably waives right to a trial by jury in any action, proceeding, or counterclaim arising out of, relating to, or in connection with thisAgreement or performance hereunder.1127. Timing . Time is of the essence with respect to the dates and times set forth in this Agreement.The Parties hereto represent and declare that they have carefully read this Agreement and know the contents thereof, and thatthey sign the same freely, voluntarily, and wholly without duress or any coercion whatsoever.[Signature Page to Follow]12IN WITNESS WHEREOF, the Parties hereto have executed this Agreement as of the Effective Date.DENBURY ONSHORE, LLCBy:/s/ James S. Matthews James S. MatthewsSenior Vice President and General CounselDENBURY RESOURCES INC.By:/s/ James S. Matthews James S. MatthewsSenior Vice President and General CounselEVOLUTION PETROLEUM CORPORATIONBy:/s/ Randall D. Keys Randall D. KeysPresident and CEONGS SUB CORP.By:/s/ Randall D. Keys Randall D. KeysPresident and CEOTERTIAIRE RESOURCES COMPANYBy:/s/ Randall D. Keys Randall D. KeysPresident and CEOSIGNATURE PAGE TO SETTLEMENT AGREEMENTEXHIBIT A[to be attached]EXHIBIT A TO SETTLEMENT AGREEMENTCONVEYANCE, ASSIGNMENT, BILL OF SALESTATE OF LOUISIANA§PARISHES OF FRANKLIN, MADISON§AND RICHLAND§KNOW ALL MEN BY THESE PRESENTS:This Conveyance, Assignment, Bill of Sale and Stipulation of Interests (this “Conveyance”) is dated as of June 24, 2016 but effective asof July 1, 2016 (the “Effective Date”) by and between DENBURY ONSHORE, LLC , a Delaware limited liability company, whose address is5320 Legacy Drive, Plano, Texas 75024 (“Assignor”), and TERTIAIRE RESOURCES COMPANY , a Texas corporation, whose address is2500 CityWest Blvd, Suite 1300, Houston, Texas 77042 (“Assignee”). Assignor and Assignee are hereinafter collectively referred to as the“Parties,” and individually as a “Party.”I. CONVEYANCEUpon the terms and conditions of the Settlement Agreement, as defined below, for One Hundred Dollars and other good and valuableconsideration, the receipt and sufficiency of which is hereby acknowledged, Assignor hereby GRANTS, BARGAINS, SELLS, CONVEYS,ASSIGNS, TRANSFERS and DELIVERS unto Assignee, an undivided twenty five percent (25%) of all of the right, title and interest, whetherpresent, contingent, or reversionary, acquired by Assignor through the following conveyances:1)That certain Conveyance, Assignment and Bill of Sale dated effective November 19, 2014 by and between GEF SPV Limited, asAssignor, and Denbury Onshore, LLC, as Assignee, recorded in Book 508, under File No. 366046 of the conveyance records ofRichland Parish, Louisiana; and2)That certain Conveyance, Assignment and Bill of Sale dated effective November 19, 2014 by and between GEF SPV Limited, asAssignor, and Denbury Onshore, LLC, as Assignee, recorded in Book 426, Page 117, under File No. 357820 of the conveyancerecords of Franklin Parish, Louisiana; and3)That certain Conveyance, Assignment and Bill of Sale dated effective November 19, 2014 by and between GEF SPV Limited, asAssignor, and Denbury Onshore, LLC, as Assignee, recorded in Book 338, Page 9, under File No. 133834 of the conveyancerecords of Madison Parish, Louisiana;hereinafter, the “Assets.”TO HAVE AND TO HOLD the Assets unto Assignee, its successors and assigns, forever, subject to, however, all the terms of andconditions of this Conveyance and the Settlement Agreement.II. WARRANTIES AND WAIVERSTHIS ASSIGNMENT IS MADE WITHOUT WARRANTY OF TITLE, EITHER EXPRESS, IMPLIED, STATUTORY OROTHERWISE, AND WITHOUT RECOURSE, EVEN AS TO THE RETURN OF CONSIDERATION, EXCEPT THAT ASSIGNORWARRANTS TITLE TO THE ASSETS AGAINST ALL CLAIMS, LIENS, BURDENS AND ENCUMBRANCES ARISING BY,THROUGH OR UNDER ASSIGNOR, BUT NOT OTHERWISE AND NOT WITH RESPECT TO ANY IMPAIRMENT ORFAILURE OF TITLE RELATED TO ANY LACK OF PRODUCTION IN PAYING QUANTITIES. THIS CONVEYANCE,ASSIGNMENT AND BILL OF SALE SHALL BE MADE WITH FULL SUBSTITUTION AND SUBROGATION TO ASSIGNEE INAND TO ALL COVENANTS AND WARRANTIES BY OTHERS HERETOFORE GIVEN OR MADE TO ASSIGNOR WITHRESPECT TO THE ASSETS.THE EXPRESS REPRESENTATIONS AND WARRANTIES OF ASSIGNOR CONTAINED IN THIS CONVEYANCE AREEXCLUSIVE AND ARE IN LIEU OF ALL OTHER REPRESENTATIONS AND WARRANTIES, EXPRESS, IMPLIED ORSTATUTORY, INCLUDING, WITHOUT LIMITATION, ANY REPRESENTATION OR WARRANTY WITH RESPECT TO THEQUALITY, QUANTITY OR VOLUME OF THE RESERVES, IF ANY, OF OIL, GAS OR OTHER HYDROCARBONS IN ORUNDER THE ASSETS, OR THE ENVIRONMENTAL CONDITION OF THE ASSETS. THE ITEMS OF PERSONAL PROPERTY,EQUIPMENT, IMPROVEMENTS, FIXTURES AND APPURTENANCES CONVEYED AS PART OF THE ASSETS ARE SOLDHEREUNDER “ AS IS, WHERE IS, AND WITH ALL FAULTS ” AND EXCEPT TO THE EXTENT THAT THOSE FAULTS ARECAUSED BY, THROUGH OR UNDER ASSIGNOR: (i) NO WARRANTIES OR REPRESENTATIONS OF ANY KIND ORCHARACTER, EXPRESS OR IMPLIED, INCLUDING ANY WARRANTY OF QUALITY, MERCHANTABILITY, FITNESS FORA PARTICULAR PURPOSE OR CONDITION, ARE GIVEN BY OR ON BEHALF OF ASSIGNOR; (ii) ASSIGNEE ACCEPTSSAME IN ITS “ AS IS, WHERE IS AND WITH ALL FAULTS ” CONDITION; (iii) ASSIGNEE HEREBY WAIVES ALLWARRANTIES, EXPRESS OR IMPLIED, INCLUDING, WITHOUT LIMITATION, ANY IMPLIED WARRANTY OFMERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONDITION, OR CONFORMITY TO SAMPLES.EXCEPT TO THE EXTENT THAT ASSIGNEE’S RIGHTS ARISE BY, THROUGH OR UNDER ASSIGNOR , ASSIGNEEEXPRESSLY WAIVES THE WARRANTY OF FITNESS FOR INTENDED PURPOSES OR GUARANTEE AGAINST HIDDEN OR2LATENT REDHIBITORY VICES UNDER LOUISIANA LAW, INCLUDING LOUISIANA CIVIL CODE ARTICLES 2520 (1870)THROUGH 2548 (1870), AND THE WARRANTY IMPOSED BY LOUISIANA CIVIL CODE ARTICLE 2475; ASSIGNEE WAIVESALL RIGHTS IN REDHIBITION PURSUANT TO LOUISIANA CIVIL CODE ARTICLE 2520, ET SEQ; ASSIGNEEACKNOWLEDGES THAT THIS EXPRESS WAIVER IS A MATERIAL AND INTEGRAL PART OF THIS SALE AND THECONSIDERATION THEREOF; AND ASSIGNEE ACKNOWLEDGES THAT THIS WAIVER HAS BEEN BROUGHT TO THEATTENTION OF ASSIGNEE AND EXPLAINED IN DETAIL AND THAT ASSIGNEE HAS VOLUNTARILY AND KNOWINGLYCONSENTED TO THIS WAIVER OF WARRANTY OF FITNESS AND/OR WARRANTY AGAINST REDHIBITORY VICES ANDDEFECTS FOR THE ABOVE DESCRIBED PROPERTY.III. MISCELLANEOUS PROVISIONSAssignor and Assignee agree, when requested, to take all such further actions and execute, acknowledge and deliver all such furtherdocuments that are necessary or useful in carrying out the purposes of this Conveyance. So long as authorized by