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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, 2019
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)

https://cdn.kscope.io/2530c44491e8566ba7cc39a39d13ae77-epclogo4qandksa02.jpg
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
 
Trading Symbol(s)
 
Name of Each Exchange On Which Registered
Common Stock, $0.001 par value
 
EPM
 
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 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
 
Smaller reporting company  ý
 
 
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, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $6.75 on the NYSE American was $158,319,105.
The number of shares outstanding of the registrant's common stock, par value $0.001, as of September 6, 2019, was 33,064,797.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant's 2019 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.



EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
2019 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
 
 
 
 

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.

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FORWARD-LOOKING STATEMENTS


This Form 10-K and the information referenced herein contains 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 Part I, Item 1A, "Risk Factors" and elsewhere in this report and as also may be described from time to time in our future reports we file with the Securities and Exchange Commission. You should read such information in conjunction with our consolidated condensed financial statements and related notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ materially from our expectations.

Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements other than as required by law. You are advised, however, to review any further disclosures we make on related subjects in our periodic filings with the Securities and Exchange Commission.


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GLOSSARY OF SELECTED PETROLEUM TERMS

The following abbreviations and definitions are terms commonly used in the crude oil and natural gas industry and throughout this form 10-K:
"BBL." A standard measure of volume for crude oil and liquid petroleum products; one barrel equals 42 U.S. gallons.
"BCF." Billion Cubic Feet of natural gas at standard temperature and pressure.
"BOE." Barrels of oil equivalent. BOE is calculated by converting 6 MCF of natural gas to 1 BBL of oil.
"BOPD." Barrels of oil per day.
"BTU" or "British Thermal Unit." The standard unit of measure of energy equal to the amount of heat required to raise the temperature of one pound of water 1 degree Fahrenheit. One Bbl of crude is typically 5.8 MMBTU, and one standard MCF is typically one MMBTU.
"CO2." Carbon dioxide, a gas that can be found in naturally occurring reservoirs, typically associated with ancient volcanoes, and also is a major byproduct from manufacturing and power production also utilized in enhanced oil recovery through injection into an oil reservoir.
"Developed Reserves." Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
"EOR." Enhanced Oil Recovery projects involve injection of heat, miscible or immiscible gas, or chemicals into oil reservoirs, typically following full primary and secondary waterflood recovery efforts, in order to gain incremental recovery of oil from the reservoir.
"Field." An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geologic structural feature and/or stratigraphic feature.*
"Farmout." Sale or transfer of all or part of the operating rights from the working interest owner (the assignor or farm-out party), to an assignee (the farm-in party) who assumes all or some of the burden of development, in return for an interest in the property. The assignor may retain an overriding royalty or any other type of interest. For Federal tax purposes, a farm-out may be structured as a sale or lease, depending on the specific rights and carved out interests retained by the assignor.
"Gross Acres or Gross Wells." The total acres or number of wells participated in, regardless of the amount of working interest owned.
"Horizontal Drilling." Involves drilling horizontally out from a vertical well bore, thereby potentially increasing the area and reach of the well bore that is in contact with the reservoir.
"Hydraulic Fracturing." Involves pumping a fluid with or without particulates into a formation at high pressure, thereby creating fractures in the rock and leaving the particulates in the fractures to ensure that the fractures remain open, thereby potentially increasing the ability of the reservoir to produce oil or gas.
"LOE." Means lease operating expense(s), a current period expense incurred to operate a well.
"MBO." One thousand barrels of oil
"MBOE." One thousand barrels of oil equivalent.
"MCF." One thousand cubic feet of natural gas at standard conditions, being approximately sea level pressure and 60 degrees Fahrenheit temperature. Standard pressure in the state of Louisiana is deemed to be 15.025 psi by regulation, but varies in other states.
"MMBOE." One million barrels of oil equivalent.
"MMBTU." One million British thermal units.
"MMCF." One million cubic feet of natural gas at standard temperature and pressure.
"Mineral Royalty Interest." A royalty interest that is retained by the owner of the minerals underlying a lease. See "Royalty Interest".
"Net Acres or Net Wells." The sum of the fractional working interests owned in gross acres or gross wells.

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"NGL." Natural gas liquids, being the combination of ethane, propane, butane and natural gasoline that can be removed from natural gas through processing, typically through refrigeration plants that utilize low temperatures, or through J-T plants that utilize compression, temperature reduction and expansion to a lower pressure.
"NYMEX." New York Mercantile Exchange.
"OOIP." Original Oil in Place. An estimate of the barrels originally contained in a reservoir before any production therefrom.
"Operator." An oil and gas joint venture participant that manages the joint venture, pays venture costs and bills the venture's non-operators for their share of venture costs. The operator is also responsible to market all oil and gas production, except for those non-operators who take their production in-kind.
"Overriding Royalty Interest or ORRI." A royalty interest that is created out of the operating or working interest. Unlike a royalty interest, an overriding royalty interest terminates with the operating interest from which it was created or carved out of. See "Royalty Interest".
"Permeability." The measure of ease with which a fluid can move through a reservoir. The unit of measure is a darcy, or any metric derivation thereof, such as a millidarcy, where one darcy equals 1,000 millidarcys. Extremely low permeability of 10 millidarcys, or less, are often associated with source rocks, such as shale, making extraction of hydrocarbons more difficult, than say sandstone traps, where permeability can be one to two darcys or more.
"Porosity." (of sand or sandstone). The relative volume of the pore space (or open area) compared to the total bulk volume of the reservoir, stated in percent. Higher porosity rocks provide more storage space for hydrocarbon accumulations than lower porosity rocks in a given cubic volume of reservoir.
“Possible Reserves.” Additional unproved reserves that analysis of geological and engineering data suggests are less likely to be recoverable than Probable Reserves, but have at least a ten percent probability of being recovered.*
"Probable Developed Producing Reserves." Probable Reserves that are Developed and Producing.*
"Probable Reserves." Additional reserves that are less certain to be recovered than Proved Reserves but which, together with Proved Reserves, are as likely as not to be recovered.*
"Producing Reserves." Any category of reserves that have been developed and production has been initiated.*
"Proved Developed Reserves." Proved Reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
"Proved Developed Nonproducing Reserves ("PDNP")." Proved Reserves that have been developed and no material amount of capital expenditures are required to bring on production, but production has not yet been initiated due to timing, markets, or lack of third party completed connection to a gas sales pipeline.*
"Proved Developed Producing Reserves ("PDP")." Proved Reserves that have been developed and production has been initiated.*
"Proved Reserves." Estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.*
"Proved Undeveloped Reserves ("PUD")." Proved Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.*
(i)  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)  Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii)  Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.


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"Present Value." When used with respect to oil and gas reserves, present value means the estimated future net revenues computed by applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs to be incurred in developing and producing the proved reserves) computed using a discount factor and assuming continuation of existing economic conditions.
"Productive Well." A well that is producing oil or gas or that is capable of production.
"PV-10." Means the present value, discounted at 10% per annum, of future net revenues (estimated future gross revenues less estimated future costs of production, development, and asset retirement costs) associated with reserves and is not necessarily the same as market value. PV-10 does not include estimated future income taxes. Unless otherwise noted, PV-10 is calculated using the pricing scheme as required by the Securities and Exchange Commission ("SEC"). PV-10 of proved reserves is calculated the same as the standardized measure of discounted future net cash flows, except that the standardized measure of discounted future net cash flows includes future estimated income taxes discounted at 10% per annum. See the definition of standardized measure of discounted future net cash flows.
"Royalty" or "Royalty Interest." 1) The mineral owner's share of oil or gas production (typically between 1/8 and 1/4), free of costs, but subject to severance taxes unless the lessor is a government. In certain circumstances, the royalty owner bears a proportionate share of the costs of making the natural gas saleable, such as processing, compression and gathering. 2) When a royalty interest is coterminous with and carved out of an operating or working interest, it is an "Overriding Royalty Interest," which also may generically be referred to as a Royalty.
"Shut-in Well." A well that is not on production, but has not yet been plugged and abandoned. Wells may be shut-in in anticipation of future utility as a producing well, plugging and abandonment or other use.
"Standardized Measure." The standardized measure of discounted future net cash flows. The Standardized Measure is an estimate of future net cash flows associated with proved reserves, discounted at 10% per annum. Future net cash flows is calculated by reducing future net revenues by estimated future income tax expenses and discounting at 10% per annum. The Standardized Measure and the PV-10 of proved reserves is calculated in the same exact fashion, except that the Standardized Measure includes future estimated income taxes discounted at 10% per annum. The Standardized Measure is in accordance with accounting standards generally accepted in the United States of America ("GAAP").

"Undeveloped Reserves." Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.*
"Working Interest." The interest in the oil and gas in place which is burdened with the cost of development and operation of the property. Also called the operating interest.
"Workover." A remedial operation on a completed well to restore, maintain or improve the well's production.
______________________________________________________________________________
*    This definition may be an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X.


