10-K

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, 2015
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                to              
Commission File Number 001-32942
EVOLUTION PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Nevada
(State or other jurisdiction of
incorporation or organization)
 
41-1781991
(IRS Employer
Identification No.)
2500 CityWest Blvd., Suite 1300, Houston, Texas 77042
(Address of principal executive offices and zip code)
(713) 935-0122
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
 
Title of Each Class
 
Name of Each Exchange On Which Registered
 
 
Common Stock, $0.001 par value
 
NYSE MKT
 
 
8.5% Series A Cumulative Preferred Stock, $0.001 par value
 
NYSE MKT
 
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes: o    No: ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes: o    No: ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: ý    No: o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes: ý    No: o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definition of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer ý
 
Non-accelerated filer o
 
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: o    No: ý
The aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $7.43 on the NYSE MKT was $183,168,484.
The number of shares outstanding of the registrant's common stock, par value $0.001, as of September 1, 2015, was 32,671,415.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant's 2015 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.

1


EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
2015 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 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. In 2013, our business was modified to include a second focus on applying our proprietary artificial lift technology for recovering incremental oil and gas from existing wells. In this document, we provide additional information about our business operations and plans for commercializing our artificial lift technology, but it is not currently a separate reportable segment of our operations. 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 2500 City West Blvd, Suite 1300, Houston, Texas 77042, and our telephone number is (713) 935-0122. We maintain a website at www.evolutionpetroleum.com, but information contained on our website does not constitute part of this document.
Our common stock is traded on the NYSE MKT under the ticker symbol "EPM". We also have preferred stock which trades under the symbol "EPM.A"
At June 30, 2015, we had ten 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, including our patented artificial lift technology, to increase production, ultimate recoveries, or both. We also provide our artificial lift technology to other operators to improve recovery of oil and gas from existing wells.
Our principal assets include interests in a CO2 enhanced oil recovery project in Louisiana’s Delhi Field and our patented artificial lift technology, GARP®. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders.
Delhi Field—Louisiana
Our mineral 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 9 million bbls of oil. The Unit is currently producing as an EOR project utilizing CO2 flood technology

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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 $2.8 million purchase of the field in 2003, the Unit had minimal production.
We own two types of interests in the Unit:
7.4% of overriding royalty interests that are in effect throughout the life of the project and mineral royalty interests, free of all operating and capital cost burdens; and
A 23.9% working interest with an associated 19.0% net revenue interest. The working interest reverted to us effective November 1, 2014, when the operator generated $200 million of net revenue from the 100% working interest less direct operating expenses and the cost of purchased CO2. Upon occurrence of this contractual payout, we began bearing 23.9% of all operating expenses and capital expenditures and our net revenue interest increased to an aggregate of 26.4%.
Our independent reservoir engineers, DeGolyer & MacNaughton, assigned the following estimated reserves net to our interests at Delhi as of June 30, 2015. Equivalent oil reserves is defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio.
12.4 million bbls of proved oil equivalent reserves, with a PV-10* of $218.7 million
9.3 million bbls of probable** oil equivalent reserves, with a PV-10* of $72.3 million
3.0 million bbls of possible** oil equivalent reserves, with a PV-10* of $13.6 million
_______________________________________________________________________________
*
PV-10 of Proved reserves is a non-GAAP measure, reconciled to the Standardized Measure at "Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues" under Item 2. Properties of this Form 10-K. Probable and Possible reserves are not recognized by GAAP, and therefore the PV-10 of such reserves cannot be reconciled to a GAAP measure.
**
With respect to the above reserve numbers, estimates of Probable and Possible reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves but which, together with Proved reserves, are as likely as not to be recovered. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of Probable and Possible reserves are by their nature much more speculative than estimates of Proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. 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 multiple phases for the installation of the CO2 flood.
Phase I began CO2 injection in November 2009. First oil production response occurred in March 2010, about three to four months earlier than expected, and production in the field increased to approximately 2,000 gross 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 before the operator temporarily suspended CO2 injection in the southwestern tip of the field due to a fluid release event in June 2013, which consisted of the uncontrolled release of CO2, water, natural gas and a small amount of oil from one or more previously plugged wells in the southwest part of the field. The operator has fully remediated the affected area, but has temporarily isolated that part of the field with a water curtain and is evaluating options to continue production from that area as a water flood, potentially aided by surfactants or other enhanced recovery techniques. It is also possible that the operator may choose to resume CO2 injection in that part of the field at a later date.
The operator has taken 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

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reversion by more than one year. We dispute the operator's position on the treatment of these costs and have filed suit against the operator over this matter and other issues related to the original 2006 agreements. See Note 17 - Commitments and Contingencies.
Since 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 economical utilization than selling of 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 $5 million. The plant is expected to be operational in the second half of calender 2016.
During the fall of 2014, post-reversion, the operator initiated work on expansion of the CO2 flood in the undeveloped eastern part of the field. These operations were suspended last fall when the operator made significant cuts in its capital budget as a result of declining oil prices. While we believe that 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 very favorable economics, even in this lower price environment, we expect the expansion of the CO2 flood to resume within the next 2-3 years. The economics of expansion will also be improved subsequent to the completion of the NGL recovery plant.
One of the three remaining development phases, part of which lies under the town of Delhi (population approximately 3,000), has been deferred by the operator. The reserves in this phase were reclassified last year from proved to probable. There are also probable reserves associated with three smaller reservoirs within the Unit in similar formations with similar production history that we expect to be developed as an additional phase of the EOR project early in the next decade. Since such development is currently more than five years from now, these reserves are wholly classified as Probable, in accordance with SEC guidelines.

Artificial Lift Technology (GARP®)
Our artificial lift technology registered as GARP® (Gas Assisted Rod Pump) was developed internally by our 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.

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. One well subsequently ceased oil production when an offset well was hydraulically fractured and the water migrated to our well bore. During fiscal 2014, we entered into a commercial agreement to install our technology on at least five wells in the Giddings Field. Three installations were completed as of the end of fiscal 2014, two of which were successful in increasing production and the balance were unsuccessful due to well bore conditions. During fiscal 2015, we completed installation of our artificial lift technology in an additional two 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.

We are in discussions with multiple industry operators to further expand the business to other fields during fiscal 2016 and have entered into master service agreements with four companies for potential deployment in the Eagle Ford, Barnett and Permian fields located in Texas. With continued success and industry acceptance, we believe GARP® could be applicable to a large number of horizontal and vertical wells worldwide. However, in the current low commodity price environment and reduced capital spending, the timing for commercial success has been slower than previously anticipated.


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Based on our production history, DeGolyer & MacNaughton assigned proved reserves of 33 MBOE to three GARP® installations that we operate with PV-10 of $0.4 million. Certain of our third party technology fees, though based on a percentage of net profits from the wells, will generally not result in the assignment of reserves by our petroleum engineers, as we do not own direct mineral interests in the wells.
Other Projects
Giddings Field—Central Texas
We began leasing activities in the Giddings Field in December 2006. In late calendar 2007, we initiated a redevelopment drilling program in the Giddings Field targeting the Austin Chalk and Georgetown formations. During fiscal 2013, we began and completed a series of sale transactions that monetized all of our non-GARP® producing wells and drilling locations.
We retained a 3-5% overriding royalty interest on 2,094 acres on all depths below the base of the Austin Chalk in Brazos, Burleson and Fayette Counties, Texas for the remaining lives of related leases, as extended. We also retained overriding royalty interests of approximately 5% in 900 net acres in the Woodbine formation and a 15% back-in working interest on approximately 258 net acres in Grimes County, Texas. We do not expect to assign any reserves to these residual interests until such time as there are successful drilling results.
Lopez Field—South Texas
We acquired leases covering approximately 782 net acres in the Lopez Field in South Texas as a first effort to test the concept of redeveloping old oil fields utilizing high flow rate production. While our development activity in the Lopez Field confirmed our concept and the potential for developing material oil reserves, the time and effort required to 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, the Sneath #1-24 and the Hendrickson #1-1. While both wells produced at the fluid rates expected, the quantities of oil and gas were far less than expected. We subsequently reworked both wells to test the role of structure in production, and 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 accepting terms under the Delhi operator's agreement with Plains Marketing LP for the delivery and pricing of our oil there. The oil from Delhi is currently transported from the field by pipeline, which results in better net pricing than the alternative of transportation by truck. 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 price differential was approximately $4.00 per barrel during our fiscal year ended June 30, 2015. The differential has narrowed from past years, but we expect that a positive LLS price differential will continue, at least in the near future.
Since 2008, we had been selling crude oil from our Giddings properties (which includes our GARP® wells) to Enterprise Crude Oil LLC, a crude oil gathering, transportation, storage and marketing company. Our agreements with Enterprise Crude Oil LLC are under a normal "evergreen" sales contracts with a thirty day cancellation provision. In June 2014, we began selling crude oil from our Giddings properties to Sunoco Partners. Oil production from our Lopez Field was sold to Flint Hill Resources. We believe that other crude oil purchasers are readily available.
We sold our natural gas and natural gas liquids from our properties in the Giddings Field under the terms of normal evergreen sales contracts at competitive prices with DCP Midstream, LP, and ETC Texas Pipeline, LTD. Gas sold to DCP and ETC was processed for removal of natural gas liquids, and we received the proceeds from the sale of the NGL products less a

