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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ý
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 2017
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                to              
Commission File Number 001-32942
EVOLUTION PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Nevada
(State or other jurisdiction of
incorporation or organization)
 
41-1781991
(IRS Employer
Identification No.)
1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079
(Address of principal executive offices and zip code)
(713) 935-0122
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
 
Title of Each Class
 
Name of Each Exchange On Which Registered
 
 
Common Stock, $0.001 par value
 
NYSE American
 

Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes: o    No: ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes: o    No: ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: ý    No: o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes: ý    No: o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
  Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definition of "large accelerated filer", "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
 
Accelerated filer ý
Non-accelerated filer o
(Do not check if a smaller reporting company)
Smaller reporting company o
Emerging growth company o
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $10.00 on the NYSE American, was $250,722,260.
The number of shares outstanding of the registrant's common stock, par value $0.001, as of September 7, 2017, was 32,905,982.


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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant's 2017 Annual Meeting of Stockholders to be filed within 120 days of the end of the fiscal year covered by this report are incorporated by reference into Part III of this report.


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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
2017 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
This Form 10-K and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words "plan," "expect," "project," "estimate," "assume," "believe," "anticipate," "intend," "budget," "forecast," "predict" and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in this Annual Report on Form 10-K as filed with the Securities and Exchange Commission ("SEC"). Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.
We use the terms, "EPM," "Company," "we," "us" and "our" to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.
PART I
Item 1.    Business
Note: See Glossary of Selected Petroleum Industry Terms at the back of this document - refer to Table of Contents
General
We are an independent oil and gas company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas, onshore in the United States. Our goal is to acquire known crude oil and natural gas resources and exploit them through the application of conventional and specialized technology, with the objective of increasing production, ultimate recoveries, or both. Additional information regarding our operating segment, major customers, revenues and assets can be found in in Item 8. Financial Statements - Notes to Consolidated Financial Statements.
Our operations began in September 2003. In May 2004, our predecessor, Natural Gas Systems, Inc., merged into a wholly-owned subsidiary of Reality Interactive, Inc., an inactive public company, which was renamed Natural Gas Systems, Inc. ("NGS"). In connection with the listing of NGS shares on the American Stock Exchange (currently the NYSE American) in July 2006, NGS was renamed Evolution Petroleum Corporation. Our principal executive offices are located at 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, and our telephone number is (713) 935-0122. We maintain a website at www.evolutionpetroleum.com, but information contained on our website does not constitute part of this document. Our common stock is traded on the NYSE American (formerly known as the NYSE MKT) under the ticker symbol "EPM".
At June 30, 2017, we had five full-time employees, not including contract personnel and outsourced service providers. None of the Company’s employees are currently represented by a union, and the Company believes that it has excellent relations with its employees. Our team is broadly experienced in oil and gas operations, development, acquisitions and financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative and other non-core functions.
Business Strategy
Our business strategy is to acquire known, underdeveloped oil and natural gas resources and exploit them through the application of capital, sound engineering and modern technology to increase production, ultimate recoveries, or both.
Our principal assets include interests in a CO2 enhanced oil recovery project in Louisiana’s Delhi field and the natural gas liquids recovery plant in the Delhi field. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders.
Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our working and royalty interests in the Delhi Holt-Bryant Unit in the Delhi field ("Unit"), located in Northeast Louisiana, are currently our sole producing assets. 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. At the time of our purchase of the field in 2003, the Unit had minimal production. We conveyed our working interest in the field to a subsidiary of Denbury Resources, Inc. in May 2006 for $50 million for the purpose of installing an enhanced oil recovery ("EOR") project in the field. We retained a 23.9% reversionary working interest upon payout of the project, as defined. Since EOR production began in March 2010, the Unit has produced over 14 million bbls of oil.
We own two types of interests in the Unit:
7.2% of overriding royalty interests that are in effect for the life of the Unit and mineral royalty interests, free of all operating and capital cost burdens; and

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A 23.9% working interest with an associated 19.0% net revenue interest. The working interest reverted to us effective November 1, 2014. Upon occurrence of this contractual payout, we began bearing 23.9% of all operating expenses and capital expenditures.
The above interests are separate and give us a combined net revenue interest of 26.2%.
Our independent reservoir engineers, DeGolyer and MacNaughton, assigned the following estimated reserves net to our interests at Delhi as of June 30, 2017. Natural gas and natural gas liquids are converted to oil equivalent volumes at the ratio of six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil.
10.1 million bbls of proved oil equivalent reserves, with a Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure") of $83 million, and PV-10* of $111 million
5.3 million bbls of probable** oil equivalent reserves
3.2 million bbls of possible** oil equivalent reserves
_______________________________________________________________________________
*
PV-10 of Proved reserves is a non-GAAP measure, reconciled to the Standardized Measure at "Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues" under Item 2. Properties of this Form 10-K. Both the Standardized Measure and PV-10 are based on the average first day of the month net commodity prices received at the Delhi field in the twelve months ending June 30, 2017, which were $46.65 per barrel of oil and $20.48 per barrel of natural gas liquids ("NGL"). Probable and possible reserves are not recognized as GAAP nor is there a comparable GAAP measure for probable and possible reserves.
**
With respect to the above reserve numbers, estimates of Probable and Possible reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves but which, together with Proved reserves, are as likely as not to be recovered, generally described as having a 50% probability of recovery. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of Probable and Possible reserves are by their nature much more speculative than estimates of Proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. These three reserve categories 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 originally planned six primary phases for the installation of the CO2 flood in the Delhi field. Four of these phases have been completed as of June 30, 2017 and two remain undeveloped. One of the remaining two phases (Phase V) is reflected as proved undeveloped in our current reserves report and the other was removed from proved reserves (Phase VI) as it was not deemed economic under current pricing guidelines for SEC purposes.
Phase I began CO2 injection in November 2009. First oil production response occurred in March 2010 and production in the field increased to approximately 1,000 gross barrels of oil per day by December 2010.
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, and field gross production increased to more than 4,000 barrels of oil per day by June 2011.
Phase III was installed during calendar 2011, and was expanded twice during calendar 2011. Production subsequently increased to more than 5,000 barrels of oil 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 barrels of oil per day.
In June 2013, following a fluid release event that consisted of the uncontrolled release of CO2, water, natural gas and a small amount of oil from a previously plugged well in the southwest part of the field, the operator temporarily suspended CO2 injection in most of the southwestern tip of the field. The operator has fully remediated the affected area, but has isolated that part of the field with a water curtain.

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This fluid release event, along with other contractual disputes, caused the Company to file suit against the operator in December 2013. In June 2016, we reached a settlement with the operator as described in Note 17 – Delhi Field Litigation Settlement.
Subsequent to the reversion of our working interest to us in November 2014, the operator initiated work on the Phase V expansion of the CO2 flood in the undeveloped eastern part of the field. This project is sometimes referred to as Test Site 5. These operations were suspended shortly after reversion when the operator made significant cuts in its capital budget as a result of declining oil prices. Resumption of this work has been electively delayed due to prevailing oil prices and the partners' allocation of capital to other Delhi projects, primarily the large investment in the NGL plant discussed below. It was further electively delayed based on the conclusion that the economics of the project would be improved if it were implemented after completion of the NGL plant, which has now occurred. We believe that the Phase V expansion of the CO2 flood has favorable economics, even in this lower price environment, and we expect this project to expand the CO2 flood to resume within the next two years.
In February 2015, we began construction of an NGL recovery plant in the Delhi Field, which was completed and operational in December 2016. Our net cost for the NGL plant totaled $26.3 million. The NGL plant extracts methane and NGL's from the CO2 recycle stream. The methane and part of the ethane produced by the NGL plant are used to generate electrical power in the field. The extracted NGL's are sold at the field to a purchaser who transports them by truck to a plant for further processing. In addition to the value of these hydrocarbon products, the increased purity of the CO2 stream re-injected into the field should result in operational benefits to the CO2 flood.
Artificial Lift Technology
We previously owned artificial lift technology registered as GARP® (Gas Assisted Rod Pump) that was developed internally by our former Senior Vice President of Operations. Its design is intended to increase production and extend the life of horizontal and vertical wells with gas, oil or associated water production with the expectation of recovering additional reserves at an economically attractive cost per BOE. We received a patent on our GARP® technology on August 30, 2011, which provides U.S. patent protection for the technology through early 2028. We have further filed for a continuation in part to our patent for recent improvements in the technology, including a concentric design which allows the technology to work in narrower diameter casing.
Subsequent to receiving our patent, we entered into demonstration joint venture projects and commercialization projects with industry operators between 2012 and early 2015. Most of these projects were successful in establishing or restoring commercial rates of production. However, with the severe decline in oil prices that began in late 2014, a significant portion of these projects were not sufficiently profitable to justify the incremental capital and operating costs of the technology.

As a result of the declining commodity price environment and reduced capital spending by the industry, the timing for commercial success of this technology was slower than previously anticipated. Based on a strategic review of these operations, we undertook the separation and transfer of these operations to a new entity controlled by the inventor of the technology and certain former employees of the Company, effective December 31, 2015. We invested $108,750 in common and preferred stock and retained a minority interest in the new entity, Well Lift Inc., together with a 5% royalty on all future gross revenues derived from the technology. We have the option to convert our preferred stock investment in Well Lift Inc, into a larger, non-controlling equity stake in the new entity. Consequently, we have retained upside for our shareholders from the potential future success of the technology, while eliminating approximately $1.0 million of annual overhead expenses. We have also retained the right to use the technology in our current wells and any future wells we develop or acquire.
Other Projects
Mississippi Lime—Kay County, Oklahoma
In 2012, we acquired a 45% interest in a joint venture with Orion Exploration, a private company based in Tulsa, Oklahoma. The joint venture was operated by Orion and engaged in the horizontal development of the Mississippi Lime reservoir in Kay County, Oklahoma. Our leasehold position, totaling approximately 6,600 acres, was located in the eastern, more oil-prone side of the play. We drilled one gross salt water disposal well and reached total depth on two horizontally drilled wells in the Mississippi Lime formation. While both wells produced at the fluid rates expected, the quantities of oil and gas were far less than expected. We subsequently reworked both wells to test the role of structure in production, and determined that this play is a structural play requiring substantial geophysical and geological work and expertise in order to be successful, as opposed to a resource play in which engineering is the primary requirement. Accordingly, we elected in fiscal 2013 to reduce our joint venture interest in undeveloped leases to 33.9%, resulting in a $1.2 million reduction in both our net property and accounts payable. In October 2014, we completed the sale of all of our leasehold interests and wells and any associated assets and abandonment liabilities in the Mississippi Lime reservoir to the operator.