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PART I
Item 1.    Business
Note: See Glossary of Selected Petroleum Industry Terms starting on page

General
Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management and development of producing oil and gas properties. The Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisition, while seeking opportunities to maintain and increase production through selective development, production enhancement and other exploitation efforts on its properties.
Our producing assets over the last three fiscal years consisted of our interests in the Delhi Holt-Bryant Unit in the Delhi field (the "Unit") in Northeast Louisiana, a CO2 enhanced oil recovery project, and a de minimis overriding royalty interest retained in a past divestiture. We have a combined net revenue interest in the Unit of 26.2% comprised of 7.2% of overriding royalty interests that are in effect for the life of the Unit and mineral royalty interests and a 23.9% working interest with an associated 19.0% net revenue interest.

Significant Activity in Fiscal 2019
Delhi proved oil equivalent reserves at June 30, 2019 were 9.0 MMBOE, a 4% decrease from the previous year. The Standardized Measure for proved reserves increased 7% to $127 million, reflecting a rise in realized commodity price from $54.71 to $58.50 per BOE. Our proved reserves consist of 85% crude oil and 15% natural gas liquids.
Delhi probable** reserves at June 30, 2019 were 4.8 MMBOE, a 7% increase over the previous year. 87% of these reserves are incremental reserves associated with existing developed and producing locations. No additional capital investment is required beyond what is captured in proved reserves.    
Delhi possible** reserves at June 30, 2019 were 4.3 MMBOE, a 7% decrease over the previous year. 91% of these reserves are incremental reserves associated with existing developed and producing locations. No additional capital investment is required beyond what is captured in proved reserves.
The twelve well infill program, consisting of ten producer wells and two CO2 injector wells, was completed and on production during fiscal 2019, converting 536 MBOE of proved undeveloped to proved developed reserves.
Capital expenditures for the six-well water curtain program and related infrastructure preceding the planned Delhi Phase V development is almost complete. The first pad commenced operations during fiscal 2019 and the second pad is expected to begin injections during our second quarter of fiscal 2020.
Our Reserves: Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our independent petroleum engineering firm, DeGolyer & MacNaughton ("D&M"), assigned the estimated reserves net to our interests at Delhi as of June 30, 2019. We had 9.0 million bbls of proved oil equivalent reserves, with a Standardized Measure of $127 million, and PV-10* of $157 million. The following table summarizes the reserves assigned by D&M:
 
Reserves as of June 30, 2019
 
Proved
 
Probable**
 
Possible**
Reserves MBOE
8,981

 
4,783

 
4,321

% Developed
82
%
 
87
%
 
91
%
Liquids %
100
%
 
100
%
 
100
%
Standardized Measure ($MM)
$
127

 
 
 
 
PV-10* ($MM)
$
157

 
 
 
 

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______________________________________________________________________________
*
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" below in Item 1. Business in this 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, 2019, which were $64.54 per barrel of oil and $23.83 per barrel of natural gas liquids ("NGL"). Probable and possible reserves are not recognized under GAAP nor is there a comparable GAAP measure for probable and possible reserves.
**
With respect to the above reserve numbers, and references to probable and possible reserves throughout this document, 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 and there must be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserve estimates. Possible reserves are even less certain and there must be at least a 10% probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible reserve estimates. 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.
Development History of the Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our working and royalty interests in the Delhi field are currently our primary 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 in the purchase and sale agreements. Since EOR production began in March 2010, the Unit has produced over 20 million bbls of oil.

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After the May 2006 conveyance, Denbury Resources, Inc., as 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.

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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 gross 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 gross barrels of oil per day.
In June 2013, following an adverse 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 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, thus removing that area from the CO2 flood.
Construction began on the NGL extraction plant in February 2015. During fiscal 2017, the NGL extraction plant was completed and began processing in December 2016. The 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 for the benefit and use 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 has resulted in operational benefits to the CO2 flood. We have incurred a net capital cost of approximately $27 million for the plant, including capital upgrades since its commissioning.
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. 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 together with the consensus that Phase V project economics would be enhanced if it were implemented after completion of the NGL plant.
During fiscal 2019 the twelve well infill program, consisting of ten producing wells and two CO2 injection wells was completed and on production. The program commenced in March 2018 to target productive oil zones in the developed areas of the field that were not being swept effectively by the CO2 flood.
Also during the year, one pad of the six-well water curtain program was completed and commenced water injection during the second half of fiscal 2019. The project began late in fiscal 2017 after completion of the NGL plant with the drilling of one well followed by three wells in fiscal 2018. During fiscal 2019, we drilled the two remaining wells and proceeded with completions and injection line work. In fiscal 2020, we expect to incur approximately $0.6 million of net capital expenditures for completing the installation of the second three-well pad planned to begin injection in the second fiscal quarter.
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 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 liquids 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 that the actual quantities recovered will equal of exceed the proved plus probable reserve estimates. Possible reserves are even less certain and generally require only a 10% or greater probability of that actual quantities recovered will equal or exceed the sum of proved, probable and possible reserve estimates. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development,

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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.
Information About the Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure") and pre-tax PV-10 of Proved Reserves
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. Refer to the "Reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash Flows" below.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2019
Our proved, probable and possible reserves at June 30, 2019, denominated in equivalent barrels using six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio, were estimated by our independent petroleum engineer, DeGolyer and MacNaughton ("D&M") which was formed in 1936, employs over 180 petroleum engineers, geologists and other technical personnel, and operates domestically and around the world. 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 of the Delhi field. 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, 2019. For additional reserve information see Note 20 – Supplemental Disclosures about Oil and Natural Gas Producing Properties (Unaudited) of the consolidated financial statements. The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $61.62 per barrel of crude oil. The net price per barrel of natural gas liquids was $23.83, 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, 2019
Reserve Category
Oil
(MBbls)
 
NGLs
(MBbls)
 
Total Reserves
(MBOE)*
PROVED
 
 
 
 
 
Developed Producing (82% of Proved)
6,274

 
1,124

 
7,398

Undeveloped (18% of Proved)
1,342

 
241

 
1,583

TOTAL PROVED
7,616

 
1,365

 
8,981

Product Mix
85
%
 
15
%
 
100
%
PROBABLE
 
 
 
 
 
Developed Producing (87% of Probable)
3,516

 
630

 
4,146

Undeveloped (13% of Probable)
540

 
97

 
637

TOTAL PROBABLE
4,056

 
727

 
4,783

Product Mix
85
%
 
15
%
 
100
%
POSSIBLE
 
 
 
 
 
Developed Producing (91% of Possible)
3,323

 
596

 
3,919

Undeveloped (9% of Possible)
341

 
61

 
402

TOTAL POSSIBLE
3,664

 
657

 
4,321

Product Mix
85
%
 
15
%
 
100
%
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio.


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The following tables present a reconciliation of changes in our proved, probable and possible reserves by major property, on the basis of equivalent MBOE quantities.
Reconciliation of Changes in Proved Reserves by Major Property
 
Delhi Field Proved
Total
Proved reserves, MBOE
 MBOE
June 30, 2018
9,368

Production
(739
)
Revisions
352

Sales of minerals in place

Improved recovery, extensions and discoveries

June 30, 2019
8,981

Reconciliation of Changes in Probable Reserves by Major Property
 
Delhi Field Probable
Total
Probable reserves, MBOE
MBOE
June 30, 2018
4,493

Revisions
290

Sales of minerals in place

Improved recovery, extensions and discoveries

June 30, 2019
4,783

Reconciliation of Changes in Possible Reserves by Major Property
 
Delhi Field Possible
Total
Possible reserves, MBOE
MBOE
June 30, 2018
4,570

Revisions
(249
)
Sales of minerals in place

Improved recovery, extensions, and discoveries

June 30, 2019
4,321

Reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash Flows
The following table provides a reconciliation of PV-10 (Non-GAAP) of our proved properties to the Standardized Measure (GAAP) as shown in Note 20 – Supplemental Disclosures about Oil and Natural Gas Producing Properties (Unaudited) of the consolidated financial statements.
 
As of June 30,
 
2019
 
2018
Estimated future net revenues
$
297,102,269

 
$
270,842,377

10% annual discount for estimated timing of future cash flows
140,489,586

 
124,798,505

Estimated future net revenues discounted at 10% (PV-10)
156,612,683

 
146,043,872

Estimated future income tax expenses discounted at 10%
(29,880,641
)
 
(27,085,458
)
Standardized Measure
$
126,732,042

 
$
118,958,414

Our primary proved producing assets as of June 30, 2019 and 2018 were our interests in the Delhi field.