applicable law so to do, (i)Assignor agrees to execute, acknowledge and deliver to Assignee all such other additional instruments, notices, division orders, transfer ordersand other documents and to do all such other and further acts and things as may be necessary to more fully and effectively convey and assign toAssignee the Assets conveyed hereby or intended so to be conveyed; and (ii) Assignee agrees to execute, acknowledge and deliver to Assignorall such other additional instruments, notices, division orders, transfer orders and other documents and to do all such other and further acts andthings as may be necessary to more fully and effectively evidence Assignor’s rights in and to the Assets.If any provision of this Conveyance is found by a court of competent jurisdiction to be invalid or unenforceable, that provision will bedeemed modified to the extent necessary to make it valid and enforceable, and if it cannot be so modified, it shall be deemed deleted and theremainder of the Conveyance shall continue and remain in full force and effect.All the terms, provisions, covenants, obligations, indemnities, representations, warranties and conditions of this Conveyance shall becovenants running with the land and shall inure to the benefit of and be binding upon, and shall be enforceable by, the parties hereto and theirrespective successors and assigns. Any subsequent transfer of all or any part of the Assets conveyed and assigned herein shall be made expresslysubject to the terms and provisions of this Conveyance.This Conveyance is made subject to that certain Settlement Agreement dated effective as of June 24, 2016 by and between the Partiesand all terms and conditions of said Settlement Agreement are incorporated herein by reference to the same extent and with the same effect as ifcopied in full herein. In the event of a conflict between the terms and conditions of this Conveyance and the said Settlement Agreement, theSettlement Agreement shall govern and control.3IN WITNESS WHEREOF, the undersigned has executed this instrument on the date of the acknowledgment annexed hereto, buteffective as of the above-stated Effective Date. ASSIGNOR:DENBURY ONSHORE, LLCBy: _________________ James S. Matthews SVP and General CounselWITNESSES:ASSIGNEE:TERTIAIRE RESOURCES COMPANYBy: ___________________ Randall D. Keys President and CEO4STATE OF TEXAS, COUNTY OF COLLINOn this ___ day of June, 2016, before me personally came and appeared James S. Matthews, to me personally known, who, beingby me duly sworn, did say that he is the Senior Vice President and General Counsel of DENBURY ONSHORE, LLC , a Delaware limitedliability company, that he signed the foregoing instrument on behalf of said limited liability company and as the free act and deed of said limitedliability company.IN WITNESS WHEREOF, I hereunto set my hand and official seal. Notary Public in and for the State of TexasSTATE OF TEXAS, COUNTY OF HARRISOn this ___ day of June, 2016, before me personally appeared Randall D. Keys, to me personally known, who, being by me dulysworn, did say that he is the President and Chief Executive Officer of TERTIAIRE RESOURCES COMPANY , a Texas corporation, and thatthe foregoing instrument was signed and delivered on behalf of the corporation by authority of its Board of Directors and that he acknowledgedthe instrument to be the free act and deed of said corporation.IN WITNESS WHEREOF, I hereunto set my hand and official seal. Notary Public in and for the State of Texas5EXHIBIT B[to be attached]EXHIBIT BTO SETTLEMENT AGREEMENTAMENDMENT TO UNIT OPERATING AGREEMENTTHIS AMENDMENT TO UNIT OPERATING AGREEMENT (this “Amendment” ) is made and entered into effective as of June 24,2016, by and between Denbury Onshore, LLC ( “Denbury” ) and NGS Sub Corp. ( “NGS” ) and its assignee, Tertiaire Resources Company (“TRC” ), both wholly-owned subsidiaries of Evolution Petroleum Corporation ( “EPM,” and collectively with NGS and TRC, “Evolution” ).Denbury, NGS, TRC, EPM, and Evolution, either individually or together as the context requires, may each be referred to herein as a “Party”and together as the “Parties.”RECITALSA. Denbury and TRC, as assignee of NGS, are parties to that certain Unit Operating Agreement entered into as of June 1, 2006governing the rights and duties of the parties thereto concerning the operation of the Delhi Holt-Bryant Unit (the “2006 UOA” ).B. The Parties desire to amend the 2006 UOA as set forth herein.AGREEMENT:The Parties, in consideration of the premises and of the mutual representations, warranties, covenants and agreements set forth hereinand intending to be bound, agree that the 2006 UOA shall be amended as set forth below:1. Definitions.(i) “Delhi Unit” shall have the meaning given to that term in the agreement entitled “Unitization Agreement, UnitizedZone, Delhi - West Delhi Field, Richland, Franklin, and Madison Parishes, Louisiana,” dated as of July 1, 1952, which wasentered into by Sun Oil Company and C. H. Murphy, Jr., and which was recorded with the Clerks of Court, State of Louisiana, inthe Parish of Richland, in COB 152, File No. 151269, in the Parish of Franklin in Notarial Book 81, File No. 25742, and inMadison Parish in Oil and Gas Book C, File No. 7201, beginning at Page 543.(ii) All other capitalized terms used in this Amendment but not defined in this Amendment shall have the meaning givensuch terms in the 2006 UOA (if any).2. All Depths within the Delhi Unit. Notwithstanding anything to the contrary contained in the 2006 UOA, from and after the datehereof, the 2006 UOA and the terms thereof shall be amended such that the 2006 UOA shall apply to all depths within the Delhi Unit, includingthe Mengel interval of the Delhi Unit (the “Mengel Interval” ). All references in the 2006 UOA to the1“Delhi Holt-Bryant Unit” shall be applicable to all depths within the Delhi Unit, including the Mengel Interval.3. Acquisition of Certain Mengel Interval Interests. Notwithstanding anything to the contrary contained in the 2006 UOA, from andafter the date hereof, either Denbury or TRC may acquire additional working interests in the Mengel Interval (such interests, the “AdditionalMengel Interval Interests” ) from one or more third parties with the goal of having uniform working interest ownership in the Delhi Holt-Bryant Unit and the Mengel Interval. In the event either Party identifies and initiates