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EX-99.1 - EXHIBIT 99.1 - EVOLUTION PETROLEUM CORPa2020fysecrotpwith991fin.htm
EX-32.2 - EXHIBIT 32.2 - EVOLUTION PETROLEUM CORPa6302020exhibit322.htm
EX-32.1 - EXHIBIT 32.1 - EVOLUTION PETROLEUM CORPa6302020exhibit321.htm
EX-31.2 - EXHIBIT 31.2 - EVOLUTION PETROLEUM CORPa6302020exhibit312.htm
EX-31.1 - EXHIBIT 31.1 - EVOLUTION PETROLEUM CORPa6302020exhibit311.htm
EX-23.2 - EXHIBIT 23.2 - EVOLUTION PETROLEUM CORPdandmconsent63020exh_232.htm
EX-23.1 - EXHIBIT 23.1 - EVOLUTION PETROLEUM CORPmossadamsconsent63020exh_2.htm
EX-21.1 - EXHIBIT 21.1 - EVOLUTION PETROLEUM CORPlistofsubs63020exh211.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 2020
 
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)

epclogo4qandksa10.jpg
Nevada
 
41-1781991
(State or other jurisdiction of
incorporation or organization)
 
(IRS Employer
Identification No.)
1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079
(Address of principal executive offices and zip code)
(713935-0122
(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:     No
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:     No
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    No: 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes    No: 
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 
 
Accelerated filer
Non-accelerated filer 
 
Smaller reporting company  
 
 
 
Emerging growth company 
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.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes:     No: 
The aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $5.47 on the NYSE American was $122,253,472.
The number of shares outstanding of the registrant's common stock, par value $0.001, as of September 1, 2020, was 32,956,469.



DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant's 2020 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
2020 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.

i


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 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.


ii


GLOSSARY OF SELECTED PETROLEUM INDUSTRY TERMS
Term
 
Definition
Bbls
 
Barrels of oil or natural gas liquids.
BFPD
 
Barrels of fluid per day.
BOE
 
Barrels of oil equivalent. BOE is calculated by converting 6 MCF of natural gas to 1 Bbl of oil which reflects energy equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
BOPD
 
Barrels of oil per day.
BTU
 
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; CO2 is a gas that can be found in naturally occurring reservoirs, is typically associated with ancient volcanoes, is a major byproduct from manufacturing and power production, and is 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 a means not involving a well.
EOR
 
Enhanced Oil Recovery; projects that 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 within or related to the same geologic structural features and/or stratigraphic features.*
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 which potentially increases 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.
MMBOE
 
One million barrels of oil equivalent.
MMBTU
 
One million British Thermal Units.
MMCE
 
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.
NGL
 
Natural gas liquids; 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 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."

iii


Permeability
 
The measure of ease with which a fluid can move through a reservoir. The unit of measure is a darcy(d), or any metric derivation thereof, such as a millidarcy(md), where one darcy equals 1,000 millidarcys. Extremely low permeability of 10 millidarcys, or less, are often associated with source rocks, such as shale. Extraction of hydrocarbons from a source rock is more difficult than a sandstone reservoir where permeability typically ranges one to two darcys or more.
Porosity
 
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.
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 a means not involving a well.
Proved Developed Nonproducing Reserves
 
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.
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 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 are 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").

iv


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.


v


PART I
Item 1.    Business
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 consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery project, and our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, and overriding royalty interests in two onshore Texas wells.
Our interests in the Delhi field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue interest of 26.2%. The field is operated by Denbury Onshore LLC ("Denbury"), a subsidiary of Denbury Resources, Inc.
On November 1, 2019, the Company acquired non-operated working interests in the Hamilton Dome field consisting of a 23.5% working interest, with an associated 19.7% revenue interest (inclusive of a small overriding royalty interest). The field is operated by Merit Energy Company ("Merit"), a private oil and gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field. Our acquired interest in Hamilton Dome aligned with the Company's strategy of adding long lived, low decline reserves expected to be supportive of our dividend over the long-term.
Significant Activity in Fiscal 2020
Proved oil equivalent reserves at June 30, 2020 were 10.2 MMBOE, a 13% increase from the previous year primarily due to the acquisition of the Hamilton Dome field in November 2019. The Standardized Measure for proved reserves decreased 51% to $62 million, as the acquisition of the Hamilton Dome field was offset by the decrease in the average first day of the month net oil price from $64.54 per barrel of oil and $23.83 per barrel of natural gas liquids at June 30, 2019 to $46.37 per barrel of oil and $9.00 per barrel of natural gas liquids at June 30, 2020. Our proved reserves consist of 80% crude oil and 20% natural gas liquids, 82% are classified as proved developed producing and 18% are proved undeveloped.
We recognized net income of $5.9 million, or $0.18 per diluted common share, our ninth consecutive year of reporting net income.
Returned to shareholders $10.7 million in cash dividends and $2.5 million in stock repurchases in fiscal 2020. The Company has paid out to shareholders more than $70 million in cash dividends since inception of the dividend program in December 2013.
Closed the acquisition of non-operating working interest in the Hamilton Dome field on November 1, 2019 which included total proved reserves of 1.47 MMBOE as of June 30, 2020 as estimated by DeGolyer & MacNaughton ("D&M"), an independent reservoir engineering firm.
Reported $12.4 million of cash flows from operations for the fiscal year ended June 30, 2020. We funded all operations, including $11.8 million of capital spending inclusive of our $9.3 million acquisition of our interest in the Hamilton Dome Field, from internal resources and remain debt free at June 30, 2020.
In order to mitigate the impact of the growing global COVID-19 pandemic on our employees, we continue to follow local stay-at-home orders and remotely work from home with minimal disruptions to our business operations.
We entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel, recording a loss of $1.4 million at June 30, 2020. Of this amount, $1.9 million were non-cash, unrealized mark-to-market losses as commodity prices improved from those existing at fiscal year-end, offset in part by $0.5 million in realized gains during the fiscal fourth quarter. 

1


We completed remaining capital expenditures for the six-well water curtain program and related infrastructure preceding the planned Delhi Phase V development, which was delayed by the operator until our fiscal fourth quarter of 2021.
In July 2020, Denbury Resources announced that it had entered into a restructuring support agreement with certain of its debt holders and filed a pre-packaged voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in Texas. Denbury Resources is seeking to eliminate $2.1 billion of debt. Denbury subsequently announced on September 3, 2020 that its plan to eliminate $2.1 billion of its bond debt has been confirmed by the court which will substantially reduce its debt and strengthen its balance sheet.
Our Reserves: Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our independent reservoir engineering firm, D&M, assigned the estimated reserves net to our interests at Delhi as of June 30, 2020; we had 8.7 million bbls of total proved oil equivalent reserves. The following table summarizes the reserves assigned by D&M:
 
Reserves as of June 30, 2020
 
Proved
Reserves MBOE
8,746

% Developed
79
%
Liquids %
100
%
Development History of the Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our working and royalty interests in the Delhi field is currently our largest producing asset. The Holt-Bryant Unit ("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 Denbury 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 21.5 million bbls of oil.

phasemapatdelhia02.jpg
After the May 2006 conveyance, Denbury as the operator, originally planned six primary phases for the installation of the CO2 flood in the Delhi field. Four of these six phases have been completed as of June 30, 2020 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 (Phase VI) was removed from proved reserves 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.

2


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 initially installed and subsequently expanded during calendar 2011. First oil production response from Phase III occurred during June 2011, and field gross production subsequently increased to more than 5,000 gross barrels of oil per day by December 2011.
Phase IV was 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. First oil production response from Phase IV occurred during August 2012, and field gross production increased to more than 7,500 gross barrels of oil per day by February 2013.
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, has isolated that part of the field with a water curtain, thus removing the area from the CO2 flood.
Construction began on the NGL extraction plant in February 2015 and 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 extraction plant are used to generate electrical power for 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. To date, we have incurred a net capital cost of approximately $27.4 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 significantly reduced capital spending as a result of declining oil prices. Resumption of this work has been delayed due to low prevailing oil prices and the operator's 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.
An infill drilling program commenced in March 2018 to target productive oil zones in the developed areas of the field that were not being swept efficiently by the CO2 flood.During fiscal 2019 the 12 well infill program, consisting of 10 producing wells and two CO2 injection wells, was completed. Proved undeveloped reserves of 536 MBOE were converted to proved developed reserves.
Additionally during fiscal 2019, 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 injection well followed by three injection wells in fiscal 2018. During fiscal 2019, the operator drilled the two remaining injection wells and proceeded with completions and injection line work. The first pad commenced operations during fiscal 2019 and the second pad began injections during our second quarter of fiscal 2020.
At June 30, 2020, we had total proved reserves of 8.7 MMBOE at Delhi, which was comprised of 6.7 MMBOE of oil and 2.0 MMBOE of NGLs as estimated by our independent petroleum engineering firm. The following table sets forth our estimated proved reserves as of June 30, 2020. For additional reserve information see Note 21 to our consolidated financial statements in Item 8.
Reserve Category
Oil
(MBbls)
 
NGLs
(MBbls)
 
Total Reserves
(MBOE)*
PROVED
 
 
 
 
 
Developed Producing (79% of Proved)
5,105

 
1,777

 
6,882

Undeveloped (21% of Proved)
1,648

 
216

 
1,864

TOTAL PROVED
6,753

 
1,993

 
8,746

Product Mix
77
%
 
23
%
 
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 which reflects energy equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