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Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company's Overall Reserve Estimation Process
Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent petroleum engineering firm under the supervision of our Chairman of the Board and interim Chief Executive Officer and Senior Vice President of Engineering and Business Development, a professional petroleum engineer. Such reserves estimates are to be in compliance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.
The reserves information in this filing is based on estimates prepared by DeGolyer and MacNaughton, our independent petroleum engineering firm, which was formed in 1936, employs over 180 petroleum engineers, geologists and other technical personnel, and operates domestically and around the world. 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 received a Bachelor of Science degree in petroleum engineering from the University of Texas in 1984, has over 35 years of experience in the energy industry and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
Our Chairman of the Board and interim Chief Executive Officer holds B.S. and M.E. degrees from Rice University in chemical engineering and earned an M.B.A. from Harvard University. He has over 30 years of experience in engineering, energy transactions, operations and finance with small independents, larger independents and major integrated oil companies. Our Senior Vice President of Engineering and Business Development received a Bachelor of Science degree in petroleum engineering from the University of Oklahoma in 1979 and has over 39 years of experience in the energy industry with upstream oil and gas companies. On July 10, 2019, Jason Brown was appointed President and Chief Executive Officer of the Company and Mr. Herlin remained as Chairman of the Board of Directors. Mr. Brown has over 20 years of experience in the energy industry and is a Registered Professional Engineer (Petroleum) in the State of Texas. He earned his B.S. degree in chemical engineering from the University of Tulsa and his M.B.A. from the Mendoza School of Business at the University of Notre Dame.
We provide our independent petroleum engineering firm with our property interests, production, current operating costs, current production prices and other information. This information is reviewed by our Senior Vice President of Engineering and Business Development and other members of management to ensure accuracy and completeness of the data prior to submission to this firm. The scope and results of our independent petroleum 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.
Proved Undeveloped Reserves
Our Proved undeveloped reserves were 1,583 MBOE at June 30, 2019, with associated future development costs of approximately $8.6 million, which are associated with the Phase V development in the eastern portion of Delhi field.
During the year ended June 30, 2019 our proved undeveloped reserves changed as follows:
 
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
 
 
Total Reserves
(MBOE)
June 30, 2018
 
1,798

 
284

 
 
 
2,082

Revisions to previous estimates
 
7

 
30

 
 
 
37

Conversion to proved developed reserves
 
(463
)
 
(73
)
 
 
 
(536
)
June 30, 2019
 
1,342

 
241

 
 
 
1,583

Oil and NGL reserves were revised upward 7 MBbls and 29 MBOE, respectively, reflecting improved existing well and NGL plant performance over the last year. The infill program, consisting of ten producer wells and two CO2 injection wells, was completed during 2019 resulting in the conversion of 463 MBbls of oil and and 73 MBOE of NGLs from Proved undeveloped reserves to proved developed reserves. Since the project's inception in March 2018, our infill project net capital expenditures have totaled $4.6 million, of which $1.8 million was incurred during fiscal 2019.
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 were to 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 82% of total Proved reserves as of June 30, 2019. 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

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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 field in February 2015. 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 fiscal 2015, we authorized the NGL plant project and from late in that fiscal year until January 2017 when production of NGLs began, we incurred $26.0 million of related capital expenditures. The NGL plant was completed in December 2016 and we converted approximately 1,377 MBOE of proved undeveloped reserves to proved developed reserves during fiscal 2017.
Since completion of the plant, we have resumed work that had been suspended in late 2014 and further deferred until the NGL recovery plant was complete. Cumulatively, we have spent $3.1 million as of June 30, 2019, including $1.6 million in fiscal 2019, on the six well water curtain program and related infrastructure required to precede the development of Phase V. As of June 30, 2019 we had drilled all the wells, including four gross wells during fiscal 2019, and commenced operations for one of the program's pads. The program was configured as two pads with each having two injector wells and one water source well. The second pad is expected to begin operations in the second fiscal quarter of 2020 and we expect to incur approximately $0.6 million net of capital expenditures to complete the program.
As of June 30, 2019, we have estimated total future net capital expenditures of approximately $8.6 million for remaining curtain infrastructure and development of Phase V in the eastern part of the field, which we expect to commence in our fourth fiscal quarter of 2020 based on our discussions with the operator. The timing of Phase V is dependent on the field operator's available funds and capital spending plans and priorities within its portfolio of properties.
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. We have been continuously developing the Delhi field and have spent over $47 million subsequent to reversion of our working interest in November 2014. 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 adverse 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, 2019, no proved, probable or possible reserves were attributed to (a) the area beneath the inhabited portion of the town of Delhi in the northeast and (b) the farthest east of the two remaining undeveloped sites in the eastern portion of the 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 do not have proved or probable reserves associated with out interests in the Mengel Sand, a separate interval within the Unit that is not currently producing, but has produced oil in the past.





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Sales Volumes, Average Sales Prices and Average Production Costs
The following table shows the Company's sales volumes and average sales prices received for crude oil, natural gas liquids, and natural gas for the periods indicated:
 
Year Ended 
 June 30, 2019
 
Year Ended 
 June 30, 2018
 
Year Ended 
 June 30, 2017
Product
Volume
 
Price
 
Volume
 
Price
 
Volume
 
Price
Crude oil (Bbls)
626,879

 
$
65.05

 
651,931

 
$
58.52

 
724,523

 
$
46.31

Natural gas liquids (Bbls)
112,013

 
$
21.87

 
93,366

 
$
28.06

 
43,907

 
$
16.01

Natural gas (Mcf)
459

 
$
2.64

 

 
$

 
16

 
$
(0.25
)
Average price per BOE*
738,968

 
$
58.50

 
745,297

 
$
54.71

 
768,433

 
$
44.58

 
 
 
 
 
 
 
 
 
 
 
 
Production costs
Amount
 
per BOE
 
Amount
 
per BOE
 
Amount
 
per BOE
Production costs, excluding ad valorem and production taxes
$
14,027,461

 
$
18.98

 
$
11,497,759

 
$
15.43

 
$
10,390,041

 
$
13.52

Total production costs, including ad valorem and production taxes
$
14,266,784

 
$
19.31

 
$
11,685,817

 
$
15.68

 
$
10,604,594

 
$
13.80

* BOE computed on units of production using a six to one conversion ratio of MCF's to barrels.
Drilling Activity
Our productive drilling activity during the past three fiscal years ended June 30, 2019, was limited to five gross (1.2 net) producer wells drilled and completed in fiscal 2019 and another five (1.2 net) producer wells completed in fiscal 2018. We completed one (0.239 net) CO2 injection well during fiscal 2019 and completed one (0.239 net) CO2 injection well during fiscal 2018. There were no completions of productive wells in fiscal 2017. No dry wells were drilled in the past three fiscal years.
In connection with establishing a six-well water curtain in advance of Phase V site development, during fiscal 2019 we drilled two (0.48 net) wells and completed three (0.72 net) wells. In fiscal 2018, we had drilled three (0.72 net) wells and in fiscal 2017 one (0.239 net) well was drilled. The three completed wells comprise the northern pad of the water curtain program and commenced injection during fiscal 2019. A pad consists of one gross water source well and two gross water injector wells.
Present Activities
As of June 30, 2019, we have three gross (0.72 net) water curtain wells remaining to be completed. We expect their completions will conclude and the wells to be online by early in our second quarter of fiscal 2020. These wells comprise the southern pad of the curtain program.
For further discussion, see "Highlights for our fiscal year 2019" 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, 2019, 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, 2019.
 
Company Operated
 
Non-Operated
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Crude oil

 

 
119

 
28.4

 
119

 
28.4

Natural gas

 

 

 

 

 

Total

 

 
119

 
28.4

 
119

 
28.4

Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2019. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves. 
Field
Developed Acreage
 
Undeveloped Acreage
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Delhi Field, Louisiana*
9,126

 
2,180

 
4,510

 
1,077

 
13,636

 
3,257

________________
* This table excludes acreage attributable to small overriding royalty interests retained in various formations in the Giddings Field area. Except for de minimis production that began on two leases during fiscal 2019, 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 and no reserves have been assigned to any of the Giddings interests.
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 include 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.
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.
Markets and Customers
Our production is marketed 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 average price differential over WTI, as quoted daily on the New York Mercantile Exchange ("NYMEX"), was approximately $6.89 per barrel during our fiscal year ended June 30, 2019. The differential has increased from the prior year and we expect that a positive LLS price differential will continue, at least in the near future. Our overall average net realized oil price, including the LLS premium and after all adjustments for transportation, marketing and other price differentials, was $4.11 per barrel more than the average WTI NYMEX price for fiscal 2019.