efforts to acquire any Additional Mengel Interval Interestsafter the date hereof, it shall notify the other Party in writing. In the event that such Party acquires any Additional Mengel Interval Interests soidentified, it will provide the other Party with written notice of such acquisition (a “Mengel Interval Acquisition Notice” ), which notice willdescribe the Additional Mengel Interval Interests acquired and will contain a description of all Acquisition Costs (as defined below) incurred inconnection with the acquisition of such Additional Mengel Interval Interests. Within thirty (30) days following the receipt of any MengelInterval Acquisition Notice, such Party shall deliver to the acquiring Party an amount in cash equal to its proportionate working interest share ofall Acquisition Costs incurred with respect to the acquisition of such Additional Mengel Interval Interests. Immediately thereafter, (X) theacquiring Party shall assign, transfer and convey to the other Party its proportionate working interest of all of such Party’s right, title and interestin and to the Additional Mengel Interval Interests (such undivided right, title and interest, the “Acquired Interests” ) to the other Party withoutany representation or warranty, but with an assignment of any representations and warranties received by the acquiring Party with respectthereto, and free and clear of all liens, security interests and other similar encumbrances created by, through and under the acquiring Party, otherthan those existing prior to such acquisition or which are created in favor of a person (other than the acquiring Party) as a condition to suchacquisition, and (Y) the recipient of such interest shall assume all obligations disclosed by the acquiring Party with respect to the AcquiredInterests required to be undertaken by the acquiring Party in connection with the underlying acquisition of the Additional Mengel IntervalInterests. For purposes of this Section 3, “Acquisition Costs” shall mean, with respect to the acquisition of any Additional Mengel IntervalInterests, all (A) consideration paid to or for the benefit of the third party in connection with the acquisition of such Additional Mengel IntervalInterests, (B) reasonable transaction expenses incurred in connection with the acquisition of such Additional Mengel Interval Interests, includingrecording fees, taxes, attorney’s fees, brokers fees, title examination fees and other due diligence costs, and (C) if such Additional MengelInterval Interests include a portion of an oil and gas lease acquired in a federal or state lease sale, the share of any bonus paid for such leasebased on that portion of the surface acreage of such lease shall be included in the Additional Mengel Interval Interests.4. Transportation Fee for CO2 Deliveries. Notwithstanding anything to the contrary contained in Section 12.1 of the 2006 UOA, theParties agree that Evolution will pay Denbury a2transportation fee for CO2 transported to the Delhi Holt-Bryant Unit through all of the CO2 pipelines upstream of the Delhi Holt-Bryant UnitCO2 purchase meter, including the trunk pipeline and the lateral pipeline to the meter which is located upstream of the CO2 recycle plant, inamounts calculated and as set forth on Exhibit A attached hereto.5. Certain Costs. Notwithstanding anything to the contrary contained in the 2006 UOA, the Parties agree that, as of the date hereof, theworking interest owners in the Delhi Unit own all CO2 piping downstream of the Delhi Holt-Bryant Unit CO2 purchase meter to the CO2recycling plant and all Delhi Holt-Bryant Unit CO2 infrastructure piping, including piping to the Unit test sites, and to and from the Unit’s CO2recycle plant (collectively, the “Downstream Pipelines” ). The Parties agree that, as of the date hereof, the cost of operating and maintainingthe Downstream Pipelines shall be proportionately borne by the working interest owners in accordance with their working interest ownership inthe Delhi Holt-Bryant Unit.6. CO2 Recycling Facility. The Parties agree that following Reversion TRC owns an interest in the CO2 Recycling Facility, includingall related real property (the “Facility” ) equal to its working interest percentage in the Delhi Holt-Bryant Unit. Except for costs incurred priorto Reversion, TRC will pay its proportionate working interest share of all operating and capital costs attributable to the Facility in proportion toits working interest percentage in the Delhi Unit. TRC specifically disclaims its rights to any beneficial interest in the Facility Usage Feeattributable to other working interest owners in the Delhi Unit.7. Ratification. Except as amended by this Amendment, all the terms and provisions of the 2006 UOA are hereby ratified and affirmedin all respects.8. Counterparts. This Amendment may be executed in one or more counterparts, including faxed or electronic counterparts, all ofwhich will be considered one and the same agreement, and shall become effective when one or more counterparts hereof have been signed byeach of the Parties and delivered.9. Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of Texas withoutgiving effect to the principles thereof relating to conflicts of laws.[Signature page follows.]3IN WITNESS WHEREOF, this Amendment has been signed by and on behalf of each of the Parties on the date set forth above.DENBURY :DENBURY ONSHORE, LLCBy:/s/ James S. Matthews James S. MatthewsSenior Vice President and General CounselEVOLUTION PETROLEUM CORPORATIONBy:/s/ Randall D. Keys Randall D. KeysPresident and Chief Executive OfficerNGS SUB CORP.By:/s/ Randall D. Keys Randall D. KeysPresident and Chief Executive OfficerTERTIAIRE RESOURCES COMPANYBy:/s/ Randall D. Keys Randall D. KeysPresident and Chief Executive OfficerSignature page to Amendment to Unit Operating AgreementEXHIBIT C[to be attached]EXHIBIT C TO SETTLEMENT AGREEMENTCAUSE NO. 2013-74863NGS SUB CORP., EVOLUTION PETROLEUM CORPORATION,AND TERTIAIRE RESOURCES COMPANY,Plaintiffs,IN THE DISTRICT COURT OFHARRIS COUNTY, TEXASv.DENBURY ONSHORE, LLC, AND DENBURY RESOURCES INC.,Defendants.133RD JUDICIAL DISTRICTJOINT AGREED MOTION TO DISMISS ALL CLAIMS WITH PREJUDICEDefendants Denbury Onshore, LLC and Denbury Resources Inc. and Plaintiffs NGS Sub Corp., Evolution Petroleum Corporation, andTertiaire Resources Company (collectively, the “Parties”) request dismissal of this lawsuit