3


For fiscal 2020, average gross daily oil production at Delhi was 5,632 BOPD and 1,106 bbls NGLs per day (6,738 BOEPD). The total gross purchased CO2 volume was 19 BCF for fiscal 2020. In February 2020, the CO2 purchase line to Delhi was shut-in by the pipeline operator for extensive repairs. No CO2 was purchased from the shut-in date through June 2020. The recycle facilities continue to operate as usual providing approximately 80% of the injected CO2 volumes to Delhi with production somewhat reduced due to lower injection volumes. Per communications with Denbury, the CO2 line is currently being repaired and is projected to be completed early in the second quarter of our fiscal 2021.
Our Reserves: Hamilton Dome - Hot Springs County, Wyoming
Our independent reservoir engineering firm, D&M, assigned the estimated reserves net to our interests at Hamilton Dome as of June 30, 2020; we had 1.5 million bbls of total proved oil equivalent reserves. The following table summarizes the reserves assigned by D&M:
 
Reserves as of June 30, 2020
 
Proved
Reserves MBOE
1,473

% Developed
100
%
Liquids %
100
%
On November 1, 2019, the Company acquired certain mineral interests in the Hamilton Dome field from Merit, who owns the vast majority of the remaining working interest in the field. The Hamilton Dome field is located in the southwest part of the Big Horn Basin in northwest Wyoming about twenty miles northwest of Thermopolis in Hot Springs County.
hamiltondomelocatormap.jpg

4


Our interest includes a 23.5% working interest and an associated 19.7% revenue interest (inclusive of a small overriding royalty interest). The Hamilton Dome field has produced over 160 MMBO over the last 100 years; Merit has operated the field over the last 25 years. Production from this field is 100% oil and is currently averaging low single-digit decline rates.
Development History of the Hamilton Dome Field - Hot Springs County, Wyoming
Oil was first discovered at the Hamilton Dome field within the Big Horn Basin in September 1918 in the Curtis/Chugwater reservoir by New York Oil Company via surface mapping. Shortly thereafter, the Phosphoria and Tensleep formations were discovered in 1919 and 1929, respectively. The field is part of an anticlinal fold with a southerly bounding fault with approximately 4,500-5,000 feet of displacement, thus providing a structural trap. The two major producing formations are the Tensleep (sandstone) and Phospohoria (limestone) reservoirs. Additional present day and historical production exists from the Curtis/Chugwater (sandstone), Amsden (sandstone), Madison (limestone), and Big Horn (dolomite) formations. These formations produce from depths ranging approximately 1,500 to 3,600 feet and have historically produced at rates of greater than 25,000 gross BOPD. The productive surface area of the field spans approximately 2,500 acres. The original oil in place of the six producing reservoirs is estimated to be at least 500 million barrels. Over the last 100 years, more than 160 million barrels have been produced from the field.
Although the Tensleep reservoir was discovered in 1929, it remained largely undeveloped until World War II. Active development of the Tensleep reservoir occurred between 1944 and 1960. The Madison and Darwin reservoirs were discovered in 1948 and 1959, respectively. These two reservoirs were developed sporadically from 1950 through the 1970’s. In 1970, 52 years after the field’s discovery, a waterflood was implemented in the Curtis/Chugwater reservoir. In 1973, the Phosphoria reservoir was unitized in order to implement a waterflood of the reservoir, this unit is still in place and is approximately 3,160 acres. In the early 1970’s, Tensleep production was down spaced to 5 acres and in the late 1970’s an isolated Tensleep waterflood was implemented. By 1981, the Tensleep reservoir had produced more than 147 million bbls. The last active development of the Curtis/Chugwater reservoir occurred in 1978 when the waterflood was ended. The Madison reservoir was further developed in the early 1990’s.
Merit Energy purchased the field in 1995 and has operated the field for 25 years; the field was unitized in 1996. The Phosphoria and Tensleep reservoirs were permitted for unlimited commingling in 1996 as well. In 1997, Merit began a capital workover program to downspace the Phosphoria reservoir to 10 acres in addition to improving the Tensleep and Phosphoria waterfloods and eliminating commingled production.
Under Merit’s operations, the wells in the Hamilton Dome field are produced via electric submersible pumps (ESP) and rod pumps. Typical workovers in the field include rod repair, ESP repair, injector acid jobs, and wellbore cleanouts.
At June 30, 2020, EPM has total net proved reserves of 1.47 MMBOE at Hamilton Dome which was entirely comprised of oil as estimated by our independent reservoir engineering firm. The following table sets forth our estimated proved reserves as of June 30, 2020 for our Hamilton Dome field. For additional reserve information see Note 21 to our consolidated financial statements in Item 8.
Reserve Category
Oil
(MBbls)
 
NGLs
(MBbls)
 
Total Reserves
(MBOE)*
PROVED
 
 
 
 
 
Developed Producing (100% of Proved)
1,473

 

 
1,473

Undeveloped (0% of Proved)

 

 

TOTAL PROVED
1,473

 

 
1,473

Product Mix
100
%
 
%
 
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 which reflects energy equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
Following acquisition in November 2019, average gross daily production was 2,048 BOPD through the end of fiscal 2020. From March to June 2020, the production rate was negatively impacted by an estimated 870 gross BOPD, or approximately 38%, due to the shut-in of 61 wells as a result of the drop in oil prices.
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,

5


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.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2020
Our proved reserves at June 30, 2020, 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 reservoir engineer, DeGolyer and MacNaughton which was formed in 1936. D&M has completed more than 23,000 projects in more than 100 countries. D&M was selected to estimate reserves primarily 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 reserves as of June 30, 2020. For additional reserve information see Note 21 to our consolidated financial statements in Item 8. The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $47.37 per barrel of crude oil. The net price per barrel of NGLs was $9.00, 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 geographic area. Pricing differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual property and product.
Reserves as of June 30, 2020
Reserve Category
Oil
(MBbls)
 
NGLs
(MBbls)
 
Total Reserves
(MBOE)*
PROVED
 
 
 
 
 
Developed Producing (82% of Proved)
6,578

 
1,777

 
8,355

Undeveloped (18% of Proved)
1,648

 
216

 
1,864

TOTAL PROVED
8,226

 
1,993

 
10,219

Product Mix
80
%
 
20
%
 
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 which reflects energy equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
.

6


The following table presents a reconciliation of changes in our proved 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, 2019
8,981

Purchases

Production
(647
)
Revisions (a)
412

Sales of minerals in place

Improved recovery, extensions and discoveries

June 30, 2020
8,746

(a) Positive revisions of 412 MBOE at Delhi field reflect adjusted methodology of forecasting NGLs independently from the oil production forecast by our independent reservoir engineering firm.
 
Hamilton Dome Field Proved
Total
Proved reserves, MBOE
 MBOE
June 30, 2019

Purchases
3,427

Production
(98
)
Revisions (a)
(1,856
)
Sales of minerals in place

Improved recovery, extensions and discoveries

June 30, 2020
1,473

(a) Negative revisions of 1,856 MBOE were due to the impacts of lower oil prices since the field’s November 2019 acquisition and to subsequent reduced rates of production. Responding to lower oil prices, in March, the operator shut in wells that were not economic to optimize the field's cash flow. Although some returned to production as prices improved, as of June 30, 2020, approximately 25% of the wells remained shut-in. The lowered historical production curve and lower SEC average price, resulted in the field reaching its economic limit sooner than it had when proved reserves were estimated at the acquisition date.
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 President and Chief Executive Officer, Jason Brown, who 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. Such reserves estimates are in compliance with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC.
The reserves information in this filing is based on estimates prepared by D&M, our independent petroleum engineering firm, which was formed in 1936 and has completed more than 23,000 projects in more than 100 countries. The person responsible for preparing the reserves report with D&M is a Registered Professional Engineer in the State of Texas and a 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.

7


We provide D&M with our property interests, production, current operating costs, current production prices and other information in order to prepare the reserve estimates. This information is reviewed by our President and Chief Executive Officer, designated operations personnel, and other members of management to ensure accuracy and completeness of the data prior to submission to D&M. The scope and results of D&M'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 1,864 MBOE at June 30, 2020, with associated future development costs of approximately $8.6 million, which are associated with the Phase V development of Delhi field. The Company does not have any proved undeveloped reserves associated with its Hamilton Dome field acquired in November of 2019.
During the year ended June 30, 2020 our proved undeveloped reserves changed as follows:
 
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
 
 
Total Reserves
(MBOE)
June 30, 2019
 
1,342

 
241

 
 
 
1,583

Revisions to previous estimates
 
306

 
(25
)
 
 
 
281

Conversion to proved developed reserves
 

 

 
 
 

June 30, 2020
 
1,648

 
216

 
 
 
1,864

Price declines resulted in a reclassification of a small volume of oil reserves from PDP to PUD at June 30, 2020. The decline in price led to currently producing wells becoming uneconomic at an earlier point in time than previously estimated.  However, when forecasted in conjunction with the PUD reserves the overall economic life of the field is extended. Due to the EOR unit nature of Delhi, this PDP reduction shifts those reserves to our PUD oil reserves as they are considered proved and expected to be recovered as a result of the development of our Phase V. NGL reserves were revised downward 25 MBbls primarily due to the adjusted methodology of projecting NGL volumes independent of oil production, shifting them into developed NGL volumes. 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 this project's inception in March 2018, its net capital expenditures have totaled $4.6 million.
The initial assignment of proved undeveloped reserves in the Delhi field was made on June 30, 2010, which encompassed a large scale CO2 enhanced oil recovery project. The operator’s development plans for the field have remained essentially unchanged and were originally scheduled to be completed by June 30, 2015, within five years from the initial recording of such proved reserves. However, as a result of the adverse fluid release event in the field in June 2013 and the resulting delay in reversion of our working interest, development of the field has not proceeded as originally scheduled. Expansion of the CO2 flood to the remaining undeveloped eastern portion of the field commenced subsequent to reversion of our working interest in late calendar 2014. We incurred $3.8 million of capital expenditures before the operator electively deferred this project as a result of a reduction in its cash flows and capital spending from the significant drop in oil prices. This project was further electively deferred as we began work on the NGL recovery plant 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 $3.7 million as of June 30, 2020, including $0.6 million and $1.6 million in fiscal years 2020 and 2019, respectively, on the six well water curtain program and related infrastructure required to precede the development of Phase V. As of June 30, 2020 we had drilled all the injection wells, including four gross injection wells during fiscal 2019, and commenced operations for one of the program's pads. The program was configured as two pads, each having two injection wells and one water source well. The second pad was completed during fiscal 2020 and began injections during our second quarter of fiscal 2020.
As of June 30, 2020, 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 May 2021 based on our discussions with the operator. The timing of Phase V development is dependent on the field operator's available funds and capital spending plans and priorities within its portfolio of properties.

