Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ý
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 2016
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                to              
Commission File Number 001-32942
EVOLUTION PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Nevada
(State or other jurisdiction of
incorporation or organization)
 
41-1781991
(IRS Employer
Identification No.)
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 par value
 
NYSE MKT
 
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes: o    No: ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes: o    No: ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: ý    No: o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes: ý    No: o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer ý
 
Non-accelerated filer o
 
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: o    No: ý
The aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 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 REFERENCE
Portions 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 into Part III of this report.

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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
2016 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
This Form 10-K and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words "plan," "expect," "project," "estimate," "assume," "believe," "anticipate," "intend," "budget," "forecast," "predict" and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in this Annual Report on Form 10-K as filed with the Securities and Exchange Commission ("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 and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.
We use the terms, "EPM," "Company," "we," "us" and "our" to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.
PART I
Item 1.    Business
Note: See Glossary of Selected Petroleum Industry Terms at the back of this document - refer to Table of Contents
General
We are an independent oil and gas company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas, onshore in the United States. We acquire known crude oil and natural gas resources and exploit them through the application of conventional and specialized technology, with the objective of increasing production, ultimate recoveries, or both. Additional information regarding our operating segment, major customers, revenues and assets can be found 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 formed in September 2003, merged into a wholly-owned subsidiary of Reality Interactive, Inc. (Nevada, "Reality"), an inactive public company, which was renamed Natural Gas Systems, Inc. ("NGS"). The former officers and directors of Reality resigned and the officers, directors and business operations of Old NGS became the Company. Concurrently with the listing of NGS shares on the NYSE MKT in July 2006, NGS was renamed Evolution Petroleum Corporation. Our principal executive offices are located at 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, and our telephone number is (713) 935-0122. We maintain a website at www.evolutionpetroleum.com, but information contained on our website does not constitute part of this document.
Our 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 currently represented 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 Strategy
Our business strategy is to acquire known, underdeveloped oil and natural gas resources and exploit them through the application of capital, sound engineering and modern technology to increase production, ultimate recoveries, or both.
Our principal assets include interests in a CO2 enhanced oil recovery project in Louisiana’s Delhi field. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders.
Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our 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. The Unit 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 secondary recovery 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 million bbls of oil. The Unit is currently producing as an EOR project utilizing CO2 flood technology following the sale of a majority of our working interest to a subsidiary of Denbury Resources, Inc., the current operator, in 2006. At the time of our purchase of the field in 2003, the Unit had minimal production.

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We 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. Effective July 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 - Delhi Litigation 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 of this 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 oil reserves 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 Net Revenues" 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 prices received 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 and natural gas that is recoverable from a particular reservoir, Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves but which, together with Proved reserves, are as likely as not to be recovered, 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 being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of Probable and Possible reserves are by their nature much more speculative than estimates of Proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. These three reserve categories and net present worth discounted at 10% relating to each category have not been adjusted to different levels of recovery 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 CO2 flood in the Delhi field. Four of these phases have been completed as of June 30, 2016 and two remain 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 it was not deemed economic under current year pricing guidelines for SEC purposes.
Phase I began CO2 injection in November 2009. First oil production response occurred in March 2010, about three to four months earlier than expected, and production in the field increased to approximately 2,000 gross BOPD.
Implementation of Phase II, which was more than double the size of Phase I, commenced with incremental CO2 injection at the end of December 2010. First oil production response from Phase II occurred during March 2011, three or more months ahead of expectations, and field gross production increased to more than 4,000 BO per day.
Phase III was installed during calendar 2011, and was expanded twice during calendar 2011. Production subsequently increased to more than 6,000 BO per day.
Phase IV was substantially installed during the first six months of calendar 2012. During early calendar 2013, the operator intensified development in the previously redeveloped western side of the field based on production results and new geological mapping that included the results of seismic data acquired over the last few years. Gross field 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 CO2, water, natural gas and a small amount of oil from a previously plugged well in the southwest part of the field, the operator temporarily suspended CO2 injection in most of the southwestern tip of the field. The operator has fully remediated the affected area, but has isolated that

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part 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 our payout 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, filed suit 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 described in 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 until reversion 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's will 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 the methane. In addition to the value of these hydrocarbon products, the increased purity of the CO2 stream re-injected into the field should result in significant operational benefits to the CO2 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 already expended 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 CO2 flood in the undeveloped eastern part of the field. This project is sometimes 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 oil prices. 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 prices and the partners' allocation of capital for such projects. Since we believe that the NGL plant and further expansion of the CO2 flood have favorable economics, even in this lower price environment, we expect the expansion of the CO2 flood to resume within the next few years. The economics of expansion will also be improved subsequent to the completion 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 the southwestern portion of the field. Following the fluid release event in June 2013, CO2 injections in this area ceased in order to reduce reservoir pressure and protect the incident area. The project includes converting three shut-in wells to water injector wells in order to expand the water curtain barrier to reduce CO2 migration into this area together with the 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. These ESP 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 was still 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 the northeast 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 probable reserves 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 reserves calculation. 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 received in 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 equivalent possible 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 is intended to increase production and extend the life of horizontal and vertical wells with gas, oil or associated water production with the expectation of recovering additional reserves 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 the technology 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 which allows 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 in demonstrating that the process works; however, these candidates were unable to prove commercial viability due to their low primary recoveries as producers.

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Subsequent to receiving our patent, we entered into demonstration joint venture projects with two different industry operators during fiscal 2012 to prove commercial application. We further expanded our commercial tests during fiscal 2013 with two additional installations and a third in fiscal 2014. All five of these installations were successful in re-establishing commercial production. During fiscal 2014, we entered into a commercial agreement to install our technology on at least five wells in the Giddings Field. Three installations were completed as of the end of fiscal 2014, two of which were successful. During fiscal 2015, we completed installation of our artificial lift technology in 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 since March 2014. The results from these projects were mixed, with many of the wells successfully establishing or restoring commercial rates of production. However, with the declining 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 slower than 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 new entity 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 preferred stock 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 our preferred stock investment into a larger, non-controlling equity stake in the new entity. Consequently, we have retained substantial upside for our shareholders from the potential future 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 the technology in our current wells and any future wells we develop or acquire.
Other Projects
Lopez Field—South Texas
We acquired leases covering approximately 782 net acres in the Lopez Field in South Texas as a first effort to test the concept of redeveloping old oil fields utilizing high flow rate production. While our development activity in the Lopez Field confirmed our concept and the potential for developing material oil reserves, the time and effort required to develop material reserves lowered the attractiveness of this project. Consequently, we elected to sell this asset during fiscal 2013 and completed such monetization in fiscal 2014.
Mississippi Lime—Kay County, Oklahoma
In 2012, we acquired a 45% interest in a joint venture with Orion Exploration, a private company based in Tulsa, Oklahoma. The joint venture was operated by Orion and engaged in the horizontal development of the Mississippi Lime reservoir in Kay County, Oklahoma. Our leasehold position, totaling approximately 6,600 acres, was located in the 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 Lime formation. While both wells produced at the fluid rates expected, the quantities of oil and gas were far less than expected. We subsequently reworked both wells to test the role of structure in production, and determined that this play is a structural play requiring substantial geophysical and geological work and expertise in order to be successful, as opposed to a resource play in which engineering is the primary requirement. 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 associated assets in the Mississippi Lime reservoir to the operator.
Markets and Customers
We market our production to third parties in a manner consistent with industry practices. In the U.S. market where we operate, crude oil and natural gas liquids are readily transportable and marketable. We do not currently market our share of crude oil production from Delhi. Although we have the right to take our 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 currently transported 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 Cushing was 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 expect that a positive LLS price differential will continue, at least in the near future.