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fee and certain operating expenses. We have no other business relationships with our crude oil, natural gas or natural gas liquids purchasers.
The following table sets forth purchasers of our oil and natural gas production for the years indicated:
 
Year Ended June 30,
Customer
2015
 
2014
 
2013
Plains Marketing L.P. (includes Delhi production)
99
%
 
96
%
 
90
%
Enterprise Crude Oil LLC
%
 
2
%
 
4
%
Flint Hills
%
 
1
%
 
2
%
ETC Texas Pipeline, LTD. 
%
 
1
%
 
%
All others
1
%
 
%
 
4
%
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 is influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, market prices, government regulation and actions of major foreign producers.
Over the past 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 in 2015, 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, 2500 City West Blvd, Suite 1300, Houston, Texas 77042, or calling (713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a 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 heavily 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 $108 per barrel to a low of $44 per barrel during our fiscal year ending June 30, 2015. 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 80% of our proved reserves at June 30, 2015 are crude oil reserves and 20% 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. In addition, our production will be impacted by the results of wells in which we have installed our GARP® technology and any future installations in which we are compensated with production or its equivalent. Although EOR production from proved reserves at Delhi has and is expected to grow over time and we expect to grow the number of GARP® installations, environmental or operating problems or lack of future investment at Delhi, lack of success in adding GARP® installations or a change in our GARP® compensation model without further development activities in new or existing projects or without acquisitions of producing properties, our net production of oil and natural gas could decline significantly over time, which could have a material adverse effect on our financial condition.
We have limited control over the activities on properties we do not operate.
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.
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.
The existing well bores in which we are installing GARP® were originally drilled years or decades earlier. As such, they contain older casing or debris that could be more subject to failure, or the well files, if available, may be incomplete or incorrect. Such problems can result in the complete loss of a well or much higher costs. Expected results are based on theoretical estimates using historical data, which may not be complete or accurate, and thus such estimates may not prove accurate. Terms of compensation for installing GARP® may well change over time based on results achieved, industry acceptance, marketing efforts and other factors.

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Our projects generally require that we acquire new leases in and around established fields or other known resources, and drill and complete wells, some of which may be horizontal, as well as negotiate the purchase of existing well bores and production equipment or install our proprietary artificial lift technology that has yet to be universally proven. Leases may not be available and required oil field services may not be obtainable on the desired schedule or at the expected costs. While the projected drilling results may be considered to be low to moderate in risk, there is no assurance as to what productive results may be obtained, if any.
Crude oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production and drilling and completing new wells are speculative activities and involve numerous risks and substantial uncertain costs.
Our growth will be materially dependent upon the success of our future development program. Drilling for crude oil and natural gas and re-working existing wells involve numerous risks, including the risk that no commercially productive crude oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:
unexpected drilling conditions;
pressure fluctuations or irregularities in formations;
equipment failures or accidents;
environmental events;
inability to obtain or maintain leases on economic terms, where applicable;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.
Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion techniques such as 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.
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, 2015, 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 patented GARP® technology may not achieve acceptance or widespread adoption by industry.
We have developed, field tested and initiated commercialization of our artificial lift technology, GARP® (Gas Assisted Rod Pump), though it may not generate substantial value. Our further success in commercializing the technology will depend upon additional positive field tests, additional customers, acceptance by industry and our ability to defend the technology from competitors through confidentiality, trade secret and patent protection.
We may be unable to continue licensing from third parties the technologies that we use in our business operations.
As is customary in the crude oil and natural gas industry, we utilize a variety of widely available technologies in the crude oil and natural gas development and drilling process. We do not have any patents or copyrights for the technology we currently utilize, except for the registered trademark and issued patent on our GARP® artificial lift technology that is in the process of commercialization. We generally license or purchase services from the holders of such technology, or outsource the technology integral to our business from third parties. Our commercial success will depend in part on these sources of

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technology and assumes that such sources will not infringe on the proprietary rights of others. We cannot be certain whether any third-party patents will require us to utilize or develop alternative technology or to alter our business plan, obtain additional licenses, or cease activities that infringe on third-parties' intellectual property rights. Our inability to acquire any third-party licenses, or to integrate the related third-party products into our business plan, could result in delays in development unless and until equivalent products can be identified, licensed, and integrated. Existing or future licenses may not continue to be available to us on commercially reasonable terms or at all. Litigation, which could result in substantial cost to us, may be necessary to enforce any patents licensed to us or to determine the scope and validity of third-party obligations or to protect our patent rights on GARP®.
Our crude oil and natural gas reserves are only estimates and may prove to be inaccurate.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. Our reserves are only estimates that may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors, such as historical production from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas product prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from prepared by different engineers or by the same engineers but at different times, may vary substantially.
Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the crude oil and natural gas industry in general. PV-10 does not necessarily correspond to market value.
Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.
We review on a periodic basis the carrying value of our crude oil and natural gas properties under the applicable rules of the various regulatory agencies, including the SEC. Under the full cost method of accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this "ceiling" test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write down of the carrying value for accounting purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our crude oil and natural gas properties when crude oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will depend in part on the prices for crude oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period. If a write down is required, it would result in a current charge to our earnings but would not impact our current cash flow from operating activities.

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 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:


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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 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

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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:

diversion of management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
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.
For example, currently proposed federal legislation, that, if adopted, could adversely affect our business, financial condition and results of operations, includes the following:
Taxes.  President Obama’s budget proposal for fiscal year 2016 recommended the elimination of certain key United States federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities for oil and gas production, and (iv) the extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes or similar changes will be enacted or, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and gas exploration and production. Any such changes could have an adverse effect on our financial position, results of operations and cash flows; and
 

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Hydraulic Fracturing.  The U.S. Congress, the EPA and various states are currently considering legislation that could adversely affect the use of the hydraulic-fracturing process. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. Any proposed legislation, if adopted, could establish an additional level of regulation, permitting and restrictions at the federal level that could adversely affect the development of unconventional oil and natural gas resources.
Our insurance may not protect us against all of the operating risks to which our business is exposed.
The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, hurricanes, flooding, pollution, releases of toxic gas and other environmental hazards and risks, which can result in (i) damage to or destruction of wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or (v) damage to property, the environment or natural resources. While we carry general liability, control of well, and operator's extra expense coverage typical in our industry, we are not fully insured against all risks incident to our business. Environmental events similar to that experienced in the Delhi field in June 2013 could defer revenue, increase operating costs and maintenance capital expenditures.
The loss of key personnel could adversely affect us.
We depend to a large extent on the services of certain key management personnel, including our executive officers, the loss of any of whom could have a material adverse effect on our operations. In particular, our future success is dependent upon Robert S. Herlin, our Chairman and Chief Executive Officer, Randall D. Keys, our President, Chief Financial Officer and Treasurer, and Daryl V. Mazzanti, our Senior Vice President of Operations, for sourcing, evaluating and closing deals, capital raising, and oversight of development and operations. Presently, the Company is not a beneficiary of any key man insurance.
Oil field service and materials' prices may increase, and the availability of such services and materials may be inadequate to meet our needs.
Our business plan to develop or redevelop crude oil and natural gas resources requires third party oilfield service vendors and various material providers, which we do not control. We also rely on third-party carriers for the transportation and distribution of our production. As our production increases, so does our need for such services and materials. Generally, we do not have long-term agreements with our service and materials providers. Accordingly, there is a risk that any of our service providers could discontinue servicing our crude oil and natural gas fields for any reason or we may not be able to source the materials we need. Any delay in locating, establishing relationships, and training our sources could result in production shortages and maintenance problems, with a resulting loss of revenue to us. In addition, if costs for such services and materials increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may have assumed when deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelop plans.
We cannot market the crude oil and natural gas that we produce without the assistance of third parties.
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.