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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 separately from the operator's share of production. Although we have the right to take our working interest production in-kind, we are currently selling our oil under the Delhi operator's agreement with Plains Marketing L.P. pursuant to the delivery and pricing terms thereunder. 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. The positive LLS Gulf Coast price differential over WTI was approximately $1.67 per barrel during our fiscal year ended June 30, 2017. The differential has narrowed from past years, but we expect that a positive LLS price differential will continue, at least in the near future. Our overall net oil price, including the LLS premium and after all adjustments for transportation, marketing and other price differentials, was $2.28 per barrel less than WTI crude oil prices, as quoted daily on the New York Mercantile Exchange.
Upon completion of the NGL plant in late 2016, we began selling natural gas liquids from the Delhi field to American Midstream Gas Solutions, L.P. Title to these products is transferred to the purchaser at the field and they are transported by truck to the purchaser's processing facility. We receive market prices, less transportation, processing and quality differential fees for the net yield of the individual natural gas liquid components, consisting of propane, butanes, and C5+ (pentanes and heavier components). There is a small component of residual ethane, but the overall yield of products is a higher value mix than is typical for natural gas liquids.
The following table sets forth purchasers of our oil and natural gas production for the years indicated:
 
Year Ended June 30,
Customer
2017
 
2016
 
2015
Plains Marketing L.P.
97
%
 
99
%
 
99
%
American Midstream Gas Solution, L.P.
3
%
 
%
 
%
All others
%
 
1
%
 
1
%
 
100
%
 
100
%
 
100
%
The loss of our purchaser at the Delhi field or disruption to pipeline transportation from the field could adversely affect our net realized pricing and potentially our near-term production levels. The loss of any of our other purchasers would not be expected to have a material adverse effect on our operations.
Market Conditions
Marketing of crude oil, natural gas, and natural gas liquids and the prices we receive are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, market prices, government regulation and actions of major foreign producers.
Over the past 30 years, crude oil price fluctuations have been extremely volatile, with crude oil prices varying from less than $10 to over $140 per barrel. Most recently, the price of oil per barrel has dropped dramatically, starting in the fourth quarter of 2014 and continuing into 2017. It has dropped 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

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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, acquire economically producible reserves and obtain capital at rates which allow economic investments.
Seasonality
For a discussion of seasonal changes that affect our business, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Economic Factors - Seasonality in this Form 10-K.
Government Regulation
Numerous federal and state laws and regulations govern the oil and gas industry. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for noncompliance. To the best of our knowledge, we are in compliance with all laws and regulations applicable to our operations and we believe that continued compliance with existing requirements will not have a material adverse impact on us. The future annual capital cost of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable. However, we do not currently anticipate that future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.
See "Government regulation and liability for environmental matters that may adversely affect our business and results of operations" under Item 1A. Risk Factors of this Form 10-K, for additional information regarding government regulation.
Insurance
We maintain insurance on our operated and non-operated properties and operations for risks and in amounts customary in the industry. Such insurance includes general liability, excess liability, control of well, operators extra expense, casualty, fraud and directors & officer's liability coverage. Not all losses are insured, and we retain certain risks of loss through deductibles, limits and self-retentions. We do not carry lost profits coverage and we do not have coverage for consequential damages.
Additional Information
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.evolutionpetroleum.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, or calling (713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
Item 1A.    Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider to be immaterial also may adversely affect us.
Risks related to the oil and gas industry and our Company
A substantial or extended decline in oil prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil significantly influences our revenue, profitability, access to capital and future rate of growth. Oil is a commodity and its price is subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, average daily prices for WTI crude oil ranged from a high of $107 per barrel to a low of $27 per barrel over the past three fiscal years ending June 30, 2017. Historically, the markets for oil and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to the following:

worldwide and regional economic conditions impacting the global supply and demand for oil and gas;

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actions of OPEC or other groups of oil producing nations;
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. A decline in oil and natural gas liquids 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 liquids prices may also reduce the amount of oil and natural gas liquids that we can produce economically, which could lead to a decline in our oil and natural gas liquids reserves. Because approximately 83% of our proved reserves at June 30, 2017 are crude oil reserves and 17% are natural gas liquids reserves, we are heavily impacted by movements in crude oil prices, which also influence natural gas liquids prices. To the extent that we have not hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas liquids prices may adversely affect our financial position.
Our revenues are concentrated in one asset and related declines in production or other events beyond our control could have a material adverse effect on our results of operations and financial results.
Substantially all 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. Environmental or operating problems or lack of future investment at Delhi could cause our net production of oil and natural gas liquids to decline significantly over time, which could have a material adverse effect on our financial condition.
We have limited control over the activities on properties we do not operate.
Substantially all of our property interests are not operated by the Company and also involve other third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Operators of these properties may act in ways that are not in our best interest. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production and materially and adversely affect our financial conditions and results of operations.
We are materially dependent upon our operator with respect to the successful operation of our principal asset, which consists of our interests the Delhi field. A materially negative change in our operator’s financial condition could negatively affect operations (or timing thereof) in the Delhi field, and consequently our income (or timing thereof) from the field as well as the value of our interests in the Delhi field.
Our royalty, mineral and working interests in the Delhi field, located in Northeast Louisiana, currently represent our sole producing asset. Over 99% of our revenues come from these interests and thus our current revenues are highly concentrated in this field. Any significant downturn in production or other events beyond our control which impact the Delhi field could have a

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material adverse effect on our results of operations and financial results (or timing thereof). We are not the operator of the Delhi field. It is operated by a subsidiary of Denbury Resources Inc. (“DNR”). Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
Further, our CO2- Enhanced Oil Recovery (“CO2-EOR”) project in the Delhi field requires significant amounts of CO2 reserves and technical expertise, the sources of which have been committed by the operator. Additional capital remains to be invested to fully develop this project, further increase production and maximize the value of this asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial and logistical matters could cause ultimate enhanced recoveries from the planned CO2- EOR project to fall short of our expectations in volume and/or timing. Such occurrences could have a material adverse effect on us, and our results of operations and financial condition. 
Our economic success is thus materially dependent upon the Delhi field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome source, (ii) secure its share of capital necessary to fund development and operating commitments with respect to the field and (iii) successfully manage related technical, operating, environmental, strategic and logistical risks, among other things. 
We are aware that DNR, which is publicly traded, has disclosed in its public SEC filings certain risks related to its current level of indebtedness and the related financial covenants. They have stated, for example, that their level of indebtedness could have important consequences, including, among others, requiring dedication of a substantial portion of DNR’s cash flow from operations to servicing their indebtedness. They noted that their ability to meet their obligations under their debt instruments will depend in part upon prevailing economic conditions and commodity prices. DNR also noted that it has from time to time deferred development spending for certain projects.
Given the current stress in the global commodity markets and oil and gas in particular, our operator could be materially negatively impacted, which could in turn negatively affect the operator’s ability to operate the Delhi field as well as its financial commitment to the CO2-EOR project in the field, and thus our interests in the Delhi field could be materially negatively impacted.
The types of resources we focus on have substantial operational risks.
Our business plan focuses on the acquisition and development of known resources in partially depleted reservoirs, naturally fractured or low permeability reservoirs, or relatively shallow reservoirs. Shallower reservoirs usually have lower pressure, which generally translates into lower reserve volumes in place. Low permeability reservoirs require more wells and substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient undepleted fractures to establish commercial production. Depleted reservoirs require successful application of newer technology to unlock incremental reserves.
Our CO2-EOR project in the Delhi field, operated by a subsidiary of Denbury Resources Inc., requires significant amounts of CO2 reserves, development capital and technical expertise, the sources of which to date have been committed by the operator. Although initial CO2 injection began at Delhi in November 2009, initial oil production response began in March 2010 and a large part of the capital budget has already been expended, additional capital remains to be invested to fully develop the EOR project, further increase production and maximize the value of the asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial and logistical risks may cause ultimate enhanced recoveries from the planned CO2-EOR project to fall short of our expectations in volume and/or timing. Such occurrences would have a material adverse effect on the Company, its results of operations and financial condition.
Crude oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production and drilling and completing new wells are speculative activities and involve numerous risks and substantial uncertain costs.
Our growth will be materially dependent upon the success of our future development program. Drilling for crude oil and natural gas and re-working existing wells involve numerous risks, including the risk that no commercially productive crude oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including, but not limited to:
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;

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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, 2017, one purchaser accounted for 97% 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 at the field. The loss of such large single purchaser for our oil and natural gas production could negatively impact the revenue we receive. We cannot assure you we could readily find other purchasers for our oil and natural gas production. In addition, the crude oil production from the Delhi field is transported by pipeline and if this pipeline transportation were disrupted and we were forced to use alternative transportation methods, our net realized pricing and potentially our near-term production levels could be adversely affected.
Our crude oil and natural gas reserves are only estimates and may prove to be inaccurate.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. Our reserves are only estimates that may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors, such as historical production from the area compared with production from other producing areas and assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas product prices, future operating costs, severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers but at different times, may vary substantially.
Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the crude oil and natural gas industry in general. The Standardized Measure and PV-10 do not necessarily correspond to market value.
Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.
We review on a periodic basis the carrying value of our crude oil and natural gas properties under the applicable rules of the various regulatory agencies, including the SEC. Under the full cost method of accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this "ceiling" test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write down of the carrying value for accounting purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our crude oil and natural gas properties when

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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. A large write-down could adversely affect our compliance with the current financial covenants under our credit facility and could limit our access to future borrowings under that facility or require repayment of any amounts that might be outstanding at the time.
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 liquids, we have, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas liquids production, including costless collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Derivative arrangements also expose us to the risk of financial loss in some circumstances, including, but not limited to, if:

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 a change in the expected 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, but not limited to the following:
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, (ii) successfully manage technical, operating, environmental, strategic and logistical development and operating risks, and (iii) maintain its own financial stability, 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.

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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, but not limited to:

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 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. Moreover, in the event of such an acquisition, 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, but not limited to:

our lean management team's capacity could be challenged by the demands of evaluating, negotiating and integrating significant acquisitions and strategic transactions in concert with the Company's on going business demands.
the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;
difficulty associated with coordinating geographically separate organizations;
an inability to secure, on acceptable terms, sufficient financing that my be required in connection with expanded operations and unknown liabilities; and
the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. In addition, even if we successfully integrate the assets acquired in an acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame.
Government regulation and liability for environmental matters may adversely affect our business and results of operations.
Crude oil and natural gas operations are subject to extensive federal, state and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are federal, state and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation and disposal of crude oil and natural gas, by-products thereof, the emission of CO2 or other greenhouse gases, 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.

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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 incidental to our business. Environmental events similar to that experienced in the Delhi field in June 2013 could defer revenue, increase operating costs and/or increase maintenance and repair 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 the abilities of Robert S. Herlin, our Chairman of the Board, Randall D. Keys, our President and Chief Executive Officer, and David Joe, Senior Vice President, Chief Financial Officer and Treasurer, to source, evaluate and close deals, raise capital, and oversee our development activities and operations. Presently, the Company is not a beneficiary of any key man life insurance.
Oil field service and materials' prices may increase, and the availability of such services and materials may be inadequate to meet our needs.
Our business plan to develop or redevelop crude oil and natural gas resources requires third party oilfield service vendors and various material providers, which we do not control. We also rely on third-party carriers for the transportation and distribution of our production. As our production increases, so does our need for such services and materials. Generally, we do not have long-term agreements with our service and materials providers. Accordingly, there is a risk that any of our service providers could discontinue servicing our crude oil and natural gas fields for any reason or we may not be able to source the materials we need. Any delay in locating, establishing relationships, and training our sources could result in production shortages and maintenance problems, with a resulting loss of revenue to us. In addition, if costs for such services and materials increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may have assumed when deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelop plans.
We cannot market the crude oil and natural gas that we produce without the assistance of third parties.
The marketability of the crude oil and natural gas that we produce depends upon the proximity of our reserves to, and the capacity of, facilities and third-party services, including crude oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities necessary to make the products marketable for end use. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in or delay or discontinuance could adversely affect our financial condition.
We face strong competition from larger oil and gas companies.
Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. We may not be able to successfully conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive crude oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment and acquiring the existing and changing technologies that we believe are and will be increasingly important to attaining success in our industry.
We have been, and in the future may become, involved in legal proceedings related to our Delhi interest or other properties or operations and, as a result, may incur substantial costs in connection with those proceedings.
From time to time we may be a defendant or plaintiff in various lawsuits.  The nature of our operations exposes us to further possible litigation claims in the future.  There is risk that any matter in litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash flow.  Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition.  Adverse litigation decisions or rulings may damage our business reputation.