8


We believe this project is economic in the current oil price environment and we expect it to be completed within the next four fiscal years. We have been continuously developing the Delhi field and have spent over $48 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, 2020, no proved 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 proved 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 any proved reserves associated with our interests in the Mengel Sand, a separate interval within the Unit that is not currently producing, but has produced oil in the past.
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, 2020
 
Year Ended 
 June 30, 2019
 
Year Ended 
 June 30, 2018
Product
Volume
 
Price
 
Volume
 
Price
 
Volume
 
Price
Crude oil (Bbls)
638,464

 
$
44.76

 
626,879

 
$
65.05

 
651,931

 
$
58.52

Natural gas liquids (Bbls)
106,159

 
$
9.59

 
112,013

 
$
21.87

 
93,366

 
$
28.06

Natural gas (Mcf)
1,087

 
$
1.90

 
459

 
$
2.64

 

 
$

Average price per BOE*
744,804

 
$
39.74

 
738,968

 
$
58.50

 
745,297

 
$
54.71

 
 
 
 
 
 
 
 
 
 
 
 
Production costs
Amount
 
per BOE
 
Amount
 
per BOE
 
Amount
 
per BOE
Production costs, excluding ad valorem and production taxes
$
12,966,923

 
$
17.41

 
$
14,027,461

 
$
18.98

 
$
11,497,759

 
$
15.43

Total production costs, including ad valorem and production taxes
$
13,505,502

 
$
18.13

 
$
14,266,784

 
$
19.31

 
$
11,685,817

 
$
15.68

*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.
Drilling Activity
Our productive drilling activity during the past three fiscal years at Delhi field ended June 30, 2020, and 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. 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 drilled three (0.72 net) wells and in fiscal 2017 one (0.239 net) well was drilled. A pad consists of one gross water source well and two gross water injector wells. The three completed wells comprise the northern pad of the water curtain program which commenced injection during fiscal 2019. The southern pad became fully operational late in the second quarter of fiscal 2020 when capital expenditures for completion work concluded.
Hamilton Dome field is considered fully developed. No wells were drilled in fiscal 2020 and there are no plans to drill wells in fiscal 2021.

9


Present Activities
The operator is completing a SCADA (supervisory control and data acquisition) well monitoring capital project at present which will improve the flow of information and assist in the real-time management of the Delhi field. There are no significant drilling plans until Phase V development, expected to commence in the fourth quarter of fiscal 2021.
For further discussion, see "Highlights for our fiscal year 2020" and "Capital Expenditures" within Item 7.
Delivery Commitments
As of June 30, 2020, 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.
If the price of oil remains above $32.00, we have a financial commitment as we entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel.
Productive Wells
The following table sets forth the number of productive oil and gas wells in which we own a working interest as of June 30, 2020.
 
Company Operated
 
Non-Operated
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Crude oil

 

 
315

 
74.5

 
315

 
74.5

Natural gas

 

 

 

 

 

Total

 

 
315

 
74.5

 
315

 
74.5

Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2020. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would allow 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 (1)
Developed Acreage
 
Undeveloped Acreage
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Delhi Field, Louisiana (2)
9,126

 
2,180

 
4,510

 
1,077

 
13,636

 
3,257

Hamilton Dome Field, Wyoming
5,908

 
1,389

 

 

 
5,908

 
1,389

Total
15,034

 
3,569

 
4,510

 
1,077

 
19,544

 
4,646


(1) All acreage, including any undeveloped, nonproductive or undrilled acreage, is held by existing production as long as continuous production is maintained in the unit.
(2) This table excludes acreage attributable to small overriding royalty interests retained in various formations in the Texas Giddings Field area. Except for de minimis production that began on two leases during later 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.

10


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 per the State of Louisiana Department of Conservation order number 96-G-5, all acreage, including any undeveloped, nonproductive or undrilled acreage is held by existing production as long as continuous production is maintained in the unit.
When the Company acquired Hamilton Dome field on November, 1 2019, the field had been fully developed through primary recovery and all acreage is reflected as developed acreage. The Tensleep and Phosphoria were permitted for commingling and unitized in 1996 following purchase of the field by Merit Energy.  The Company estimates that our developed acreage includes 5,908 gross (1,389 net) acres in the Hamilton Dome field, with no acres attributable as undeveloped.  We own 23.5% working interest in the field, along with a small overriding royalty interest. As Hamilton Dome is unitized, all acreage is held by existing production as long as continuous production is maintained in the unit. We are not operators of Hamilton Dome field.
For more complete information regarding current year activities, including crude oil and natural gas production, refer to Item 7.
Markets and Customers
Our production is marketed to third parties in a manner consistent with industry practices. In the United States of America 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 nor from Hamilton Dome separately from the operators' shares of production. Although we have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts. Under such arrangements we typically do not know the identity of the buyers of production except in the case of the Delhi field where there is a sole buyer for oil and another for NGL's.
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 $0.77 per barrel during our fiscal year ended June 30, 2020, compared to $4.11 per barrel for the prior year. In the current fiscal year, the differential was impacted by market conditions over the second half of the fiscal year and trucking charges that were incurred for several months while the sales pipeline underwent repair. NGL production is sold to a midstream processing company which fractionates the stream and sells the resulting hydrocarbons.
On November 1, 2019, Evolution acquired a non-operated interest in the Hamilton Dome field in Wyoming. All the field’s production is sour heavy crude oil which is the sole component of the field’s reserves. Crude oil is transported by pipeline primarily to purchasers in Casper, Wyoming. As a result of transportation differentials, the high sulfur content and low API gravity, this crude trades at a discount to WTI, averaging $17.62 lower over the last eight months. Although we have the option of taking our production in kind, we have elected to have the operator market our share of production. Our realized price is net of transportation and marketing costs.
The following table sets forth purchasers of our oil and natural gas liquid production for the years indicated:
 
Year Ended June 30,
Customer
2020
 
2019
Plains Marketing L.P. (Delhi field oil)
87
%
 
94
%
Merit Energy Company (Hamilton Dome field oil)
10
%
 
%
Third Coast Midstream (Delhi field NGLs)
3
%
 
6
%
All others
%
 
%
Total
100
%
 
100
%
The loss of a purchaser at either the Delhi or Hamilton Dome fields or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.

11


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.
Oil prices over the past few years have fluctuated and been extremely volatile. For example, average daily prices for WTI crude oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel over our past few fiscal years. Starting in the fourth quarter of 2014, the price of oil per barrel dropped dramatically and continuing into 2017 before recovering somewhat in late calendar 2018, then weakening again in 2019 and dropping substantially in 2020 as a result of the impact of the COVID-19 pandemic and geopolitical factors. Worldwide factors such as global health pandemics, 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.
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, 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. 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 areas and geological systems and the abilities to efficiently conduct operations, achieve technological advantages, identify, and acquire economically producible reserves and obtain capital at rates which allow economic investments.
Risk Management
Derivative instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We have designed a risk management policy to use derivative instruments from time to time during periods of extraordinary price volatility and when such instruments are needed to ensure the Company can meet its current dividend policy, fund its capital expenditures commitments and maintain liquidity. We determine the duration of derivative positions to approximate the anticipated period of volatility and the percentage of our production to be hedged, based on our view of current and future market conditions. We do not enter into derivative contracts for speculative trading purposes.
While there are many different types of derivatives available, we typically use fixed-price swap and costless collars to attempt to manage price risk. The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under the agreement is below the floor.
We entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel. In the future we may add additional swaps or other derivative positions covering a variable portion of our anticipated future production during subsequent periods.
It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. As of June 30, 2020, we did not post collateral under any of our derivative contracts as they are uncollateralized trades. We will continue to evaluate the benefit of employing derivatives in the future. See Item 7A and Note 19 to our consolidated financial statements in Item 8 for additional information.
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 environment is often difficult and costly; substantial penalties may be incurred for noncompliance. To the best of our knowledge, we are in compliance with all federal and state-level laws and regulations applicable to our operations. The future annual capital cost of complying with the regulations applicable to our operations is

12


uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable. We do not currently anticipate that continued and future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.
See discussion captioned "Government regulation and liability for oil and gas operations and environmental matters may adversely affect our business and results of operations" in Item 1A.
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  and 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, 2020, 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.
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.