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The following table sets forth purchasers of our oil and natural gas production for the years indicated:
 
Year Ended June 30,
Customer
2016
 
2015
 
2014
Plains Marketing L.P. (includes Delhi production)
99
%
 
99
%
 
96
%
Enterprise Crude Oil LLC
%
 
%
 
2
%
Flint Hills
%
 
%
 
1
%
ETC Texas Pipeline, LTD. 
%
 
%
 
1
%
All others
1
%
 
1
%
 
%
Total
100
%
 
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 Conditions
Marketing 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 is difficult to predict. These factors include changes in supply and demand, market prices, government regulation and actions of major foreign producers.
Over the past 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. Most recently, 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 prices for crude oil. Local factors also influence prices for crude oil and include increasing or decreasing production trends, quality differences, regulation and transportation issues unique to certain producing regions and reservoirs.
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 in supply and demand, derivatives trading, pipeline availability, BTU content of the natural gas and weather patterns, among others, cause natural gas prices to be subject to significant fluctuations. Due to the practical difficulties in transporting natural gas, local and regional factors tend to influence product prices more for natural gas than for crude oil.
Competition
The oil and natural gas industry is highly competitive for prospects, acreage and capital. Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. Competitors are national, regional or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are expertise in given geographical and geological areas and the abilities to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves and obtain affordable capital.
Government Regulation
Numerous federal and state laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for noncompliance. To the best of our knowledge, we are in compliance with all laws and regulations applicable to our operations and we believe that continued compliance with existing requirements will not have a material adverse impact on us. The future annual capital cost of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable. However, we do not currently anticipate that future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.
See "Government regulation and liability for environmental matters that may adversely affect our business and results of operations" under Item 1A. Risk Factors of this Form 10-K, for additional information regarding government regulation.

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Insurance
We maintain insurance on our operated and non-operated properties and operations for risks and in amounts customary in the industry. Such insurance includes general liability, excess liability, control of well, operators extra expense, casualty, fraud and directors & officer's liability coverage. Not all losses are insured, and we retain certain risks of loss through deductibles, limits and self-retentions. We do not carry lost profits coverage and we do not have coverage for consequential damages.
Additional Information
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.evolutionpetroleum.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford 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 a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
Item 1A.    Risk Factors
Our 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 we currently consider immaterial also may adversely affect us.
Risks related to the oil and gas industry and our Company
A 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 expenditure obligations 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 subject to 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 to a 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 likely continue 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 factors include 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 will reduce 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 on satisfactory 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 oil and 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% of our 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 not

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hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas prices may adversely affect our financial position.
Our revenues are concentrated in one asset and declines in production or other events beyond our control could have a material adverse effect on our results of operations and 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 in this 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 our results 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 in order to sustain our business operations.
In general, the volumes of production from crude oil and natural gas properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we acquire additional properties containing proved reserves or conduct successful development activities, or both, our proved reserves will decline. Our production is heavily dependent on our interests in EOR production that began during March 2010 in the Delhi field. Although EOR production from proved reserves 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 and natural 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 have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Operators of these properties may act in ways that are not in our best interest. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production and materially and adversely affect our financial conditions and results of operations.
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 materially negative 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 of our 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 from these 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 the Delhi 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 of Denbury Resources Inc. (“DNR”). Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
Further, our CO2- Enhanced Oil Recovery (“CO2-EOR”) project in the Delhi field requires significant amounts of CO2 reserves and technical expertise, the sources of which 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 this asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial and logistical matters could cause ultimate enhanced recoveries from the planned CO2- 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 of operations and financial condition. 
Our economic success is thus materially dependent upon the Delhi field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome source, (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 CO2 flood in the undeveloped eastern part of the field. These operations were suspended by the end 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 current commodity prices, resumption of

7




this 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 financial covenants. They have stated, for example, that their level of indebtedness could have important consequences, including, among others, requiring dedication of a substantial portion 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 part upon 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 turn negatively affect the operator’s ability to operate the Delhi field as well as its financial commitment to the CO2-EOR project in the field, and thus our interests in the Delhi field could 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, or relatively shallow reservoirs. Shallower reservoirs usually have lower pressure, which translates into fewer natural gas volumes in place. Low permeability reservoirs require more wells and substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient undepleted fractures to establish commercial production. Depleted reservoirs require successful application of newer technology to unlock incremental reserves.
Our CO2-EOR project in the Delhi field, operated by a subsidiary of Denbury Resources Inc., requires significant amounts of CO2 reserves, development capital and technical expertise, the sources of which to date have been committed by the operator. Although initial CO2 injection began at Delhi in November 2009, initial oil production response began in March 2010 and a large part of the capital budget has already been expended, 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 and logistical risks may cause ultimate enhanced recoveries from the planned CO2-EOR project to fall short of our expectations in volume and/or timing. Such occurrences would have a material adverse effect on the Company, 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 wells are speculative activities and involve numerous risks and substantial uncertain costs.
Our growth will be materially dependent upon the success of our future development program. Drilling for crude oil and natural gas and re-working existing wells involve numerous risks, including the risk that no commercially productive crude oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:
unexpected drilling conditions;
pressure fluctuations or irregularities in formations;
equipment failures or accidents;
environmental events;
inability to obtain or maintain leases on economic terms, where applicable;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.
Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion techniques such as horizontal drilling or CO2 injection or other injectants do not guarantee that we will find and produce crude oil and/or natural gas in our wells in economic quantities. Our future drilling activities may not be successful and, if unsuccessful, such failure would have an adverse effect on our future results of operations and financial condition. We cannot assure you that our overall drilling success rate or our drilling success rate for activities within a particular geographic area will not decline.
We may also identify and develop prospects through a number of methods, some of which do not include horizontal drilling or tertiary injectants, and some of which may be unproven. The drilling and results for these prospects may be particularly uncertain. We cannot assure you that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive crude oil or natural gas.

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The loss of a large single purchaser of our oil and natural gas could reduce the competition of our production.
For the year ended June 30, 2016, one purchaser accounted for 99% of our oil and natural gas revenues. We do not currently market our share of crude oil production from the 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 Plains Marketing 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 we receive. 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 is transported by pipeline and if this pipeline transportation were disrupted and we were forced to use alternative transportation methods, our net realized pricing and potentially our near-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 be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors, such as historical production from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas product prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers but at different times, may vary substantially.
Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the crude oil and natural gas industry in general. 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 the SEC. Under the full cost method of accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this "ceiling" test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write down of the carrying value for accounting purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our crude oil and natural gas properties when crude oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will depend in part on the prices for crude oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period. If a write down is required, it would result in a current charge to our earnings but would not impact our current cash flow from operating activities.
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, enter into 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 derivative instruments 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 are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Derivative arrangements also expose 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 cash margin 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 CO2 from its reserves in the Jackson Dome, secure all of the development capital necessary to fund its and our cost interests and (ii) successfully manage technical, operating, environmental, strategic and logistical development and operating risks, among other things.
We cannot assure you that we will be able to successfully grow or manage any such growth.
Our operations require significant amounts of capital and additional financing may be necessary in order for us to continue our exploitation activities, including meeting potential future drilling obligations.
Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and gas acquisitions, exploitation and development activities. Certain of our undeveloped leasehold acreage may be subject to leases that will expire unless production is established. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available to us on favorable terms.
We may be subject to risks in connection with acquisitions because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties 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 be generally consistent with industry practices. Our review will not reveal all existing

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or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not 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 for environmental 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 will generally 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 such indemnification 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 to acquisitions, 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 in concert 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 operations while 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 required to 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 to effectively 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, production volume, 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 to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of crude oil and natural gas, by-products thereof and other substances and materials produced or used in connection with crude oil and natural gas operations. In addition, we may inherit liability for environmental damages, whether actual or not, caused by previous owners of property we purchase or lease or nearby properties. As a result, we may incur substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us, such as diminishing the demand for our products through legislative enactment of proposed new penalties, fines and/or taxes on carbon that could have the effect of raising prices to the end user.
Our insurance may not protect us against all of the operating risks to which our business is exposed.
The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, hurricanes, flooding, pollution, releases of toxic gas and other environmental hazards and risks, which can result in (i) damage to or destruction of wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or (v) damage to property, the environment or natural resources. While we carry general liability, control of well, and operator's extra expense coverage typical in our industry, we are not fully insured against all risks incident to our business. Environmental events similar to that experienced in the Delhi field in June 2013 could defer revenue, increase operating costs and maintenance capital expenditures.