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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 has relatively low trading volume and the market price has been, and is likely to continue to be, volatile. For example, during the fiscal year ending June 30, 2017, our stock price as traded on the NYSE American ranged from $5.12 to $10.20. The variance in our stock price makes it difficult to forecast with 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.
As of June 30, 2017, our executive officers and directors, in the aggregate, beneficially owned approximately 2.9 million shares, or approximately 8.8% of our beneficial common stock base. JVL Advisors LLC controlled approximately 5.1 million shares or approximately 15.4% of our outstanding common stock. ArrowMark Colorado Holdings LLC controlled approximately 2.5 million shares, or approximately 7.4% of our outstanding common stock. Advisory Research, Inc. also controlled approximately 2.5 million shares, or approximately 7.4% of our outstanding common stock and Blackrock Fund Advisors controlled approximately 2.2 million shares, or approximately 6.6% of our outstanding common stock. As a result, any of these holders could potentially exercise significant influence over matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.
The market for our common stock is limited and may not provide adequate liquidity.
Our common stock trades on the NYSE American. Our trading volume increased in fiscal 2017 compared to fiscal 2016, but trading volume in our common stock is relatively low compared to larger companies. During the fiscal year ended June 30, 2017, the daily trading volume in our common stock ranged from a low of 12,316 shares to a high of 521,709 shares, with average daily trading volume of 127,419 shares. Our holders may find it more difficult to sell their shares, should they desire to do so, based on the trading volume and price of our stock at that time relative to the quantity of shares to be sold.

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If securities or industry analyst do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.
Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge there are four independent analysts that cover our company. The limited number of published reports by independent securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.
The issuance of additional common stock and preferred stock could dilute existing stockholders.
We currently have in place a registration statement which allows the Company to publicly issue up to $500 million of additional securities, including debt, common stock, preferred stock, and warrants. At any time we may make private offerings of our securities. The shelf registration is intended to provide greater flexibility to the company in financing growth or changing our capital structure. We are authorized to issue up to 100,000,000 shares of common stock. To the extent of such authorization, our board of directors has the ability, without seeking stockholder approval, to issue additional shares of common stock in the future for such consideration as our board may consider sufficient. The issuance of additional common stock in the future would reduce the proportionate ownership and voting power of the common stock now outstanding. We are also authorized to issue up to 5,000,000 shares of preferred stock, the rights and preferences of which may be designated in series by our board of directors. Such designation of any 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.
Continued payment of dividends on our common stock could be impacted.
Our Board of Directors declared cash dividends on our common stock for the first time in December 2013 and we have declared and paid quarterly cash dividends since that time. However, there is no certainty that dividends will be declared by the Board of Directors in the future. Any payment of cash dividends on our common stock in the future will be dependent upon the amount of funds legally available, our earnings, if any, our financial condition and business plan, restrictions contained in current or future 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 or choose to continue to pay cash dividends on our common stock.
Item 1B.    Unresolved Staff Comments
None.
Item 2.    Properties
Certain parts of the information required by Item 2. are contained in Item 1. Business
Oil & Gas Properties
Additional detailed information describing the types of properties we own can be found in "Business Strategy" under Item 1. Business of this Form 10-K.
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues
The SEC sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These rules require disclosure of oil and gas proved reserves by significant geographic area, using the trailing 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

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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, generally described as having a 50% probability of recovery. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of Probable and Possible reserves are by their nature much more speculative than estimates of Proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. These three reserve categories have not been adjusted to different levels of recovery risk among these categories and are therefore not comparable and are not meaningfully combined.
Estimated pre-tax future net revenues from the production of Proved reserves 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 this Item 2. Properties.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2017
Our proved, probable and possible reserves at June 30, 2017, denominated in equivalent barrels using a conversion ratio of six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil, were estimated by our independent petroleum engineering firm, DeGolyer and MacNaughton ("D&M"). D&M was selected to estimate reserves for our interests in the Delhi field due to their expertise in CO2-EOR projects and to ensure consistency with the operator. The scope and results of their procedures are summarized in a letter from the firm, which is included as exhibit 99.1 to this Annual Report on Form 10-K.
The following table sets forth our estimated proved, probable and possible reserves as of June 30, 2017. See Note 23 to the consolidated financial statements for additional unaudited reserve information. The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $48.85 per barrel of crude oil. The net price per barrel of natural gas liquids was $20.48, which does not have any single comparable reference index price. The NGL price was based on historical prices received. For periods for which no historical price information was available, we used comparable pricing in the area. Pricing differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual property and product.

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Reserves as of June 30, 2017
Reserve Category
Oil
(MBbls)
 
NGLs
(MBbls)
 
Total Reserves
(MBOE)*
PROVED
 
 
 
 
 
Developed (79% of Proved)
6,617

 
1,333

 
7,950

Undeveloped (21% of Proved)
1,755

 
353

 
2,108

TOTAL PROVED
8,372

 
1,686

 
10,058

Product Mix
83
%
 
17
%
 
100
%
 
 
 
 
 
 
PROBABLE
 
 
 
 
 
Developed (82% of Probable)
3,577

 
720

 
4,297

Undeveloped (18% of Probable)
808

 
163

 
971

TOTAL PROBABLE
4,385

 
883

 
5,268

Product Mix
83
%
 
17
%
 
100
%
 
 
 
 
 
 
POSSIBLE
 
 
 
 
 
Developed (89% of Possible)
2,373

 
478

 
2,851

Undeveloped (11% of Possible)
304

 
61

 
365

TOTAL POSSIBLE
2,677

 
539

 
3,216

Product Mix
83
%
 
17
%
 
100
%
*BOE computed using a conversion ratio of 42 gallons of natural gas liquids to one barrel of oil.
The following tables present a reconciliation of changes in our proved, probable and possible reserves by major property, on the basis of equivalent MBOE quantities.
Reconciliation of Changes in Proved Reserves
 
Delhi Field Proved
Total
Proved reserves, MBOE
 MBOE
June 30, 2016
10,823.4

Production
(768.4
)
Revisions, net
3.4

Sales of minerals in place

Improved recovery, extensions and discoveries

June 30, 2017
10,058.4

Reconciliation of Changes in Probable Reserves
 
Delhi Field Probable
Total
Probable reserves, MBOE
 MBOE
June 30, 2016
4,497.3

Revisions, net
770.7

Sales of minerals in place

Improved recovery, extensions and discoveries

June 30, 2017
5,268.0



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Reconciliation of Changes in Possible Reserves
 
Delhi Field Possible
Total
Possible reserves, MBOE
MBOE
June 30, 2016
2,714.0

Revisions, net
502.2

Sales of minerals in place

Improved recovery, extensions, and discoveries

June 30, 2017
3,216.2

Reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash Flows
The following table provides a reconciliation of PV-10 of our proved properties to the Standardized Measure as shown in Note 23 of the consolidated financial statements.
 
For the Years Ended June 30,
 
2017
 
2016
Estimated future net revenues
$
189,347,437

 
$
187,713,581

10% annual discount for estimated timing of future cash flows
78,452,886

 
86,844,543

Estimated future net revenues discounted at 10% (PV-10)
110,894,551

 
100,869,038

Estimated future income tax expenses discounted at 10%
(27,956,998
)
 
(22,911,719
)
Standardized Measure
$
82,937,553

 
$
77,957,319

Our sole producing assets as of June 30, 2017 and 2016 were our interests in the Delhi field. 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 Reserves Estimation Process
Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent engineering firm under the supervision of our Chairman of the Board, our Chief Executive Officer and a professional petroleum engineer, serving as either an employee of or consultant to the Company. Such reserves estimates are to be in compliance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. Our Chairman of the Board holds B.S. and M.E. degrees from Rice University in chemical engineering and earned an M.B.A. from Harvard University. He has over 30 years of experience in engineering, energy transactions, operations and finance with small independents, larger independents and major integrated oil companies. Our Chief Executive Officer holds a Bachelor of Business Administration from the University of Texas at Austin. He has over 30 years of experience in the energy industry, predominantly with upstream oil and gas companies. Our outside consultant for these reserves estimates is a licensed professional engineer with over 30 years of experience in oil and gas operations and petroleum reservoir engineering and holds a Bachelor of Science in Petroleum Engineering from Texas A&M University. In addition, we engaged another consultant with significant experience in CO2 enhanced oil recovery projects to advise us on certain technical matters related to the Delhi field. This consultant has more than 25 years of experience, including service with two large firms which are industry leaders. He is a registered professional engineer and holds a Master of Science in Petroleum Engineering from Texas A&M University.
The reserves information in this filing is based on estimates prepared by DeGolyer and MacNaughton, our independent engineering firm. The person responsible for preparing the reserves report with D&M is a Registered Professional Engineer in the State of Texas and a Senior Vice President of the firm. He holds a Bachelor of Science degree in Geology in 1973 from Eastern New Mexico University and earned a Master of Science degree in Petroleum Engineering from the University of Texas at Austin in 1975. He has over 38 years of oil and gas reservoir experience. We provide our engineering firm with property interests, production, current operating costs, current production prices and other information. This information is reviewed by our Senior Management and outside consultant to ensure accuracy and completeness of the data prior to submission to our independent engineering firm. The scope and results of our independent engineering firm's procedures, as well as their professional qualifications, are summarized in the letter included as exhibit 99.1 to this Annual Report on Form 10-K.