13


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 a negative $38 per barrel over our past few fiscal years. 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:
changes in global supply and demand for oil and natural gas, which has recently been negatively affected by concerns about the impact of COVID-19;
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 affecting energy consumption; and
the price and availability of alternative fuels.
Substantially all of our production is sold to purchasers under short-term (less than 12-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 80% of our proved reserves at June 30, 2020 are crude oil reserves and 20% 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 two assets 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.
Our revenues come from our royalty, mineral and working interests in the Delhi field in Louisiana and the Hamilton Dome field in Wyoming and thus our current revenues are highly concentrated in these fields. Any significant downturn in production, oil and NGL prices, or other events beyond our control which impact these fields could have a material adverse effect on our results of operations and financial results. We are not the operator of these fields, 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 and our newly acquired interests in the

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Hamilton Dome field in Wyoming. Environmental or operating problems or lack of extended future investment in either of these fields 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. In fiscal 2020, our production was impacted by the operators of both fields. Delhi production volumes were negatively impacted as a result of the financial strain Denbury was under and their lack of investment in projects in the field, including the delay of our Phase V, in addition to the purchased CO2 line being shut in for repairs. In the Hamilton Dome field Merit temporarily shut in a portion of the production as it was uneconomic at the historically low prices. As of June 30, 2020, a number of these wells have returned to production and we continue to monitor their performance; however, there is no guarantee that prolonged periods of being shut in or lack of investment would not negatively impact future production.
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 operators with respect to the successful operation of our principal assets, which consists of our interests Delhi and Hamilton Dome fields. A materially negative change in our operator’s financial condition could negatively affect operations (or timing thereof) in these fields, and consequently our income (or timing thereof) from these fields as well as the value of our interests in these fields.
Our royalty, mineral and working interests in the Delhi field, located in Northeast Louisiana are our primary producing assets. Approximately 90% of our revenues come from the Delhi 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. 
On February 22, 2020, DNR experienced a pressure loss in its CO2 purchase pipeline resulting in an immediate shut down.  DNR cut out a section of the failed pipeline and sent it out for analysis on the cause of the failure and remediation procedures.  Analysis results, with the consultation the government regulating agency, recommended repairing the damaged section of pipeline.  DNR has informed the Company that preparations for this project are underway and the CO2 purchases line should be back in operation October 1, 2020.
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. 
In July 2020, Denbury announced that it had entered into a Restructuring Support Agreement (the “RSA”) with holders of 100% of revolving credit facility loans, approximately 67.2% of second lien notes and approximately 70.8% of convertible notes for a “pre-packaged” plan to eliminate $2.1 billion of bond debt and subsequently filed for voluntarily filed petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas. Denbury subsequently announced on September 3rd that its plan to eliminate $2.1 billion of its bond debt has been confirmed by the court which will substantially reduce its debt, strengthen its balance sheet, and position Denbury to free up capital for investment in properties such as Delhi again.


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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 and Hamilton Dome assets are productive from relatively shallow reservoirs; we may pursue assets that produce from deeper reservoirs in the future. 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 cost and 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 produce incremental reserves.
Our CO2-EOR project in the Delhi field, operated by a subsidiary of Denbury Resources Inc., requires significant amounts of CO2 reserves, development capital and technical expertise, the sources of which to date have been committed by the operator. Although initial CO2 injection began at Delhi in November 2009, initial oil production response began in March 2010 and a large part of the capital budget has already been expended. Additional capital remains to be invested to fully develop the EOR project, further increase production, and maximize the value of the asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial, and logistical risks may cause ultimate enhanced recoveries from the planned CO2-EOR project to fall short of our expectations in volume and/or timing. Such occurrences would have a material adverse effect on the Company, its results of operations and financial condition.
Crude oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production, and drilling and completing new wells are speculative activities which 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. The risk that no commercially productive crude oil or natural gas reservoirs will be encountered is paramount. The cost of drilling, completing and operating wells is substantial and uncertain; 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 reservoir formations;
equipment failures or accidents;
regulatory climate;
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, 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 guarantee that our overall drilling success rate 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, 2020, one purchaser accounted for approximately 87% of our total oil revenues. We do not currently market our share of crude oil production from the Delhi or Hamilton Dome fields. Although we have the right to take our working interest production in-kind, we are currently accepting terms under the operators' agreements for the delivery and pricing of our oil. The loss of a large purchaser for our oil production could negatively impact the revenue we receive. We cannot guarantee that we could readily find other purchasers for our oil and natural gas production. In addition, the crude oil production from the Delhi and Hamilton Dome fields is transported by pipeline; if either of these pipelines 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.

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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 inherent uncertainties. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot always be measured in an exact manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors. These factors include historical production from the area compared with production from other comparable producing areas, 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, work-over costs, and remedial costs. Some or all of these assumptions utilized in estimating reserve volumes may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of reserves, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected from reserves may vary substantially depending on the timing ang and different engineers preparing reserves estimates.
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; 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. Interest rates in effect vary from time to time based on risks associated with us or the oil and natural gas industry in general. The Standardized Measure does not necessarily correspond to market value.
Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.
On a periodic basis we review the carrying value of our crude oil and natural gas properties under the applicable rules of 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 of 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, 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. Derivative arrangements may include 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.

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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;
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.
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 portions of our undeveloped leasehold acreage may be subject to expiration 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 will be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult and may involve unexpected costs or delays.

We periodically evaluate acquisitions of reserves, properties, prospects, 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.

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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, integrating significant acquisitions, and strategic transactions in concert with the Company's ongoing business demands;
the challenge and cost of integrating acquired operations, information management, 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 may be required in connection with expanded operations and unknown liabilities; and
the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. In addition, even if we successfully integrate the assets acquired in an acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volumes, cost savings from operating synergies, 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 from 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 from 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 operators, vendors, suppliers, customers and other business partners may become the target of cyber attacks or information security breaches. Cyber attacks or information security breaches 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 of America and abroad. Computers are necessary to transport our oil and gas 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 United States of America 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

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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 one or more key personnel could have a material adverse effect on our operations. In particular, our future success is dependent upon 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 oil and gas 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, resulting in 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 redevelopment 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, 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, 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. We may not be able to successfully conduct our operations, evaluate and select suitable properties, or consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive crude oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment, and acquiring the existing and changing technologies that we believe are and will be increasingly important to attaining success in our industry.

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We 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. This could result in a reduction or elimination of the revenue received by us from such properties.
Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the ongoing global outbreak of a novel strain of the coronavirus identified in late 2019 (“COVID-19”), may materially adversely affect our business.
We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operations and adversely affect out financial condition. In December 2019, a novel strain of a coronavirus, COVID-19, was identified in Wuhan, China. This virus continues to spread globally including in the United States of America. These and other actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting and lead to disruptions in our permitting activities and critical business relationships.Additionally, the COVID-19 outbreak and governmental restrictions have significantly impacted economic activity and markets and have dramatically reduced current and anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of the current COVID-19 outbreak and the potential for future outbreaks are uncertain and difficult to predict.
The extent to which COVID-19 impacts our business will depend on future developments, which are highly uncertain and cannot be predicted, including new information which may emerge concerning the severity of the coronavirus and the actions to contain the coronavirus or treat its impact, among others. We are unable to predict the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments, including the length of time that the pandemic continues, its ongoing effect on the demand for oil and natural gas and the response of the overall economy and the financial markets after governmental restrictions are eased.
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 United States of America 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 of America or abroad remain prolonged, demand for petroleum products could diminish or stagnate, and production costs could increase. These situations 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, 2020, our stock price as traded on the NYSE American ranged from $2.16 to $7.05. 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;

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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.
Significant ownership of our common stock is concentrated in a small number of shareholders who may be able to affect the outcome of the election of our directors and all other matters submitted to our stockholders for approval.
As of June 30, 2020 our executive officers and directors, in the aggregate, beneficially owned approximately 2.7 million shares, or approximately 8.2% of our beneficial common stock base. Blackrock Fund Advisors, et al controlled approximately 3.4 million shares or approximately 10.2% of our outstanding common stock, Arrowmark Colorado Holdings, LLC controlled approximately 2.6 million shares or approximately 7.8% of our outstanding common stock, Renaissance Technologies, LLC controlled approximately 2.4 million shares or approximately 7.3% of our outstanding common stock, Advisory Research, Inc controlled approximately 1.5 million shares or approximately 4.5% of our outstanding common stock and JVL Advisors, LLC controlled approximately 1.5 million shares or approximately 4.5% of our outstanding common stock. As a result, any of these holders could potentially exercise significant influence over matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover, or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.
The market for our common stock is limited and may not provide adequate liquidity.
Our common stock trades on the NYSE American. Our trading volumes decreased slightly in fiscal 2020 compared to fiscal 2019. Trading volume in our common stock is relatively low compared to larger companies. During the fiscal year ended June 30, 2020, the daily trading volume in our common stock ranged from a low of 42,300 shares to a high of 931,500 shares, with average daily trading volume of 155,610 shares compared to average daily volume of 180,353 in fiscal 2019. 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.
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

22


discouraging bids for our common stock.
Payment of dividends on our common stock has been in the past, and could be in the future, reduced or eliminated.
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, our 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. Although it is our intent to maintain a steady dividend for our shareholders, there is no guarantee that we will be able to do so. For example, during the 3rd quarter of fiscal 2020, we reduced our quarterly dividend from $0.10 per common share to $0.025 per common share. 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 above and in Note 6 to our consolidated financial statements in Item 8, which information is incorporated herein by reference.
Item 3.  Legal Proceedings
See Note 16 to our consolidated financial statements in Item 8 for a description of any legal proceedings, which is incorporated herein by reference.
Item 4.  Mine Safety Disclosures
Not Applicable.