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We are, and in the future may become, involved in legal proceedings related to our Delhi interest or other properties or operations and, as a result, may incur substantial costs in connection with those proceedings.
In December 2013 we filed a lawsuit against the operator of the Delhi field alleging that the operator improperly charged the payout account for capital expenditures and costs of capital, failed to adhere to preferential rights to participate in acquisitions within the defined area of mutual interest, breached the promises to assume environmental liabilities and fully indemnify us from such costs, and other breaches. We are seeking declaration of the validity of the 2006 agreements and recovery of damages and attorneys’ fees. The operator subsequently filed counterclaims, including the assertion that we owed it additional revenue interests pursuant to the 2006 agreements and that the transfer of our reversionary working interest from our wholly owned subsidiary to our parent corporation and subsequently to another wholly owned subsidiary breached their preferential right to purchase. We have denied their counterclaims as being without merit and not timely. We may incur significant legal costs in this matter and the outcome is uncertain.
Ownership of our oil, gas and mineral production depends on good title to our property.
Good and clear title to our oil, gas and mineral properties is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, gas and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim which could result in a reduction or elimination of the revenue received by us from such properties.
Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.
During the last few years, concerns over inflation, energy costs, 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 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 is relatively thinly traded and the market price has been, and is likely to continue to be, volatile. For example, during the fiscal year ending June 30, 2015, our stock price as traded on the NYSE MKT ranged from $5.68 to $11.19. The variance in our stock price makes it difficult to forecast with any certainty the stock price at which an investor may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as:
actual or anticipated variations in our results of operations;
naked short selling of our common stock and stock price manipulation;
changes or fluctuations in the commodity prices of crude oil and natural gas;
general conditions and trends in the crude oil and natural gas industry;
redemption demands on institutional funds that hold our stock; and
general economic, political and market conditions.
Our executive officers, directors and affiliates may be able to control the election of our directors and all other matters submitted to our stockholders for approval.
Our executive officers and directors, in the aggregate, beneficially own approximately 3.2 million shares, or approximately 10% of our beneficial common stock base. JVL Advisors LLC controls approximately 4.9 million shares or approximately 15% of our outstanding common stock. As a result, these holders could exercise significant influence over matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.

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The market for our common stock is limited and may not provide adequate liquidity.
Our common stock is relatively thinly traded on the NYSE MKT. In the fiscal year ending June 30, 2015, the actual daily trading volume in our common stock ranged from 20,800 shares of common stock to a high of 759,200 shares of common stock traded. 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 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, 2015. 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.

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For example, higher market interest rates could cause the market price of the Series A Preferred Stock to decrease.
We could be prevented from paying dividends on our Series A Preferred Stock.
Although dividends on the Series A Preferred Stock are cumulative and arrearages will accrue until paid, preferred stockholders will only receive cash dividends on the Series A Preferred Stock if we have funds legally available for the payment of dividends and such payment is not restricted or prohibited by law, the terms of any senior shares or any documents governing our indebtedness. Our business may not generate sufficient cash flow from operations to enable us to pay dividends on the Series A Preferred Stock when payable. In addition, existing or future debt, credit facility arrangements, contractual covenants or arrangements we enter into may restrict or prevent future dividend payments. Accordingly, there is no guarantee that we will be able to pay any cash dividends on our Series A Preferred Stock.
Furthermore, in some circumstances, we may pay dividends in stock rather than cash, and our stock price may be depressed at such time.
Our Series A Preferred Stock has not been rated and will be subordinated to all of our existing and future debt.
Our Series A Preferred Stock has not been rated by any nationally recognized statistical rating organization. In addition, with respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock will be subordinated to any existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock. We may also incur additional indebtedness in the future to finance potential acquisitions or the development of new properties and the terms of the Series A Preferred Stock do not require us to obtain the approval of the holders of the Series A Preferred Stock prior to incurring additional indebtedness. As a result, our existing and future indebtedness may be subject to restrictive covenants or other provisions that may prevent or otherwise limit our ability to make dividend or liquidation payments on our Series A Preferred Stock. Upon our liquidation, our obligations to our creditors would rank senior to our Series A Preferred Stock and would be required to be paid before any payments could be made to holders of our Series A Preferred Stock.
We could be prevented from continuing to pay dividends on our Common Stock.
Our board of directors declared 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
Company Location
Our corporate headquarters are located at 2500 CityWest Boulevard, Suite 1300, Houston, Texas. We entered into a sublease agreement, effective on March 1, 2007, to rent approximately 8,400 square feet of Class "A" office space in the Westchase District area in West Houston. The current monthly base rent is $13,251, having escalated from a monthly base rate of $11,507 in August 2011. The sublease expires by its term on July 31, 2016.
Oil & Gas Properties
Additional detailed information describing the types of properties we own can be found in "Business Strategy" under Item 1. Business of this Form 10-K.
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues
The SEC sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These rules require disclosure of oil and gas proved reserves by significant geographic area, using the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve

15

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volumes. Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.
There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.
Estimates of Probable and Possible reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves but which, together with Proved reserves, are as likely as not to be recovered. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of Probable and Possible reserves are by their nature much more speculative than estimates of Proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. 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 not are meaningfully combined.
Estimated future net revenues discounted at 10% or PV-10 is a financial measure that is not recognized by GAAP. We believe that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by analysts and investors in evaluating oil and natural gas companies, and that it is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. Further, analysts and investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. We also use this pre-tax measure when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled herein.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2015
Our proved and probable reserves at June 30, 2015, denominated in equivalent barrels using six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio, were estimated by our independent petroleum engineer, DeGolyer and MacNaughton ("D&M"). D&M was selected for our interests in the Delhi Field due to their expertise in CO2-EOR projects and to ensure consistency with the operator who has utilized D&M for their reserves estimates in the Delhi Field. We also chose to have D&M estimate our Giddings properties beginning in 2014 in order to simplify and consolidate our reserve reporting. D&M has significant expertise in this region as well. The scope and results of their procedures are summarized in a letter from the firm, which is included as exhibit 99.4 to this Annual Report on Form 10-K.
The following table sets forth our estimated proved and probable reserves as of June 30, 2015. See Note 22 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 $71.88 per barrel of crude oil and $3.44 per MMbtu of natural gas. The price of natural gas liquids was based on the historical price received, if no historical received price is available, historical pricing in the area. Pricing differentials were applied to all properties, on an individual property basis. Quality adjustments have been applied based on actual BTU factors for each well and a shrinkage factor has been applied based on production volumes versus actual sales volumes.

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June 30, 2015
Reserve Category
Oil
(MBbls)
 
NGLs
(MBbls)
 
Natural Gas
(MMcf)
 
Total Reserves
(MBOE)
 
PV-10
PROVED
 
 
 
 
 
 
 
 
 
Developed (59% of Proved)
7,347

 
2

 
5

 
7,350

 
$
189,212,263

Undeveloped (41% of Proved)
2,665

 
2,432

 

 
5,096

 
29,494,234

TOTAL PROVED
10,012

 
2,434

 
5

 
12,446

 
$
218,706,497

Product Mix
80
%
 
20
%
 
%
 
100
%
 
 
PROBABLE
 
 
 
 
 
 
 
 
 
Developed (43% of Probable)
4,034

 

 

 
4,034

 
$
38,266,787

Undeveloped (57% of Probable)
3,376

 
1,929

 

 
5,305

 
34,029,936

TOTAL PROBABLE
7,410

 
1,929

 

 
9,339

 
$
72,296,723

Product Mix
79
%
 
21
%
 
%
 
100
%
 
 
POSSIBLE
 
 
 
 
 
 
 
 
 
Developed (55% of Possible)
1,625

 

 

 
1,625

 
$
9,108,736

Undeveloped (45% of Possible)
730

 
599

 

 
1,329

 
4,526,868

TOTAL POSSIBLE
2,355

 
599

 

 
2,954

 
$
13,635,604

Product Mix
80
%
 
20
%
 
%
 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
The following tables present a reconciliation of changes in our proved and probable reserves by major property, on the basis of equivalent MBOE quantities.
Reconciliation of Changes in Proved Reserves by Major Property
 
Delhi
Field
 
Giddings
Field
 
Proved
Total
Proved reserves, MBOE
 MBOE
 
 MBOE
 
 MBOE
June 30, 2014
13,117.4

 
172.1

 
13,289.5

Production
(448.2
)
 
(4.6
)
 
(452.8
)
Revisions
(255.4
)
 
(134.9
)
 
(390.3
)
Sales of minerals in place

 

 

Improved recovery, extensions and discoveries

 

 

June 30, 2015
12,413.8

 
32.6

 
12,446.4

Reconciliation of Changes in Probable Reserves by Major Property
 
Delhi
Field
 
Giddings
Field
 
Probable
Total
Probable reserves, MBOE
 MBOE
 
 MBOE
 
 MBOE
June 30, 2014
9,466.9

 

 
9,466.9

Revisions
(127.5
)
 

 
(127.5
)
Sales of minerals in place

 

 

Improved recovery, extensions and discoveries

 

 

June 30, 2015
9,339.4

 

 
9,339.4


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 22 of the consolidated financial statements.