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The loss of key personnel could adversely affect us.
We depend to a large extent on the services of certain key management personnel, including our executive officers, the loss of any of whom could have a material adverse effect on our operations. In particular, our future success is dependent upon Robert S. Herlin, our Executive Chairman, Randall D. Keys, our President and Chief Executive Officer, and David Joe, Senior Vice President, Chief Financial Officer and Treasurer, for sourcing, evaluating and closing deals, capital raising, and oversight of development and operations. Presently, the Company is not a beneficiary of any key man insurance.
Oil field service and materials' prices may increase, and the availability of such services and materials may be inadequate to meet our needs.
Our business plan to develop or redevelop crude oil and natural gas resources requires third party oilfield service vendors and various material providers, which we do not control. We also rely on third-party carriers for the transportation and distribution of our production. As our production increases, so does our need for such services and materials. Generally, we do not have long-term agreements with our service and materials providers. Accordingly, there is a risk that any of our service providers could discontinue servicing our crude oil and natural gas fields for any reason or we may not be able to source the materials we need. Any delay in locating, establishing relationships, and training our sources could result in production shortages and maintenance problems, with a resulting loss of revenue to us. In addition, if costs for such services and materials increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may have assumed when deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelop plans.
We cannot market the crude oil and natural gas that we produce without the assistance of third parties.
The marketability of the crude oil and natural gas that we produce depends upon the proximity of our reserves to, and the capacity of, facilities and third-party services, including crude oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities necessary to make the products marketable for end use. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in or delay or discontinuance could adversely affect our financial condition.
We face strong competition from larger oil and gas companies.
Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. We may not be able to successfully conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive crude oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment and acquiring the existing and changing technologies that we believe are and will be increasingly important to attaining success in our industry.
We 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 incur substantial 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.  There is 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 our financial 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 effect on 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 our claim which could result in a reduction or elimination of the revenue received by us from such properties.
Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.
During the last few years, concerns over inflation, energy costs, declining oil and gas prices, geopolitical issues, the availability and cost of credit, the U.S. mortgage market, uncertainties with regard to European sovereign debt, the slowdown

12




in economic growth in large emerging and developing markets, such as China, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on 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, which could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors', suppliers' and customers' ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition.
Risks Associated with Our Stock
Our stock price has been and may continue to be volatile.
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 ending June 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 stock price at which an investor may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as:
actual or anticipated variations in our results of operations;
naked short selling of our common stock and stock price manipulation;
changes or fluctuations in the commodity prices of crude oil and natural gas;
general conditions and trends in the crude oil and natural gas industry;
redemption demands on institutional funds that hold our stock; and
general economic, political and market conditions.
Our executive officers, directors and affiliates may be able to control the election of our directors and all other matters submitted to our stockholders for approval.
Our executive officers and directors, in the aggregate, beneficially own approximately 2.8 million shares, or approximately 8.5% of our beneficial common stock base. JVL Advisors LLC controls approximately 4.9 million shares or approximately 14.8% of our outstanding common stock, and Advisory Research controls approximately $3.5 million shares 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 the effect of delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.
The market for our common stock is limited and may not provide adequate liquidity.
Our common stock is relatively thinly traded on the NYSE MKT. During the fiscal year ending June 30, 2016, the daily trading volume in our common stock ranged from a 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 relatively limited liquidity in our shares of common stock. Selling our shares is more difficult because smaller quantities of shares are bought and sold and news media coverage about us is limited. These factors result in a limited trading market for our common stock and therefore holders of our stock may be unable to sell shares purchased, should they desire to do so.
If securities or industry analyst do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.
Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge there are three independent analysts that cover our company. The limited number of published reports by independent securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.
The issuance of additional common stock and preferred stock could dilute existing stockholders.
We currently have in place a registration statement which allows the Company to publicly issue up to $500 million of additional securities, including debt, common stock, preferred stock, and warrants. At any time we may make private offerings

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of our securities. The shelf registration is intended to provide greater flexibility to the company in financing growth or changing our capital structure. We are authorized to issue up to 100,000,000 shares of common stock. To the extent of such authorization, our board of directors has the ability, without seeking stockholder approval, to issue additional shares of common stock in the future for such consideration as our board may consider sufficient. The issuance of additional common stock in the future would reduce the proportionate ownership and voting power of the common stock now outstanding. We are also authorized to issue up to 5,000,000 shares of preferred stock, the rights and preferences of which may be designated in series by our board of directors, of which, at least 317,319 shares of Series A Preferred Stock are issued and outstanding as of September 1, 2016. Such designation of new series of preferred stock may be made without stockholder approval, and could create additional securities which would have dividend and liquidation preferences over the common stock now outstanding. Preferred stockholders could adversely affect the rights of holders of common stock by:
exercising voting, redemption and conversion rights to the detriment of the holders of common stock;
receiving preferences over the holders of common stock regarding our surplus funds in the event of our dissolution, liquidation or the payment of dividends to Preferred stockholders;
delaying, deferring or preventing a change in control of our company; and
discouraging bids for our common stock.
Our Series A Preferred Stock is thinly traded and has no stated maturity date.
The shares of Series A Preferred Stock were listed for trading on the NYSE MKT under the symbol "EPM.PR.A" on July 5, 2011 and are thinly traded on the NYSE MKT. Since the securities have no stated maturity date, investors seeking liquidity will be limited to selling their shares in the secondary market. An active trading market for the shares may not develop or, even if it develops, may not last, in which case the trading price of the shares could be adversely affected and your ability to transfer your shares of Series A Preferred Stock will be limited. We have the right to redeem all shares of Series A Preferred Stock at face value 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 the Series A Preferred Stock if we have funds legally available for the payment of dividends and such payment is not restricted or prohibited by law, the terms of any senior shares or any documents governing our indebtedness. Our business may not generate sufficient cash flow from operations to enable us to pay dividends on the Series A Preferred Stock when payable. In addition, existing or future debt, credit facility arrangements, contractual covenants or arrangements we enter into may restrict or prevent future dividend payments. Accordingly, there is no guarantee that we will be able to pay any cash dividends on our Series A Preferred Stock.
Furthermore, in some circumstances, we may pay dividends in stock rather than cash, and our stock price may be depressed at such time.
Our Series A Preferred Stock has not been rated and will be subordinated to all of our existing and future debt.
Our Series A Preferred Stock has not been rated by any nationally recognized statistical rating organization. In addition, with respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock will be subordinated to any existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock. We may also incur additional indebtedness in the future to finance potential acquisitions or the development of new properties and the terms of the Series A Preferred Stock do not require us to obtain the approval of the holders of the Series A Preferred Stock prior to incurring additional indebtedness. As a result, our existing and future indebtedness may be subject to restrictive covenants or other provisions that may prevent or otherwise limit our ability to make dividend or liquidation payments on our