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Proved Undeveloped Reserves
After completion of the NGL plant in the Delhi field, our remaining proved undeveloped reserves were 2,108 MBOE at June 30, 2017, with associated future development costs of approximately $14.1 million. Our proved undeveloped reserves are comprised of (a) 1,564 MBOE of reserves and $10.9 million of future development costs associated with the Phase V development in the eastern portion of the field and (b) 544 MBOE of reserves and $3.2 million of future development costs associated with a proposed eight-well infill drilling program to increase production and recover reserves which are not believed to be effectively producible with the existing well configuration. The infill project has aspects of both acceleration of production and an increase in ultimate reserves recovery and is being treated as a proved undeveloped project.
During the year ended June 30, 2017 our proved undeveloped reserves changed as follows:
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
Total Reserves
(MBOE)
June 30, 2016
1,420

 
2,235

 
3,655

Revisions to previous estimates
335

 
(505
)
 
(170
)
Conversion to proved developed reserves

 
(1,377
)
 
(1,377
)
June 30, 2017
1,755

 
353

1,755

2,108

We converted 1,377 MBOE of undeveloped reserves as the NGL plant was commissioned in December 2016 and initial production commenced. NGL reserves were revised downward 596 MBOE reflecting lower than originally expected plant production partially offset by 91 MBOE of reserves added by the infill project. The 335 MBOE upward revision for oil is due to 453 MBOE infill project reserves partly offset by a 118 MBOE lower estimate for Phase V.
The initial assignment of proved undeveloped reserves in the Delhi field was made on June 30, 2010, which encompassed 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. Developed reserves are approximately 79% of total proved reserves as of June 30, 2017. However, as a result of the adverse fluid release event in the field in June 2013 and the resulting delay in reversion of our working interest, development of the field has not proceeded as originally scheduled. Expansion of the CO2 flood to the remaining undeveloped eastern portion of the field commenced subsequent to reversion of our working interest in late calendar 2014. We incurred $3.8 million of capital expenditures before the operator electively deferred this project as a result of a reduction in its cash flows and capital spending from the significant drop in oil prices. This project was further electively deferred as we began work on the NGL recovery plant in the Delhi field. It was determined that the economics of development of the remaining eastern portion of the field would be significantly improved after the NGL plant was completed.
During the year ended June 30, 2015 we authorized the NGL plant project and incurred $5.0 million of related capital expenditures. During the years ended June 30, 2016 and 2017, the Company incurred a further $16.5 million and $4.8 million, respectively, of NGL plant capital expenditures. The NGL plant was completed in December 2016 and we converted approximately 1,377 MBOE of proved undeveloped reserves to developed reserves during the year ended June 30, 2017.
As of June 30, 2017, we had estimated future net capital expenditures of $10.9 million remaining for development of the eastern part of the field. This work was suspended in late 2014 and further deferred until the NGL recovery plant was complete. We believe this project is economic in the current oil price environment and we expect it to be completed within the next two fiscal years. This would be nine years after the initial recording of proved reserves. During this period, we have been continuously developing the Delhi field and have spent over $35 million subsequent to reversion. We also have approximately $3.2 million of future net capital expenditures associated with the infill drilling program described above. Given the long-term nature of CO2 EOR development projects, we believe that the remaining undeveloped reserves in the Delhi field satisfy the conditions to continue to be treated as proved undeveloped reserves because (1) we initially established the development plan for the Delhi field in 2010 and continue to follow that plan, as adjusted to incorporate the completion of the NGL plant in late 2016 and delays relating to the 2013 fluid release event; (2) we have had significant ongoing development activities at this project that, as budgeted and currently being expended, reflect a significant and sufficient portion of remaining capital expenditures to convert proved undeveloped reserves to proved developed reserves; and (3) the operator has a historical record of completing the development of comparable long-term projects.
As of June 30, 2017, no proved, probable or possible reserves were attributed to (a) the suspended southwestern tip area of the field, (b) the area beneath the inhabited portion of the Town of Delhi in the northeast and (c) the farthest east of the two remaining undeveloped sites in the eastern portion of field (Phase VI) due to the current economics and other technical aspects of our future development plans. In addition, no probable reserves are currently attributed to three smaller reservoirs within the Unit in similar formations with similar production history due to the lower oil price utilized in our reserves calculation. We also

17

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do not have proved or probable reserves associated with the Mengel Sand, a separate interval within the Unit that is not currently producing, which was received in the litigation settlement in June 2016.
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, 2017
 
Year Ended 
 June 30, 2016
 
Year Ended 
 June 30, 2015
Product
Volume
 
Price
 
Volume
 
Price
 
Volume
 
Price
Crude oil (Bbls)
724,523

 
$
46.31

 
658,041

 
$
39.71

 
450,713

 
$
61.59

Natural gas liquids (Bbls)
43,907

 
$
21.28

 
491

 
$
16.06

 
1,358

 
$
27.41

Natural gas (Mcf)
16

 
$
(0.25
)
 
1,620

 
$
1.79

 
7,981

 
$
3.33

Average price per BOE*
768,433

 
$
44.88

 
658,802

 
$
39.68

 
453,401

 
$
61.37

 
 
 
 
 
 
 
 
 
 
 
 
Production costs
Amount
 
per BOE
 
Amount
 
per BOE
 
Amount
 
per BOE
Production costs, excluding ad valorem and production taxes
$
10,621,256

 
$
13.82

 
$
8,767,490

 
$
13.31

 
$
9,285,396

 
$
20.48

Total production costs, including ad valorem and production taxes
$
10,835,809

 
$
14.10

 
$
9,062,179

 
$
13.76

 
$
9,335,244

 
$
20.59

* BOE computed using a conversion ratio of six MCF's of natural gas to one barrel of oil equivalent. Natural gas liquids converted at 42 gallons to one barrel of oil equivalent.
Drilling Activity
Our productive drilling activity during the past three fiscal years ended June 30, 2017 was limited to one fiscal 2015 gross (0.239 net) development well drilled in the Delhi field. We also drilled one gross (0.239 net) water injection well in fiscal 2017 in the Delhi field. No dry wells were drilled in the past three fiscal years.
Present Activities
During fiscal year 2015, we commenced construction of a natural gas liquids ("NGL") recovery plant in the Delhi field, which was completed in December 2016.
During fiscal 2017, we drilled one water injection well as part of a project of four water injection wells connected to the continued development of Phase V in the eastern portion of the Delhi field. We also plan to drill eight infill wells in the field to increase production and ultimate reserves recovery. We have authorized expenditures for these projects totaling approximately $6.0 million. This spending was planned to commence in July 2017, but has been electively deferred by the operator until calendar 2018 based on a near-term capital budget reduction in response to weak oil prices.
For further discussion, see "Highlights for our fiscal year 2017" 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, 2017, we were not committed to provide a fixed and determinable quantity of oil, NGLs or gas under existing agreements, nor do we currently intend to enter into any such agreements.

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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, 2017.
 
Company Operated
 
Non-Operated
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Crude oil

 

 
104

 
24.8

 
104

 
24.8

Natural gas

 

 

 

 

 

Total

 

 
104

 
24.8

 
104

 
24.8

During the year ended June 30, 2017, we transferred one well in the Giddings field back to its previous operator under our contractual arrangement and later plugged and abandoned our two remaining wells in the field as none of the three wells were producing at economic rates in the existing price environment. We have no other wells operated by the Company at this time.
Our remaining wells consist solely of those in the Delhi field. Delhi has an estimated 104 productive oil wells. It also has approximately 45 CO2 injection wells and approximately 20 water injection wells. Certain of these wells may be shut-in from time to time and certain wells can potentially be converted to other purposes. Further, there may be other shut-in or previously abandoned well-bores in the field which can be reactivated. Accordingly, the active well count in the field is subject to change over time.
Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2017. 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.
 
Developed Acreage
 
Undeveloped Acreage
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Delhi Field, Louisiana *
9,126

 
2,180

 
4,510

 
1,077

 
13,636

 
3,257

When the Company acquired the Delhi field in 2003, the field had been fully developed through primary and secondary recovery and all of such acreage was reflected as developed acreage. With the addition of a CO2-EOR project in the field, certain acreage is now reflected as undeveloped using tertiary recovery operations. We estimate that our developed acreage currently includes 9,126 gross (2,180 net) acres in the Delhi field, with approximately 4,510 gross (1,077 net) acres attributable to the remaining undeveloped areas in the eastern part of the field. We own a 23.9% working interest in the field, along with certain mineral and royalty interests. We are not the operator of the EOR project.
Our interests includes all depths from the surface of the earth to the top of the Massive Anhydride, including the Delhi Holt Bryant Unit, which is currently under CO2 flood, and the Mengel Sand Interval, which is within the boundary of the field, but is currently not producing. As the Delhi field is unitized, all acreage, including any undeveloped, nonproductive or undrilled acreage is held by existing production as long as continuous production is maintained in the unit.
* This table excludes acreage attributable to small overriding royalty interests retained in various formations in the Giddings Field area. None of such acreage is currently producing and our interests are subject to expiration if leases are not maintained by others or commercial production is not established. It does not currently appear likely that we will obtain any significant value from these interests.
For more complete information regarding current year activities, including crude oil and natural gas production, refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.
Item 3.    Legal Proceedings
See Note 18 – Commitments and Contingencies under Item 8. Financial Statements for a description of legal proceedings, which is incorporated herein by reference.

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Item 4.    Mine Safety Disclosures
Not Applicable.


20

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PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
Our common stock is currently traded on the NYSE American under the ticker symbol "EPM". The following table shows, for each quarter of the fiscal years ended June 30, 2017 and 2016, the high and low sales prices for EPM as reported by the NYSE American.
NYSE American: EPM
2017:
High
 
Low
Fourth quarter ended June 30, 2017
$
8.45

 
$
6.75

Third quarter ended March 31, 2017
$
10.20

 
$
7.20

Second quarter ended December 31, 2016
$
10.20

 
$
6.35

First quarter ended September 30, 2016
$
6.85

 
$
5.12


2016:
High
 
Low
Fourth quarter ended June 30, 2016
$
5.97

 
$
4.45

Third quarter ended March 31, 2016
$
5.12

 
$
3.60

Second quarter ended December 31, 2015
$
7.54

 
$
4.70

First quarter ended September 30, 2015
$
6.70

 
$
4.02


Shares Outstanding and Holders
As of June 30, 2017, there were 33,087,308 shares of common stock issued and outstanding, held by approximately 224 holders of record. We estimate there are over 2,000 individuals and entities that hold our stock through nominees.
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. We increased our dividend rate to $0.065 per share, effective with the dividend payment in December 2016 and later raised its dividend rate to $0.07 per share, effective with the dividend payment in March 2017. As of June 30, 2017, we had paid fifteen consecutive quarterly dividends on our common stock. All dividends on our Series "A" Perpetual Preferred stock were timely declared and paid monthly prior to the redemption of such preferred stock. 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, our ability to continue to pay common stock dividends is dependent on compliance with certain financial covenants related to debt service coverage, as defined in the agreement.
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, 2012 to June 30, 2017 with the cumulative total return of the S&P 500 Index and the S&P Oil & Gas Exploration and Production Index of publicly traded companies over the same period. The graph assumes that $100 was invested on June 30, 2012 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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https://cdn.kscope.io/c6fa73a3f3a36fab874a0813a781969a-evolutionpet_chart-31139a05.jpg
Securities Authorized For Issuance Under Equity Compensation Plans
Plan category
Number of
securities to
be issued
upon exercise
of outstanding
options,
warrants and
rights
(a)
 
 
 
Weighted-average
exercise
price of
outstanding
Options, warrants
and rights
(b)
 
Number of securities
remaining
available for future
issuance under
equity compensation
plans (excluding
securities reflected
in column (a))(1)
Equity compensation plans approved by security holders:
 
 
 
 
 
 
 
    Outstanding options

 
(1)
 
$

 
 
    Outstanding contingent rights to shares
113,270

 
(1)
 

 
 
  Total
113,270

 
 
 
$

 
1,100,000

Equity compensation plans not approved by security holders

 
 
 

 

Total
113,270

 
 
 
$

 
1,100,000


(1)
As of June 30, 2017, all stock options had been exercised and no shares of common stock were issuable related to outstanding stock options. The Amended and Restated 2004 Stock Plan (the "Plan") provided for the issuance of a total of 6,500,000 common shares. Under the Plan as of June 30, 2017, 3,939,365 common shares had been issued upon the exercise of stock options, 2,382,843 shares of restricted common stock had been issued (of which 391,624 were unvested as of June 30, 2017), contingent restricted stock grants of 145,646 shares had been reserved (of which 113,270 were unvested as of June 30, 2017) and 32,146 remaining reserved shares were released in December 2016 to the Company's authorized but unissued and unreserved shares. The Plan was terminated upon the adoption of 2016 Equity Incentive Plan (the "2016 Plan"), which authorized the issuance of 1,100,000 shares of common stock. During fiscal 2017, no awards were made under the 2016 Plan.