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For the Years Ended June 30,
 
2015
 
2014
Estimated future net revenues
$
448,113,943

 
$
671,972,966

10% annual discount for estimated timing of future cash flows
229,407,446

 
352,227,569

Estimated future net revenues discounted at 10% (PV-10)
218,706,497

 
319,745,397

Estimated future income tax expenses discounted at 10%
(59,509,958
)
 
(93,667,725
)
Standardized Measure
$
159,196,539

 
$
226,077,672


The following table provides a reconciliation of PV-10 of each of our proved properties to the Standardized Measure as shown in Note 22 of the consolidated financial statements.
 
For the Years Ended June 30,
 
2015
 
2014
Delhi Field
$
218,320,579

 
$
318,076,654

Giddings Field
385,918

 
1,668,743

Estimated future net revenues discounted at 10% (PV-10)
$
218,706,497

 
$
319,745,397

Estimated future income tax expenses discounted at 10%
(59,509,958
)
 
(93,667,725
)
Standardized Measure
$
159,196,539

 
$
226,077,672

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

Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company's Overall Reserve Estimation Process
Our policies regarding internal controls over reserve estimates require reserves to be prepared by an independent engineering firm under the supervision of our Chief Executive Officer and Senior Vice President of Operations and to be in compliance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. Our Chief Executive Officer 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 Senior Vice President of Operations has over 25 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 firm Senior Vice President. He holds a Bachelor of Science degree in Petroleum Engineering awarded in 1974 from Texas A&M University and has over 40 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 Vice President of Operations and our Chief Executive Officer to ensure accuracy and completeness of the data prior to submission to our independent engineering firm. The scope and results of our independent engineering firm's procedures, as well as their professional qualifications, are summarized in the letter included as exhibit 99.4 to this Annual Report on Form 10-K.
Proved Undeveloped Reserves
Our proved undeveloped reserves were 5,097 MBOE at June 30, 2015 with associated future development costs of approximately $47.6 million. The 222 MBOE decrease in proved undeveloped reserves from 5,319 MBOE as of June 30, 2014 is primarily due to re-designing the gas plant and the economic decision to consume recovered natural gas internally to lower Delhi Field lease operating expense instead of selling to third parties resulting in a 404 MBOE natural gas reserve decrease partially offset by a 185 MBOE increase from better NGL recovery.
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 59% developed as of June 30, 2015. However, as a result of the adverse fluid release event in the field in June 2013 and the resultant delay in reversion of our working interest, the full development of the

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field is now planned to continue over next four 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 addition of the gas plant to recover natural gas liquids and methane has required additional planning and has resulted in a prudent delay in the full development of the field. 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 have established and continue to follow the previously adopted development plan for this project; (2) we have significant ongoing development activities at this project and (3) the operator has a historical record of completing the development of comparable long-term projects.
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, 2015
 
Year Ended 
 June 30, 2014
 
Year Ended 
 June 30, 2013
Product
Volume
 
Price
 
Volume
 
Price
 
Volume
 
Price
Crude oil (Bbls)
450,713

 
$
61.59

 
169,783

 
$
102.84

 
196,379

 
$
105.34

Natural gas liquids (Bbls)
1,358

 
$
27.43

 
3,516

 
$
33.32

 
7,272

 
$
34.81

Natural gas (Mcf)
7,981

 
$
3.33

 
26,655

 
$
3.60

 
139,006

 
$
2.95

Average price per BOE*
453,401

 
$
61.37

 
177,742

 
$
99.43

 
226,819

 
$
94.13

 
 
 
 
 
 
 
 
 
 
 
 
Production costs
Amount
 
per BOE
 
Amount
 
per BOE
 
Amount
 
per BOE
Production costs, excluding ad valorem and production taxes
$
9,321,271

 
$
20.56

 
$
1,156,011

 
$
6.50

 
$
1,713,833

 
$
7.56

Total production costs, including ad valorem and production taxes
$
9,335,244

 
$
20.59

 
$
1,193,573

 
$
6.72

 
$
1,780,738

 
$
7.85

* BOE computed on units of production using a six to one conversion ratio of MCF's to barrels.
Drilling Activity
The following table sets forth our drilling activity during the past three fiscal years. During fiscal year 2015 and 2014, we did not drill any new wells. During fiscal 2013, we completed 2 gross and 0.8 net wells in Kay County, Oklahoma.
 
Year Ended June 30,
 
2015
 
2014
 
2013
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Productive wells drilled
 
 
 
 
 
 
 
 
 
 
 
Development

 

 

 

 

 

Exploratory

 

 

 

 
2.0

 
0.8

Total

 

 

 

 
2.0

 
0.8

Nonproductive dry wells drilled
 
 
 
 
 
 
 
 
 
 
 
Development

 

 

 

 
1.0

 
0.2

Exploratory

 

 

 

 

 

Total

 

 

 

 
1.0

 
0.2

Present Activities
During fiscal year 2015, we jointly commenced, with the field operator, the construction of a natural gas liquids ("NGL") recovery plant 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.
During fiscal year 2015, we plugged and abandoned three legacy wells in the Giddings Field that had been shut-in in past years.

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Table of Contents

For further discussion, see "Highlights for our fiscal year 2015" 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, 2015, we are not committed to provide a fixed and determinable quantity of oil, NGLs or gas under existing agreements.
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, 2015.    
 
Company Operated
 
Non-Operated
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Crude oil
3

 
2.9

 
86

 
20.6

 
89

 
23.5

Natural gas

 

 

 

 

 

Total
3

 
2.9

 
86

 
20.6

 
89

 
23.5

Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2015. 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*
13,636

 
3,257

 

 

 
13,636

 
3,257

Giddings Field, Texas**
2,168

 
2,134

 

 

 
2,168

 
2,134

Total
15,804

 
5,391

 

 

 
15,804

 
5,391

Our developed acreage includes 13,636 gross (3,257 net) acres in Delhi field, which is being developed using CO2-EOR operations. We own a 23.9% working interest and a 7.4% royalty interest, combined this results in a 26.4% net revenue interest in Delhi. 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, 99% working interest in one well subject to a back-in reversion of 22.5%.
*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.
**Excludes acreage for 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 17—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.


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Table of Contents

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, 2015 and 2014, the high and low sales prices for EPM as reported by the NYSE MKT.
NYSE MKT: EPM
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


2014:
High
 
Low
Fourth quarter ended June 30, 2014
$
13.15

 
$
9.92

Third quarter ended March 31, 2014
$
13.83

 
$
11.56

Second quarter ended December 31, 2013
$
12.77

 
$
11.01

First quarter ended September 30, 2013
$
12.59

 
$
10.68


Shares Outstanding and Holders
As of June 30, 2015, there were 32,845,205 shares of common stock issued and outstanding, held by approximately 222 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, 2015, we had paid seven 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, an existing loan balance and/or letter of credit commitment would restrict our ability to pay common stock dividends.
Performance Graph
The following graph presents a comparison of the yearly percentage change in the cumulative total return on our Common Stock over the period from June 30, 2010 to June 30, 2015 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, 2010 in our common stock at the closing market price at the beginning of this period and in each of the other two indices and the reinvestment of all dividends, if any. The graph is presented in accordance with requirements of the SEC. Shareholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.

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Securities Authorized For Issuance Under Equity Compensation Plans
Plan category
Number of
securities to
be issued
upon exercise
of outstanding
options,
warrants and
rights
(a)
 
 
 
Weighted-average
exercise
price of
outstanding
Options, warrants
and rights
(b)
 
Number of securities
remaining
available for future
issuance under
equity compensation
plans (excluding
securities reflected
in column (a))(1)
Equity compensation plans approved by security holders:
 
 
 
 
 
 
 
    Outstanding options
91,061

 
(1)
 
$
2.50

 
 
    Outstanding contingent rights to shares
56,286

 
(1)
 

 
 
  Total
147,347

 
 
 
$
1.55

 
542,529

Equity compensation plans not approved by security holders

 
 
 

 

Total
147,347

 
 
 
$
1.55

 
542,529


(1)
As of June 30, 2015, there were 91,061 shares of common stock issuable upon exercise of outstanding stock options. The Amended and Restated 2004 Stock Plan (the "Plan") provides for the issuance of a total of 6,500,000 common shares. Under the Plan as of June 30, 2015, 3,854,134 common shares had been issued upon the exercise of stock options, 1,955,990 shares of restricted common stock had been issued (of which 262,227 were unvested as of June 30, 2015), contingent rights for 56,286 shares had been reserved but not issued (all of which are unvested) and 542,529 shares of common stock remain available for future grants.