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Upon completion of the NGL plant in December 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
2019
 
2018
Plains Marketing L.P. (Oil sales from Delhi)
94
%
 
92
%
American Midstream Gas Solutions. L.P. (NGL sales from Delhi)
6
%
 
8
%
All others
%
 
%
Total
100
%
 
100
%
The loss of a 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. More recently, the price of oil per barrel dropped dramatically, starting in the fourth quarter of 2014 and continuing into 2017 before recovering somewhat in late calendar 2018 and then weakening again in 2019. Worldwide factors such as geopolitical, international trade disruptions and tariffs, macroeconomic, supply and demand, refining capacity, petrochemical production and derivatives trading, among others, influence prices for crude oil. Local factors also influence prices for crude oil and include increasing or decreasing production trends, quality differences, regulation and transportation issues unique to certain producing regions and reservoirs.
Also over the past 30 years, domestic natural gas prices have been extremely volatile, ranging from $1 to $15 per MMBTU. The spot market for natural gas, changes in supply and demand, derivatives trading, pipeline availability, BTU content of the natural gas and weather patterns, among others, cause natural gas prices to be subject to significant fluctuations. Due to the practical difficulties in transporting natural gas, local and regional factors tend to influence product prices more for natural gas than for crude oil.
Competition
The oil and natural gas industry is highly competitive for prospects, acreage and capital. Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. Competitors are national, regional or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are expertise in given geographical and geological areas and the abilities to efficiently conduct operations, achieve technological advantages, identify, acquire economically producible reserves and obtain capital at rates which allow economic investments.
Government Regulation
Numerous federal and state laws and regulations govern the oil and gas industry, including environmental laws and regulations. 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.

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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 oil and gas 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.
Employment
At June 30, 2019, we had four 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. As a result of the retirement of Randy Keys, President and Chief Executive Officer on May 31, 2018, the Board of Directors named Robert Herlin to act as Interim Chief Executive Officer and to commence a search for a permanent Chief Executive Officer. A special Transition Services Committee of the board was created with one member, William Dozier, to provide additional operational oversight to the Company during the transition to a new Chief Executive Officer. On July 10, 2019, Mr. Jason Brown was appointed by the Board of Directors to serve as President and Chief Executive Officer of the Company. Robert Herlin, remained as Chairman of the Board.
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 Securities and Exchange Commission ("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.

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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 $74 per barrel to a low of $27 per barrel over the past four fiscal years ending June 30, 2019. 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;
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 85% of our proved reserves at June 30, 2019 are crude oil reserves and 15% 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 NGL 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.

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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 virtually represents 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 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”), an independent oil and gas company specializing in tertiary recovery with CO2. 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 (so that such cash flows would not be available for capital expenditures or other purposes). 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. Our Delhi asset is productive from a relatively shallow reservoir but we may pursue assets that produce from deeper reservoirs. Shallower reservoirs usually have lower pressure, which generally translates into lower reserve volumes in place. Deeper reservoirs have higher pressures and usually more reserve volumes, but capturing those reserves often comes at increased drilling and completion risk. 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

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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 extracting natural gas liquids 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;
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 may 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, 2019, one purchaser accounted for 94% of our oil and natural gas liquid 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.

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Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the crude oil and natural gas industry in general. The Standardized Measure and PV-10 do not necessarily correspond to market value.
Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.
We review on a periodic basis the carrying value of our crude oil and natural gas properties under the applicable rules of the various regulatory agencies, including the SEC. Under the full cost method of accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this "ceiling" test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write down of the carrying value for accounting purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our crude oil and natural gas properties when crude oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will depend in part on the prices for crude oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period. If a write down is required, it would result in a current charge to our earnings but would not impact our current cash flow from operating activities. 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 liquids 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 plan 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 projects;
our ability to develop new and 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;

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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, (ii) secure all of the development capital necessary to fund its and our cost interests, and further develop the Delhi field, such as advancement of Phase V development in the undeveloped eastern part of the field, (iii) successfully manage technical, operating, environmental, strategic and logistical development and operating risks, and (iv) 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 may require significant amounts of capital and additional financing may be necessary in order for us to continue our exploitation activities, including meeting potential future drilling obligations.
Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and gas acquisitions, exploitation and development activities. Certain of our undeveloped leasehold acreage may be subject to leases that will expire unless production is established. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available to us on favorable terms.
We may be subject to risks in connection with acquisitions because of uncertainties in evaluating recoverable reserves, well performance and potential liabilities, as well as uncertainties in forecasting oil and gas prices and future development, production and marketing costs, and the integration of significant acquisitions may be difficult.
We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including, 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

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the full benefits we may expect in estimated proved reserves, production volumes, 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 oil and gas operations and 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. These laws and regulations may affect the costs, manner and feasibility of our operations and require us to make significant expenditures in order to comply. 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, failure to comply with these laws and regulations may result in substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us, such as diminishing the demand for our products through legislative enactment of proposed new penalties, fines and/or taxes on carbon that could have the effect of raising prices to the end user.
Our business could be negatively affected by security threats. A cyber attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our operator, vendors, suppliers, customers and other business partners, may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyber attacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber attacks.
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

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the abilities of Robert Herlin, our Chairman of the Board, Jason Brown, our President and Chief Executive Officer, and David Joe, Senior Vice President, Chief Financial Officer, Treasurer and Corporate Secretary, 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 larger independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than ours. We may not be able to successfully conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive crude oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment and acquiring the existing and changing technologies that we believe are and will be increasingly important to attaining success in our industry.
We have been, and in the future may become, involved in legal proceedings related to our Delhi interest or other properties or operations and, as a result, may incur substantial costs in connection with those proceedings.
From time to time we may be a defendant or plaintiff in various lawsuits.  The nature of our operations exposes us to further possible litigation claims in the future.  There is risk that any matter in litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash flow.  Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition.  Adverse litigation decisions or rulings may damage our business reputation.
Ownership of our oil, gas and mineral production depends on good title to our property.
Good and clear title to our oil, gas and mineral properties is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, gas and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim which could result in a reduction or elimination of the revenue received by us from such properties.

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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, regional or worldwide increases in tariffs or other trade restrictions, 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, production costs could increase, any of 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, 2019, our stock price as traded on the NYSE American ranged from $5.99 to $12.32. 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, 2019 our executive officers and directors, in the aggregate, beneficially owned approximately 2.5 million shares, or approximately 7.4% of our beneficial common stock base. Blackrock Fund Advisors, et al controlled approximately 3.5 million shares or approximately 10.6 % of our outstanding common stock, Renaissance Technologies, LLC controlled approximately 2.2 million shares or approximately 6.7% of our outstanding common stock, and JVL Advisors, LLC controlled approximately 2.1 million shares or approximately 6.5%. 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 volumes increased in fiscal 2019 compared to fiscal 2018. Trading volume in our common stock is relatively low compared to larger companies. During the fiscal year ended June 30, 2019, the daily trading volume in our common stock ranged from a low of 45,600 shares to a high of 1,079,500 shares, with average daily trading volume of 180,353 shares compared to average daily volume of 112,015 in fiscal 2018. 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 analysts do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.
Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge there are three independent analysts that cover our company. The limited number of published reports by independent securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.
The issuance of additional common stock and preferred stock could dilute existing stockholders.
We currently have in place an effective 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
Information regarding our properties is included in “Item 1. Business” above and in “Note 6. Property and Equipment” of the Notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data,”which information is incorporated herein by reference.
Item 3.    Legal Proceedings
See Note 16 – Commitments and Contingencies under Item 8. Financial Statements for a description of legal proceedings, which is incorporated herein by reference.
Item 4.    Mine Safety Disclosures
Not Applicable.


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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, 2019 and 2018, the high and low sales prices for EPM as reported by the NYSE American.
NYSE American: EPM
2019:
High
 
Low
Fourth quarter ended June 30, 2019
$
7.40

 
$
5.99

Third quarter ended March 31, 2019
$
8.11

 
$
6.44

Second quarter ended December 31, 2018
$
12.83

 
$
6.17

First quarter ended September 30, 2018
$
12.00

 
$
9.60


2018:
High
 
Low
Fourth quarter ended June 30, 2018
$
10.50

 
$
7.75

Third quarter ended March 31, 2018
$
8.30

 
$
6.70

Second quarter ended December 31, 2017
$
7.63

 
$
6.35

First quarter ended September 30, 2017
$
8.70

 
$
6.35


Shares Outstanding and Holders
As of June 30, 2019, there were 33,183,730 shares of common stock issued and outstanding, held by approximately 250 holders of record. We estimate there are approximately 2,000 individuals and institutions that hold our stock through nominees.
Dividends
We began paying cash quarterly dividends on our common stock in December 2013. Over the last two fiscal years, the Company made the following cash dividends per share:
 
Years Ended June 30,
 
2019
 
2018
Fourth quarter ended June 30,
$0.100
 
$0.100
Third quarter ended March 31,
$0.100
 
$0.100
Second quarter ended December 31,
$0.100
 
$0.075
First quarter ended September 30,
$0.100
 
$0.075
`
As of June 30, 2019, we had paid twenty-three consecutive quarterly dividends on our common stock. In August 2019, the Company declared a $0.10 per share dividend payable on September 30, 2019. 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, 2014 to June 30, 2019 with the cumulative total return of the S&P 500 Index and

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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, 2014 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.
https://cdn.kscope.io/2530c44491e8566ba7cc39a39d13ae77-chart-dcada9c9ad8f5dd69e5.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
10,156

 
(1)
 

 
 
  Total
10,156

 
 
 
$

 
852,111

Equity compensation plans not approved by security holders

 
 
 

 

Total
10,156

 
 
 
$

 
852,111


(1)
As of June 30, 2019, 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, 2019, 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 42,833

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were unvested as of June 30, 2019), contingent restricted stock grants of 145,646 shares had been reserved (of which 10,156 were unvested as of June 30, 2019) 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 2019, 110,982 awards were made under the 2016 Plan and 852,111 shares of common stock remain available for future grants at June 30, 2019.