23


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, 2020 and 2019, the high and low sales prices for EPM as reported by the NYSE American.
NYSE American: EPM
2020:
High
 
Low
Fourth quarter ended June 30, 2020
$
3.20

 
$
2.23

Third quarter ended March 31, 2020
$
5.62

 
$
2.16

Second quarter ended December 31, 2019
$
5.86

 
$
5.08

First quarter ended September 30, 2019
$
7.05

 
$
5.55


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


Shares Outstanding and Holders
As of June 30, 2020, there were 32,956,469 shares of common stock issued and outstanding. As of September 1, 2020, there were approximately 213 registered shareholders of our common stock.
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,
 
2020
 
2019
Fourth quarter ended June 30,
$0.025
 
$0.100
Third quarter ended March 31,
$0.100
 
$0.100
Second quarter ended December 31,
$0.100
 
$0.100
First quarter ended September 30,
$0.100
 
$0.100
`
As of June 30, 2020, we have paid 27 consecutive quarterly dividends on our common stock. In August 2020, the Company declared a $0.025 per share dividend payable on September 30, 2020. 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, results of operations, applicable dividend restrictions, 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, 2015 to June 30, 2020 with the cumulative total return of the S&P 500 Index and the S&P

24


Oil & Gas Exploration and Production Index of publicly traded companies over the same period. The graph assumes that $100 was invested on June 30, 2015 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.
chart-33cba170af4f558eb47.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

 
 
 
$

 
 
    Outstanding contingent rights to shares
200,000

 
(1)
 

 
 
  Total
200,000

 
 
 
$

 
390,489

Equity compensation plans not approved by security holders

 
 
 

 

Total
200,000

 
 
 
$

 
390,489

(1) In December 2016, the Company adopted the Equity Incentive Plan (the "2016 Plan"), which authorized the issuance of 1,100,000 shares of common stock. As of June 30, 2020, the Company has granted 709,511 awards under the 2016 Plan and 390,489 shares of common stock remain available for future grants.


25


Issuer Purchases of Equity Securities
During the fourth quarter ended June 30, 2020, the Company did not purchase any common stock in the open market under the previously announced share repurchase program and no shares of common stock were surrendered by its employees to pay their share of payroll taxes arising from vesting of restricted stock.
Item 6.  Selected Financial Data
The selected consolidated financial data, set forth below should be read in conjunction with Item 7 and Item 8.
 
June 30,
 
2020
 
2019
 
2018
 
2017
 
2016
Income Statement Data
 
 
 
 
 
 
 
 
 
Revenues
$
29,599,296

 
$
43,229,621

 
$
40,773,527

 
$
34,253,681

 
$
26,349,502

Cost of revenues
13,505,502

 
14,266,784

 
11,685,817

 
10,604,594

 
9,133,111

Depreciation, depletion and amortization
5,761,498

 
6,253,083

 
6,102,288

 
5,779,069

 
5,214,174

General and administrative expenses
5,259,659

 
5,072,931

 
6,773,781

 
4,985,408

 
9,079,597

Net loss on derivative contracts
1,383,204

 

 

 

 

Restructuring charges

 

 

 
4,488

 
1,257,433

Income from operations
3,689,433

 
17,636,823


16,211,641

 
12,880,122

 
1,665,187

Other income (expense)
66,643

 
1,222,604

 
(25,126
)
 
4,855

 
32,565,954

Income tax provision (benefit)
(2,180,996
)
 
3,482,361

 
(3,431,969
)
 
4,840,664

 
9,570,779

Net income attributable to the Company
5,937,072

 
15,377,066


19,618,484

 
8,044,313

 
24,660,362

Dividends on preferred stock

 

 

 
250,990

 
674,302

Deemed dividend on preferred shares called for redemption

 

 

 
1,002,440

 

Net income attributable to common shareholders
$
5,937,072

 
$
15,377,066


$
19,618,484

 
$
6,790,883

 
$
23,986,060

Earnings per common share:
 
 
 
 
 
 
 
 
 
Basic
$
0.18

 
$
0.46

 
$
0.59

 
$
0.21

 
$
0.73

Diluted
$
0.18

 
$
0.46

 
$
0.59

 
$
0.21

 
$
0.73


 
June 30, 2020
 
June 30, 2019
 
June 30, 2018
 
June 30, 2017
 
June 30, 2016
Balance Sheet Data
 
 
 
 
 
 
 
 
 
Total current assets
$
25,316,698

 
$
35,178,927

 
$
32,147,556

 
$
26,142,527

 
$
37,086,450

Total assets
92,138,236

 
95,761,844

 
93,662,544

 
88,268,668

 
97,451,051

Total current liabilities
4,278,859

 
2,752,694

 
4,430,214

 
2,718,894

 
8,528,908

Total liabilities
18,013,754

 
15,635,986

 
16,373,065

 
19,798,813

 
21,129,901

Total stockholders' equity
74,124,482

 
80,125,858

 
77,289,479

 
68,469,855

 
76,321,150

Number of common shares outstanding
32,956,469

 
33,183,730

 
33,080,543

 
33,087,308

 
32,907,863

Working capital
21,037,839

 
32,426,233

 
27,717,342

 
23,423,633

 
28,557,542

Cash dividends to common shareholders
10,740,754

 
13,272,058

 
11,594,541

 
8,432,435

 
6,565,823


26


Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations
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. In support of that objective, 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 enhancements, 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 our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, and overriding royalty interests in two onshore Texas wells.
Our interests in the Delhi field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue interest of 26.2%. The field is operated by Denbury.
On November 1, 2019, the Company acquired mineral interests in the Hamilton Dome field consisting of a 23.5% working interest, with an associated 19.7% revenue interest (inclusive of a small overriding royalty interest). The field is operated by Merit, a private oil and gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field. Our acquired interest in this field aligned with the Company's strategy of adding long-lived, low decline reserves expected to be supportive of our dividend over the long-term.
Highlights for our Fiscal Year 2020 and Operations Update

Proved oil equivalent reserves at June 30, 2020 were 10.2 MMBOE, a 13% increase from the previous year primarily due to the acquisition of the Hamilton Dome field in November 2019. The Standardized Measure for proved reserves decreased 51% to $62 million, as the acquisition of the Hamilton Dome field was offset by the decrease in the average first day of the month net oil price from $64.54 per barrel of oil and $23.83 per barrel of natural gas liquids at June 30, 2019 to $46.37 per barrel of oil and $9.00 per barrel of natural gas liquids at June 30, 2020. Our proved reserves consist of 80% crude oil and 20% natural gas liquids, 82% are classified as proved developed producing and 18% are proved undeveloped.
We recognized net income of $5.9 million, or $0.18 per diluted common share, our ninth consecutive year of reporting net income.
Returned to shareholders $10.7 million in cash dividends and invested $2.5 million in stock repurchases in fiscal 2020. The Company has paid out to shareholders more than $70 million in cash dividends since inception of the dividend program in December 2013.
Closed the acquisition of non-operated working interest in Hamilton Dome field on November 1, 2019 which included total proved reserves of 1.47 MMBOE as of June 30, 2020 as estimated by D&M, an independent reservoir engineering firm.
Reported $12.4 million of cash flows from operations for the fiscal year ended June 30, 2020. We funded all operations, including $11.8 million of capital spending inclusive of our $9.3 million acquisition of our interest in the Hamilton Dome Field, from internal resources and remain debt free at June 30, 2020. 

27


In order to mitigate the impact of the growing global COVID-19 pandemic on our employees, we continue to follow local stay-at-home orders and remotely work from home with minimal disruptions to our business operations.
We entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel, recording a loss of $1.4 million at June 30, 2020. Of this amount, $1.9 million were non-cash, unrealized mark-to-market losses as commodity prices improved from those existing at fiscal year-end, offset in part by $0.5 million in realized gains during the fiscal fourth quarter. 
We completed remaining capital expenditures for the six-well water curtain program and related infrastructure preceding the planned Delhi Phase V development, which was delayed by the operator until the fourth quarter of 2021.
In July 2020, Denbury Resources announced that it had entered into a restructuring support agreement with certain of its debt holders and filed a pre-packaged voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in Texas. Denbury Resources is seeking to eliminate $2.1 billion of debt. Denbury subsequently announced on September 3, 2020 that its plan to eliminate $2.1 billion of its bond debt has been confirmed by the court which will substantially reduce its debt and strengthen its balance sheet.
Oil & Natural Gas Liquids Reserves (based on SEC average NYMEX WTI oil price of $47.37 per barrel at June 30, 2020)
Proved oil equivalent reserves at June 30, 2020 were 10.2 MMBOE, a 13% increase from the previous year primarily due to the acquisition of the Hamilton Dome field in November 2019. The Standardized Measure for proved reserves decreased 51% to $62 million, reflecting the decrease in the average first day of the month net oil price from $64.54 per barrel of oil and $23.83 per barrel of natural gas liquids at June 30, 2019 to $47.37 per barrel of oil and $9.00 per barrel of natural gas liquids at June 30, 2020. Price decreases are partially offset by the acquisition of the Hamilton Dome field in November 2019. Our proved reserves are 80% crude oil and 20% natural gas liquids, and of these proved reserves, 82% are classified as proved developed and producing and 18% are proved undeveloped.
The following table is a summary of our proved reserves as of June 30, 2020 and 2019:
 
Proved
 
 
 