22

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Issuer Purchases of Equity Securities
During the quarter ended June 30, 2017, the Company did not purchase any common stock in the open market under the previously announced share repurchase program and no shares of common stock were surrendered by employees in exchange for required payroll taxes arising from the vesting of restricted stock and/or exercise of stock options.
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,
 
2017
 
2016
 
2015
 
2014
 
2013
Income Statement Data
 
 
 
 
 
 
 
 
 
Revenues
$
34,484,896

 
$
26,349,502

 
$
27,841,265

 
$
17,673,508

 
$
21,349,920

Cost of revenues
10,835,809

 
9,133,111

 
9,355,613

 
1,193,573

 
1,780,738

Depreciation, depletion, and amortization
5,719,405

 
5,165,120

 
3,615,737

 
1,228,685

 
1,300,207

Accretion expense
59,664

 
49,054

 
34,866

 
41,626

 
72,312

General and administrative expense
4,985,408

 
9,079,597

 
6,256,783

 
8,388,291

 
7,495,309

Restructuring charges
4,488

 
1,257,433

 
(5,431
)
 
1,293,186

 

Income from operations
12,880,122

 
1,665,187


8,583,697

 
5,528,147

 
10,701,354

Other income (expense)
4,855

 
32,565,954

 
(147,619
)
 
(38,836
)
 
(43,165
)
Income tax provision
4,840,664

 
9,570,779

 
3,444,221

 
1,891,998

 
4,029,761

Net income attributable to the Company
$
8,044,313

 
$
24,660,362


$
4,991,857

 
$
3,597,313

 
$
6,628,428

Dividends on Series A Preferred Stock
250,990

 
674,302

 
674,302

 
674,302

 
674,302

Deemed dividend on preferred shares called for redemption
1,002,440

 

 

 

 

Net income attributable to common shareholders
$
6,790,883

 
$
23,986,060


$
4,317,555

 
$
2,923,011

 
$
5,954,126

Earnings per common share:
 
 
 
 
 
 
 
 
 
Basic
$
0.21

 
$
0.73

 
$
0.13

 
$
0.09

 
$
0.21

Diluted
$
0.21

 
$
0.73

 
$
0.13

 
$
0.09

 
$
0.19


 
June 30, 2017
 
June 30, 2016
 
June 30, 2015
 
June 30, 2014
 
June 30, 2013
Balance Sheet Data
 
 
 
 
 
 
 
 
 
Total current assets
$
26,142,527

 
$
37,086,450

 
$
23,693,048

 
$
26,304,803

 
$
27,436,076

Total assets
88,268,668

 
97,451,051

 
69,882,727

 
65,015,752

 
66,556,296

Total current liabilities
2,718,894

 
8,528,908

 
9,329,257

 
2,999,726

 
2,632,750

Total liabilities
19,798,813

 
21,129,901

 
21,306,150

 
13,138,230

 
11,720,135

Stockholders' equity
68,469,855

 
76,321,150

 
48,576,577

 
51,877,522

 
54,836,161

 
 
 
 
 
 
 
 
 
 
Number of common shares outstanding
33,087,308

 
32,907,863

 
32,845,205

 
32,615,646

 
28,608,969

 
 
 
 
 
 
 
 
 
 
Working capital, net
$23,423,633
 
$28,557,542
 
$14,363,791
 
$23,305,077
 
$24,803,326
 
 
 
 
 
 
 
 
 
 
Cash dividends to common stockholders
$8,432,435
 
$6,565,823
 
$9,833,642
 
$9,723,833
 
$


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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, Financial Statements and Supplementary Data. Our discussion and analysis includes forward-looking information that involves risks and uncertainties. It should be read in conjunction with Risk Factors under Item 1A of this Form 10-K, together with the statement of Forward-Looking Information at the beginning of this report for discussion of the risks and uncertainties that could cause our actual results to be materially different from those contained in our forward-looking statements.
Executive Overview
General
We are engaged primarily in the development and production of oil and gas reserves within known oil and gas reservoirs in the United States. 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 required beneficial ownership of our common stock.
Our strategy is to grow the value of our assets to maximize the value realized by our shareholders. In addition, we plan to continue to return cash to shareholders in the form of quarterly cash dividends and potential stock buybacks under our share repurchase program.
We expect to fund our share of fiscal 2018 expenditures in the Delhi field from working capital and net cash flows from the property.
Highlights for our fiscal year 2017
Financial
Our fiscal 2017 net income was 6.8 million, or $0.21 per share. This marks our sixth consecutive fiscal year of reporting positive net income.
We funded all operations, including $7.6 million of capital spending, from internal resources and remained debt free. We ended the fiscal year with at least $10 million of available liquidity under our credit facility, with no debt outstanding.
We returned $8.4 million to common shareholders in the form of cash dividends during fiscal 2017. With the increase in the quarterly common stock dividend to an annual rate of $0.30 effective September 2017, we have increased dividends by 50% from the annual rate of $0.20 a year ago. We remain committed to our dividend policy and rewarding our long-term shareholders.
We completed the redemption of our 8.5% Series A Cumulative Preferred Stock at a cost of $7.9 million. This will increase funds potentially available to common stockholders by $674,302 per year, or $0.02 per common share.
We ended the year with working capital of $23.4 million, down slightly from $28.6 million last year, but after funding all dividends, capital expenditures and the redemption of our preferred stock. Our strong balance sheet and working capital position have given us the stability to weather this industry downturn and provide an important resource for potential future acquisitions and growth. Our working capital at June 30, 2017 included $23.0 million of cash on hand.
Operations
Our net production volumes at Delhi increased by 17%, to 2,105 barrels of oil equivalent per day ("BOEPD") from 1,800 BOEPD in the prior year. The majority of this increase resulted from the continued conformance and production enhancement workover program in the Delhi field. Natural gas liquid ("NGL") volumes for part of the year also contributed to the production gain.

Our oil and NGL revenues were up over 31%, to $34.5 million from $26.1 million in fiscal 2016. In addition to higher net production volumes, we also experienced a 13% increase in our average price per barrel of oil equivalent ("BOE"), which rose to $44.88, from $39.68 per BOE in the prior year.


24

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The Delhi NGL Plant was completed in December 2016 and began production January 2017. The NGL plant had a final net cost of approximately $26.3 million and has been producing at approximately 70-75% of capacity since initial operations were stabilized. In August 2017, we completed inlet modifications to the CO2 recycle plant that have enabled the NGL plant to operate at full capacity. The NGL plant has been effective in removing methane and valuable NGL's to increase the purity of the CO2 stream and is expected to improve the efficiency of the CO2 flood.
Oil & Gas Reserves (based on SEC defined net oil price of $46.65 and NGL price of $20.48 per barrel)
Delhi proved oil equivalent reserves at June 30, 2017 were 10.1 MMBOE. After adjusting for production of approximately 0.8 MMBOE, our remaining net oil equivalent reserves were essentially flat with the prior year. The Standardized Measure (defined below) increased 6% to $83 million as a result of a higher oil and NGL prices, partially offset by an increase in future operating costs. Proved reserves are 83% oil and 17% natural gas liquids, with 79% of these proved reserves developed and producing.
Delhi probable oil equivalent reserves at June 30, 2017 were 5.3 MMBOE, an 18% increase over the prior year.
Delhi possible oil equivalent reserves at June 30, 2017 were 3.2 MMBOE, a 19% increase over the prior year.
The following table is a summary of our proved, probable and possible reserves for 2017 and 2016:
 
Proved
 
 
 
Probable
 
 
 
Possible
 
 
 
2017
 
2016
 
Change
 
2017
 
2016
 
Change
 
2017
 
2016
 
Change
Reserves MMBOE
10.1

 
10.8

 
(6
)%
 
5.3

 
4.5

 
18
%
 
3.2

 
2.7

 
19
%
% Developed
79
%
 
66
%
 
20
 %
 
82
%
 
69
%
 
19
%
 
89
%
 
72
%
 
24
%
Liquids %
100
%
 
100
%
 
 %
 
100
%
 
100
%
 
%
 
100
%
 
100
%
 
%
Standardized Measure ($MM)
$
83

 
$
78

 
6
 %
 
 
 
 
 
 
 
 
 
 
 
 
PV-10* ($MM)
$
111

 
$
101

 
10
 %
 
 
 
 
 


 
 
 
 
 


____________________________________________________________________________
*
PV-10 of Proved reserves is a pre-tax non-GAAP measure. We have included a reconciliation of PV-10 to the unaudited after-tax Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure"), which is the most directly comparable financial measure calculated in accordance with GAAP, in Item 2. "Properties." We believe that the presentation of the non-GAAP financial measure of PV-10 provides useful and relevant information to investors because of its wide use by analysts and investors in evaluating the relative monetary significance of oil and natural gas properties, and as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. We also use this pre-tax measure when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled in Item 2. Properties. Probable and possible reserves are not recognized as GAAP, nor is there a comparable GAAP measure.
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 99.1 of this Form 10-K.
Delhi Field EOR—Northeast Louisiana
Proved reserves volumes totaled 10.1 MMBOE with a Standardized Measure of $83 million and a PV-10* value of $111 million compared to the prior year's 10.8 MMBOE with a Standardized Measure of $78 million and a PV-10* value of $101 million. Our reserves quantities in the Delhi field were generally consistent with expectations year over year. Oil production in the field exceeded expectations in the fiscal year, and this led to a 0.5 MMBO (6%) positive revision in proved oil reserves. Results from the NGL plant were below our original expectations, and this resulted in a 0.5 MMBO (22%) negative revision to NGL reserves. Combined, these revisions had virtually no effect on equivalent reserves volumes. However with oil prices more than twice the level of NGL prices, the overall impact on value was positive.