14




Series A Preferred Stock. Upon our liquidation, our obligations to our creditors would rank senior to our Series A Preferred Stock and would be required to be paid before any payments could be made to holders of our Series A Preferred Stock.
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 since that 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 the future will be dependent upon the amount of funds legally available, our earnings, if any, our financial condition and business plan, restrictions contained in our Series A Preferred Stock and any debt instruments, contractual covenants or arrangements we may enter into, our anticipated capital requirements and other factors that our board of directors may think are relevant. Accordingly, there is no guarantee that we will be able to continue to pay cash dividends on our common stock.
Item 1B.    Unresolved Staff Comments
None.
Item 2.    Properties
The information required by Item 2. is contained in Item 1. Business
Oil & Gas Properties
Additional detailed information describing the types of properties we own can be found in "Business Strategy" under Item 1. Business of this Form 10-K.
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues
The SEC sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These rules require disclosure of oil and gas proved reserves by significant geographic area, using the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.
There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.
Estimates of Probable and Possible reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves but which, together with Proved reserves, are as likely as not to be recovered, 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 being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of Probable and Possible reserves are by their nature much more speculative than estimates of Proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. These three reserve categories and net present worth discounted at 10% relating to each 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, and that it is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. Further, analysts and investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. We also use this pre-tax measure when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled herein.

15




Summary of Oil & Gas Reserves for Fiscal Year Ended 2016
Our 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 of oil conversion ratio, were estimated by our independent petroleum engineer, DeGolyer and MacNaughton ("D&M"). D&M was selected for our interests in the Delhi field due to their expertise in CO2-EOR projects and to ensure consistency with the operator who also uses D&M for their reserves estimates in the Delhi field. We also chose to have D&M estimate 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 scope and results of their procedures are summarized in a letter from the firm, which is included as exhibit 99.4 to this Annual Report on Form 10-K.
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 additional unaudited reserve information is provided. The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $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 price is available, historical pricing in the area. Pricing differentials were applied to all properties, on an individual property basis. Quality adjustments have been applied based on actual BTU factors for each well and a shrinkage factor has been applied based on production volumes versus actual sales volumes.

16




Reserves as of June 30, 2016
Reserve Category
Oil
(MBbls)
 
NGLs
(MBbls)
 
Total Reserves
(MBOE)*
PROVED
 
 
 
 
 
Developed (66% of Proved)
7,168

 

 
7,168

Undeveloped (34% of Proved)
1,420

 
2,235

 
3,655

TOTAL PROVED
8,588

 
2,235

 
10,823

Product Mix
79
%
 
21
%
 
100
%
PROBABLE
 
 
 
 
 
Developed (69% of Probable)
3,092

 

 
3,092

Undeveloped (31% of Probable)
471

 
934

 
1,405

TOTAL PROBABLE
3,563

 
934

 
4,497

Product Mix
79
%
 
21
%
 
100
%
POSSIBLE
 
 
 
 
 
Developed (72% of Possible)
1,964

 

 
1,964

Undeveloped (28% of Possible)
187

 
563

 
750

TOTAL POSSIBLE
2,151

 
563

 
2,714

Product Mix
79
%
 
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
 
Delhi
Field
 
Giddings
Field
 
Proved
Total
Proved reserves, MBOE
 MBOE
 
 MBOE
 
 MBOE
June 30, 2015
12,413.8

 
32.6

 
12,446.4

Production
(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, 2016
10,823.4

 

 
10,823.4

Reconciliation of Changes in Probable Reserves by Major Property
 
Delhi
Field
 
Giddings
Field
 
Probable
Total
Probable reserves, MBOE
 MBOE
 
 MBOE
 
 MBOE
June 30, 2015
9,339.4

 

 
9,339.4

Revisions
(4,842.1
)
 

 
(4,842.1
)
Sales of minerals in place

 

 

Improved recovery, extensions and discoveries

 

 

June 30, 2016
4,497.3

 

 
4,497.3






17





Reconciliation of Changes in Possible Reserves by Major Property
 
Delhi
Field
 
Giddings
Field
 
Possible
Total
Possible reserves, MBOE
MBOE
 
MBOE
 
MBOE
June 30, 2015
2,954.4

 

 
2,954.4

Revisions
(240.4
)
 

 
(240.4
)
Sales of minerals in place

 

 

Improved recovery, extensions, and discoveries

 

 

June 30, 2016
2,714.0

 

 
2,714.0

Reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash Flows
The following table provides a reconciliation of PV-10 of our proved properties to the Standardized Measure as shown in Note 23 of the consolidated financial statements.
 
For the Years Ended June 30,
 
2016
 
2015
Estimated future net revenues
$
187,713,581

 
$
448,113,943

10% annual discount for estimated timing of future cash flows
86,844,543

 
229,407,446

Estimated future net revenues discounted at 10% (PV-10)
100,869,038

 
218,706,497

Estimated future income tax expenses discounted at 10%
(22,911,719
)
 
(59,509,958
)
Standardized Measure
$
77,957,319

 
$
159,196,539

The 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 financial statements.
 
For the Years Ended June 30,
 
2016
 
2015
Delhi Field
$
100,869,038

 
$
218,320,579

Giddings Field

 
385,918

Estimated future net revenues discounted at 10% (PV-10)
$
100,869,038

 
$
218,706,497

Estimated future income tax expenses discounted at 10%
(22,911,719
)
 
(59,509,958
)
Standardized Measure
$
77,957,319

 
$
159,196,539

Additional information about the properties we own can be found in Item 1. Business.
Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company's Overall Reserve Estimation Process
Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Executive Chairman, 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 generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. Our Executive Chairman holds B.S. and M.E. degrees from Rice University in chemical engineering and earned an M.B.A. from Harvard University. He has over 30 years of experience in engineering, energy transactions, operations and finance with small independents, larger independents and major integrated oil companies. Our Chief Executive Officer holds a Bachelor of Business Administration degree from the 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 at Norman. The reserve information in this filing is based on estimates prepared by DeGoyler and MacNaughton, our independent engineering firm. The person responsible for preparing 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 in Geology 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.

18




He has over 36 years of oil and gas reservoir experience. We provide our engineering firm with property interests, production, current operating costs, current production prices and 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 our independent engineering firm. The scope and results of our independent engineering firm's procedures, as well as their professional qualifications, are summarized in the letter included as exhibit 99.4 to this Annual Report on Form 10-K.
Proved Undeveloped Reserves
Our proved undeveloped reserves were 3,655 MBOE at June 30, 2016 with associated future development costs of approximately $14.9 million. During the year ended June 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 end of 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 for Phase 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 remaining eastern 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 less recoverable reserves and higher future development costs than the Phase V project we continue to carry as proved undeveloped. There were no reclassifications of proved undeveloped 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 CO2 enhanced oil recovery project. The operator’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 the initial 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 in June 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 converted to proved reserves during fiscal 2015 and 2016, development expenditures were ongoing. Expansion of the CO2 flood to the remaining undeveloped eastern portion of the field commenced subsequent to reversion of our working interest in late calendar 2014. The Company incurred $3.8 million of capital expenditures until the operator suspended this project 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 million of 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 its completion 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 part of 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, approximately seven 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 additional planning and has resulted in a prudent delay in the full development of the field's proved reserves. Given the nature of CO2 EOR projects, we believe that the undeveloped reserves 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 previously adopted 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 have significant ongoing development activities at this project that, as budgeted and currently being expended, reflect a significant and sufficient portion of remaining capital expenditures to convert proved undeveloped reserves to proved developed reserves; and (3) the operator has a historical record of completing the development of comparable long-term projects.