Issuer Purchases of Equity Securities
Period
(a) Total Number of
Shares (or Units)
Purchased (1) (2)
 
(b) Average Price
Paid per Share (or
Units)
 
(c) Total Number of Shares
(or Units) Purchased as Part
of Publicly Announced Plans
or Programs
 
(d) Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
April 1, 2019 to April 30, 2019
None
 
Not applicable
 
Not applicable
 
$3.4 million
May 1, 2019 to May 31, 2019
None
 
Not applicable
 
Not applicable
 
$3.4 million
June 1, 2019 to June 30, 2019
2,935
 
$6.19
 
266,192
 
$3.4 million
(1)    During the fourth quarter ended June 30, 2019, the Company received shares of common stock from certain of its employees which were surrendered in exchange for their payroll tax liabilities arising from vestings of restricted stock and contingent restricted stock. The acquisition cost per share reflects the weighted-average market price of the Company's shares on the dates vested.
(2)    On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Under the program's terms, shares may be repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases will depend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time. Such shares are initially recorded as treasury stock, then subsequently canceled. The Company repurchased 430 shares in June 2019 at an average price of $6.07 per share. There were no other program purchases in fiscal 2019.

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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,
 
2019
 
2018
 
2017
 
2016
 
2015
Income Statement Data
 
 
 
 
 
 
 
 
 
Revenues
$
43,229,621

 
$
40,773,527

 
$
34,253,681

 
$
26,349,502

 
$
27,841,265

Cost of revenues
14,266,784

 
11,685,817

 
10,604,594

 
9,133,111

 
9,355,613

Depreciation, depletion, and amortization
6,253,083

 
6,102,288

 
5,779,069

 
5,214,174

 
3,650,603

General and administrative expense
5,072,931

 
6,773,781

 
4,985,408

 
9,079,597

 
6,256,783

Restructuring charges

 

 
4,488

 
1,257,433

 
(5,431
)
Income from operations
17,636,823

 
16,211,641


12,880,122

 
1,665,187

 
8,583,697

Other income (expense)
1,222,604

 
(25,126
)
 
4,855

 
32,565,954

 
(147,619
)
Income tax provision (benefit)
3,482,361

 
(3,431,969
)
 
4,840,664

 
9,570,779

 
3,444,221

Net income attributable to the Company
$
15,377,066

 
$
19,618,484


$
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
$
15,377,066

 
$
19,618,484


$
6,790,883

 
$
23,986,060

 
$
4,317,555

Earnings per common share:
 
 
 
 
 
 
 
 
 
Basic
$
0.46

 
$
0.59

 
$
0.21

 
$
0.73

 
$
0.13

Diluted
$
0.46

 
$
0.59

 
$
0.21

 
$
0.73

 
$
0.13


 
June 30, 2019
 
June 30, 2018
 
June 30, 2017
 
June 30, 2016
 
June 30, 2015
Balance Sheet Data
 
 
 
 
 
 
 
 
 
Total current assets
$
35,178,927

 
$
32,147,556

 
$
26,142,527

 
$
37,086,450

 
$
23,693,048

Total assets
95,761,844

 
93,662,544

 
88,268,668

 
97,451,051

 
69,882,727

Total current liabilities
2,752,694

 
4,430,214

 
2,718,894

 
8,528,908

 
9,329,257

Total liabilities
15,635,986

 
16,373,065

 
19,798,813

 
21,129,901

 
21,306,150

Stockholders' equity
80,125,858

 
77,289,479

 
68,469,855

 
76,321,150

 
48,576,577

Number of common shares outstanding
33,183,730

 
33,080,543

 
33,087,308

 
32,907,863

 
32,845,205

Working capital, net
32,426,233

 
27,717,342

 
23,423,633

 
28,557,542

 
14,363,791

Cash dividends to common stockholders
13,272,058

 
11,594,541

 
8,432,435

 
6,565,823

 
9,833,642


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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview
Results of Operations
Liquidity and Capital Resources
Critical Accounting Policies
Executive Overview
General
Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management and development of oil and gas properties. The Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisitions, while seeking opportunities to maintain and increase production through selective development, production enhancement and other exploitation efforts on its properties.
Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery project, and a de minimis overriding royalty interest retained in a past divestiture.
By policy, every employee and director maintains a beneficial ownership position in our common stock. We believe this ownership helps ensure that the interests of our employees and directors are aligned with our stockholders.
In May 2018, our then President and Chief Executive Officer elected to retire as of May 31, 2018. Robert Herlin, our Chairman of the Board, founder and previous CEO, was appointed by the board to the position of Interim CEO.  A special Transition Services Committee of the board was created with one member, William Dozier, to provide additional operational oversight to the Company during the transition to a new CEO. On July 10, 2019, Mr. Jason Brown, age 42, was appointed by the Board of Directors to serve as President and Chief Executive Officer of the Company. Robert Herlin, remained as Chairman of the Board.
Highlights for our 2019 Fiscal Year

We recognized net income of $15.4 million, or $0.46 per diluted common share, our eighth consecutive year of reporting net income
We funded all operations, including $5.2 million of capital spending, from internal resources and remained debt free  
We returned $13.3 million to common shareholders in the form of cash dividends
Oil and NGL revenues increased by $2.5 million to $43.2 million, an increase of 6%
We increased working capital by 17% to $32.4 million at June 30, 2019, with cash on hand of $31.6 million. The twelve well infill program, consisting of ten producer wells and two CO2 injector wells, was completed and on production during fiscal 2019, converting 536 MBOE of proved undeveloped to proved developed reserves
Capital expenditures for the six-well water curtain program and related infrastructure preceding the planned Delhi Phase V development is almost complete. The first pad commenced operations during fiscal 2019 and the second pad is expected to begin injections during our second quarter of fiscal 2020
Oil & Natural Gas Liquids Reserves (based on SEC average NYMEX WTI oil price of $61.62 per barrel at June 30, 2019)
Delhi proved oil equivalent reserves at June 30, 2019 were 9.0 MMBOE, a 4% decrease from the previous year. The Standardized Measure for proved reserves increased 7% to $127 million, reflecting a rise in realized commodity prices from $54.71 to $58.50 per BOE. Our proved reserves are 85% crude oil and 15% natural gas liquids, and of these proved reserves, 82% are classified as proved developed and producing and 18% are proved undeveloped.
Delhi probable reserves at June 30, 2019 were 4.8 MMBOE, a 7% increase over the previous year. 87% of these reserves are classified as probable developed and producing, as they are incremental reserves associated with existing developed and producing locations. No additional capital investment is required beyond what is captured in proved reserves.    

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Delhi possible reserves at June 30, 2019 were 4.3 MMBOE, a 7% decrease over the previous year. 91% of these reserves are classified as possible developed and producing, as they are incremental reserves associated with existing developed and producing locations. No additional capital investment is required beyond what is captured in proved reserves.    
The following table is a summary of our proved, probable and possible reserves as of June 30, 2019 and 2018:
 
Proved
 
 
 
Probable
 
 
 
Possible
 
 
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Reserves MMBOE
9.0

 
9.4

 
(4
)%
 
4.8

 
4.5

 
7
%
 
4.3

 
4.6

 
(7
)%
% Developed
82
%
 
78
%
 
5
 %
 
87
%
 
80
%
 
9
%
 
91
%
 
88
%
 
3
 %
Liquids %
100
%
 
100
%
 
 %
 
100
%
 
100
%
 
%
 
100
%
 
100
%
 
 %
Standardized Measure ($MM)
$
127

 
$
119

 
7
 %
 
 
 
 
 
 
 
 
 
 
 
 
PV-10* ($MM)
$
157

 
$
146

 
8
 %
 
 
 
 
 


 
 
 
 
 