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Probable reserve volumes at Delhi were 5.3 MMBOE, an increase of 18% compared to 4.5 MMBOE in the prior year. Possible reserves volumes at Delhi were 3.2 MMBOE, an increase of 19% compared to 2.7 MMBOE in the prior year. Both of these reserve estimates were increased based on positive production performance in the field and its expected positive impact on ultimate reserve recoveries.
Gross production at Delhi in the fourth quarter of fiscal 2017 was 8,559 BOEPD, essentially flat compared to 8,616 BOEPD in the third fiscal quarter. Oil production was 7,540 barrels of oil per day (“BOPD”), down 3% from the third fiscal quarter’s 7,786 BOPD. NGL production in the fourth quarter was 1,019 BOEPD, up 23% from the prior quarter of 830 BOEPD. Oil production was impacted in the fourth quarter due to a weather related power outage, compressor downtime and a planned facility shut down for maintenance.
During the past two years, we have participated in multiple conformance and re-entry projects, as well as workovers to convert idle wells into producers, that were primarily responsible for the increased production rates. We are continuing to evaluate similar projects within the field in order to optimize production and increase ultimate reserve recoveries.
Our cost of purchased CO2 in the Delhi field, the largest single component of operating costs, is directly tied to the price of oil sold from the field. Therefore this major operating cost has dropped commensurate with the price of crude. Also, we have been successful in realizing a sustained reduction in aggregate CO2 injection rates without impacting oil production rates. Gross CO2 injection rates for the year ended June 30, 2017 averaged 73.1 MMcf per day, a decline of 1% compared to the 73.8 MMcf per day during fiscal 2016. We have experienced increases to total lease operating expenses in the second half of fiscal 2017, primarily due to new costs associated with the NGL plant and prolonged issues with optimizing throughput and plant operations. We have also recently increased purchased CO2 injections, which has resulted in higher costs. Our overall lifting costs for the year were $14.10 per BOE, up slightly from $13.76 per BOE in the prior year. This remains a healthy field margin despite the prolonged low oil price environment.
Following the December 31, 2016 startup of the NGL plant, NGL sales commenced in mid-January 2017 and have been continuous ever since. In the fiscal year, we recorded over $0.9 million of NGL revenues. Our gross NGL production was 459 BOEPD and was sold at an average price of $21.28 per barrel. Production from the NGL plant is transported by truck to a fractionation plant in East Texas. Under the marketing contract, we receive market index pricing for each NGL component, based on the processed yield, less transportation and fractionation (or processing) fees. There may also be a quality deduction for NGL's that do not meet the purchaser's specifications. The current mix of products contains a large percentage (approximately 68%) of higher value NGL's, such as pentanes and butane, and almost no lower value ethane. Market pricing for NGL's during the winter period was seasonally high, but our price was affected by quality deductions on much of the NGL's produced during the fiscal year.
The NGL plant includes an electric turbine to convert methane and part of the ethane processed by the plant to electricity. This turbine is generating power for the NGL plant and is expected to supply excess power to the CO2 recycle facility, which we expect to lower our overall power costs in the Delhi field. During the initial two quarters of production, with the NGL plant operating at approximately 70-75% of capacity, we have not seen measurable savings in power costs. The NGL plant is accomplishing its primary objective of removing the lighter hydrocarbons (i.e. methane and ethane), thereby increasing the purity of the CO2 recycle stream and improving the efficiency of the flood. Over time, it is expected to increase the recovery of crude oil in the field. The plant is also providing feedstock to power the electric turbine and producing significant quantities of higher value NGL's for sale.
Remaining estimated capital expenditures for our proved undeveloped reserves amount to $6.71 per BOE for the infill drilling project and Phase V. No remaining capital expenditures are required to develop our probable or possible reserves as these reserves reflect incremental quantities associated with a greater percentage recovery of hydrocarbons in place than the recovery quantities assumed for proved reserves. Looking forward, the timing of plans for continued development of the eastern part of the Delhi field is dependent on the operator’s plans for capital allocation within their portfolio. We continue to believe that this high quality and economically viable project will be executed as planned, subject to oil price volatility.
Liquidity and Capital Resources
We had $23.0 million and $34.1 million in cash and cash equivalents at June 30, 2017 and June 30, 2016, respectively. In addition, we had $10 million of availability under our senior secured reserve-based credit facility on both dates. During the year ended June 30, 2017, we funded our operations and capital spending with cash generated from operations and cash on hand. As of June 30, 2017, our working capital was $23.4 million, compared to working capital of $28.6 million at June 30, 2016. The $5.2 million working capital decrease is primarily due to a $11.0 million decrease in cash, partly offset by a $0.1 million increase in prepaid expenses together with declines of $3.7 million and $1.5 million in accounts payable and accrued liabilities, respectively.

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On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility (the "Facility") with MidFirst Bank. The Facility provides a senior secured revolving credit facility with an elected borrowing base of $10 million (the “Borrowing Base”) and a maximum borrowing amount of $50 million. The Facility matures on April 11, 2019, and is secured by substantially all of the Company’s assets.
The Borrowing Base is subject to periodic redeterminations and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on May 15 and November 15 of each year. The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and changes to certain hedging positions. With volatility in commodity prices, our borrowing base and related commitments under the Facility could be reduced in the future. The Facility bears interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.0%.  In November 2016 and May 2017, as part of our semiannual borrowing base redeterminations, the lender's commitment, based on our requests, was reaffirmed at $10 million, with our next borrowing base redetermination scheduled for November 2017.
The Facility contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a debt service coverage ratio of not less than 1.1 to 1.0 and (iii) a consolidated tangible net worth of not less than $40 million, each as defined in the Facility. The Facility also contains other affirmative and negative covenants and events of default. As of June 30, 2017, the Company was in compliance with all covenants contained in the Facility, and no amounts were outstanding under the Facility.
We have historically funded our operations through cash available from operations and working capital. Our primary source of cash in fiscal 2017 were funds generated from the sale of oil and natural gas liquids production. A portion of these cash flows were used to fund our capital expenditures. While we expect to continue to expend capital to further develop the Delhi field, we and the operator have flexibility as to when this capital is spent. Certain projects were recently electively delayed by the operator based on their funds available for capital spending in the current oil price environment. The Company expects to manage future development activities in the Delhi field within the boundaries of its operating cash flow and existing working capital.
Cash Flows from Operating Activities
For the year ended June 30, 2017, cash flows provided by operating activities were $16.5 million, reflecting $19.0 million provided by operations before $2.5 million used by other working capital changes. Of the $19.0 million provided before working capital changes, approximately $8.0 million resulted from net income and $10.9 million was attributable to non-cash expenses and gains.
For the year ended June 30, 2016, cash flows provided by operating activities were $30.7 million, reflecting $28.9 million provided by operations before $1.8 million provided by other working capital changes. Of the $28.9 million provided before working capital changes, approximately $24.7 million resulted from net income and $4.2 million was attributable to non-cash expenses and gains.
For the year ended June 30, 2015, cash flows provided by operating activities were $10.4 million, reflecting $10.9 million provided by operations before $0.5 million used by other working capital changes. Of the $10.9 million provided before working capital changes, approximately $5.0 million resulted from net income and $5.9 million was attributable to non-cash expenses and gains.
Cash Flows from Investing Activities
For the year ended June 30, 2017, investing activities used $10.5 million of cash, consisting primarily of cash capital expenditures of approximately $10.2 million for Delhi field, partially offset by $0.3 million of derivative settlements paid.
For the year ended June 30, 2016, investing activities used $17.6 million of cash, consisting primarily of cash capital expenditures of approximately $21.1 million for the Delhi field, partially offset by $3.6 million of derivative settlement payments received.
For the year ended June 30, 2015, investing activities used $5.0 million of cash, consisting primarily of cash 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 from the sale of properties in the Mississippi Lime project in October 2014.
Oil and gas capital expenditures incurred, which includes accrued and other noncash expenditures, were $7.6 million, $19.7 million, and $11.2 million, respectively, for the years ended June 30, 2017, 2016, and 2015. 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 Disclosure of Cash Flow Information.

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Cash Flows from Financing Activities
For the year ended June 30, 2017, financing activities used $17.1 million of cash, comprised of $8.4 million of common stock cash dividends, $0.3 million of preferred dividends, $7.9 million for redemption of preferred stock in November 2016 and $0.5 million of treasury stock acquired through the surrender of shares in satisfaction of payroll liabilities related to vestings of stock-based compensation.
For the year ended June 30, 2016, financing activities provided $0.9 million of cash from $9.6 million of tax benefits related to stock-based compensation partially offset by $7.2 million of dividend payments to common and preferred shareholders and $1.4 million of treasury stock acquisitions primarily attributable to the Company's share buyback program. The tax benefits included a $1.5 million cash refund received from the State of Louisiana for carryback of stock-based compensation deductions to previously filed returns.
During the year ended June 30, 2015, we used $9.2 million in cash for financing activities, comprised of $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.
Capital Budget
During fiscal 2017, our net share of capital expenditures was approximately $7.6 million, of which $4.8 million was related to the NGL plant, with the balance for conformance projects, capital maintenance and repairs and drilling a new water injection well.
An infill drilling program is planned for the second half of fiscal 2018 with an estimated net cost of $3.2 million. This program will consist of three new CO2 injection wells and five new production wells and will target productive oil zones which we believe are not being swept effectively by the current CO2 flood. This infill program is expected to both add production and increase ultimate recoveries above the current proved oil reserves.
We have identified and approved additional net capital expenditures over the next fiscal year totaling $2.8 million for water injection and other infrastructure projects in preparation for the Phase V pattern development. In addition, there will continue to be conformance workover projects and maintenance capital expenditures that cannot be estimated accurately at this time. The amount of these projects is not expected to be material to our financial position.
With the NGL plant completed, there are two remaining capital project phases planned to exploit the eastern part of the Delhi field. The first phase of this project, Phase V, 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 Phase V project, which has an estimated cost of $10.9 million net to our working interest, has favorable economics, even in this lower price environment, and, based on discussions with the operator, expect the related expansion of the CO2 flood to resume in fiscal 2019. The last phase of the project, Phase VI, has less favorable economics and will require a significant increase in oil prices or other improvements to the economics of the project before it is expected to move forward.
  Funding for our anticipated capital expenditures at Delhi over the next fiscal year is expected to be met from cash flows from operations and current working capital.
Liquidity Outlook
Our current liquidity position is very strong, with $23.4 million of working capital, which is significantly in excess of our expected capital needs. We also expect positive cash flow in the future. Our future liquidity is dependent on the realized prices we receive for the oil 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 short term oil price volatility with the goal of achieving a more predictable level of cash flows to support the Company’s capital expenditure and dividend programs. From time to time, the Company has used both fixed price swap agreements and costless collars to manage its exposure to crude oil price risk. We have no derivative commitments at June 30, 2017. While the use of 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 will be significantly impacted by the prices we receive for our production.
Funding for our anticipated capital expenditures over the next two fiscal years is expected to be met from cash flows from operations and current working capital. Our preference is to remain debt free under our current operating plans, but we have

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access to at least $10 million of availability under a senior secured credit facility if required. In addition we have a maximum of $500 million authorized under an effective shelf registration statement with Securities and Exchange Commission under which we may sell securities from time to time in one or more offerings. We may choose to evaluate and pursue new growth opportunities through acquisitions or other transactions. In that event, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do so at this time.
The Board of Directors instituted a cash dividend on our common stock in December 2013 and we have since paid fifteen consecutive quarterly dividends. Distribution of free cash flow in excess of our operating and capital requirements through cash dividends and potential 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. With construction of the NGL plant completed during fiscal 2017, we announced an increase in the common stock cash dividend to $0.065 per share, effective with the dividend payment in December 2016. Following the redemption of our preferred stock and the end of its dividend requirement, we announced a further increase in the common stock dividend to $0.07 per share, effective with the dividend payment in March 2017. In August 2017, the Company announced a further increase in the common stock cash dividend to $0.075 per share, effective with the dividend payment in September 2017. The Board of Directors reviews the quarterly dividend rate in light of current financial results and operations, forecasted financial results, the timing of further expansion of Delhi development and the outlook for crude oil prices.