19




Sales Volumes, Average Sales Prices and Average Production Costs
The following table shows the Company's sales volumes and average sales prices received for crude oil, natural gas liquids, and natural gas for the periods indicated:
 
Year Ended 
 June 30, 2016
 
Year Ended 
 June 30, 2015
 
Year Ended 
 June 30, 2014
Product
Volume
 
Price
 
Volume
 
Price
 
Volume
 
Price
Crude oil (Bbls)
658,041

 
$
39.71

 
450,713

 
$
61.59

 
169,783

 
$
102.84

Natural gas liquids (Bbls)
491

 
$
16.06

 
1,358

 
$
27.41

 
3,516

 
$
33.32

Natural gas (Mcf)
1,620

 
$
1.79

 
7,981

 
$
3.33

 
26,655

 
$
3.60

Average price per BOE*
658,802

 
$
39.68

 
453,401

 
$
61.37

 
177,742

 
$
99.43

 
 
 
 
 
 
 
 
 
 
 
 
Production costs
Amount
 
per BOE
 
Amount
 
per BOE
 
Amount
 
per BOE
Production costs, excluding ad valorem and production taxes
$
8,767,490

 
$
13.31

 
$
9,285,396

 
$
20.48

 
$
1,148,974

 
$
6.46

Total production costs, including ad valorem and 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 Activity
Our 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 years.
Present Activities
During 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. In addition to the value of these hydrocarbon products, the increased purity of the CO2 stream re-injected into the field should result in significant operational benefits to the CO2 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. Following the fluid release event in June 2013, CO2 injections in this area ceased in order to reduce reservoir pressure and protect the incident area. The project includes converting three shut-in wells to water injector wells in order to expand the water curtain barrier to reduce CO2 migration into this area together with the 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. These ESP production wells will create a 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 and Results of Operations of this Form 10-K.
Delivery Commitments
As 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 to enter into any such agreements.

20




Productive Wells
The 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 the expected disposition of our three company operated wells.
 
Company Operated
 
Non-Operated
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Crude oil
3

 
2.9

 
89

 
21.3

 
92

 
24.2

Natural gas

 

 

 

 

 

Total
3

 
2.9

 
89

 
21.3

 
92

 
24.2

Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2016. Developed acreage refers to acreage on which 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 which wells 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. 
Field
Developed Acreage
 
Undeveloped Acreage
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Delhi Field, Louisiana*
9,126

 
2,180

 
4,510

 
1,077

 
13,636

 
3,257

Giddings Field, Texas**
2,168

 
2,134

 

 

 
2,168

 
2,134

Total
11,294

 
4,314

 
4,510

 
1,077

 
15,804

 
5,391

When 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 reflected as developed acreage. With the addition of a CO2-EOR project in the field, certain acreage is now reflected as undeveloped using tertiary recovery operations. We estimate that our 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 remaining undeveloped 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. Subsequent to 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 CO2 and Mengel Units. As the Delhi field is a 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 of Financial Condition and Results of Operations of this Form 10-K.
Item 3.    Legal Proceedings
See 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 Disclosures
Not Applicable.


21




PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
Our common stock is currently traded on the NYSE MKT under the ticker symbol "EPM". 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: EPM
2016:
High
 
Low
Fourth quarter ended June 30, 2016
$
5.97

 
$
4.45

Third quarter ended March 31, 2016
$
5.12

 
$
3.60

Second quarter ended December 31, 2015
$
7.54

 
$
4.70

First quarter ended September 30, 2015
$
6.70

 
$
4.02


2015:
High
 
Low
Fourth quarter ended June 30, 2015
$
7.97

 
$
5.77

Third quarter ended March 31, 2015
$
8.10

 
$
5.68

Second quarter ended December 31, 2014
$
10.25

 
$
6.50

First quarter ended September 30, 2014
$
11.19

 
$
8.95


Shares Outstanding and Holders
As of June 30, 2016, there were 32,907,863 shares of common stock issued and outstanding, held by approximately 218 holders of record.
Dividends
We 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. As of 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 declared and 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 future earnings, financial condition, applicable dividend restrictions and capital requirements and other factors deemed relevant by the Board of Directors. Under our current revolving credit facility, 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 pay common stock dividends.
Performance Graph
The following graph presents a comparison of the yearly percentage change in the cumulative total return on our Common Stock over the period from June 30, 2011 to June 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. The graph 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 and the reinvestment of all dividends, if any. The graph is presented in accordance with requirements of the SEC. Shareholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.

22




https://cdn.kscope.io/6b3bd1c93d72d88e6c7f626f2910216a-evolutionpet_chart-31139a04.jpg
Securities Authorized For Issuance Under Equity Compensation Plans
Plan category
Number of
securities to
be issued
upon exercise
of outstanding
options,
warrants and
rights
(a)
 
 
 
Weighted-average
exercise
price of
outstanding
Options, warrants
and rights
(b)
 
Number of securities
remaining
available for future
issuance under
equity compensation
plans (excluding
securities reflected
in column (a))(1)
Equity compensation plans approved by security holders:
 
 
 
 
 
 
 
    Outstanding options
35,231

 
(1)
 
$
2.19

 
 
    Outstanding contingent rights to shares
91,172

 
(1)
 

 
 
  Total
126,403

 
 
 
$
0.61

 
282,133

Equity compensation plans not approved by security holders

 
 
 

 

Total
126,403

 
 
 
$
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 the exercise 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 restricted stock 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.


23




Issuer Purchases of Equity Securities
Period
(a) Total Number of
Shares (or Units)
Purchased (1) (2)
 
(b) Average Price
Paid per Share (or
Units)
 
(c) Total Number of Shares
(or Units) Purchased as Part
of Publicly Announced Plans
or Programs
 
(d) Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
April 1, 2016 to April 30, 2016
none
 

 
 
May 1, 2016 to May 31, 2016
none
 

 
 
June 1, 2016 to June 30, 2016
229 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 in exchange for their payroll tax liabilities arising from vestings of restricted stock. The acquisition cost per share reflected the weighted-average market price of the Company's shares at the dates vested.
(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 be repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases will depend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time. Such shares were initially recorded as treasury stock, then subsequently canceled.
Item 6.    Selected Financial Data
The selected consolidated financial data, set forth below should be read in conjunction with Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" and with the consolidated financial statements and notes to those consolidated financial statements included elsewhere in this report.
 