____________________________________________________________________________
*
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 1. "Business - Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues." 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 oil and gas companies, and that it is relevant and useful in 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 is reconciled to the Standardized Measure in Item 1. Business. Probable and possible reserves are not recognized as GAAP, nor is there a comparable GAAP measure.
Additional property and project information is included under Item 1. Business, Item 8. Financial Statements - Notes to the Financial Statements and Exhibit 99.1 of this Form 10-K.
Delhi Field
Our interests in the Delhi field consist of a 23.9% working interest (with associated 19.0% net revenue interest) and separate overriding royalty and mineral interests of 7.2%. This yields a total net revenue interest of 26.2%. The Delhi field is operated by Denbury Onshore, LLC (the "operator"), a subsidiary 100% owned by Denbury Resources Inc. .
Proved reserves volumes totaled 9.0 MMBOE with a Standardized Measure of $127 million and a PV-10* value of $157 million compared to the prior year's 9.4 MMBOE with a Standardized Measure of $119 million and a PV-10* value of $146 million. Improved performance of producing wells has led to a 0.152 MMBOE, or 2%, positive revision in proved oil reserves. Performance from the NGL plant was improved via capitalized modifications resulting in a 0.199 MMBOE, or 16%, positive revision to NGL reserves. Probable reserve volumes at Delhi were 4.8 MMBOE, an increase of 7% compared to 4.5 MMBOE in the prior year. Possible reserves volumes at Delhi were 4.3 MMBOE, a decrease of 7% compared to 4.6 MMBOE in the prior year. The reclassification to probable from possible are primarily the result of timing and recent performance.
Gross production at Delhi in the fourth quarter of fiscal 2019 was 7,843 BOEPD, a 2% increase compared to 7,687 BOEPD in the third fiscal quarter. Oil production was 6,364 BOPD, a 2% decrease from the third fiscal quarter’s 6,474 BOPD. NGL production in the fourth quarter was 1,479 BOEPD, 22% higher than prior quarter production of 1,213 BOEPD. Oil production was impacted by compressor downtime during the fourth quarter. Earlier in the year, the operator modified the flow regime of the recycle facility which led to improved NGL production over the past two quarters. However, this modification resulted in compressor issues causing the downtime in the fourth quarter. The compressor was repaired and oil production recovered in July. We expect NGL production to be approximately 1,100 to 1,200 BOEPD over the next several months. The

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operator is investigating solutions to recapture the NGL rates seen in the fourth quarter. All twelve wells in the infill program initiated in fiscal 2018 have been completed, and consist of two CO2 injection wells and ten producer wells.
The average oil price realized by Evolution during the fourth quarter of fiscal 2019 was $64.77 compared to $59.12 during the previous quarter. The average NGL price realized by Evolution during the fourth quarter of fiscal 2019 was $15.27 per barrel compared to $16.37 during the previous quarter. Evolution continues to benefit from the premium that Delhi field oil receives selling under Louisiana Light Sweet ("LLS") pricing, as compared to the more widely known West Texas Intermediate ("WTI") price, and the oil is shipped to market directly by pipeline, the most efficient means of transportation from the field. Our received NGL price for royalty production is burdened by a capital recovery charge, which is mostly offset by our working interest share of such capital recovery that is reflected as a reduction in lease operating expense.
Our overall lifting costs for the year were $19.31 per BOE increased 23% from $15.68 per BOE in the prior year. Gross CO2 purchase volume rates for the fiscal 2019 averaged 85.2 MMcf per day, compared to 65.0 MMcf per day in the prior year, a 31% increase. This increase together with an 8% higher price per mcf resulted in a 41% increase in CO2 cost compared to the prior year. Our cost of purchased CO2, the largest single component of operating costs, is directly tied to the price of oil sold from the Delhi field. Other lease operating expenses for the fiscal 2019 increased 9.1% compared to the prior year, primarily due to higher fuel gas expense, labor and chemicals.
For fiscal 2019, our gross NGL production was 1,171 BOEPD, which sold at an average price of $21.87 per barrel, compared to prior year gross production of 976 BOEPD for which we realized $28.06 per barrel. Production from the NGL plant is transported by truck to a processing plant in East Texas, and therefore bears a material transportation charge. Plant efficiencies have improved from the prior year and the higher realized price reflects both the impact of higher oil prices and improvements in meeting the purchaser's specification requirements. Under the operator's marketing contract, we receive market index pricing for each NGL component, based on the processed yield, less transportation, processing fees and other deductions. Our current mix of products is very rich containing higher value NGL's, such as pentanes and butane. Market pricing for our NGL's during the fourth quarter averaged approximately 36% of WTI prices (net realized price is after deduction of transportation and fractionation charges). NGL prices have fallen significantly from a peak in late 2018 in response to worldwide supply and demand. Historically, NGL demand has had a seasonal pattern with prices tending to be higher in the cooler months of the year. Accordingly, the relationship between NGL prices and WTI has fluctuated over time and we expect such volatility to continue.

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 supplies excess power to the CO2 recycle facility. 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 approximately $6.00 per BOE for 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. Development of unquantified volumes is dependent upon the timing of excess capacity within the processing plant and oil price. We continue to believe that this high quality and economically viable project will be executed as planned, subject to oil price volatility.

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Results of Operations
Years Ended June 30, 2019 and 2018
Revenues
Compared to the the prior fiscal year, fiscal 2019 revenues increased 6.0% due to 6.9% higher realized commodity prices partially offset by a very slight decrease in production volumes. The following table summarizes total production volumes, daily production volumes, average realized prices and revenues:
 
Years Ended June 30,
 
 
 
 
 
2019
 
2018
 
Variance
 
Variance %
Oil and gas production
 
 
 
 
 
 
 
  Crude oil revenues
$
40,779,052

 
$
38,153,417

 
$
2,625,635

 
6.9
 %
  NGL revenues
2,449,359

 
2,620,110

 
(170,751
)
 
(6.5
)%
  Natural gas revenues
1,210

 

 
1,210

 
n.m.

  Total revenues
$
43,229,621

 
$
40,773,527

 
$
2,456,094

 
6.0
 %
 
 
 
 
 
 
 
 
  Crude oil volumes (Bbl)
626,879

 
651,931

 
(25,052
)
 
(3.8
)%
  NGL volumes (Bbl)
112,013

 
93,366

 
18,647

 
20.0
 %
  Natural gas volumes (Mcf)
459

 

 
459

 
n.m.

Equivalent volumes (BOE)
738,968

 
745,297

 
(6,329
)
 
(0.8
)%
 
 
 
 
 
 
 
 
  Crude oil (BOPD, net)
1,717

 
1,786

 
(69
)
 
(3.9
)%
  NGLs (BOEPD, net)
307

 
256

 
51

 
19.9
 %
  Natural gas (BOEPD, net)
1

 

 
1

 
n.m

 Equivalent volumes (BOEPD, net)
2,025

 
2,042

 
(17
)
 
(0.8
)%
 
 
 
 
 
 
 
 
  Crude oil price per Bbl
$
65.05

 
$
58.52

 
$
6.53

 
11.2
 %
  NGL price per Bbl
21.87

 
28.06

 
(6.19
)
 
(22.1
)%
  Natural gas price per Mcf
2.64

 

 
2.64

 
 %
   Equivalent price per BOE
$
58.50

 
$
54.71

 
$
3.79

 
6.9
 %
n. m. Not meaningful.
Production Costs
The $2.6 million increase in production costs was due to a 41% increase in CO2 costs together with 9% higher other production costs.
 
Years Ended June 30,
 
 
 
 
 
2019
 
2018
 
Variance
 
Variance %
CO2 costs (a)
$
6,674,905

 
$
4,729,506

 
$
1,945,399

 
41.1
%
Other production costs
7,591,879

 
6,956,311

 
635,568

 
9.1
%
Total production costs
$
14,266,784

 
$
11,685,817

 
$
2,580,967

 
22.1
%
 
 
 
 
 
 
 
 
CO2 costs per BOE
$
9.03

 
$
6.35

 
$
2.68

 
42.2
%
All other production costs per BOE
10.28

 
9.33

 
0.95

 
10.2
%
Production costs per BOE
$
19.31

 
$
15.68

 
$
3.63

 
23.2
%
(a) Under our contract with the operator, purchased CO2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes of approximately 8.5% and transportation costs of $0.20 per mcf. Transportation costs will decline effective January 1, 2020 as per contract terms.

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Years Ended June 30,
 
 
 
 
 
2019
 
2018
 
Variance
 
Variance %
CO2 costs per mcf
$
0.90

 
$
0.83

 
$
0.07

 
8.4
%
CO2 volumes (MMcf per day, gross)
85.2

 
65.0

 
20.2

 
31.1
%
The $1.9 million increase in CO2 costs was due to a 31% increase in purchased volumes together with a 8.4% increase in price per mcf reflecting the higher realized oil price. The increase in other production costs primarily consisted of higher costs of $0.3 million for fuel gas expense, $0.2 million for labor, and $0.1 million for chemicals.
Depletion, Depreciation and Amortization ("DD&A")
DD&A expense was 2.5% higher compared to the same year-ago period principally due to a 3.4% higher oil and gas DD&A rate as production volumes were virtually unchanged from fiscal 2018.
 