with prejudice pursuant to the Joint Agreed Order ofDismissal approved by the parties’ respective counsel of record, and would respectfully show the Court as follows:I.The Parties have amicably resolved the dispute between them and request that this Court dismiss all claims which were asserted or whichcould have been asserted in the above-captioned lawsuit with prejudice. All costs will be borne by the party incurring same. A proposed Order isattached for the convenience of the Court.JOINT AGREED MOTION TO DISMISS ALL CLAIMS WITH PREJUDICE - PAGE 1Respectfully submitted, James R. LeahyState Bar No. 12089500GREENBERG TRAURIG, LLP1000 Louisiana, Suite 1700Houston, TX 77002Telephone: (713) 374-3500Facsimile: (713) 374-3505E-Mail: leahy.j@gtlaw.comMatthew R. StammelState Bar No. 24010419Robert P. RitchieState Bar No. 24079213 VINSON & ELKINS L.L.P. 2001 RossAvenue, Suite 3700Dallas, TX 75201-2975Telephone: (214) 220-7700Facsimile: (214) 220-7716E-Mail: mstammel@velaw.comE-Mail: rritchie@velaw.comChris VerducciState Bar No. 24051470LOCKE LORD LLP2800 JP Morgan Chase Tower600 Travis StreetHouston, TX 77002Telephone: (713) 226-1200Facsimile: (713) 223-3717E-Mail: cverducci@lockelord.comE-Mail: acastro@lockelord.comAttorneys for DefendantsAttorneys for Plaintiffs CERTIFICATE OF SERVICEI hereby certify that on the ___th day of June, 2016, a true and correct copy of the foregoing document was served on all counsel ofrecord using the Court’s Electronic Case File system in accordance with Rule 21a, TEX. R. CIV. P. Matthew R. StammelJOINT AGREED MOTION TO DISMISS ALL CLAIMS WITH PREJUDICE - PAGE 2EXHIBIT D[to be attached]EXHIBIT D TO SETTLEMENT AGREEMENTCAUSE NO. 2013-74863NGS SUB CORP., EVOLUTION PETROLEUM CORPORATION,AND TERTIAIRE RESOURCES COMPANY,Plaintiffs,IN THE DISTRICT COURT OFHARRIS COUNTY, TEXASv.DENBURY ONSHORE, LLC, AND DENBURY RESOURCES INC.,Defendants.133RD JUDICIAL DISTRICTJOINT AGREED ORDER OF DISMISSALCame for consideration the Joint Agreed Motion for Dismissal with Prejudice requesting that all claims in this case be dismissed withprejudice. The Court, having reviewed the pleadings on file and considered the Motion, is of the opinion that the Motion should be granted in allrespects.It is therefore ORDERED that the Motion is GRANTED and that all claims which were asserted or which could have been asserted inthe above-captioned case are DISMISSED with prejudice. Each party shall bear its own costs.DATED ____ day of ____________ 2016. PRESIDING JUDGEExhibit 21.1List of Subsidiaries of Evolution Petroleum CorporationName of Subsidiary Jurisdiction ofIncorporation orOrganizationNGS Sub Corp. DelawareNGS Technologies, Inc. DelawareEvolution Operating Co., Inc. TexasTertiaire Resources Company TexasEvolution Petroleum OK, Inc. TexasNGS Resources, LLC (Subsidiary of NGS Technologies, Inc.) TexasExhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe consent to the incorporation by reference in Registration Statement No. 333-193899 on Form S-3, Registration Statement No. 333‑211338 onForm S‑3, Registration Statement No. 333‑152136 on Form S‑8, Registration Statement No. 333‑140182 on Form S‑8, and Registration Statement No.333‑183746 on Form S‑8 of Evolution Petroleum Corporation of our report dated September 9, 2016 , relating to the consolidated financial statements ofEvolution Petroleum Corporation (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the effectiveness ofinternal control over financial reporting) of Evolution Petroleum Corporation, appearing in this Annual Report on Form 10-K of Evolution PetroleumCorporation for the year ended June 30, 2016./s/ Hein & Associates LLPHein & Associates LLPHouston, TexasSeptember 9, 2016EXHIBIT 23.2DEGOLYER AND MACNAUGHTON500 I SPRING ALLEY ROAD SUITE 800 EASTDALLAS, TEXAS 75244September 8, 2016Evolution Petroleum Corporation 1155 Dairy AshfordSuite 425Houston, Texas 77079Ladies and Gentlemen:We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton, to the inclusion of ourletter report dated August 25 2016, and to the inclusion of information taken from our " Report as of June 30, 2016 on Reserves and Revenue of CertainProperties owned by Evolution Petroleum Corporation" in the sections Business Strategy-Delhi Field CO 2 EOR (Enhanced Oil Recovery) Project,Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues, Item 7. Management's Discussion and Analysis of Financial Condition andResults of Operations in the Form 10-K of Evolution Petroleum Corporation for the year ended June 30, 2016. We further consent to the incorporationby reference of information in the Form 10-K in the Evolution Petroleum Corporation Registration Statement No. 333-152136 on Form S-8, RegistrationStatement No. 333-140182 on Form S-8, Registration Statement No. 333-183746 on Form S-8, Registration Statement No. 333-211338 on Form S-3,and Registration Statement No. 333-193899 on Form S-3.Very truly yours,/s/ DeGolyer and MacNaughtonDeGOLYER and MacNAUGHTONTexas Registered Engineering Firm F-716Exhibit 23.3W. D. Von Gonten & Co.Petroleum Engineering10496 Old Kay Road, Suite 200Houston, Texas 77043CONSENT OF INDEPENDENT PETROLEUM ENGINEERSWe, the firm of W. D. Von Gonten & Co., consent to the use of our name and the use of our reports regarding Evolution Petroleum Corporation Estimated Proved Reserves andFuture Net Revenues "as of July 1, 2006 through July 1, 2013" in the relevant pages of the Form 10-K of Evolution Petroleum Corporation for the fiscal year ended June 30,2016. We further consent to the incorporation by reference of information contained in our report as of July 2, 2013, in the Evolution Petroleum Corporation RegistrationStatement No. 333-152136 on Form S-8, Registration Statement No. 333-140182 on Form S-8, Registration Statement No. 333- 183746 on Form S-8, Registration Statement No.333-211338 on Form S-3 and Registration Statement No. 333-193899 on Form S-3.Yours truly ,/s/William D . Von Gonten , Jr.William D . Von Gonten , Jr.PresidentTX#73244September 7 , 2016EXHIBIT 31.1CERTIFICATIONI, Randall D. Keys, President and Chief Executive Officer of Evolution Petroleum Corporation, certify that:1.I have reviewed this annual report on Form 10-K of Evolution Petroleum Corporation;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, inlight of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition,results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure thatmaterial information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly duringthe period in which this report is being prepared;b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, toprovide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles;c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of thedisclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (theregistrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internalcontrol over financial reporting; and5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditorsand the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely toadversely affect the registrant's ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financialreporting. Date: September 9, 2016 /s/ RANDALL D. KEYSRandall D. KeysPresident and Chief Executive OfficerEXHIBIT 31.2CERTIFICATIONI, David Joe, Chief Financial Officer of Evolution Petroleum Corporation, certify that:1.I have reviewed this annual report on Form 10-K of Evolution Petroleum Corporation;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, inlight of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition,results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure thatmaterial information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly duringthe period in which this report is being prepared;b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, toprovide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles;c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of thedisclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (theregistrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internalcontrol over financial reporting; and5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditorsand the audit committee of the registrant's Board of Directors (or persons performing the equivalent functions):a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely toadversely affect the registrant's ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financialreporting. Date: September 9, 2016 /s/ DAVID JOEDavid JoeChief Financial OfficerEXHIBIT 32.1 CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002The undersigned, Randall D. Keys, President and Chief Executive Officer of Evolution Petroleum Corporation (the "Company"), certifies in connection with the filingwith the Securities and Exchange Commission of the Company's Annual Report on Form 10-K for the year ended June 30, 2016 (the "Report") pursuant to 18 U.S.C.Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to his knowledge, that:1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.IN WITNESS WHEREOF, the undersigned has executed this certification as of the 9th day of September, 2016 . /s/ RANDALL D. KEYSRandall D. Keys President and Chief Executive OfficerA signed original of this written statement require d by Section 906 has been provided to Evolution Petroleum Corporation and will be retained by Evolution PetroleumCorporation and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certificate is being furnished to the Securities and ExchangeCommission as an exhibit to this Form 10-K and shall not be considered filed as part of the Form 10-K.EXHIBIT 32.2 CERTIFICATION PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002The undersigned, David Joe, Chief Financial Officer of Evolution Petroleum Corporation (the "Company"), certifies in connection with the filing with the Securities andExchange Commission of the Company's Annual Report on Form 10-K for the year ended June 30, 2016 (the "Report") pursuant to 18 U.S.C. Section 1350, as adopted pursuantto Section 906 of the Sarbanes-Oxley Act of 2002, to his knowledge, that:1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.IN WITNESS WHEREOF, the undersigned has executed this certification as of the 9th day of September, 2016 . /s/ DAVID JOE David Joe Chief Financial OfficerA signed original of this written statement required by Section 906 has been provided to Evolution Petroleum Corporation and will be retained by Evolution PetroleumCorporation and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certificate is being furnished to the Securities and ExchangeCommission as an exhibit to this Form 10-K and shall not be considered filed as part of the Form 10-K.Exhibit 99.4DeGolyer and MacNaughton5001 Spring Valley RoadSuite 800 EastDallas, Texas 75244August 25, 2016Evolution Petroleum Corporation1155 Dairy Ashford, #425Houston, Texas 77079Ladies and Gentlemen:Pursuant to your request, we have prepared estimates of the extent and value of the net proved, probable, and possible oil, condensate, naturalgas liquids (NGL), and gas reserves, as of June 30, 2016, of certain properties in which Evolution Petroleum Corporation (Evolution) has representedthat it owns an interest. This evaluation was completed on August 25, 2016. The properties evaluated consist of working and royalty interests locatedin the Delhi field in Richland Parish, Louisiana. Evolution has represented that these properties account for 100 percent of its proved reserves as ofJune 30, 2016. The net proved reserves estimates prepared by us have been prepared in accordance with the reserves definitions of Rules 4-10 (a) (1)-(32) of Regulation S-X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with the guidelinesspecified in Item 1202 (a) (8) of Regulation S-K, and is to be used for inclusion in certain SEC filings by Evolution.Estimates of reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be producedfrom these properties after June 30, 2016. Net reserves are defined as that portion of the gross reserves attributable to the interests owned byEvolution after deducting all royalties and interests owned by others.Values of proved, probable, and possible reserves in this report are expressed in terms of estimated future gross revenue, future net revenue,and present worth. Future gross revenue is that revenue which will accrue to the evaluated interests from the production and sale of the estimated netreserves. Future net revenue is calculated by deducting production and ad valorem taxes, operating expenses, andDeGolyer and MacNaughton # 2capital and abandonment costs from the future gross revenue. Operating expenses include field operating expenses, carbon dioxide purchaseexpenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income taxexpenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at 