June 30,
 
2016
 
2015
 
2014
 
2013
 
2012
Income Statement Data
 
 
 
 
 
 
 
 
 
Revenues
$
26,349,502

 
$
27,841,265

 
$
17,673,508

 
$
21,349,920

 
$
17,962,038

Cost of revenues
9,133,111

 
9,355,613

 
1,193,573

 
1,780,738

 
1,774,999

Depreciation, depletion, and amortization
5,165,120

 
3,615,737

 
1,228,685

 
1,300,207

 
1,136,974

Accretion expense
49,054

 
34,866

 
41,626

 
72,312

 
77,505

General and administrative expense
9,079,597

 
6,256,783

 
8,388,291

 
7,495,309

 
6,143,286

Restructuring charges
1,257,433

 
(5,431
)
 
1,293,186

 

 

Income from operations
1,665,187

 
8,583,697


5,528,147

 
10,701,354

 
8,829,274

Other income (expense)
32,565,954

 
(147,619
)
 
(38,836
)
 
(43,165
)
 
3,778

Income tax provision
9,570,779

 
3,444,221

 
1,891,998

 
4,029,761

 
3,700,922

Net income attributable to the Company
$
24,660,362

 
$
4,991,857


$
3,597,313

 
$
6,628,428

 
$
5,132,130

Dividends on Series A Preferred Stock
674,302

 
674,302

 
674,302

 
674,302

 
630,391

Net income attributable to common shareholders
$
23,986,060

 
$
4,317,555


$
2,923,011

 
$
5,954,126

 
$
4,501,739

Earnings per common share:
 
 
 
 
 
 
 
 
 
Basic
$
0.73

 
$
0.13

 
$
0.09

 
$
0.21

 
$
0.16

Diluted
$
0.73

 
$
0.13

 
$
0.09

 
$
0.19

 
$
0.14



24




 
June 30, 2016
 
June 30, 2015
 
June 30, 2014
 
June 30, 2013
 
June 30, 2012
Balance Sheet Data
 
 
 
 
 
 
 
 
 
Total current assets
$
37,086,450

 
$
23,693,048

 
$
26,304,803

 
$
27,436,076

 
$
16,769,789

Total assets
97,451,051

 
69,882,727

 
65,015,752

 
66,556,296

 
58,955,486

Total current liabilities
8,528,908

 
9,329,257

 
2,999,726

 
2,632,750

 
5,088,917

Total liabilities
21,129,901

 
21,306,150

 
13,138,230

 
11,720,135

 
12,332,698

Stockholders' equity
76,321,150

 
48,576,577

 
51,877,522

 
54,836,161

 
46,622,788

 
 
 
 
 
 
 
 
 
 
Number of common shares outstanding
32,907,863

 
32,845,205

 
32,615,646

 
28,608,969

 
27,882,224


25




Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, Financial Statements and Supplementary Data. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors 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 cause our actual results to be materially different from our forward-looking statements.
Executive Overview
General
We are engaged primarily in the development of oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional and proprietary technology. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain control of our assets for the benefit of our shareholders, including a substantial ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership of our common stock.
Our strategy is to grow the value of our Delhi assets to maximize the value realized by our shareholders. In addition, we plan to return cash to the shareholders in the form of 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 2016
Finances
We funded all operations, including $21.1 million of capital spending, from internal resources and remained debt free.  All of our capital expenditures and dividends 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 rewarding our 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 $10.0 million. 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 price volatility 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, a separate interval within the Delhi field that is not currently producing. We also reached agreement on our ownership of the CO2 recycle facility and on the long term costs of purchased CO2.

Installation and construction of the NGL recovery plant at Delhi is approximately 90% complete. Technical completion and start-up of the plant is scheduled to begin in November 2016. Our net share of capital expenditures for

26




this 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 fiscal year 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 a conformance 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 interest and 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 the prior 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 minority equity 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 equity ownership 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 reserves declined 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, and 66% 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
 
Change
Reserves MMBOE
10.8

 
12.4

 
(13
)%
 
4.5

 
9.3

 
(52
)%
 
2.7

 
3.0

 
(10
)%
% Developed
66
%
 
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 Discounted Future 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 wide use by analysts and investors in evaluating the relative monetary significance of oil and natural gas properties, and as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. We also use this pre-tax measure when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled in Item 2. Properties.
Projects
Additional property and project information is included under Item 1. Business, Item 2. Properties, Item 8. Financial Statements - Notes to the Financial Statements and Exhibit 99.4 of this Form 10-K.
Delhi Field EOR—Northeast Louisiana
Proved 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 12.4 MMBOE with a Standardized Measure of $159 million and a PV-10* value of $219

27




million. 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 prior year production and removal of proved undeveloped reserves in Phase VI which were deemed to be uneconomic in the current price environment. Proved undeveloped reserves declined 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 not deemed 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, all three due to the reduced SEC oil price applied. The Phase VI eastern development patterns removed from our proved undeveloped reserves had significantly lower recoverable reserves 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 settlement agreement.
Our cost of purchased CO2 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 from the 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 aggregate CO2 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 106 MMCF/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 costs per 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 the prior 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 development plans 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. Production volumes 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 potential additional 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 total estimated 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, the methane 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 plant should also increase the efficiency of the CO2 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, no remaining estimated capital expenditures are required to develop our probable or possible reserves as these reserves reflect incremental quantities associated with a greater percentage recovery of hydrocarbons in place than the recovery quantities assumed for proved reserves. Looking forward, the timing of plans for continued development of the eastern 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 economically viable project will be executed as planned, subject to oil price volatility.
GARP® - Artificial Lift Technology
As a result of a strategic review, Company management recommended and the Board approved a transfer of a majority interest in our GARP® oilfield technology operations to a new unaffiliated entity, led by our former SVP of Operations, who invented the technology, effective December 31, 2015. Evolution retained a minority equity interest 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 be employees 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.

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Other Fields
During 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 to declining production and depressed commodity prices, two wells have now been temporarily abandoned, and one well bore was returned to the previous operator per contractual agreement, 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 wells compared 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 associated with these assets as of June 30, 2015 or 2014.
Liquidity and Capital Resources
We 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 of oil 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 our properties near term, such development will be more limited while commodity prices remain low and unstable. The Company will manage any development activity in the context 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 credit facility 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 base of $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 the Company’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 each May 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 gas properties of the Company or its subsidiaries and cancellation of certain hedging positions. With the recent volatility in commodity prices, our borrowing base and related commitments 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) the adjusted 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 service coverage 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 other affirmative 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 were outstanding 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 $13.9 million increase in cash.
Cash Flows from Operating Activities
For 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 million provided by other working capital changes. Of the $28.9 million provided before working capital changes, approximately $24.7 million resulted from net income and $4.2 million 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 used by 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 was attributable to non-cash expenses.

29




For the year ended June 30, 2014, cash flows provided by operating activities were $8.1 million, reflecting $7.7 million provided by operations before $0.4 million provided by other working capital changes. Of the $7.7 million provided before working capital changes, $3.6 million resulted from net income and $4.1 million was attributable to non-cash expenses.
Cash Flows from Investing Activities
For 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 Delhi field 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 proceeds received 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 Giddings and 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 million from 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 for related non-cash items presented at Note 13 - Supplemental Cash Flow Information.
Cash Flows from Financing Activities
For 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 offset by $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 share buyback 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 previously filed 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 of preferred 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 related to 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 of preferred stock dividends and $1.7 million of treasury stock acquired through the surrender of shares by certain officers and employees in satisfaction of payroll liabilities related to stock-based compensation, partially offset by cash inflows of $0.5 million from a tax benefit related to stock-based compensation and $3.3 million from stock option exercises.
Capital Budget
Delhi Field
During 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 have been 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 well bore integrity, including previously plugged wells, drilling and completion of monitoring wells and larger projects to recomplete or workover wells which may be capitalized instead 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 the NGL 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 be estimated 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 the fall 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 suspended work on this phase. The resumption of this project is dependent on prevailing oil prices, the availability of capital for such projects and the relative

30




economics 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 working interest, has favorable economics, even in this lower price environment, and expect the expansion of the CO2 flood to resume within the next two years. Phase VI has less favorable 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. The economics of both projects will be improved subsequent to the completion and startup of the NGL recovery plant in late calendar 2016.
Liquidity Outlook
Our 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 expect positive 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 and the 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 Company began 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 of cash 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 floor prices on anticipated future oil production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. Our future revenues, cash flow, profitability, access to capital and future rate of growth are significantly impacted by the prices we receive 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. Our preference 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 we have an effective shelf registration statement with Securities and Exchange Commission. We may choose to evaluate new growth opportunities through acquisitions or other transactions. 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 advantageous for 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 declared the 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 common stock 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 shareholders through 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 as appropriate.