Years Ended June 30,
 
 
 
 
 
2019
 
2018
 
Variance
 
Variance %
DD&A of proved oil and gas properties
$
6,122,515

 
$
5,980,307

 
$
142,208

 
2.4
 %
Depreciation of other property and equipment
15,498

 
18,127

 
(2,629
)
 
(14.5
)%
Amortization of intangibles
13,564

 
13,564

 

 
 %
Accretion of asset retirement obligations
101,506

 
90,290

 
11,216

 
12.4
 %
Total DD&A
$
6,253,083

 
$
6,102,288

 
$
150,795

 
2.5
 %
 
 
 
 
 
 
 
 
Oil and gas DD&A rate per BOE
$
8.29

 
$
8.02

 
$
0.27

 
3.4
 %
General and Administrative Expenses
Expenses for the fiscal 2019 decreased $1.7 million, or 25.1%, to $5.1 million from the same year-ago period primarily due to higher fiscal 2018 expenses such as $0.8 million of higher consulting and legal costs for acquisition pursuits, $0.6 million of litigation expense, $0.5 million of non-cash stock compensation expense and $0.3 million of compensation costs associated with the retirement of the then Chief Executive Officer, partially offset by $0.3 million of increased Board expense for fiscal 2019 during the search for a new Chief Executive Officer and $0.2 million of related executive search fees.
Other Income and Expenses
Other income and expense (net) increased due primarily to the $1.1 million breakup fee related to our Enduro stalking horse bid received during August 2018, plus higher earned interest income due to increasing interest rates in fiscal 2019.
 
Years Ended June 30,
 
 
 
 
 
2019
 
2018
 
Variance
 
Variance %
Enduro transaction breakup fee
1,100,000

 

 
1,100,000

 
n.m.

Interest and other income
239,150

 
85,654

 
153,496

 
179.2
%
Interest expense
(116,546
)
 
(110,780
)
 
(5,766
)
 
5.2
%
Total other income, net
$
1,222,604

 
$
(25,126
)
 
$
1,247,730

 
n.m.

n. m. Not meaningful.

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Net Income
Net income available to common stockholders for the year ended June 30, 2019 decreased $4.2 million, or 22%, to $15.4 million compared to the prior year primarily due to a non-recurring prior year deferred tax credit of $6.0 million, partially offset by a $2.7 million, or 17% increase, in income before income taxes. This fiscal 2018 deferred tax benefit resulted from the revaluation of our deferred income tax liabilities at December 31, 2017 to reflect the lower federal statutory rate under the Tax Cut and Jobs Act.
 
Years Ended June 30,
 
 
 
 
 
2019
 
2018
 
Variance
 
Variance %
Income before income taxes
18,859,427

 
16,186,515

 
2,672,912

 
16.5
 %
Income tax provision (benefit)
3,482,361

 
(3,431,969
)
 
6,914,330

 
(201.5
)%
Net income available to common stockholders
$
15,377,066

 
$
19,618,484

 
$
(4,241,418
)
 
(22.0
)%
Income tax provision as a percentage of income before income taxes
19
%
 
(37
)%
 
 
 
 
Excluding the effect of the $6.1 million tax benefit from income taxes for the nine months ended March 31, 2018, income tax as a percentage of income before income taxes would have been approximately 18%. For the years ended June 30, 2019 and 2018, our respective statutory federal tax rates were 21% and 27.55%, as we used a blended rate during our fiscal 2018 in which the Tax Cut and Jobs Act was enacted. The benefit of the lower statutory rate in the current year was partially offset by a decreased benefit from depletion in excess of basis as much of our depletion carryover had been utilized by June 30, 2018.
Liquidity and Capital Resources
At June 30, 2019, we had $31.6 million in cash and cash equivalents (and no restricted cash) and $27.7 million of cash, cash equivalents and restricted cash at June 30, 2018.
In addition, we have a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of $50 million. The Facility had $40 million of undrawn elected borrowing base availability on June 30, 2019. Under the Facility the borrowing base shall be determined semiannually as of May 15 and November 15. There have been no borrowings under the Facility, which matures on April 11, 2021, and it is secured by substantially all of the Company’s assets.
During the current fiscal year, we amended the credit agreement to broaden the definition for Use of Proceeds to provide funds, limited to an amount not in excess of 25% of the borrowing base, for investments into cash flow generating assets complimentary to the production of oil and gas.
Any future borrowings bear interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined under the Facility, plus 1.0%. The Facility contains covenants that 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 $50.0 million, each as defined in the Facility. The Facility also contains other customary affirmative and negative covenants and events of default. As of June 30, 2019, the Company was in compliance with all covenants contained in the Facility.
During the year ended June 30, 2019, we funded our operations, capital expenditures and cash dividends with cash generated from operations resulting in an increase of $3.9 million in cash. As of June 30, 2019, our working capital was $32.4 million, an increase of $4.7 million over working capital of $27.7 million at June 30, 2018.
We have historically funded our operations through cash from operations and working capital. Our primary source of cash is the sale of oil and natural gas liquids production. A portion of these cash flows are 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. The Company expects to manage future development activities in the Delhi field within the boundaries of its operating cash flow and existing working capital.
We may choose to pursue new growth opportunities through acquisitions or other transactions. In addition to our cash on hand, we have access to at least $40 million of undrawn elected borrowing base availability under our senior secured credit facility. In addition we have an effective shelf registration statement with Securities and Exchange Commission under which we may issue up to $500 million of new debt or equity securities. If we choose to pursue new growth opportunities, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be

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advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to issue additional equity at this time.
Our other significant use of cash is our on-going cash dividend program. The Board of Directors instituted a cash dividend on our common stock in December 2013 and we have since paid twenty-three consecutive quarterly dividends. Distribution of a large portion 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 cash dividends over time as appropriate. On August 9, 2019, the Board declared the next quarterly common stock dividend of $0.10 per share, which will be paid on September 30, 2019 to stockholders of record on September 13, 2019. The Board reviews the quarterly dividend rate in view of our financial position and operations, forecasted results, including the outlook for oil and NGL prices, the timing of further expansion of Delhi field development and other potential growth opportunities.
Capital Budget - Delhi Field
During the year ended June 30, 2019, we incurred $5.2 million of capital expenditures at Delhi. This spending included $0.7 million for capital upgrades to the NGL plant, injection lines and facilities, $1.1 million for CO2 conformance projects and capital maintenance, $1.6 million for Phase V infrastructure (i.e. water curtain wells) in the eastern portion of the field, and $1.8 million for the infill drilling program.
The twelve well infill drilling program in the Delhi field is complete and the wells are contributing. There are ten producing oil wells and two CO2 injection wells. While we intended to drill four injection wells, two of the planned injectors were completed as producers. These wells may be re-completed as injectors at a later date. The injectors and producers were drilled and completed in areas needing additional support to sweep oil. Since the program's inception in fiscal 2018, our net capital expenditures have totaled $4.6 million.
We expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures. Such amounts are not known or approved yet but we expect them to run in the $1.0 to $2.0 million magnitude as it has the past two fiscal years.
Our proved undeveloped reserves at June 30, 2019 included 1,583 MBOE of reserves and approximately $8.6 million of future development costs associated with Phase V development in the eastern portion of the field. Such development requires participation by both the operator and Evolution, and the operator has not yet finalized its capital expenditure budget for 2020. Based our discussions with the operator, in fiscal 2020, we expect to spend about $0.6 million to complete the south water curtain in preparation for the Phase V development, which is expected to commence late in fiscal 2020. In our last three fiscal years we have incurred a total of $3.1 million on the water curtain program in advance of this development. The timing of Phase V is also dependent, in part, on the field operator's available funds and capital spending plans and priorities within its portfolio of properties.
Funding for our anticipated capital expenditures at Delhi over the next two fiscal years is expected to be met from cash flows from operations and current working capital.
Overview of Cash Flow Activities
The table below compares a summary of our condensed consolidated statements of cash flows for year ended June 30, 2019 and 2018.
 
June 30,
 
 
Increases (Decreases) in Cash:
2019
 
2018
 
Difference
 
(In Millions)
Net cash provided by operating activities
$
24.1

 
$
20.5

 
$
3.6

Net cash used in investing activities
(6.8
)
 
(3.7
)
 
(3.1
)
Net cash used in financing activities
(13.4
)
 
(12.2
)
 
(1.2
)
Change in cash, cash equivalents and restricted cash
$
3.9

 
$
4.6

 
$
(0.7
)
Cash provided by operating activities in the current year increased $3.6 million compared to the fiscal 2018 due to a $5.8 million increase in cash provided by non-cash expenses and $2.1 million increase in cash provided from current operating assets and liabilities partially offset by a $4.3 million decrease in cash provided by net income. Fiscal 2018 total non-cash expenses were impacted by the one-time $6.0 million deferred income tax credit related to enactment of the Tax Cut and Jobs Act.

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Cash used in investing activities increased $3.1 million due to higher capital expenditure disbursements in the 2019 period.
Cash used in financing activities increased $1.2 million due to $1.6 million of higher cash dividends, reflecting a higher quarterly dividend rate of $0.10 per share throughout fiscal 2019 compared to $0.075 per share during the first half of fiscal 2018 and $0.10 per share paid the subsequent two quarters, partially offset by $0.4 million of lower common share repurchases related to stock-based awards vestings.
Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2019, we are obligated to make under our contractual obligations and commitments. We expect to fund these contractual obligations with cash on hand and cash generated from operations.
 