2020
 
2019
 
Change
Reserves MMBOE
10.2

 
9.0

 
13.3
 %
% Developed
82
%
 
82
%
 
 %
Liquids %
100
%
 
100
%
 
 %
Standardized Measure ($MM)
$
62

 
$
127

 
(51
)%
Additional property and project information is included under Item 1 and in Note 6 and Note 21 to our consolidated financial statements in Item 8, and in Exhibit 99.1 of this Form 10-K.
Delhi Field
Proved reserves volumes totaled 8.7 MMBOE compared to the prior year's 9.0 MMBOE. Year over year, decreased oil prices and temporary curtailment of CO2 purchases since February 2020 has led to a 0.2 MMBOE, or a 2% negative revision in proved oil reserves. Adjustment of projecting NGL reserves independent of oil production resulted in a 0.6 MMBOE, or 46% positive revision to NGL reserves.
Gross production at Delhi in the fourth quarter of fiscal 2020 was 6,082 BOEPD, an 8% decrease compared to 6,597 BOEPD in the third fiscal quarter. Oil production was 4,985 BOPD, an 9% decrease from the third fiscal quarter’s 5,499 BOPD. NGL fourth quarter production of 1,097 BOEPD was virtually flat compared to prior quarter production. Oil production was significantly impacted by materially lower CO2 purchases when the CO2 purchase pipeline, upstream of Delhi field, was shut-in for repairs in late February throughout the end of fiscal 2020. The operator has commenced repairs to the pipeline and expects an in service date of October 2020. The loss of CO2 purchases, coupled with the decline in oil prices, led to the operator electing to freeze non-essential capital projects through the end of fiscal 2020.
The average oil price realized by Evolution during the fourth quarter of fiscal 2020 was $23.74 compared to $47.27 during the previous quarter, a decrease of 50%. The average NGL price realized by Evolution during the fourth quarter of fiscal 2020 was $2.11 per barrel compared to $9.56 during the previous quarter, a decrease of 78%. The decline was attributable to the decrease in all realized commodity prices in fiscal fourth quarter. The COVID-19 pandemic, combined with a market share competition between certain members of the OPEC+ member nations, continued to adversely impact demand for commodity products,

28


which caused a global supply/demand imbalance for oil that resulted in extreme volatility in benchmark oil prices, with prices ranging from a low of a negative price of $37.63 per Bbl to a high of $40.46 per Bbl during our fiscal fourth quarter.
Although we historically 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, in the fiscal fourth quarter, the field realized a discount to WTI of $4.26. Oil produced from Delhi field 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 that is reflected as a reduction in lease operating expense.
Our overall lifting costs for the year were $16.50 per BOE, which decreased 14.6% from $19.31 per BOE in the prior year. Gross CO2 purchase volume rates for the fiscal 2020 averaged 51.9 MMcf per day, compared to 85.2 MMcf per day in the prior year, a 39% decrease due to the Delhi CO2 purchase pipeline shut-in for repairs. This decrease together with a 14% lower price per mcf resulted in a 48% decrease in CO2 cost compared to the prior year. Our cost of purchased CO2, the largest single component of operating costs at Delhi, is directly tied to the price of oil sold from the Delhi field. Other lease operating expenses for fiscal 2020 decreased 5.6% compared to the prior year, primarily due to lower fuel gas, parts and workover expenses.
For fiscal 2020, our gross NGL production was 1,106 BOEPD, which sold at an average price of $9.59 per barrel, compared to prior year gross production of 1,171 BOEPD for which we realized $21.87 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. Our current mix of products is very rich containing higher value NGLs, such as pentanes and butane. 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 in the future.
The NGL plant includes an electric turbine that converts methane and part of the ethane processed by the plant into electricity. This turbine generates power primarily 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, smaller chain hydrocarbons (i.e. methane and ethane), thereby increasing the purity of the CO2 recycle stream and improving the efficiency of the CO2 flood throughout the field. Over time, the NGL plant is expected to increase and enhance the recovery of crude oil in the field. The NGL plant is not only providing feedstock to power the electric turbine, it is also producing significant quantities of higher value NGLs to sell to market.
Remaining estimated capital expenditures for our proved undeveloped reserves amount to approximately $6.38 per BOE for Phase V. Looking forward, the timing of plans for continued development of the eastern part of the Delhi field are dependent on the operator’s schedule 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.
Hamilton Dome
At June 30, 2020, we had total proved reserves of 1.5 MMBOE which was entirely comprised of oil as estimated by our independent petroleum engineering firm D&M.
Gross oil production at Hamilton Dome in the fourth quarter of fiscal 2020 was 1,642 BOPD, a 29% decrease compared to 2,328 BOPD in the third fiscal quarter quarter primarily due to the operator shutting in uneconomic wells at the extremely low oil price. There were limited capital expenditures in the field during fiscal 2020 due primarily to the decrease in oil prices. Most projects focused on maintenance, but in March 2020, a larger, and more efficient, ESP was installed in the Step Scale 117 which resulted in an increase in average production since completion of 5 BOPD. The average oil price realized by Evolution during the fourth quarter was $16.12 compared to $30.23 during the previous quarter, a decrease of 47%. Production from this field is transported by pipeline to customers in the Western Canadian Select market; prices are discounted from WTI. In the fourth quarter our realized price reflected a $11.88 per barrel discount from the WTI price. For this fiscal year, subsequent to our acquisition, our lifting costs at Hamilton Dome have averaged $28.93 per barrel.

29


Impact of Geopolitical Factors and the COVID-19 Pandemic
On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States of America declared a national emergency with respect to COVID-19. The virus has continued to spread in the United States of America and abroad. National, state, and local authorities have recommended social distancing, imposed quarantine and isolation measures, as well as mandatory business closures on large portions of the population. These measures, while intended to protect human life, are expected to have serious adverse impacts on domestic and foreign economies of uncertain severity and duration. The effectiveness of economic stabilization efforts, including government payments to affected citizens and industries, is uncertain.
The nature of the COVID-19 pandemic makes it extremely difficult to predict the impact on the Company’s business and operations. However, the likely overall economic impact of the pandemic is viewed as highly negative to the general economy, especially the oil and natural gas industry. During the six months ended June 30, 2020, primarily driven by the COVID-19 pandemic and actions taken by OPEC+, the benchmark price of WTI dropped significantly. Although global outputs can be adjusted to support commodity pricing levels, the Company expects the price of crude oil to remain volatile in the near term. Uncertainty regarding the future actions of foreign oil producers, such as Saudi Arabia and Russia, and the risk that they take actions that will prolong or exacerbate the current over-supply of crude oil is also contributing to the recent decline in oil prices.
Currently, all of the Company’s property interests are not operated by the Company and involve other third-party working interest owners. As a result, the Company has limited ability to influence or control the operation or future development of such properties. In light of the current price and economic environment, the Company continues to be proactive with its third-party operators to review spending and alter plans as appropriate.
The Company is focused on maintaining its operations and system of controls remotely and has implemented its business continuity plans in order to allow its employees to securely work from home. The Company was able to transition the operation of its business with minimal disruption and to maintain its system of internal controls and procedures. 
Liquidity and Capital Resources
At June 30, 2020, we had $19.7 million in cash and cash equivalents, primarily impacted by the $9.3 million purchase of certain mineral interests in Hamilton Dome field in November 2019, compared to $31.6 million of cash and cash equivalents at June 30, 2019.
In addition, the Company has a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of $50 million subject to a borrowing base determined by the lender based on the value of our oil and gas properties. The Facility had a $27 million borrowing base on June 30, 2020. However, our ability to access the borrowing base is also limited by our compliance with certain financial covenants, including a debt service ratio covenant, described below. As a consequence of declining oil prices adversely impacting our EBITDA upon which the debt service ratio is calculated, at June 30, 2020 our borrowings would have been limited to approximately $8 million. There are no borrowings outstanding under the Facility, which matures on April 11, 2021. The Facility is secured by substantially all of the reserves associated with the Delhi field.
Any future borrowings bear interest, at the Company's option, at either the London Interbank Offered Rate ("LIBOR") plus 2.75% or the Prime Rate, as defined under the Facility, plus 1.0%. The Facility contains covenants requiring 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, 2020, the Company was in compliance with all covenants contained in the Facility.
The Company has historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced oil and natural gas liquids. A portion of these cash flows is used to fund capital expenditures. The Company expects to manage future development activities in the Delhi field and the limited capital maintenance requirements of the Hamilton Dome field within the boundaries of its operating cash flow and existing working capital.
The Company is pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, the Company has limited access to an undrawn borrowing base available under its senior secured credit facility, The Company also has an effective shelf registration statement with the SEC under which the Company may issue up to $500 million of new debt or equity securities.

30


During the fiscal year ended June 30, 2020, the Company funded operations, capital expenditures and cash dividends with cash generated from operations resulting in a decrease of $11.9 million in cash. Uses of cash included the acquisition of the Hamilton Dome field ($9.3 million), cash dividends on common shares ($10.7 million) and repurchasing shares under the buyback program ($2.5 million). As of June 30, 2020, working capital was $21.0 million, a decrease of $9.3 million over working capital of $32.4 million at June 30, 2019.
The Board of Directors instituted a cash dividend payable on shares of our common stock in December 2013. The Company has since paid 27 consecutive quarterly dividends. Distribution of a substantial portion of cash flow in excess of operating and capital requirements through cash dividends is a priority of the Company’s financial strategy. However, due to current depressed price environment and a desire to preserve cash to potentially pursue opportunities that will grow dividends over time, the Board of Directors believed it was in the best interest of the Company to reduce its quarterly dividend rate from $0.10 per share to $0.025 per share, effective in the quarter ending June 30, 2020. The reduced dividend rate will continue to reward shareholders with a yield of approximately 3% at current stock price levels. The Company intends to grow dividend levels as appropriate.
In May 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company’s common stock. The Company monitors its stock price and looks to opportunistically purchase its common stock when market conditions are deemed to be appropriate. During the year ended June 30, 2020, the Company purchased 440,666 shares at an average cost of $5.51 per share bringing its total to $4.0 million to purchase 706,858 common shares at an average price of $5.72 per share.