31




Results of Operations
The following table sets forth certain financial information with respect to our oil and natural gas operations:
 
Year Ended June 30,
 
2016
 
2015
 
2014
Oil and gas production:
 
 
 
 
 
Crude oil revenues
$
26,130,762

 
$
27,761,291

 
$
17,460,392

NGL revenues
7,885

 
37,227

 
117,166

Natural gas revenues
2,895

 
26,601

 
95,950

Total revenues
$
26,141,542

 
$
27,825,119

 
$
17,673,508

 
 
 
 
 
 
Crude oil volumes (Bbl)
658,041

 
450,713

 
169,783

NGL volumes (Bbl)
491

 
1,358

 
3,516

Natural gas volumes (Mcf)
1,620

 
7,981

 
26,655

Equivalent 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

 
$
102.84

NGL price per Bbl
16.06

 
27.41

 
33.32

Natural gas price per Mcf
1.79

 
3.33

 
3.60

Equivalent price per BOE
$
39.68

 
$
61.37

 
$
99.43

 
 
 
 
 
 
Production costs (a)
$
9,062,179

 
$
9,335,244

 
$
1,193,573

Production costs per BOE
$
13.76

 
$
20.59

 
$
6.72

 
 
 
 
 
 
Oil and gas DD&A (b)
$
4,906,123

 
$
3,220,990

 
$
1,192,370

Oil and gas DD&A per BOE
$
7.45

 
$
7.10

 
$
6.71

 
 
 
 
 
 
Artificial lift technology services:
 
 
 
 
 
Services revenues
$
207,960

 
$
16,146

 
$

Cost of service
70,932

 
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 years ended June 30, 2016, 2015, and 2014, respectively.

Year ended June 30, 2016 compared with the Year ended June 30, 2015
Net 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 diluted share, 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 derivative gains, 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 net production and revenues or production costs as reversion of our working interest did not occur until November 1, 2014. Delhi oil production and

32




revenues 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 period as 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 the Company'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 full twelve 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 $8.9 million of which $4.1 million was for CO2 costs, compared to $8.5 million, of which $5.1 million was for CO2 costs, in the year-ago period. Average gross injection volumes decreased 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, which includes $8.66 per working interest BOE for CO2 costs. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, which bear 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 year service 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 a result 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. In June, 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 technology operations. 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 personnel termination 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 from the 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 gains on 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 as a 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 was due 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, 2014
Net 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 $1.4 million, 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 $8.1 million 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 in the prior year to 6,038 BOPD in the current year.

33




Production 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 the Delhi 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 in the 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 not include 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 production costs 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 our November 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 CO2 costs. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, which bear no production 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 the prior 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 financial officer, 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, partially offset 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-cash charge 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 from January to December 2014 and $376,000 of non-cash stock compensation expense for accelerated restricted stock vesting for terminated employees.  All restructuring obligations had 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 year due 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 three under performing wells of a third party customer. The remaining expense increase was primarily the result of higher depreciation of artificial lift equipment placed in service during 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 the depletion 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 in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services greatly impact our lease operating expenses and our capital expenditures. During fiscal 2016, we have seen 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 and development 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 be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries, companies, as well as consumers, which impact demand for crude oil and natural gas. If demand 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, thereby lowering 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 our petroleum products. Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather including hurricanes that may substantially affect oil and natural gas production and imports.

34




Contractual Obligations and Other Commitments
The 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 and commitments. We expect to fund these contractual obligations with cash on hand and cash generated from operations.
 
Payments Due by Period
 
Total
 
Less than
1 Year
 
1 - 3 Years
 
3 - 5 Years
 
More than 5 Years
Contractual Obligations
 
 
 
 
 
 
 
 
 
Operating lease
$
220,292

 
$
80,235

 
$
140,057

 

 

Other Obligations
 
 
 
 
 
 
 
 
 
Asset retirement obligations
962,196

 
201,896

 

 

 
760,300

Total obligations
$
1,182,488

 
$
282,131

 
$
140,057

 
$

 
$
760,300

As 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 Field which we expect to fund in the first quarter of fiscal 2017.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets and liabilities and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates have a significant effect on our consolidated financial statements. Our significant accounting policies are included in Note 2 to the consolidated financial statements. Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our consolidated financial statements.
Oil and Natural Gas Properties.    Companies engaged in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and gas industry. We apply the full cost accounting method for our oil and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 2016, we had no unevaluated properties costs.
Estimates of Proved Reserves.    The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense, and the estimated future net cash flows associated with those proved reserves is the basis in determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including reservoir performance, additional development activity, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates represent the most accurate assessments possible, including the hiring of independent engineers to prepare our reserve estimates, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial statements. Material revisions to reserve estimates and / or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves, affecting our quarterly ceiling test calculation and could significantly affect our depletion rate. A 10% decrease in commodity prices used to determine our proved reserves and Standardized Measure as of June 30, 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.

35




On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and gas reserves. The rule allows consideration of new technologies in evaluating reserves, generally limits the designation of proved reserves to those projects forecast to be commenced within five years of the end of the period, allows companies to disclose their probable and possible reserves to investors, requires reporting of oil and gas reserves using an average price based on the previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices, revises the disclosure requirements for oil and gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.
Valuation of Deferred Tax Assets.    We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared or filed; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carry backs and carry forwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our net operating loss). If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of June 30, 2016, we have recorded a valuation 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 the ultimate realization of deferred tax assets. Based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible, as of end of the current fiscal year, we believe that it is more likely than not that the Company will realize the benefits of its net deferred tax assets. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would increase in the period it is determined that recovery is not probable.
Stock-based Compensation.    We estimate the fair value of stock option awards on the date of grant using the Black-Scholes option pricing model. This valuation method requires the input of certain assumptions, including expected stock price volatility, expected term of the award, the expected risk-free interest rate, and the expected dividend yield of the Company's stock. The risk-free interest rate used is the U.S. Treasury yield for bonds matching the expected term of the option on the date of grant. Because of our limited trading experience of our common stock and limited exercise history of our stock option awards, estimating the volatility and expected term is very subjective. We base our estimate of our expected future volatility on peer companies whose common stock has been trading longer than ours, along with our own limited trading history while operating as an oil and natural gas producer. Future estimates of our stock volatility could be substantially different from our current estimate, which could significantly affect the amount of expense we recognize for our stock-based compensation awards.
Off Balance Sheet Arrangements
The Company has no off-balance sheet arrangements as of June 30, 2016.
Item 7A.    Quantitative and Qualitative Disclosures About Market Risks
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
Commodity Price Risk
Our most significant market risk is the pricing for crude oil, natural gas and NGLs. We expect energy prices to remain volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline. In addition, a non-cash write-down of our oil and gas properties could be required under full cost accounting rules if future oil and gas commodity prices sustained a significant decline. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as, if and when needed. We use derivative instruments to

36




manage 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 price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes.

37




Item 8.    Financial Statements

Index to Consolidated Financial Statements
 
 
 
 
 
 

38





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Stockholders
Evolution Petroleum Corporation

 We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and subsidiaries (the “Company”) as of June 30, 2016 and 2015, and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the three years in the period ended June 30, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
 We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Evolution Petroleum Corporation and subsidiaries as of June 30, 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 with U.S. generally accepted accounting principles.
 We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Evolution Petroleum Corporation and subsidiaries’ internal control over financial reporting as of June 30, 2016, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013, and our report dated September 9, 2016 expressed an unqualified opinion on the effectiveness of Evolution Petroleum Corporation’s internal control over financial reporting.