Payments Due by Period
 
Total
 
Less than
1 Year
 
1 - 3 Years
 
3 - 5 Years
 
More than 5 Years
Contractual Obligations
 
 
 
 
 
 
 
 
 
Purchase commitments in connection with joint interest agreement
$
861,674

 
$
861,674

 
$

 
$

 
$

Operating lease
182,208

 
34,322

 
147,886

 

 

Other Obligations
 
 
 
 
 
 
 
 
 
Asset retirement obligations
1,610,845

 
50,244

 

 

 
1,560,601

Total Obligations
$
2,654,727

 
$
946,240

 
$
147,886

 
$

 
$
1,560,601


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 – Summary of Significant Accounting Policies of 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, 2019, 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

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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, 2019 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, 2019 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $313,000, $658,000 and $1,042,000, 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 drilled five years from the initial recognition date of such reserves, allows companies to disclose their probable and possible reserves to investors, requires reporting of oil and gas reserves using an average price based on the previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices, revises the disclosure requirements for oil and gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.
Valuation of Deferred Tax Assets.    We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared or filed; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carry backs and carry forwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our net operating loss). If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of June 30, 2019, 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. This technique uses a geometric Brownian motion model with defined variables and randomly generates values for each variable through multiple trials. Variables include 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 award on the date of grant. 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 and, for certain awards, the Company's share price attaining a set target.
Recent Accounting Pronouncements.    See Note 2 – Summary of Significant Accounting Policies to our Consolidated Financial Statements for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards Board.
Off Balance Sheet Arrangements
The Company has no off-balance sheet arrangements as of June 30, 2019.
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

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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, 2019.


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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

Opinion on the Financial Statements
 
We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and Subsidiaries (the “Company”) as of June 30, 2019 and 2018, the related consolidated statements of operations, cash flows and changes in stockholders’ equity for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of June 30, 2019 and 2018, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of June 30, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated September 12, 2019 expressed an unqualified opinion on the Company’s internal control over financial reporting.

 Basis for Opinion
 
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.



/s/    Moss Adams LLP

Houston, Texas
September 12, 2019

We have served as the Company’s auditor since 2017.



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Stockholders
Evolution Petroleum Corporation

Opinion on Internal Control over Financial Reporting
 
We have audited Evolution Petroleum Corporation and Subsidiaries’ (the “Company”) internal control over financial reporting as of June 30, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 30, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of Evolution Petroleum Corporation and Subsidiaries as of June 30, 2019 and 2018, the related consolidated statements of operations, cash flows and changes in stockholders’ equity for the years then ended, and the related notes (collectively referred to as the “consolidated  financial statements”) and our report dated September 12, 2019
expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
 
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 included in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. 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.

Definition and Limitations of Internal Control Over Financial Reporting
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.


/s/ Moss Adams LLP

Houston, Texas
September 12, 2019

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
 
June 30, 2019
 
June 30, 2018
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
31,552,533

 
$
24,929,844

Restricted cash

 
2,751,289

Receivables
3,168,116

 
3,941,916

Prepaid expenses and other current assets
458,278

 
524,507

Total current assets
35,178,927

 
32,147,556

Property and equipment, net of depreciation, depletion, and amortization
 
 
 
Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization
60,346,466

 
61,239,746

Other property and equipment, net
26,418

 
30,407

Total property and equipment, net
60,372,884

 
61,270,153

Other assets, net
210,033

 
244,835

Total assets
$
95,761,844

 
$
93,662,544

Liabilities and Stockholders' Equity
 
 
 
Current liabilities
 
 
 
Accounts payable
$
2,084,140

 
$
3,432,568

Accrued liabilities and other
537,755

 
874,886

State and federal taxes payable
130,799

 
122,760

Total current liabilities
2,752,694

 
4,430,214

Long term liabilities
 
 
 
Deferred income taxes
11,322,691

 
10,555,435

Asset retirement obligations
1,560,601

 
1,387,416

Total liabilities
15,635,986

 
16,373,065

Commitments and contingencies (Note 16)

 

Stockholders' equity
 
 
 
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,183,730 and 33,080,543 shares as of June 30, 2019 and 2018, respectively
33,183

 
33,080

Additional paid-in capital
42,488,913

 
41,757,645

Retained earnings
37,603,762

 
35,498,754

Total stockholders' equity
80,125,858

 
77,289,479

Total liabilities and stockholders' equity
$
95,761,844

 
$
93,662,544


   See accompanying notes to consolidated financial statements.

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Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
 
Years Ended June 30,
 
2019
 
2018
Revenues
 
 
 
Crude oil
$
40,779,052

 
$
38,153,417

Natural gas liquids
2,449,359

 
2,620,110

Natural gas
1,210

 

Total revenues
43,229,621

 
40,773,527

Operating costs
 
 
 
Production costs
14,266,784

 
11,685,817

Depreciation, depletion and amortization
6,253,083

 
6,102,288

General and administrative expenses*
5,072,931

 
6,773,781

Total operating costs
25,592,798

 
24,561,886

Income from operations
17,636,823

 
16,211,641

Other
 
 
 
Enduro transaction breakup fee
1,100,000

 

Interest and other income
239,150

 
85,654

Interest (expense)
(116,546
)
 
(110,780
)
Income before income tax provision
18,859,427

 
16,186,515

Income tax provision (benefit)
3,482,361

 
(3,431,969
)
Net income attributable to common shareholders
$
15,377,066

 
$
19,618,484

Earnings per common share
 
 
 
Basic
$
0.46

 
$
0.59

Diluted
$
0.46

 
$
0.59

Weighted average number of common shares outstanding
 
 
 
Basic
33,160,283

 
33,126,469

Diluted
33,169,718

 
33,178,535

_______________________________________________________________________________
*
General and administrative expenses for the years ended June 30, 2019 and 2018 included non-cash stock-based compensation expense of $888,162 and $1,366,764, 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,
 
2019
 
2018
Cash flows from operating activities
 
 
 
Net income attributable to the Company
$
15,377,066

 
$
19,618,484

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
6,268,239

 
6,158,555

Stock-based compensation
888,162

 
1,366,764

Deferred income taxes
767,256

 
(5,270,856
)
Changes in operating assets and liabilities:
 
 
 
Receivables
773,800

 
(1,215,214
)
Prepaid expenses and other current assets
66,229

 
(136,835
)
Accounts payable and accrued expenses
(90,891
)
 
(107,081
)
Income taxes payable
8,039

 
122,760

Net cash provided by operating activities
24,057,900

 
20,536,577

Cash flows from investing activities
 
 
 
Development of oil and natural gas properties
(6,746,142
)
 
(3,690,845
)
Capital expenditures for other property and equipment
(11,509
)
 
(7,846
)
Other assets

 
(19,282
)
Net cash used by investing activities
(6,757,651
)
 
(3,717,973
)
Cash flows from financing activities
 
 
 
Common share repurchases, including shares surrendered for tax withholding
(156,791
)
 
(571,083
)
Common stock dividends paid
(13,272,058
)
 
(11,594,541
)
Net cash provided by (used in) financing activities
(13,428,849
)
 
(12,165,624
)
Net increase in cash, cash equivalents and restricted cash
3,871,400

 
4,652,980

Cash, cash equivalents and restricted cash, beginning of year
27,681,133

 
23,028,153

Cash, cash equivalents and restricted cash, end of year
$
31,552,533

 
$
27,681,133

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the statements of financial position that sum to the totals of the such amounts shown in the statements of cash flows.
 
Years Ended June 30,
 
2019
 
2018
Cash and cash equivalents
$
31,552,533

 
$
24,929,844

Restricted cash included in current assets

 
2,751,289

Total cash, cash equivalents and restricted cash shown in the statements of cash flows
$
31,552,533

 
$
27,681,133


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, 2019 and 2018
 
Common Stock
 
 
 
 
 
 
 
 
 
Additional
Paid-in
Capital
 
Retained
Earnings
 
Treasury
Stock
 
Total
Stockholders'
Equity
 
Shares
 
Par Value
 
Balance, June 30, 2017
33,087,308

 
$
33,087

 
$
40,961,957

 
$
27,474,811

 
$

 
$
68,469,855

Issuance of restricted common stock
183,537

 
183

 
(183
)
 

 

 

Forfeitures of restricted stock
(117,094
)
 
(117
)
 
117

 

 

 

Common share repurchases, including shares surrendered for tax withholding
(73,208
)
 

 

 

 
(571,083
)
 
(571,083
)
Retirements of treasury stock

 
(73
)
 
(571,010
)
 

 
571,083

 

Stock-based compensation

 

 
1,366,764