In early March 2020, oil prices declined rapidly. As a consequence of unprecedented commodity price volatility and uncertainty on April 6, 2020, the Company elected to enter into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020, at a fixed swap price of $32.00 per barrel. The fixed price swap contracts will significantly reduce volatility in the Company's near-term realized oil price and resulting revenues, thus supporting its current business plans and objectives. The Company expects to have sufficient liquidity to meet all its identified cash requirements for at least the next 12 months.
Capital Expenditures
For the year ended June 30, 2020, we incurred $11.8 million on capital projects consisting of $9.3 million for the acquisition of Hamilton Dome field, $0.9 million for a non-cash asset addition related to Hamilton Dome asset retirement obligations, $1.5 million at the Delhi field (primarily for the NGL plant and completion of the water curtain) and $0.1 million for capital workovers at Hamilton Dome.
Based on discussions with the Delhi and Hamilton Dome operators, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures, primarily at the Delhi field. Such amounts are not known or approved but we expect such expenditures to be in the range of $0.75 million to $1.0 million over the next 12 months. In addition, we have planned for Delhi Phase V development expenditures of approximately $1.9 million to be incurred in the fourth quarter of our fiscal 2021. Phase V development expenditures are expected to total $8.6 million with $3.7 million to be incurred in fiscal 2022 and the remainder over the next two years.
Our proved undeveloped reserves at June 30, 2020 included 1.86 MMBOE 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 the Company. Based on our discussions with the operator, we expect drilling to commence in fiscal 2022, but 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 over the next 24 months is expected to be met from cash flows from operations and current working capital.
Full Cost Pool Ceiling Test
At the year ended June 30, 2020, our capitalized costs of oil and gas properties were below the full cost valuation ceiling; however, we could experience an impairment if current price levels persist or worsen. The trend of lower oil prices reduced the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the

31


average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test at June 30, 2020 were $47.37 per barrel of oil and $9.00 per barrel of natural gas liquids. A significant decline from these prices would likely result in a ceiling test impairment charge.
Overview of Cash Flow Activities
The table below compares a summary of our consolidated statements of cash flows for year ended June 30, 2020 and 2019.
 
June 30,
 
 
Increases (Decreases) in Cash:
2020
 
2019
 
Difference
 
(In Millions)
Net cash provided by operating activities
$
12.4

 
$
24.1

 
$
(11.7
)
Net cash used in investing activities
(11.1
)
 
(6.8
)
 
(4.3
)
Net cash used in financing activities
(13.2
)
 
(13.4
)
 
0.2

Change in cash, cash equivalents and restricted cash
$
(11.9
)
 
$
3.9

 
$
(15.8
)
Cash provided by operating activities in the current year decreased $11.7 million compared to fiscal 2019. The difference is primarily as the result of decrease in net income of $9.4 million due to lower realized commodity prices together with a $3.2 million increase in cash used by operating assets and liabilities. Enhanced Oil Recovery credits claimed on income tax returns for fiscal 2019, 2018 and 2017 resulted in an income tax refund receivable that contributed to the use of cash by operating activities.
Cash used in investing activities decreased $4.3 million primarily due to the acquisition of the Hamilton Dome field in November 2019. The decrease is partially offset by a reduction in capital expenditures in fiscal 2020 due to the decrease in realized commodity prices.
Cash used in financing activities remained relatively flat year over year as the reduction in cash used for cash dividends was offset by the Company's common share repurchase program in fiscal 2020. The Company reduced its quarterly dividend rate from $0.10 per share to $0.025 per share for the fourth quarter of fiscal year 2020. The Company spent a total of $2.5 million to purchase 440,666 shares of its common stock at an average price of $5.51.
Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2020, 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
 
 
 
 
 
 
 
 
 
AFE purchase commitments in connection with joint interest agreements
$
201,104

 
$
201,104

 
$

 
$

 
$

Operating lease
139,268

 
54,290

 
84,978

 

 

Other Obligations
 
 
 
 
 
 
 
 
 
Asset retirement obligations
2,588,894

 

 
65,163

 
43,442

 
2,480,289

Total Obligations
$
2,929,266

 
$
255,394

 
$
150,141

 
$
43,442

 
$
2,480,289



32


Results of Operations
Years Ended June 30, 2020 and 2019
Revenues
Compared to the prior fiscal year, fiscal 2020 revenues decreased 31.5% due to 32.1% lower realized commodity prices. The decrease is partially offset by a very slight increase in production volumes. The following table summarizes total production volumes, daily production volumes, average realized prices and revenues:
 
Years Ended June 30,
 
 
 
 
 
2020
 
2019
 
Variance
 
Variance %
Oil and gas production
 
 
 
 
 
 
 
  Crude oil revenues
$
28,578,879

 
$
40,779,052

 
$
(12,200,173
)
 
(29.9
)%
  NGL revenues
1,018,349

 
2,449,359

 
(1,431,010
)
 
(58.4
)%
  Natural gas revenues
2,068

 
1,210

 
858

 
70.9
 %
  Total revenues
$
29,599,296

 
$
43,229,621

 
$
(13,630,325
)
 
(31.5
)%
 
 
 
 
 
 
 
 
  Crude oil volumes (Bbl)
638,464

 
626,879

 
11,585

 
1.8
 %
  NGL volumes (Bbl)
106,159

 
112,013

 
(5,854
)
 
(5.2
)%
  Natural gas volumes (Mcf)
1,087

 
459

 
628

 
136.8
 %
Equivalent volumes (BOE)
744,804

 
738,968

 
5,836

 
0.8
 %
 
 
 
 
 
 
 
 
  Crude oil (BOPD, net)
1,744

 
1,717

 
27

 
1.6
 %
  NGLs (BOEPD, net)
290

 
307

 
(17
)
 
(5.5
)%
  Natural gas (BOEPD, net)

 
1

 
(1
)
 
n.m

 Equivalent volumes (BOEPD, net)
2,034

 
2,025

 
9

 
0.4
 %
 
 
 
 
 
 
 
 
  Crude oil price per Bbl
$
44.76

 
$
65.05

 
$
(20.29
)
 
(31.2
)%
  NGL price per Bbl
9.59

 
21.87

 
(12.28
)
 
(56.1
)%
  Natural gas price per Mcf
1.90

 
2.64

 
(0.74
)
 
(28.0
)%
   Equivalent price per BOE
$
39.74

 
$
58.50

 
$
(18.76
)
 
(32.1
)%
n. m. Not meaningful.


33


(Gain) Loss on Derivative Contracts
Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in crude oil prices. This amount represents the (i) (gain) loss related to fair value adjustments on our open, or unrealized, derivative contracts and (ii) (gains) losses on settlements of derivative contracts for positions that have settled or been realized.
 
Years Ended June 30,
 
 
 
 
 
2020
 
2019
 
Variance
 
Variance %
Oil Derivative Contracts
 
 
 
 
 
 
 
Realized (gain) loss on derivatives, net
$
(528,139
)
 
$

 
$
(528,139
)
 
n.m.
Unrealized (gain) loss on derivatives
1,911,343

 

 
1,911,343

 
n.m.
Loss on derivatives
$
1,383,204

 
$

 
$
1,383,204

 
n.m.
 
 
 
 
 
 
 
 
Crude oil price per Bbl (including impact of realized derivatives)
$
45.59

 
 
 
 
 
 
n. m. Not meaningful.
Production Costs
Production costs (also referred to as lease operating expenses) are presented in two components: (i) CO2 costs for the Delhi field and (ii) other production costs for both the Delhi and Hamilton Dome fields. The $0.8 million decrease in total production costs was due to a 47.5% decrease in CO2 costs. The decrease is partially offset by a 31.8% increase in other production costs.
 
Years Ended June 30,
 
 
 
 
 
2020
 
2019
 
Variance
 
Variance %
CO2 costs (a)
$
3,501,507

 
$
6,674,905

 
$
(3,173,398
)
 
(47.5
)%
Other production costs
10,003,995

 
7,591,879

 
2,412,116

 
31.8
 %
Total production costs
$
13,505,502

 
$
14,266,784

 
$
(761,282
)
 
(5.3
)%
 
 
 
 
 
 
 
 
CO2 costs per BOE
$
4.70

 
$
9.03

 
$
(4.33
)
 
(48.0
)%
All other production costs per BOE
13.43

 
10.28

 
3.15

 
30.6
 %
Production costs per BOE
$
18.13

 
$
19.31

 
$
(1.18
)
 
(6.1
)%
(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 and transportation costs as per contract terms.
 
Years Ended June 30,
 
 
 
 
 
2020
 
2019
 
Variance
 
Variance %
CO2 costs per mcf
$
0.77

 
$
0.90

 
$
(0.13
)
 
(14.4
)%
CO2 volumes (MMcf per day, gross)
51.9

 
85.2

 
(33.3
)
 
(39.1
)%
The $3.2 million decrease in CO2 costs was due to a 39.1% decrease in rate of purchased volumes together with a 14.4% decrease in price per Mcf associated with the lower realized oil price. The upstream pipeline that supplies CO2 to the Delhi field was shut-in on February 22, 2020, when a pressure loss was detected. CO2 purchases were temporarily suspended through our fiscal year-end. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. The recycle facilities continued to operate as usual during the purchase pipeline suspension. The pipeline is owned and operated by Denbury Resources, and the Company does not have any ownership in the portion of the pipeline under repair. The operator expects the pipeline to be back in service in October 2020.
Compared to fiscal 2019, "Other production costs" increased 31.8% primarily due to the acquisition of the Hamilton Dome field in November 2019. The Delhi field's "Other production costs" decreased slightly by 5.6% impacted by cost control measures as a result of lower oil prices.
Compared to fiscal 2019, Delhi field costs decreased 15% to $16.50 per BOE of Delhi current year production primarily due to lower CO2 costs, as discussed above. 