Hein & Associates LLP
Houston, Texas
September 9, 2016

39





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Stockholders
Evolution Petroleum Corporation

We have audited Evolution Petroleum Corporation's internal control over financial reporting as of June 30, 2016, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Evolution Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.
 We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (c) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 In our opinion, Evolution Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of June 30, 2016, based on criteria established 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 Evolution Petroleum Corporation and subsidiaries as of June 30, 2016 and 2015, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended June 30, 2016 and our report dated September 9, 2016 expressed an unqualified opinion.

Hein & Associates LLP
Houston, Texas
September 9, 2016

40




Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
 
June 30, 2016
 
June 30, 2015
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
34,077,060

 
$
20,118,757

Receivables
2,638,188

 
3,122,473

Deferred tax asset
105,321

 
82,414

Derivative assets, net
14,132

 

Prepaid expenses and other current assets
251,749

 
369,404

Total current assets
37,086,450

 
23,693,048

Property and equipment, net of depreciation, depletion, and amortization
 
 
 
Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization
59,970,463

 
45,186,886

Other property and equipment, net
28,649

 
276,756

Total property and equipment, net
59,999,112

 
45,463,642

Other assets
365,489

 
726,037

Total assets
$
97,451,051

 
$
69,882,727

Liabilities and Stockholders' Equity
 
 
 
Current liabilities
 
 
 
Accounts payable
$
5,809,107

 
$
8,173,878

Accrued liabilities and other
2,097,951

 
855,373

Derivative liabilities, net

 
109,974

State and federal taxes payable
621,850

 
190,032

Total current liabilities
8,528,908

 
9,329,257

Long term liabilities
 
 
 
Deferred income taxes
11,840,693

 
11,242,551

Asset retirement obligations
760,300

 
715,767

Deferred rent

 
18,575

Total liabilities
21,129,901

 
21,306,150

Commitments 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, 317,319 shares issued and outstanding at June 30, 2016 and 2015, respectively, with a total liquidation preference of $7,932,975 ($25.00 per share)
317

 
317

Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,907,863 and 32,845,205 shares as of June 30, 2016 and 2015, respectively
32,907

 
32,845

Additional paid-in capital
47,171,563

 
36,847,289

Retained earnings
29,116,363

 
11,696,126

Total stockholders' equity
76,321,150

 
48,576,577

Total liabilities and stockholders' equity
$
97,451,051

 
$
69,882,727


   See accompanying notes to consolidated financial statements.

41




Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
 
Years Ended June 30,
 
2016
 
2015
 
2014
Revenues
 
 
 
 
 
Crude oil
$
26,130,762

 
$
27,761,291

 
$
17,460,392

Natural gas liquids
7,885

 
37,227

 
117,166

Natural gas
2,895

 
26,601

 
95,950

Artificial lift technology services
207,960

 
16,146

 

Total revenues
26,349,502

 
27,841,265

 
17,673,508

Operating costs
 
 
 
 
 
Production costs
9,062,179

 
9,335,244

 
1,193,573

Cost of artificial lift technology services
70,932

 
20,369

 

Depreciation, depletion and amortization
5,165,120

 
3,615,737

 
1,228,685

Accretion of discount on asset retirement obligations
49,054

 
34,866

 
41,626

General and administrative expenses*
9,079,597

 
6,256,783

 
8,388,291

Restructuring charges
1,257,433

 
(5,431
)
 
1,293,186

Total operating costs
24,684,315

 
19,257,568

 
12,145,361

Income from operations
1,665,187

 
8,583,697

 
5,528,147

Other
 
 
 
 
 
Gain on settled derivative instruments, net
3,315,123

 

 

Gain (loss) on unsettled derivative instruments, net
124,106

 
(109,974
)
 

Delhi field litigation settlement
28,096,500

 

 

Delhi field insurance recovery related to pre-reversion event
1,074,957

 

 

Interest and other income
26,211

 
35,991

 
30,256

Interest (expense)
(70,943
)
 
(73,636
)
 
(69,092
)
Income before income tax provision
34,231,141

 
8,436,078

 
5,489,311

Income tax provision
9,570,779

 
3,444,221

 
1,891,998

Net income attributable to the Company
24,660,362

 
4,991,857

 
3,597,313

Dividends on preferred stock
674,302

 
674,302

 
674,302

Net income attributable to common shareholders
$
23,986,060

 
$
4,317,555

 
$
2,923,011

Earnings per common share
 
 
 
 
 
Basic
$
0.73

 
$
0.13

 
$
0.09

Diluted
$
0.73

 
$
0.13

 
$
0.09

Weighted average number of common shares outstanding
 
 
 
 
 
Basic
32,810,375

 
32,817,456

 
30,895,832

Diluted
32,861,231

 
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.

42




Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
 
Years Ended June 30,
 
2016
 
2015
 
2014
Cash flows from operating activities
 
 
 
 
 
Net income attributable to the Company
$
24,660,362

 
$
4,991,857

 
$
3,597,313

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation, depletion and amortization
5,211,494

 
3,664,373

 
1,272,778

Impairments included in restructuring charge
569,228

 

 

Stock-based compensation
1,750,209

 
943,653

 
1,352,322

Stock-based compensation related to restructuring
59,339

 

 
376,365

Accretion of discount on asset retirement obligations
49,054

 
34,866

 
41,626

Settlement of asset retirement obligations

 
(223,564
)
 
(315,952
)
Deferred income taxes
575,235

 
1,422,489

 
1,344,812

Deferred 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 costs
50,414

 

 

Changes in operating assets and liabilities:
 
 
 
 
 
Receivables
484,285

 
(1,665,261
)
 
507,592

Prepaid expenses and other current assets
24,754

 
378,049

 
(480,899
)
Accounts payable and accrued expenses
822,730

 
551,452

 
663,645

Income taxes payable
431,818

 
190,032

 
(233,548
)
Net cash provided by operating activities
30,653,193

 
10,380,775

 
8,108,909

Cash flows from investing activities
 
 
 
 
 
Derivative settlements received
3,633,831

 

 

Proceeds from asset sales

 
398,242

 
542,347

Development 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

 

 
250,000

Other 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 options
51,000

 
141,600

 
3,252,801

Acquisitions 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 compensation
9,650,657

 
1,633,946

 
509,096

Other
33

 
67

 
6,850

Net cash provided (used) by financing activities
935,408

 
(9,160,247
)
 
(8,348,174
)
Net increase (decrease) in cash and cash equivalents
13,958,303

 
(3,821,757
)
 
(988,071
)
Cash and cash equivalents, beginning of year
20,118,757

 
23,940,514

 
24,928,585

Cash and cash equivalents, end of year
$
34,077,060

 
$
20,118,757

 
$
23,940,514

See accompanying notes to consolidated financial statements.

43




Evolution Petroleum Corporation and Subsidiaries
Consolidated Statement of Changes in Stockholders' Equity
For the Years Ended June 30, 2016, 2015 and 2014
 
Preferred
 
Common Stock
 
 
 
 
 
 
 
 
 
Additional
Paid-in
Capital
 
Retained
Earnings
 
Treasury
Stock
 
Total
Stockholders'
Equity
 
Shares
 
Par Value
 
Shares
 
Par Value
 
Balance, June 30, 2013
317,319

 
$
317

 
28,608,969

 
$
29,410

 
$
31,813,239

 
$
24,013,035

 
$
(1,019,840
)
 
$
54,836,161

Issuance 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

 

 

 
3,871,407