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Table of Contents

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, 2015 to April 30, 2015
none
 

 
 
May 1, 2015 to May 31, 2015
none
 

 
 
June 1, 2015 to June 30, 2015
64,126 shares of Common Stock
 
$6.87
 
63,372
 
Approximately $4.6 million

(1)
During the fourth fiscal quarter ended June 30, 2015, the Company received 754 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)
On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. 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.

23

Table of Contents

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,
 
2015
 
2014
 
2013
 
2012
 
2011
Income Statement Data
 
 
 
 
 
 
 
 
 
Revenues
$
27,841,265

 
$
17,673,508

 
$
21,349,920

 
$
17,962,038

 
$
7,530,875

Production costs - Delhi field
8,516,323

 

 

 

 

Artificial lift technology costs
743,802

 
609,221

 
390,238

 
124,703

 

Production costs - other properties
95,488

 
584,352

 
1,390,500

 
1,650,296

 
1,379,327

Depreciation, depletion, and amortization
3,615,737

 
1,228,685

 
1,300,207

 
1,136,974

 
563,104

Accretion expense
34,866

 
41,626

 
72,312

 
77,505

 
59,913

General and administrative expense
6,256,783

 
8,388,291

 
7,495,309

 
6,143,286

 
5,335,384

Restructuring charges
(5,431
)
 
1,293,186

 

 

 

Income from operations
8,583,697

 
5,528,147

 
10,701,354

 
8,829,274

 
193,147

Other income (expense)
(147,619
)
 
(38,836
)
 
(43,165
)
 
3,778

 
14,214

Income tax provision
3,444,221

 
1,891,998

 
4,029,761

 
3,700,922

 
448,914

Net income (loss) attributable to the Company
$
4,991,857

 
$
3,597,313

 
$
6,628,428

 
$
5,132,130

 
$
(241,553
)
Dividends on Series A Preferred Stock
674,302

 
674,302

 
674,302

 
630,391

 

Net income (loss) attributable to common shareholders
$
4,317,555

 
$
2,923,011

 
$
5,954,126

 
$
4,501,739

 
$
(241,553
)
Earnings per common share:
 
 
 
 
 
 
 
 
 
Basic
$
0.13

 
$
0.09

 
$
0.21

 
$
0.16

 
$
(0.01
)
Diluted
$
0.13

 
$
0.09

 
$
0.19

 
$
0.14

 
$
(0.01
)

 
June 30, 2015
 
June 30, 2014
 
June 30, 2013
 
June 30, 2012
 
June 30, 2011
Balance Sheet Data
 
 
 
 
 
 
 
 
 
Total current assets
$
23,693,048

 
$
26,304,803

 
$
27,436,076

 
$
16,769,789

 
$
6,357,840

Total assets
69,882,727

 
65,015,752

 
66,556,296

 
58,955,486

 
39,951,953

Total current liabilities
9,329,257

 
2,999,726

 
2,632,750

 
5,088,917

 
2,211,932

Total liabilities
21,306,150

 
13,138,230

 
11,720,135

 
12,332,698

 
6,487,196

Stockholders' equity
48,576,577

 
51,877,522

 
54,836,161

 
46,622,788

 
33,464,757

 
 
 
 
 
 
 
 
 
 
Number of common shares outstanding
32,845,205

 
32,615,646

 
28,608,969

 
27,882,224

 
27,612,916


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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview
General
We are engaged primarily in the development of oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional and proprietary technology. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain control of our assets for the benefit of our shareholders, including a substantial ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership of our common stock.
Our strategy is to grow the value of our Delhi asset to maximize the value realized by our shareholders while commercializing our patented GARP® artificial lift technology for recovering incremental oil and gas reserves. In addition, we plan to return cash to the shareholders in the form of a quarterly cash dividend and also stock buybacks under our previously announced share repurchase program.
We expect to fund our fiscal 2016 capital program from working capital and net cash flows from our properties.
Highlights for our fiscal year 2015
Finances
We remained debt free.  All of our 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 $10.5 million to shareholders in the form of cash dividends during fiscal 2015. We paid a total of $9.8 million in common stock dividends and $0.7 million in preferred stock dividends in fiscal year 2015.
We initiated a stock buyback program. We have authorized the purchase of as much as $5.0 million of our common stock under this program.
Working capital was $14.3 million at June 30, 2015 compared to $23.3 million at the prior year end. At June 30, 2015, working capital included $20.1 million of cash on hand.
We entered into hedges for approximately two-thirds of our oil production for the six month period ending December 31, 2015. As of June 30, 2015, we recorded a loss of $109,974 to reflect our derivative position at its then current market value. Based on a subsequent decline in oil prices, we realized gains of $138,787 and $412,985, for July 2015 and August 2015, respectively, for expiring derivative contacts. These derivatives have allowed us to receive the WTI equivalent of approximately $55.00 per barrel for the hedge quantities sold during these periods.
Operations
Our net oil production volumes at Delhi increased by over 173% year over year. Monthly production has been steadily increasing since October 2014 as a result of a production optimization program and the replacement of a well which had experienced mechanical problems. 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. Combined with our existing royalty and mineral interests of 7.4%, our total net revenue interest in the Delhi field is 26.4%.

We approved AFEs to commence the construction of a NGL recovery plant at Delhi. The gross total costs of the project is $103 million. Our net share of capital expenditures for this project is $24.6 million, and is expected to be funded through cash flow from operations and working capital.

Our fiscal 2015 net income to common shareholders was $4.3 million, a 48% increase from fiscal 2014 net income of $2.9 million. During fiscal 2015, increased Delhi revenues and lower general & administrative expenses led to significantly higher net income, offset in part by increased DD&A expenses and higher income tax expense. This is our fourth consecutive year of reporting net income to common shareholders.

Total revenues in fiscal 2015 were $27.8 million, a 57% increase from $17.7 million in fiscal 2014. During fiscal 2015, reversion of our working interest at Delhi in November 2014 contributed substantially to annual revenues, offset by lower realized oil prices at Delhi and a decrease in artificial lift technology revenues year over year.

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Oil & Gas Reserves
Delhi proved oil equivalent reserves at June 30, 2015 decreased to 12.4 MMBOE, a 5% decline from the previous year and corresponding PV-10* declined to $219 million, 32% lower than prior year. Proved reserves are 80% oil and 20% natural gas liquids, and 59% of these reserves are developed and producing.
Delhi probable reserves at June 30, 2015 decreased to 9.3 MMBOE, a 1% decrease over the previous year and corresponding PV-10* decreased to $72 million, 47% lower than prior year.
Reserve Life Index** for proved oil reserves at Delhi is approximately 17 years.
The following table is a summary of our proved and probable reserves for 2015 and 2014:
 
Proved
 
 
 
Probable
 
 
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
Reserves MMBOE
12.4

 
13.3

 
(6.8
)%
 
9.3

 
9.5

 
(2.1
)%
% Developed
59
%
 
60
%
 
(1.7
)%
 
43
%
 
43
%
 
 %
Liquids %
100
%
 
96
%
 
4.2
 %
 
100
%
 
97
%
 
3.1
 %
PV-10* ($MM)
$
219

 
$
320

 
(31.6
)%
 
$
72

 
$
136

 
(47.1
)%
_______________________________________________________________________________

*
PV-10 of Proved reserves is a pre-tax non-GAAP measure. We have included a reconciliation of PV-10 to the unaudited after-tax Standardized Measure of Discounted Future Net Cash Flows, which is the most directly comparable financial measure calculated in accordance with GAAP, in Item 2. "Properties." We believe that the presentation of the non-GAAP financial measure of PV-10 provides useful and relevant information to investors because of its wide use by analysts and investors in evaluating the relative monetary significance of oil and natural gas properties, and as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. We also use this pre-tax measure when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled below. Probable and Possible reserves are not recognized by GAAP, and therefore the PV-10 of Probable and Possible reserves cannot be reconciled to a GAAP measure.
** Reserve Life Index is a relative measure of the average life of a Company’s reserves calculated as the remaining reserves divided by the current rate of production. In our calculation we have used total Proved oil reserves divided by expected oil production in the first 12 months of the reserve report, calculated on a gross basis. Natural gas and NGL reserves and production were not considered material or relevant for the purpose of this calculation as they are currently undeveloped. We believe that this measure is relevant to understanding and analyzing our reserve base and is useful to investors and analysts in comparing our company to others in the industry. This measure is not an absolute measure of the expected life of our reserves, nor is it intended to convey information about any specific event or time in the future.
Projects
Additional property and project information is included under Item 1. Business, Item 2. Properties, Item 8. Financial Statements - Notes to the Financial Statements and Exhibit 99.4 of this Form 10-K.
Delhi Field EOR—Northeast Louisiana
Our reserves quantities in the Delhi Field were consistent with expectations year over year. Positive revisions in recoveries of NGLs were offset by production from the prior year and plans to more economically utilize our methane reserves to generate power in the field, thereby reducing operating costs, rather than sell them into the market. The reserves report reflects the November 2014 reversion of our 23.9% working interest, together with our 7.4% overriding royalty and mineral interests in the field.