In May 2015, we established a stock repurchase plan to allow us to acquire up to $5.0 million of our common stock over time. We have repurchased $1.6 million of common stock under the plan, but made no repurchases during fiscal 2017. The timing and amount of repurchases will depend upon several factors, including financial resources and market conditions. In general, our share repurchase program is limited to discretionary funds and is of lesser importance than our primary objectives related to our development capital spending at Delhi and our common stock dividend program. There is no fixed termination date for the repurchase program, and the repurchase program may be suspended or discontinued at any time.
New Accounting Pronouncements Adopted
As discussed in Note 2 "Summary of Significant Accounting Policies," the Company early adopted two new accounting pronouncements, effective for the three months ended September 30, 2016, the first quarter of fiscal year 2017.
ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting. Under previous guidance excess tax benefits were recognized as paid in capital to the extent they reduced cash taxes otherwise payable, and tax deficiencies were recognized as an offset to accumulated excess benefits, if any, or in the statement of operations. The new guidance requires companies to record excess tax benefits and tax deficiencies as income tax benefit or expense in the statements of operations when the awards vest or are settled. Under the required modified retrospective transition, the Company had no cumulative-effect adjustment to retained earnings at the beginning of the period of adoption, as its accumulated excess tax benefits had been completely used in reducing taxable income for the year ended June 30, 2016. The Company elected to prospectively adopt the presentation of excess tax benefits in the operating section of the statements of cash flows. Accordingly, such statements for pre-adoption periods will continue to present excess tax benefits in the financing section. For vestings that occurred in the year ended June 30, 2017, a related tax deficiency of $27,884 was included in the operating section of the statement of cash flows as income tax expense and for the year ended June 30, 2016, $9.7 million of cash provided by tax benefits related to stock-based compensation was included in the financing section of statement of cash flow. Except for the accounting for income taxes discussed above, none of the other provisions in this amended guidance had a material impact on our condensed consolidated financial statements.
ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. The update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. As a result, current deferred tax assets have been netted together with noncurrent deferred income tax liabilities on the June 30, 2017 consolidated balance sheet. The prior years presented were not retroactively adjusted.

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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,
 
2017
 
2016
 
2015
Oil and gas production:
 
 
 
 
 
Crude oil revenues
$
33,550,698

 
$
26,130,762

 
$
27,761,291

NGL revenues
934,202

 
7,885

 
37,227

Natural gas revenues
(4
)
 
2,895

 
26,601

Total revenues
$
34,484,896

 
$
26,141,542

 
$
27,825,119

 
 
 
 
 
 
Crude oil volumes (Bbl)
724,523

 
658,041

 
450,713

NGL volumes (Bbl)
43,907

 
491

 
1,358

Natural gas volumes (Mcf)
16

 
1,620

 
7,981

Equivalent volumes (BOE)
768,433

 
658,802

 
453,401

 
 
 
 
 
 
  Crude oil (BOPD, net)
1,985

 
1,798

 
1,235

  NGLs (BOEPD, net)
120

 
1

 
4

  Natural gas (BOEPD, net)

 
1

 
4

 Equivalent volumes (BOEPD, net)
2,105

 
1,800

 
1,242

 
 
 
 
 
 
Crude oil price per Bbl
$
46.31

 
$
39.71

 
$
61.59

NGL price per Bbl
21.28

 
16.06

 
27.41

Natural gas price per Mcf
(0.25
)
 
1.79

 
3.33

Equivalent price per BOE
$
44.88

 
$
39.68

 
$
61.37

 
 
 
 
 
 
CO2 costs
$
4,477,866

 
$
4,090,938

 
$
5,050,506

All other lease operating expenses (a)
6,357,943

 
4,971,241

 
4,284,738

Production costs
$
10,835,809

 
$
9,062,179

 
$
9,335,244

Production costs per BOE
$
14.10

 
$
13.76

 
$
20.59

 
 
 
 
 
 
CO2 volumes (Mcf, gross)
26,664,188

 
26,996,624

 
25,615,144

CO2 volumes (MMcf per day, gross)
73.1

 
73.8

 
70.2

 
 
 
 
 
 
Oil and gas DD&A (b)
$
5,687,903

 
$
4,906,123

 
$
3,220,990

Oil and gas DD&A per BOE
$
7.40

 
$
7.45

 
$
7.10

 
 
 
 
 
 
Artificial lift technology services:
 
 
 
 
 
Services revenues
$

 
$
207,960

 
$
16,146

Cost of service

 
70,932

 
20,369

Depreciation and amortization expense
$

 
$
238,475

 
$
374,371

(a) Includes ad valorem and production taxes of $214,553, $294,689, and $49,848 for the years ended June 30, 2017, 2016, and 2015, respectively.
(b) Excludes depreciation and amortization expense of artificial lift technology services below and excludes non-operating asset depreciation of $31,502, $20,522, and $20,376 for the years ended June 30, 2017, 2016, and 2015, respectively.

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Year ended June 30, 2017 compared with the Year ended June 30, 2016
Net Income. For the year ended June 30, 2017, we generated net income of $6.8 million, or $0.21 per diluted share, on total revenues of $34.5 million. This compares to net income of $24.0 million, or $0.73 per diluted share, on total revenues of $26.1 million for the corresponding year-ago period.  The $17.2 million earnings decrease principally resulted from a decrease of $32.6 million in other income, reflecting a prior year $28.1 million litigation settlement, a $3.4 million decrease in derivative instrument gains, and a $1.1 million prior year insurance settlement together with a $0.6 million increase in allocated net income to holders of called preferred shares, partially offset by $8.1 million of higher revenue, $3.1 million of decreased operating costs, and $4.7 million of lower income taxes.
Oil and Gas Production. Revenues increased 31.9% to $34.5 million primarily as a result of a 16.6% increase in production volumes from the year-ago period together with a 13.1% increase in realized prices from $39.68 per equivalent barrel to $44.88 per barrel in the current year. Delhi production and revenues comprise virtually all of our revenues. Net Delhi oil production of 1,985 BOPD was 10.4% higher compared to the prior year as a result of production enhancement and conformance operations in the field. In addition $0.9 million of initial plant NGL sales commenced at the beginning of our third fiscal quarter and averaged 120 BOEPD over the entire fiscal year.
Production Costs. Production costs for the year ended June 30, 2017 were $10.8 million, a 19.6% increase from the prior year. CO2 costs for the current year were $4.5 million, or 9.5% higher than the prior year, due to a higher CO2 price partially offset by a 1.2% decrease in purchase volumes as a result of operational efficiencies. The current year average gross CO2 injection rate was 73.1 MMcf per day, compared to 73.8 MMcf per day in the prior year. For the current year, production costs were $14.10 per barrel on total production volumes, compared to $13.76 per BOE in the prior year. Calculated solely on our Delhi working interest volumes, production costs were $19.01 per barrel of which $8.03 per barrel was COcost. These latter production costs per barrel exclude production volumes from our royalty interests in the Delhi field as they bear only certain allocated NGL production costs, and are therefore higher than the rates per barrel on our total production volumes.
General and Administrative Expenses (“G&A”). G&A expenses decreased $4.1 million, or 45%, from the prior year, to $5.0 million for the year ended June 30, 2017, primarily due to a $2.6 million decrease in litigation costs, a $0.6 million decrease in stock-based compensation, $0.5 million of lower bonus expense, and $0.5 million of lower salary and benefit expenses.
Other Income and Expenses. For the year ended June 30, 2017, aggregate other items decreased $32.6 million from the prior year due to the $28.1 million Delhi field litigation settlement in the prior year, a $3.4 million decrease in derivative gains and a $1.1 million insurance recovery in the prior year.
Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A increased $0.6 million, or 11%, to $5.7 million for the year ended June 30, 2017 compared to the prior year, due to an increase of $0.8 million in full cost pool depletion, partially offset by a $0.2 million decrease in fixed asset depreciation, which was impacted by the prior year impairment of artificial lift equipment. Compared to the prior year, the increase in full cost pool amortization reflects a 16.6% production increase to 0.8 million BOE, partially offset by a small 0.7% decrease in the amortization rate to $7.40 per BOE.
Year ended June 30, 2016 ("Fiscal 2016") compared with the Year ended June 30, 2015 ("Previous Year")
Net Income. For the year ended June 30, 2016, we generated net income of $24.0 million, or $0.73 per diluted share, on total revenues of $26.3 million. This compares to net income of $4.3 million, or $0.13 per diluted share, on total revenues of $27.8 million for the previous year.  The $19.7 million increase in earnings resulted from $28.1 million from the Delhi field litigation settlement, $1.1 million from an insurance recovery, and $3.5 million of derivative gains, partially offset by $6.1 million of higher income taxes, $1.5 million of lower revenue, and $5.4 million of higher operating expenses (which includes a $1.3 million non-recurring restructuring charge).
Oil and Gas Production. Revenues decreased $1.7 million to $26.1 million primarily as a result of a 35% decline in realized prices from $61.37 per equivalent barrel in the previous year to $39.68 per barrel in fiscal 2016, partially offset by a 45% increase in production volumes. The previous year did not include a full twelve months of net production and revenues or production costs as reversion of our working interest did not occur until November 1, 2014. Delhi oil production and revenues comprise virtually all of our revenues. Delhi gross production of 6,778 BOPD was 12% higher that the average gross production of 6,038 BOPD in the previous year as a result of production enhancement and conformance operations in the field.
Production Costs. Production costs for fiscal 2016 decreased $0.2 million to $9.1 million from $9.3 million in the previous year due to a $0.6 million decrease for the Company's operated wells as a result of previous year workover expense, partially offset by $0.4 million increase at the Delhi field. Delhi production costs for fiscal 2016 were $8.9 million, of which $4.1 million was for CO2 costs, compared to previous year production costs of $8.5 million, of which $5.1 million was for CO2 costs. Average gross injection volumes decreased from 105,848 Mcf per day in the post-reversion previous year period to

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73,762 Mcf per day for the year ended June 30, 2016. For the year ended June 30, 2016, production costs were $13.76 per BOE on total production volumes. Production costs were $18.90 per BOE calculated solely on our Delhi working interest volumes, which includes $8.66 per working interest BOE for CO2 costs. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, which bear no production costs, and are therefore higher than the rates per BOE on our total production volumes.
Artificial Lift Technology Services. Service revenues were $0.2 million for the year ended June 30, 2016 as a result of fiscal 2016 installations at third party wells. Prior year service revenues and costs were negligible.
Cost of Artificial Lift Technology Services. Cost of technology services were $0.1 million for the year ended June 30, 2016 as a result of fiscal 2016 project activity.
General and Administrative Expenses (“G&A”). G&A expenses increased $2.8 million, or 45%, from the previous year, to $9.1 million for the year ended June 30, 2016, as a result of a $1.7 million increase in litigation costs and a $0.8 million increase in stock compensation expense. Total litigation costs for fiscal 2016 were approximately $2.7 million. In June 2016, we relocated our office to substantially smaller and less expensive premises. This cost savings will be reflected in future periods.
Restructuring charge. Effective December 31, 2015, we recognized a $1.3 million restructuring charge related to the separation of our GARP® artificial lift technology operations. Approximately $0.6 million of the charge consists of the impairment of assets used in that operation and $0.6 million was associated with accrued personnel termination costs to be paid from January 2016 through June 2017. The restructuring charge also includes approximately $0.1 million of non-cash stock compensation expense from the accelerated vesting of restricted stock. As a result of the restructuring, future annual overhead cost savings are estimated to be approximately $1.0 million per year.
Other Income and Expenses. During the year ended June 30, 2016, the Company realized gains of $28.1 million from the Delhi field litigation settlement, $3.4 million of gains on derivatives and $1.1 million from an insurance recovery at the Delhi field.
Depletion & Amortization Expense (“DD&A”).  DD&A increased $1.5 million, or 43% to $5.2 million for fiscal 2016 compared to $3.6 million for the previous year as a result of $1.7 million of higher amortization of the full cost pool, partially offset by $0.1 million of lower depreciation on artificial lift technology. Compared to the previous year, production volumes increased 45% to 0.7 million BOE and the amortization rate increased 5% to $7.45 per BOE. Compared to the previous year, the higher amortization rate was due to an 18% decrease in our pool of unamortized costs, partially offset by a 13% decline in proved reserves BOE.
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 2017, we have seen a firming of prices for operating and capital costs as a result of improving demand and a closer balance with the supply of goods and services in the industry. Product prices, operating costs and development costs may not always move in tandem.
Known Trends and Uncertainties.  General worldwide economic conditions, as well as economic conditions for the oil and gas industry specifically, continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries and companies, as well as consumers, which impact demand for crude oil and natural gas. If the supply of crude oil and natural gas continues to exceed demand in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues, profits, cash flow and working capital going forward.
Seasonality.  Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products.  Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather, including hurricanes, that may substantially affect oil and natural gas production and imports.