10 percentcompounded annually over the expected period of realization. Present worth should not be construed as fair market value because no considerationwas given to additional factors that influence the prices at which properties are bought and sold.Estimates of oil, condensate, NGL and gas reserves and future net revenue should be regarded only as estimates that may change as furtherproduction history and additional information become available. Not only are such reserves and revenue estimates based on that information which iscurrently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting suchinformation.Data used in this report were obtained from Evolution, from records on file with the appropriate regulatory agencies, and from public sources.In the preparation of this report we have relied, without independent verification, upon such information furnished by Evolution with respect toproperty interests evaluated, production from such properties, current costs of operation and development, current prices for production, agreementsrelating to current and future operations and sale of production, and various other information and data that were accepted as represented. It was notconsidered necessary to make a field examination of the physical condition and operation of the properties.Methodology and ProceduresEstimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques thatare in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineersentitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)." The methodor combination of methods used in the analysis was tempered by experience with similar reservoirs, stage of development, quality and completenessof basic data, and production history.Based on the current stage of field development, production performance, theDeGolyer and MacNaughton # 3development plans provided by Evolution, and the analyses of areas offsetting existing wells with test or production data, reserves were classified asproved, probable, or possible.Most of the proved, probable, and possible reserves estimated for the evaluated interests are located in the Holt-Bryant reservoir in the Delhifield. This reservoir was originally discovered in 1944, produced under primary means until unitized for water injection in 1953, and was purchasedby Denbury Resources (Denbury) in 2006 in order to initiate a carbon dioxide injection program. Average depth is 3,235 feet subsea The Delhi unit is13,636 acres, and the unit area is approximately 6,189 acres. Denbury began carbon dioxide injection in 3 patterns in November 2009 and has sinceexpanded to 15 patterns, which have all seen production response to injection. Evolution owns working and overriding royalty interests in the unit.The volumetric method was used to estimate the original oil in place (OOIP). Structure maps were utilized to delineate each reservoir, andisopach maps were utilized to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used toprepare these maps as well as to estimate. Representative values for porosity and water saturation. Cumulative recovery from the Delhi unit prior tocarbon dioxide injection was about 195 million barrels. Estimates of ultimate recovery resulting from carbon dioxide injection in the Holt-Bryantreservoir were obtained after applying recovery factors to the current carbon dioxide flood area OOIP of 323 million barrels. This recovery factor isbased on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and theproduction histories. Oil production response to the carbon dioxide was observed in March 2010. Based on the production response from a number ofproducers, and noting the amount of carbon dioxide injection to date, a total recovery factor for proved reserves was estimated to be about 13.8percent of pattern-area OOIP, incremental probable reserves about 4.2 percent of OOIP, and incremental possible reserves about 2.5 percent of OOIP.Evolution has represented that processing of produced gas for NGL will begin in January 2017. Estimates of NGL reserves were based oninstallation of a plant to recover NGL and methane. The methane is planned to be used as fuel for plant and field operations. The plant NGL yield wasprovided by Evolution.Gas quantities estimated herein are expressed as separator gas and sales gas. Separator gas is the gas remaining after field separation but priorto gas processing and shrinkage for fuel use or flare. Sales gas is defined as that portion of the separator gas toDeGolyer and MacNaughton # 4be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. All of the produced gas is consumed as fuel or lost inprocessing so the net sales gas reserves are zero. Gross gas reserves are reported as separator gas. All gas quantities are expressed at a temperaturebase of 60 degrees Fahrenheit and at a pressure base of 15.025 pounds per square inch absolute. Gas quantities included in this report are expressedin thousands of cubic feet (Mcf).Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation and are expressed in terms of barrels(bbl) representing 42 United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and arepresented herein as a summed quantity. NGL reserves are those attributed to the leasehold interests according to processing agreements.Definition of ReservesPetroleum reserves included in this report are classified by degree of proof as proved, probable, or possible. Reserves classifications used inthis report are in accordance with the reserves definitions of Rules 4-10 (a) (1)-(32) of Regulation S-X of the SEC. Reserves are judged to beeconomically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation ofcurrent regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves wereestimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent withthe effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not includingescalations based upon future conditions. The petroleum reserves are classified as follows:Proved oil and gas reserves - Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineeringdata, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and underexisting economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right tooperate expire, unless evidence Indicates that renewal is reasonablyDeGolyer and MacNaughton # 5certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons musthave commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.