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Proved reserves volumes totaled 12.4 MMBOE compared to 13.3 MMBOE in the prior year. Prior year proved reserves included 0.5 MMBOE of methane to be produced from the NGL plant currently under development, whereas our current reserves exclude methane volumes and instead account for the methane as contributing to lower projected operating costs through use as fuel. Our PV-10* value of $219 million was consistent with our expectations in this lower price environment. We receive favorable Light Louisiana Sweet crude oil pricing in the field, which continues to trade at a premium to WTI, as well as low pipeline transportation costs to get our production to market.
Additionally, 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 sales from the field, so this major operating cost has dropped commensurate with the price of crude. We have also seen reductions in other field operating costs as the operator has focused on initiatives to lower field operating expenses.
Probable reserve volumes at Delhi were 9.3 MMBOE, compared to 9.5 MMBOE in the prior year that included 0.3 MMBOE of methane. Possible reserves volumes at Delhi of 3.0 MMBOE were virtually flat compared to the prior year. In both cases, other positive adjustments substantially offset the reduction in natural gas reserves from the revised plans to utilize this gas for power generation.
Gross production at Delhi in the fourth quarter of fiscal 2015 was 6,328 barrels of oil per day (“BOPD”), up 2% from the third fiscal quarter’s 6,203 BOPD. Production volumes net to the Company were 1,677 BOPD and 1,644 BOPD, respectively. We expect production from the field to average in excess of 6,000 BOPD until we add the additional volumes from the NGL plant in the second half of calendar 2016 and complete the roll-out of the remaining CO2 projects in subsequent years. We expect production growth to continue well into the next decade.
The plans and purchases for construction of the NGL plant are underway and we are anticipating startup in the second half of calendar 2016. The plant has a total estimated cost of $24.6 million net to Evolution, of which approximately $5.0 million had been incurred as of June 30, 2015. The reserves report includes projected peak proved production volumes of approximately 1,850 barrels of liquids per day from the NGL plant over the next five years, and peak probable volumes of 1,140 barrels of liquids per day later next decade. 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 is also expected to increase the efficiency of the CO2 flood, and the reserves report reflects incremental gross crude oil production volumes in the range of 500 BOPD once the plant is operational.
Remaining estimated capital expenditures amount to $9.34 per BOE for proved undeveloped reserves and $4.89 for probable undeveloped 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 these high quality and economically viable projects will be executed as planned, subject to oil price volatility.
GARP® - Artificial Lift Technology
Results from our artificial lift technology were adversely affected by declining production in our company operated wells and high production costs due to workovers. Our Gas Assisted Rod Pump (GARP® ) technology continues to face a challenging marketing environment as the industry copes with lower revenues and significantly reduced spending budgets.
During the fiscal year, the GARP® installation in the Appelt #1H well, which had been shut-in for over a year due to solids production, was worked over to install better solids handling capacity and restored to producing status. The Selected Lands #2 well was also restored to economic production in March 2015. Lastly, the Philip #1 well was abandoned after unsuccessful workovers to prevent solids from causing repeated mechanical pump failures. These pump issues were unrelated to our GARP® technology.
We continue to work to advance the development of the GARP® technology and have filed three new GARP® patents and one provisional GARP® patent to solve specific needs identified by customers. Recent GARP® marketing and business development efforts have secured three master service agreements, including with one major, one super-independent and one large independent oil producer and a fourth agreement is pending. Approval as a vendor to provide oil field services is a necessary first step to install our GARP® technology, but the installation is governed by a separate agreement.
Other Fields
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.

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Liquidity and Capital Resources
We had $20.1 million and $23.9 million in cash and cash equivalents at June 30, 2015 and June 30, 2014, respectively. In addition, we have $5.0 million of availability under our unsecured revolving credit facility at fiscal year end.
During our fiscal year ended June 30, 2015, we financed our operations with cash generated from operations and cash on hand. At June 30, 2015, our working capital was $14.4 million, compared to working capital of $23.3 million at June 30, 2014. The $8.9 million working capital decrease is primarily due to a $7.7 million increase in accounts payable reflecting post-reversion Delhi field operating expenses and capital expenditures together with $3.8 million of lower cash, partially offset by $1.7 million of lower accrued liabilities principally attributable to incentive compensation, restructuring and officer retirement accruals and $1.7 million of increased oil and gas revenue receivables subsequent to our working interest reversion. 
Cash Flows from Operating Activities
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.
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.
For the year ended June 30, 2013, cash flows provided by operating activities were $11.9 million, reflecting $6.6 million of net income together with $5.3 million provided by non-cash expenses, including $2.5 million from deferred income taxes, $1.5 million from stock compensation, and $1.3 million from depreciation, depletion and amortization.
Cash Flows from Investing Activities
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 the Sneath and Hendrickson wells drilled in the Mississippi Lime during the prior year. We received approximately $542,000 of proceeds from asset sales, including $402,500 from the December sale of our South Texas properties, and $250,000 of cash from the maturity of a certificate of deposit.
Cash paid for oil and gas capital expenditures during the year ended June 30, 2013 was $4.9 million. Of these expenditures, $0.7 million was for leasehold acquisitions, principally in the Mississippi Lime, and $4.2 million was for development activities. Development activities were predominantly in the Mississippi Lime, where one salt water disposal well and two wells were drilled. In Giddings, expenditures were centered on adding three new GARP® wells. An inflow of $3.5 million was received for proceeds from the sales of a portion of our Giddings exploration and production properties. In December 2012, an expiring $250,000 certificate of deposit was rolled over beginning a new annual term.
Oil and gas capital expenditures incurred, which includes accrued expenditures, were $11.2 million, $1.2 million, and $3.4 million, respectively, for the years ended June 30, 2015, 2014, and 2013. 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 12, "Supplemental Cash Flow Information".
Cash Flows from Financing Activities
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

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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.
During the year ended June 30, 2013, we paid preferred dividends of $0.7 million and acquired $0.1 million of treasury stock through the surrender of shares by certain officers and employees in satisfaction of payroll liabilities related to stock-based compensation. A tax benefit related to stock-based compensation provided $0.8 million.
Capital Budget
Delhi Field
With the operator's determination that reversion of our 23.9% working interest and 19.0% net revenue interest in Delhi occurred effective November 1, 2014, we began funding our share of capital expenditures in the field as of that date. From reversion through June 30, 2015, our net share of capital expenditures was approximately $10.4 million, including $5.0 million for the gas processing plant. Capital expenditures also included redrilling a producer well, testing and strengthening of well bore integrity in various wells in the field, including previously plugged wells, and drilling and completion of monitoring wells.
Projected capital expenditures over the next fiscal year are currently expected to total approximately $19.6 million net to our working interest for the balance of the costs of the NGL recovery plant.

Beyond the NGL recovery plant, there are other capital projects to exploit proved undeveloped reserves in 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 economics of this project versus other projects in the operator's portfolio. We believe this project has very favorable economics, even in this lower price environment, and expect the expansion of the CO2 flood to resume within the next 2-3 years. The economics of this expansion will also be improved subsequent to the completion of the NGL recovery plant.
GARP® - Artificial Lift Technology
Based on our current marketing and business plans, we expect that our capital requirements for artificial lift technology operations will be relatively minor over the next fiscal year.
Liquidity Outlook
Our liquidity is highly dependent on the realized prices we receive for the oil, natural gas and natural gas liquids we produce. 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 forecasted production from July 1, 2015 to December 31, 2015 to achieve a more predictable level of cash flows to support the Company’s capital expenditure program. Costless collars used by the Company to manage risk are designed to establish floor and ceiling 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. Liquidity could also be affected by any litigation outcome, positive or negative.
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 $5.0 million unsecured revolving line of credit. This facility is intended primarily to provide a standby source of liquidity to meet future capital expenditures at Delhi or other future capital needs.
The Board of Directors and management instituted a cash dividend on our common stock in December 2013 at an initial quarterly rate of $0.10 per common share. However, as a result of the decline in oil prices which began in the fall of 2014, combined with the anticipated $24.6 million cost of building and installing the Delhi NGL gas plant during calendar years 2015 and 2016, the Dividend Committee and the Board of Directors believed it was prudent to adjust the quarterly dividend rate from $0.10 per share to $0.05 per share, effective with the quarter ending March 31, 2015. The reduction in the dividend rate will allow the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield. 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. Payment of free cash flow in excess of our operating and capital requirements through cash dividends and repurchases of our common stock remains a priority of our financial strategy, and it is our long term goal to increase our dividends over time as appropriate.