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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, 2017, 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
 

1 Year or Less
 
1 - 3 Years
 
3 - 5 Years
 
More than 5 Years
Contractual Obligations
 
 
 
 
 
 
 
 
 
Operating lease
$
140,057

 
$
73,073

 
$
66,984

 

 

Other Obligations
 
 
 
 
 
 
 
 
 
Asset retirement obligations
1,288,743

 
35,115

 

 

 
1,253,628

Total obligations
$
1,428,800

 
$
108,188

 
$
66,984

 
$

 
$
1,253,628

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, 2017, 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 as of June 30, 2017 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, 2017 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $329,000, $696,000 and $1,106,000, 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

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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, 2017, 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.    The fair value and expected vesting period of the Company's market-based awards were determined using a Monte Carlo simulation based on the historical volatility of our total common stock return compared to the historical volatilities of the other companies in the index. Vesting of market-based awards is based on the Company's total common stock return compared to a peer group of other companies in our industry with comparable market capitalizations. 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, 2017.
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 NGL's. 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. We primarily utilize swaps and costless collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes. The Company had no positions in derivative instruments at June 30, 2017.

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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, 2017 and 2016, 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, 2017. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
 We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 consolidated financial position of Evolution Petroleum Corporation and subsidiaries as of June 30, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2017, 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, 2017, 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 15, 2017 expressed an unqualified opinion on the effectiveness of the Evolution Petroleum Corporation and subsidiaries' internal control over financial reporting.

Hein & Associates LLP
Houston, Texas
September 15, 2017

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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 and subsidiaries' (the "Company") internal control over financial reporting as of June 30, 2017, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. The Company’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, the Company maintained, in all material respects, effective internal control over financial reporting as of June 30, 2017, 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, 2017 and 2016, 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, 2017 and our report dated September 15, 2017 expressed an unqualified opinion.

Hein & Associates LLP
Houston, Texas
September 15, 2017

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
 
June 30, 2017
 
June 30, 2016
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
23,028,153

 
$
34,077,060

Receivables
2,726,702

 
2,638,188

Deferred tax asset

 
105,321

Prepaid expenses and other current assets
387,672

 
265,881

Total current assets
26,142,527

 
37,086,450

Property and equipment, net of depreciation, depletion, and amortization
 
 
 
Oil and natural gas property and equipment, net (full-cost method of accounting)
61,790,068

 
59,970,463

Other property and equipment, net
40,689

 
28,649

Total property and equipment
61,830,757

 
59,999,112

Other assets
295,384

 
365,489

Total assets
$
88,268,668

 
$
97,451,051

Liabilities and Stockholders' Equity
 
 
 
Current liabilities
 
 
 
Accounts payable
$
2,101,055

 
$
5,809,107

Accrued liabilities and other
617,839

 
2,097,951

State and federal taxes payable

 
621,850

Total current liabilities
2,718,894

 
8,528,908

Long term liabilities
 
 
 
Deferred income taxes
15,826,291

 
11,840,693

Asset retirement obligations, net of current portion
1,253,628

 
760,300

Total liabilities
19,798,813

 
21,129,901

Commitments and contingencies (Note 18)

 

Stockholders' equity
 
 
 
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated; no shares outstanding at June 30, 2017 as all shares were redeemed November 14, 2016 (Note 10); and 317,319 shares issued and outstanding at June 30, 2016 with a liquidation preference of $7,932,975 ($25.00 per share)

 
317

Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,087,308 and 32,907,863 shares as of June 30, 2017 and 2016, respectively
33,087

 
32,907

Additional paid-in capital
40,961,957

 
47,171,563

Retained earnings
27,474,811

 
29,116,363

Total stockholders' equity
68,469,855

 
76,321,150

Total liabilities and stockholders' equity
$
88,268,668

 
$
97,451,051









   See accompanying notes to consolidated financial statements.

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
 
Years Ended June 30,
 
2017
 
2016
 
2015
Revenues
 
 
 
 
 
Crude oil
$
33,550,698

 
$
26,130,762

 
$
27,761,291

Natural gas liquids
934,202

 
7,885

 
37,227

Natural gas
(4
)
 
2,895

 
26,601

Artificial lift technology services

 
207,960

 
16,146

Total revenues
34,484,896

 
26,349,502

 
27,841,265

Operating costs
 
 
 
 
 
Production costs
10,835,809

 
9,062,179

 
9,335,244

Cost of artificial lift technology services

 
70,932

 
20,369

Depreciation, depletion and amortization
5,719,405

 
5,165,120

 
3,615,737

Accretion of discount on asset retirement obligations
59,664

 
49,054

 
34,866

General and administrative expenses*
4,985,408

 
9,079,597

 
6,256,783

Restructuring charges (income)
4,488

 
1,257,433

 
(5,431
)
Total operating costs
21,604,774

 
24,684,315

 
19,257,568

Income from operations
12,880,122

 
1,665,187

 
8,583,697

Other
 
 
 
 
 
Gain on realized derivative instruments, net
43,890

 
3,315,123

 

Gain (loss) on unrealized derivative instruments, net
(14,132
)
 
124,106

 
(109,974
)
Delhi field litigation settlement

 
28,096,500

 

Delhi field insurance recovery related to pre-reversion event

 
1,074,957

 

Interest and other income
56,855

 
26,211

 
35,991

Interest expense
(81,758
)
 
(70,943
)
 
(73,636
)
Income before income tax provision
12,884,977

 
34,231,141

 
8,436,078

Income tax provision
4,840,664

 
9,570,779

 
3,444,221

Net income attributable to the Company
8,044,313

 
24,660,362

 
4,991,857

Dividends on preferred stock
250,990

 
674,302

 
674,302

Deemed dividend on preferred shares called for redemption
1,002,440

 

 

Net income attributable to common shareholders
$
6,790,883

 
$
23,986,060

 
$
4,317,555

Earnings per common share
 
 
 
 
 
Basic
$
0.21

 
$
0.73

 
$
0.13

Diluted
$
0.21

 
$
0.73

 
$
0.13

Weighted average number of common shares outstanding
 
 
 
 
 
Basic
33,034,480

 
32,810,375

 
32,817,456

Diluted
33,110,560

 
32,861,231

 
32,924,018

_______________________________________________________________________________
*
General and administrative expenses for the years ended June 30, 2017, 2016 and 2015 included non-cash stock-based compensation expense of $1,180,618, $1,750,209, and $943,653, respectively. These years also included litigation expenses of $127,435, $2,729,755, and $1,015,105, respectively.

See accompanying notes to consolidated financial statements.

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
 
Years Ended June 30,
 
2017
 
2016
 
2015
Cash flows from operating activities
 
 
 
 
 
Net income attributable to the Company
$
8,044,313

 
$
24,660,362

 
$
4,991,857

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation, depletion and amortization
5,775,946

 
5,211,494

 
3,664,373

Impairments included in restructuring charge

 
569,228

 

Stock-based compensation
1,180,618

 
1,809,548

 
943,653

Accretion of discount on asset retirement obligations
59,664

 
49,054

 
34,866

Settlement of asset retirement obligations
(157,910
)
 

 
(223,564
)
Deferred income taxes
4,090,919

 
575,235

 
1,422,489

Deferred rent

 

 
(17,145
)
(Gain) loss on derivative instruments, net
(29,758
)
 
(3,439,229
)
 
109,974

Noncash gain on Delhi field litigation settlement

 
(596,500
)
 

Write-off of deferred loan costs

 
50,414

 

Changes in operating assets and liabilities:
 
 
 
 
 
Receivables
(88,514
)
 
484,285

 
(1,665,261
)
Prepaid expenses and other current assets
(135,923
)
 
24,754

 
378,049

Accounts payable and accrued expenses
(1,626,648
)
 
822,730

 
551,452

Income taxes payable
(621,850
)
 
431,818

 
190,032

Net cash provided by operating activities
16,490,857

 
30,653,193

 
10,380,775

Cash flows from investing activities
 
 
 
 
 
Derivative settlements received (paid)
(272,318
)
 
3,633,831

 

Proceeds from asset sales

 

 
398,242

Capital expenditure for development of oil and natural gas properties
(10,158,960
)
 
(21,095,901
)
 
(4,890,909
)
Capital expenditures for technology and other equipment
(32,260
)
 
(6,883
)
 
(313,059
)
Other assets

 
(161,345
)
 
(236,559
)
Net cash used by investing activities
(10,463,538
)
 
(17,630,298
)
 
(5,042,285
)
Cash flows from financing activities
 
 
 
 
 
Proceeds from the exercise of stock options

 
51,000

 
141,600

Common share repurchases, including shares surrendered for tax withholding
(459,858
)
 
(1,357,185
)
 
(333,841
)
Cash dividends to common stockholders
(8,432,435
)
 
(6,565,823
)
 
(9,833,642
)
Cash dividends to preferred stockholders
(250,990
)
 
(674,302
)
 
(674,302
)
Redemption of preferred shares
(7,932,975
)
 

 

Deferred loan costs

 
(168,972
)
 
(94,075
)
Tax benefits related to stock-based compensation

 
9,650,657

 
1,633,946

Other
32

 
33

 
67

Net cash provided (used) by financing activities
(17,076,226
)
 
935,408

 
(9,160,247
)
Net increase (decrease) in cash and cash equivalents
(11,048,907
)
 
13,958,303

 
(3,821,757
)
Cash and cash equivalents, beginning of year
34,077,060

 
20,118,757

 
23,940,514

Cash and cash equivalents, end of year
$
23,028,153

 
$
34,077,060

 
$
20,118,757


See accompanying notes to consolidated financial statements.

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
For the Years Ended June 30, 2017, 2016 and 2015
 
Preferred
 
Common Stock
 
 
 
 
 
 
 
 
 
Additional
Paid-in
Capital
 
Retained
Earnings
 
Treasury
Stock
 
Total
Stockholders'
Equity
 
Shares
 
Par Value
 
Shares
 
Par Value
 
Balance, June 30, 2014
317,319

 
$
317

 
32,615,646

 
$
32,615

 
$
34,632,377

 
$
17,212,213

 
$

 
$
51,877,522

Issuance of restricted common stock

 

 
213,466

 
214

 
(147
)
 

 

 
67

Exercise of stock options

 

 
87,000

 
87

 
141,513

 

 

 
141,600

Common share repurchases, including shares surrendered for tax withholding

 

 
(70,907
)
 

 

 

 
(504,124
)
 
(504,124
)
Retirements of treasury stock

 

 

 
(71
)
 
(504,053
)
 

 
504,124

 

Stock-based compensation

 

 

 

 
943,653

 

 

 
943,653

Tax benefits related to stock-based compensation

 

 

 

 
1,633,946

 

 

 
1,633,946

Net income

 

 

 

 

 
4,991,857

 

 
4,991,857

Common stock cash dividends