(i) The area of the reservoir considered as proved includes:(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, withreasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of availablegeoscience and engineering data.(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH)as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact withreasonable certainty.(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists foran associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but notlimited to, fluid injection) are included in the proved classification when:(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as awhole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technologyestablishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has beenapproved for development by all necessary parties and entities, including governmental entities.DeGolyer and MacNaughton # 6(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determinedas an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined bycontractual arrangements, excluding escalations based upon future conditions.Probable reserves - 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.(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum ofestimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actualquantities recovered will equal or exceed the proved plus probable reserves estimates.(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations ofavailable data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonablecertainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are incommunication with the proved reservoir.(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of thehydrocarbons in place than assumed for proved reserves.(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.DeGolyer and MacNaughton # 7Possible reserves - Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability ofexceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probabilitythat the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations ofavailable data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to defineclearly the area and vertical limits of commercial production from the reservoir by a defined project.(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons inplace than the recovery quantities assumed for probable reserves.(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternativetechnical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons toresults in successful similar projects.(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoirwithin the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or othergeological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are incommunication with the known (proved)DeGolyer and MacNaughton # 8reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are incommunication with the proved reservoir.(vi) Pursuant to paragraph (iii) of the proved oil and gas reserves definition, where direct observation has defined a highest knownoil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higherportions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliabletechnology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil orgas based on reservoir fluid properties and pressure gradient interpretations.Developed oil and gas reserves - Developed oil and gas reserves are reserves of any category that can be expected to be recovered:(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment isrelatively minor compared to the cost of a new well; and(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is bymeans not involving a well.Undeveloped oil and gas reserves - Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from newwells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certainof production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economicproducibility at greater distances.DeGolyer and MacNaughton # 9(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicatingthat they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application offluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actualprojects in the same reservoir or an analogous reservoir, as defined in [section 210.4-10 (a) Definitions], or by other evidence usingreliable technology establishing reasonable certainty.The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future drilling,testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic andtechnological factors as well as the time element. Probable and possible reserves in this report have not been adjusted in consideration of theseadditional risks and therefore are not comparable with proved reserves.Primary Economic AssumptionsRevenue values in this report were estimated using the initial prices and costs specified by Evolution. Future prices were estimated usingguidelines established by the SEC and the Financial Accounting Standards Board (FASB). The prices used in this report were based on SECguidelines. The assumptions used for estimating future prices and expenses are as follows:Oil and Condensate PricesAn oil and condensate price differential for each property was calculated from data provided by Evolution. The price for each propertywas calculated by applying this differential to a WTI crude oil price of $42.91 per barrel and was held constant over the life of eachproperty. The WTI price of $42.91 is the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12DeGolyer and MacNaughton # 10month period prior to June 30, 2016. The volume-weighted average price attributable to the proved reserves over the lives of theproperties was $40.91 per barrel.NGL PricesEvolution has represented that the NGL prices were based on a 12-month average price, calculated as the unweighted arithmetic averageof the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices aredefined by contractual arrangements. The volume-weighted average price attributable to the proved reserves over the lives of theproperties was$14.38 per barrel.Operating Expenses, Capital Costs, and Abandonment CostsEstimates of operating expenses, capital costs, and abandonment costs, based on information provided by Evolution for current costs,were used for the lives of the properties with no increases in the future based on inflation. Future expenditures are estimated to be higherthan current levels due to the installation of a carbon dioxide injection