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Results of Operations
The following table sets forth certain financial information with respect to our oil and natural gas operations:
 
Year Ended June 30,
 
2015
 
2014
 
2013
Delhi field:
 
 
 
 
 
Crude oil revenues
$
27,573,641

 
$
16,908,666

 
$
19,219,036

Crude oil volumes (Bbl)
448,187

 
164,224

 
180,658

Average price per Bbl
$
61.52

 
$
102.96

 
$
106.38

  Delhi field production costs
$
8,516,323

 
$

 
$

  Delhi field production costs per BOE
$
19.00

 
$

 
$

 
 
 
 
 
 
Artificial lift technology:
 
 
 
 
 
  Crude oil revenues
$
170,369

 
$
414,270

 
$
323,488

  NGL revenues
36,480

 
115,172

 
16,661

  Natural gas revenues
24,260

 
93,890

 
34,914

  Service revenues
16,146

 

 

  Total revenues
$
247,255

 
$
623,332

 
$
375,063

 
 
 
 
 
 
  Crude oil volumes (Bbl)
2,352

 
4,115

 
3,476

  NGL volumes (Bbl)
1,335

 
3,460

 
432

  Natural gas volumes (Mcf)
7,450

 
26,105

 
10,531

  Equivalent volumes (BOE)
4,929

 
11,927

 
5,664

 
 
 
 
 
 
  Crude oil price per Bbl
$72.44
 
$100.67
 
$93.06
  NGL price per Bbl
$27.33
 
$33.29
 
$38.57
  Natural gas price per Mcf
$3.26
 
$3.60
 
$3.32
    Equivalent price per BOE
$50.16
 
$52.26
 
$66.22
 
 
 
 
 
 
  Artificial lift production costs
$
743,802

 
$
609,221

 
$
390,238

  Production costs per BOE
150.90

 
51.08

 
68.90

 
 
 
 
 
 
Other properties:
 
 
 
 
 
  Revenues
$
20,369

 
$
141,510

 
$
1,755,821

  Equivalent volumes (BOE)
285

 
1,591

 
40,497

  Equivalent price per BOE
$
71.47

 
$
88.94

 
$
43.36

 
 
 
 
 
 
  Production costs
$
95,488

 
$
584,352

 
$
1,390,500

  Production costs per BOE
$
335.05

 
$
367.29

 
$
34.34

 
 
 
 
 
 
Combined:
 
 
 
 
 
Oil and gas DD&A (a)
$
3,220,990

 
$
1,192,370

 
$
1,255,209

Oil and gas DD&A per BOE
$
7.10

 
$
6.71

 
$
5.53

(a) Excludes technology equipment impairment of $275,682, depreciation of technology equipment, office furniture, fixtures and equipment, and amortization of other assets totaling $119,065 for the year ended June 30, 2015 and aggregate depreciation and amortization of $36,515 and $44,998 for the years ended June 30, 2014, and 2013, respectively.

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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.  Earning increased $1.4 million reflecting $10.2 million of higher revenue together with $2.1 million of lower G&A and $1.3 million restructuring expenses, partially offset by $8.2 million higher production costs, $2.4 million of increased DD&A and $1.6 million of higher income taxes.
 
Delhi Field. Revenues increased 63% to $27.6 million as a result of a 173% increase in production volumes from the prior fiscal year primarily due to the November 2014 reversion of our working interest, partially offset by a 40% decline in realized crude oil prices, from $102.96 per barrel to $61.52 per barrel. Gross production decreased 0.6% to 6,038 BOPD compared to 6,076 BOPD for the year-ago period. Production costs for the current fiscal year were $8.5 million, of which $5.1 million was for CO2 purchases and transportation expenses, compared to no 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. Under our contract with the operator, purchased CO2 is priced at 1% of the oil price in the field per Mcf plus $0.20 per Mcf transportation costs plus sales taxes. Accordingly, such costs will be reduced in the future if oil prices remain at lower price levels. From our November 1, 2014 working interest reversion to June 30, 2015, total production costs were $29.89 per working interest BOE which includes CO2 costs of $17.72 per working interest BOE.

Artificial Lift Technology. Revenues decreased 60% to $247,000 reflecting a 59% volume decrease, primarily as a result of losing production at the Philip DL #1, together with a 4% decrease in the realized price per BOE, from $52.26 per barrel to $50.16 per barrel. We recorded $16,146 of service revenue from GARP® installations for a third-party customer. Artificial lift production costs were $744,000, which included $571,000 in workover costs incurred in recovering proved reserves by restoring production on the Appelt and the Selected Lands #2 wells and unfruitful attempts to restore production at the Philip DL #1.

Other Properties. The Company began divesting its non-core oil and gas properties in fiscal 2013. Revenues from other properties decreased to $20,000 compared to $142,000 in fiscal 2014. The prior year production costs were high as a result of workover costs in South Texas and high water production in the Mississippi Lime. We completed our divestiture process in the second quarter of our current fiscal year with the sale of the remaining interests in our Mississippi Lime properties.
 
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 vice president and 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 7 – 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 $275,682 impairment charge for GARP® equipment installations on three under performing wells of a third party customer together with the remaining expense increase primarily the result of higher other property and equipment depreciation reflecting 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 higher estimated cost for the Delhi Field gas plant at June 30, 2015.
Year ended June 30, 2014 compared with the Year ended June 30, 2013
Net Income Available to Common Shareholders.  For the year ended June 30, 2014, we generated net income of $2.9 million or $0.09 per diluted share, (which includes a $1.3 million restructuring charge, $1.4 million of non-recurring charges related to stock option exercises and the retirement of the Company’s chief financial officer) on total oil and natural gas revenues of $17.7 million.  For the year ended June 30, 2014, non-cash stock compensation expense was $1.7 million of which $203,861

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related to the retirement charge. This compares to a net income of $6.0 million, or $0.19 per diluted share, (which includes $1.5 million of non-cash stock-based compensation expense) on total oil and natural gas revenues of $21.3 million for the corresponding prior year period.  The earnings decline is due to lower revenue, higher G&A, and a current year restructuring charge, partially offset by lower lease operating expense and income taxes.  Additional details of the components of net income are explained in greater detail below.
 
Delhi Field. Revenue decreased 12% to $16.9 million primarily because of a 9% volume decline attributable to the June 2013 Event, together with a 3% lower price per BOE.

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

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

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

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

General and Administrative Expenses (“G&A”).  G&A expenses, including $1.4 million of one-time charges, increased 12% to $8.4 million during the year ended June 30, 2014 from $7.5 million in the prior year.  The $0.9 million increase was primarily due to approximately $672,000 of higher compensation and benefits impacted by an officer's retirement, $146,000 of higher transaction expenses, $121,000 of lower absorption to drilling projects and $90,000 in higher consulting expense, partially offset by lower stock compensation expense of $179,000. Stock-based compensation was $1.4 million (16% of total G&A) for the year ended June 30, 2014 compared to $1.5 million (21% of total G&A) for the year ended June 30, 2013.
 
Restructuring Charges.  The Company recorded $1.3 million of restructuring expense in December 2013 primarily reflecting $956,000 of termination benefits to be paid from January to December 2014 and $376,000 of non-cash stock compensation expense for accelerated restricted stock vesting for terminated employees.  See Note 7 — Restructuring.
 
Oil and Gas Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A decreased by 5% to $1.2 million for the year ended June 30, 2014, compared to $1.3 million for the prior year. This change was principally due to a 21% increase in depletion rate to $6.71 per BOE, partially offset by a 22% volume decrease.
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 2015 we have not seen material changes in cost. 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 continues to decrease with a great oversupply in the future, it may continue to put downward pressure on crude oil and natural gas prices, thereby lowering our revenues and working capital going forward. In addition, our lease operating expenses and their percentage of our revenues are likely to increase as reversion of our back-in interest at Delhi or other additions to our working interest production would dilute extraordinary margins we have enjoyed from our mineral and overriding royalty interests at Delhi.
        Seasonality.    Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products. Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather including hurricanes that may substantially affect oil and natural gas production and imports.