program, which began in November 2009 and is to be expandedthrough 2022. Evolution is expected to pay $0.64 per Mcf of carbon dioxide until December 2019, and then $0.54 per Mcf of carbondioxide thereafter. Recycled carbon dioxide is expected to cost 16 cents per Mcf. Future capital costs as provided by Evolution wereestimated using 2016 values and were not adjusted for inflation. No significant capital costs other than abandonment are expected after2028.Production and Ad Valorem TaxesProduction taxes were based on current state tax rates. The Delhi carbon dioxide flood has been qualified as a tertiary recovery project. Assuch, no oil and condensate production taxes will be charged until a payout is achieved of investment and certainDeGolyer and MacNaughton # 11interest expenses by all revenue from the project. Oil and condensate production taxes then revert to the normal 12.5-percent rate, whichare held constant until average oil production per well drops below 25 barrels per day, and then reduced to 6.25 percent. However, payoutis not expected toBe reached prior to depletion. As such, no oil and condensate production taxes are included. Production taxes for NGL are included at$0.98 per barrel. Evolution has stated that no ad valorem taxes are charged to the Louisiana royalty owners, so no such taxes wereincluded until conversion to a working interest.Summary and ConclusionsThe estimates of net proved, probable, and possible reserves attributable to Evolution from the properties evaluated, as of June 30, 2016, aresummarized as follows, and expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf): Net Reserves Oil (Mbbl) NGL (Mbbl) Sales Gas (MMcf)Proved Developed Producing 7,168 — — Developed Nonproducing — — — Undeveloped 1,421 2,235 —Total Proved 8,589 2,235 — Probable Developed Producing 3,092 — — Developed Nonproducing — — — Undeveloped 472 934 —Total Probable 3,564 934 — Possible Developed Producing 1,965 — — Developed Nonproducing — — — Undeveloped 186 563 —Total Possible 2,151 563 — Note: Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.DeGolyer and MacNaughton # 12The estimated future revenue to be derived from the production and sale of the estimated net proved, probable, and possible reserves, as ofJune 30, 2016, of the properties evaluated is summarized as follows, expressed in thousands of dollars (M$): Proved Developed Developed TotalProducing Non-Producing Undeveloped Proved(M$) (M$) (M$) (M$)Future Gross Revenue293,250 — 90,241 383,491Production Taxes— — 2,186 2,186Ad Valorem Taxes1,202 — 361 1,563Operating Expenses143,835 — 31,598 175,433Capital Costs526 — 14,803 15,329Abandonment Costs1,194 — 72 1,266Future Net Revenue146,493 — 41,221 187,714Present Worth at 10 Percent88,901 — 11,968 100,869 Probable Developed Developed Total Producing Non-Producing Undeveloped Probable (M$) (M$) (M$) (M$)Future Gross Revenue126,503 — 32,709 159,212Production Taxes— — 913 913Ad Valorem Taxes519 — 130 649Operating Expenses27,240 — 6,319 33,559Capital Costs— — — —Abandonment Costs— — — —Future Net Revenue98,744 — 25,347 124,091Present Worth at 10 Percent40,079 — 6,879 46,958 Possible Developed Developed Total Producing Non-Producing Undeveloped Possible (M$) (M$) (M$) (M$)Future Gross Revenue80,360 — 15,721 96,081Production Taxes— — 551 551Ad Valorem Taxes329 — 63 392Operating Expenses12,577 — 3,123 15,700Capital Costs— — — —Abandonment Costs— — — —Future Net Revenue67,454 — 11,984 79,438Present Worth at 10 Percent19,665 — 2,284 21,949Notes:1.Future income tax expenses were not taken into account in the preparation of these estimates.2.Values for probable and possible reserves have not been risk adjusted to make them comparable to values for proved reserves.While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant's ability torecover its oil, condensate, NGL, and gas reserves, we are not aware of any such governmental actions which would restrictDeGolyer and MacNaughton # 13the recovery of the June 30, 2016, estimated reserves.In our opinion, the information relating to estimated proved, probable, and possible reserves, estimated future net revenue from provedreserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, NGL and gas contained in this report has beenprepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries - Oil and Gas (Topic 932): Oil and GasReserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4-10 (a) (1)-(32) of Regulation S-X andRules 302(b), 1201, 1202(a) (1), (2), (3), (4), (5), (8), and 1203(a) of Regulation S-K of the Securities and Exchange Commission; provided,however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forthherein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, asengineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficienttherefor.DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughoutthe world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Evolution. Our fees were notcontingent on the results of our evaluation. This letter report has been prepared at the request of Evolution. DeGolyer and MacNaughton has used allassumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this reportSubmitted, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 /s/ Dennis W. Thompson, PE Dennis W. Thompson, PE Senior Vice President DeGolyer and MacNaughtonDeGolyer and MacNaughtonCERTIFICATE of QUALIFICATIONI, Dennis W. Thompson, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244U.S.A., hereby certify:1.That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the report entitled “Report as of June 30, 2016on Reserves and Revenue of Certain Properties owned by Evolution Petroleum Corporation,” and that I, as Senior Vice President, was responsiblefor the preparation of this report.2.That I attended Eastern New Mexico University, and that I graduated with a Bachelor of Science degree in Geology in the year 1973; that I earneda Master of Science degree in Petroleum Engineering from the University of Texas at Austin in 1975; that I am a Registered ProfessionalEngineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 36 years of experience inoil and gas reservoir studies and reserves evaluations. /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 /s/ Dennis W. Thompson, PE Dennis W. Thompson, PE Senior Vice President DeGolyer and MacNaughton

Continue reading text version or see original annual report in PDF format above