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Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2015, 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
$
172,262

 
$
159,011

 
$
13,251

 

 

Other Obligations
 
 
 
 
 
 
 
 
 
Asset retirement obligations
772,990

 
57,223

 

 

 
715,767

Total obligations
$
945,252

 
$
216,234

 
$
13,251

 
$

 
$
715,767

We have entered into employment agreements with two of the Company's senior executives. The employment contracts provide for severance payments in the event of termination by the Company for any reason other than cause or permanent disability, or in the event of a constructive termination, as defined. The agreements provide for the payment of base pay and certain medical and disability benefits for periods ranging form 6 months to 1 year after termination. The total contingent obligations under the employment contracts as of June 30, 2015 was approximately $473,000.
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, 2015, 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, 2015 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, 2015 of 5%,

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10% and 15% would affect depreciation, depletion and amortization expense by approximately $242,000, $509,000 and $808,000, respectively.
On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and gas reserves. The rule allows consideration of new technologies in evaluating reserves, generally limits the designation of proved reserves to those projects forecast to be commenced within five years of the end of the period, allows companies to disclose their probable and possible reserves to investors, requires reporting of oil and gas reserves using an average price based on the previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices, revises the disclosure requirements for oil and gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.
Valuation of Deferred Tax Assets.    We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared or filed; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carry backs and carry forwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our net operating loss). If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of June 30, 2015, 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, 2015.
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 manage our exposure to commodity price risk from time to time based on our assessment of such risk.

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Item 8.    Financial Statements

Index to Consolidated Financial Statements
 
 
 
 
 
 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Evolution Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and subsidiaries (the "Company") as of June 30, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2015, 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, 2015, 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 11, 2015 expressed an unqualified opinion on the effectiveness of Evolution Petroleum Corporation’s internal control over financial reporting.



Hein & Associates LLP
Houston, Texas
September 11, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Evolution Petroleum Corporation
We have audited Evolution Petroleum Corporation’s internal control over financial reporting as of June 30, 2015, 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, 2015, 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, 2015 and 2014, 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, 2015, and our report dated September 11, 2015 expressed an unqualified opinion.




Hein & Associates LLP
Houston, Texas
September 11, 2015

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
 
June 30, 2015
 
June 30, 2014
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
20,118,757

 
$
23,940,514

Receivables
3,122,473

 
1,457,212

Deferred tax asset
82,414

 
159,624

Prepaid expenses and other current assets
369,404

 
747,453

Total current assets
23,693,048

 
26,304,803

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
45,186,886

 
37,822,070

Other property and equipment, net
276,756

 
424,827

Total property and equipment, net
45,463,642

 
38,246,897

Other assets
726,037

 
464,052

Total assets
$
69,882,727

 
$
65,015,752

Liabilities and Stockholders' Equity
 
 
 
Current liabilities
 
 
 
Accounts payable
$
8,173,878

 
$
441,722

Accrued liabilities and other
855,373

 
2,558,004

Derivative liabilities, net
109,974

 

State and federal taxes payable
190,032

 

Total current liabilities
9,329,257

 
2,999,726

Long term liabilities
 
 
 
Deferred income taxes
11,242,551

 
9,897,272

Asset retirement obligations
715,767

 
205,512

Deferred rent
18,575

 
35,720

Total liabilities
21,306,150

 
13,138,230

Commitments and contingencies (Note 17)

 

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, 2015 and 2014, 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 32,845,205 and 32,615,646 shares as of June 30, 2015 and 2014, respectively
32,845

 
32,615

Additional paid-in capital
36,847,289

 
34,632,377

Retained earnings
11,696,126

 
17,212,213

Total stockholders' equity
48,576,577

 
51,877,522

Total liabilities and stockholders' equity
$
69,882,727

 
$
65,015,752

   See accompanying notes to consolidated financial statements.

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
 
Years Ended June 30,
 
2015
 
2014
 
2013
Revenues
 
 
 
 
 
Delhi field
$
27,573,641

 
$
16,908,666

 
$
19,219,036

Artificial lift technology
247,255

 
623,332

 
375,063

Other properties
20,369

 
141,510

 
1,755,821

Total revenues
27,841,265

 
17,673,508

 
21,349,920

Operating costs
 
 
 
 
 
Production costs - Delhi field
8,516,323

 

 

Production costs - artificial lift technology
743,802

 
609,221

 
390,238

Production costs - other properties
95,488

 
584,352

 
1,390,500

Depreciation, depletion and amortization
3,615,737

 
1,228,685

 
1,300,207

Accretion of discount on asset retirement obligations
34,866

 
41,626

 
72,312

General and administrative expenses*
6,256,783

 
8,388,291

 
7,495,309

Restructuring charges**
(5,431
)
 
1,293,186

 

Total operating costs
19,257,568

 
12,145,361

 
10,648,566

Income from operations
8,583,697

 
5,528,147

 
10,701,354

Other
 
 
 
 
 
(Loss) on derivative instruments, net
(109,974
)
 

 

Interest income
35,991

 
30,256

 
22,580

Interest (expense)
(73,636
)
 
(69,092
)
 
(65,745
)
Income before income tax provision
8,436,078

 
5,489,311

 
10,658,189

Income tax provision
3,444,221

 
1,891,998

 
4,029,761

Net income attributable to the Company
4,991,857

 
3,597,313

 
6,628,428

Dividends on preferred stock
674,302

 
674,302

 
674,302

Net income attributable to common shareholders
$
4,317,555

 
$
2,923,011

 
$
5,954,126

Earnings per common share
 
 
 
 
 
Basic
$
0.13

 
$
0.09

 
$
0.21

Diluted
$
0.13

 
$
0.09

 
$
0.19

Weighted average number of common shares outstanding
 
 
 
 
 
Basic
32,817,456

 
30,895,832

 
28,205,467

Diluted
32,924,018

 
32,564,067

 
31,975,131

_______________________________________________________________________________

*
General and administrative expenses for the years ended June 30, 2015, 2014 and 2013 included non-cash stock-based compensation expense of $943,653, $1,352,322, and $1,531,745, respectively.

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


   
See accompanying notes to consolidated financial statements.

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Table of Contents

Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
 
Years Ended June 30,
 
2015
 
2014
 
2013
Cash flows from operating activities
 
 
 
 
 
Net income attributable to the Company
$
4,991,857

 
$
3,597,313

 
$
6,628,428

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation, depletion and amortization
3,664,373

 
1,272,778

 
1,341,055

Stock-based compensation
943,653

 
1,352,322

 
1,531,745

Stock-based compensation related to restructuring

 
376,365

 

Accretion of discount on asset retirement obligations
34,866

 
41,626

 
72,312

Settlement of asset retirement obligations
(223,564
)
 
(315,952
)
 
(90,531
)
Deferred income taxes
1,422,489

 
1,344,812

 
2,512,978

Deferred rent
(17,145
)
 
(17,145
)
 
(17,146
)
Loss on derivative instruments, net
109,974

 

 

Changes in operating assets and liabilities:
 
 
 
 
 
Receivables from oil and natural gas sales
(1,666,009
)
 
176,707

 
(289,506
)
Receivables from income taxes and other
748

 
281,822

 
(189,813
)
Due from joint interest partners

 
49,063

 
47,088

Prepaid expenses and other current assets
378,049

 
(480,899
)
 
(33,121
)
Accounts payable and accrued expenses
551,452

 
663,645

 
278,436

Income taxes payable
190,032

 
(233,548
)
 
141,581

Net cash provided by operating activities
10,380,775

 
8,108,909

 
11,933,506

Cash flows from investing activities
 
 
 
 
 
Proceeds from asset sales
398,242

 
542,347

 
3,479,976

Development of oil and natural gas properties
(4,890,909
)
 
(966,931
)
 
(4,163,080
)
Acquisitions of oil and natural gas properties

 
(59,315
)
 
(755,194
)
Capital expenditures for technology and other equipment
(313,059
)
 
(312,890
)
 

Maturities of certificates of deposit

 
250,000

 

Other assets
(236,559
)
 
(202,017
)
 
(32,160
)
Net cash used by investing activities
(5,042,285
)
 
(748,806
)
 
(1,470,458
)
Cash flows from financing activities
 
 
 
 
 
Proceeds from the exercise of stock options
141,600

 
3,252,801

 
70,719

Acquisitions of treasury stock
(333,841
)
 
(1,655,251
)
 
(137,818
)
Common stock dividends paid
(9,833,642
)
 
(9,723,833
)
 

Preferred stock dividends paid
(674,302
)
 
(674,302
)
 
(674,302
)
Deferred loan costs
(94,075
)
 
(63,535
)
 
(16,211
)
Tax benefits related to stock-based compensation
1,633,946

 
509,096

 
794,569

Other
67

 
6,850

 
32

Net cash provided (used) by financing activities
(9,160,247
)
 
(8,348,174
)
 
36,989

Net increase (decrease) in cash and cash equivalents
(3,821,757
)
 
(988,071
)
 
10,500,037

Cash and cash equivalents, beginning of year
23,940,514

 
24,928,585

 
14,428,548