34


For fiscal 2020, Hamilton Dome field costs per BOE were $28.93.
Depletion, Depreciation and Amortization ("DD&A")
Total DD&A expense was 7.9% lower compared to the same one year-ago period due to an 8.7% decrease in the oil and gas DD&A amortization rate; the volume change between the two periods was very slight. The integration of the Hamilton Dome asset contributed to an overall lower composite DD&A per BOE rate.
 
Years Ended June 30,
 
 
 
 
 
2020
 
2019
 
Variance
 
Variance %
DD&A of proved oil and gas properties
$
5,592,651

 
$
6,122,515

 
$
(529,864
)
 
(8.7
)%
Depreciation of other property and equipment
8,779

 
15,498

 
(6,719
)
 
(43.4
)%
Amortization of intangibles
13,564

 
13,564

 

 
 %
Accretion of asset retirement obligations
146,504

 
101,506

 
44,998

 
44.3
 %
Total DD&A
$
5,761,498

 
$
6,253,083

 
$
(491,585
)
 
(7.9
)%
 
 
 
 
 
 
 
 
Oil and gas DD&A per BOE
$
7.51

 
$
8.29

 
$
(0.78
)
 
(9.4
)%
General and Administrative Expenses
Total general and administrative expenses for fiscal 2020 increased $0.2 million, or 3.7%, to $5.3 million from the same year-ago period. The increase is primarily due to higher non-cash stock-based compensation of $0.4 million related to new grants associated with the hiring of a new executive officer and increased consulting expense of $0.1 million, partially offset by a decrease of $0.3 million in bonus expense.

35


Other Income and Expenses
Other income and expenses (net) decreased due primarily to the non-recurring Enduro transaction breakup fee income received during fiscal 2019. During May 2018, the Company entered into a Purchase and Sale Agreement to acquire, as the "stalking horse" bidder, certain oil and gas assets from an affiliate of Enduro Resource Partners LLC ("Enduro") for a purchase price of $27.5 million, subject to the outcome of Enduro's Chapter 11 process. In the first quarter of 2019, the Company was repaid its deposit together with related earned interest when a higher bidder first emerged in the bidding process. Interest income is lower due to lower invested balances together with declining interest rates.
 
Years Ended June 30,
 
 
 
 
 
2020
 
2019
 
Variance
 
Variance %
Enduro transaction breakup fee

 
1,100,000

 
(1,100,000
)
 
(100.0
)%
Interest and other income
177,418

 
239,150

 
(61,732
)
 
(25.8
)%
Interest expense
(110,775
)
 
(116,546
)
 
5,771

 
(5.0
)%
Total other income, net
$
66,643

 
$
1,222,604

 
$
(1,155,961
)
 
(94.5
)%
Net Income
Net income available to common stockholders for the year ended June 30, 2020 decreased $9.4 million, or 61%, to $5.9 million compared to the last fiscal year. Pre-tax income decreased due to the aforementioned revenue and expense variances. Our income tax provision decreased primarily due to lower pre-tax income as our effective income tax rate was relatively unchanged from the year-ago period. During the current period, we recorded a $2.8 million income tax benefit related to Enhanced Oil Recovery credits claimed on income tax returns for fiscal 2019, 2018 and 2017 .
 
Years Ended June 30,
 
 
 
 
 
2020
 
2019
 
Variance
 
Variance %
Income before income taxes
3,756,076

 
18,859,427

 
(15,103,351
)
 
(80.1
)%
Income tax provision (benefit)
(2,180,996
)
 
3,482,361

 
(5,663,357
)
 
(162.6
)%
Net income available to common stockholders
$
5,937,072

 
$
15,377,066

 
$
(9,439,994
)
 
(61.4
)%
Income tax provision (benefit) as a percentage of income before income taxes
(58
)%
 
18
%
 
 
 
 


36


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, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our consolidated financial statements. Our significant accounting policies are included in Note 2 to our consolidated statements in Item 8. 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 and 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. 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, 2020, we had no unevaluated property costs. Oil and natural gas property costs included represent non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling 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 for determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires 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; this includes 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 prepared by our third party independent engineers represent the most accurate assessments possible, 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. These changes could affect 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, 2020 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, 2020 of 5%, 10% and 15% would affect depreciation, depletion, and amortization expense by approximately $290,000, $612,000, and $970,000, 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; this would result in an increase to our income tax expense. As of June 30, 2020, we have recorded a valuation allowance for the portion of our net operating loss that is limited by IRS Section 382.

37


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, we believe that it is more likely than not that the Company will realize the benefits of its net deferred tax assets at the time of this report. 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.    Refer to Note 2 to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data 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, 2020.
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.
Derivative Instruments and Hedging Activity
We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil prices.We do not enter into derivative contracts for speculative trading purposes. In early March 2020, oil prices declined rapidly. As a consequence of unprecedented commodity price volatility and uncertainty on April 6, 2020, we elected to enter into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020, at a fixed swap price of $32.00 per barrel. The fixed price swap contracts will significantly reduce volatility in our near-term realized oil price and resulting revenues, thus supporting our current business plans and objectives.
We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. As of June 30, 2020, we did not post collateral under our derivative contract as it is an uncollateralized trade. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, ("ASC 815"). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 20 to our consolidated financial statements for more details.


38


Item 8.    Consolidated Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

39



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, 2020 and 2019, 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, 2020 and 2019, 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.

 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 Public Company Accounting Oversight Board (United States) (“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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

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 10, 2020

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

40


Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
 
June 30, 2020
 
June 30, 2019
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
19,662,528

 
$
31,552,533

Receivables from oil and gas sales
1,919,213

 
$
3,168,116

Receivables for federal and state income tax refunds
3,243,271

 

Prepaid expenses and other current assets
491,686

 
458,278

Total current assets
25,316,698

 
35,178,927

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
66,512,281

 
60,346,466

Other property and equipment, net
17,639

 
26,418

Total property and equipment, net
66,529,920

 
60,372,884

Other assets, net
291,618

 
210,033

Total assets
$
92,138,236

 
$
95,761,844

Liabilities and Stockholders' Equity
 
 
 
Current liabilities
 
 
 
Accounts payable
$
1,471,679

 
$
2,084,140

Accrued liabilities and other
716,648

 
537,755

Derivative contract liabilities
1,911,343

 

State and federal taxes payable
179,189

 
130,799

Total current liabilities
4,278,859

 
2,752,694

Long term liabilities
 
 
 
Deferred income taxes
11,061,023

 
11,322,691

Asset retirement obligations
2,588,894

 
1,560,601

Operating lease liability
84,978

 

Total liabilities
18,013,754

 
15,635,986

Commitments and contingencies (Note 16)

 

Stockholders' equity
 
 
 
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,956,469 and 33,183,730 shares as of June 30, 2020 and 2019, respectively
32,956

 
33,183

Additional paid-in capital
41,291,446

 
42,488,913

Retained earnings
32,800,080

 
37,603,762

Total stockholders' equity
74,124,482

 
80,125,858

Total liabilities and stockholders' equity
$
92,138,236

 
$
95,761,844


   See accompanying notes to consolidated financial statements.

41


Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
 
Years Ended June 30,
 
2020
 
2019
Revenues
 
 
 
Crude oil
$
28,578,879

 
$
40,779,052

Natural gas liquids
1,018,349

 
2,449,359

Natural gas
2,068

 
1,210

Total revenues
29,599,296

 
43,229,621

Operating costs
 
 
 
Production costs
13,505,502

 
14,266,784

Depreciation, depletion, and amortization
5,761,498

 
6,253,083

Net loss on derivative contracts
1,383,204

 

General and administrative expenses*
5,259,659

 
5,072,931

Total operating costs
25,909,863

 
25,592,798

Income from operations
3,689,433

 
17,636,823

Other
 
 
 
Enduro transaction breakup fee

 
1,100,000

Interest and other income
177,418

 
239,150

Interest (expense)
(110,775
)
 
(116,546
)
Income before income tax provision
3,756,076

 
18,859,427

Income tax provision (benefit)
(2,180,996
)
 
3,482,361

Net income (loss) attributable to common shareholders
$
5,937,072

 
$
15,377,066

Earnings per common share
 
 
 
Basic
$
0.18

 
$
0.46

Diluted
$
0.18

 
$
0.46

Weighted average number of common shares outstanding
 
 
 
Basic
33,031,149

 
33,160,283

Diluted
33,033,091

 
33,169,718

*
General and administrative expenses for the years ended June 30, 2020 and 2019 included non-cash stock-based compensation expense of $1,285,663 and $888,162, respectively.

See accompanying notes to consolidated financial statements.

42


Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
 
Years Ended June 30,
 
2020
 
2019
Cash flows from operating activities
 
 
 
Net income attributable to the Company
$
5,937,072

 
$
15,377,066

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion, and amortization
5,761,498

 
6,253,083

Stock-based compensation
1,285,663

 
888,162

Settlement of asset retirement obligations
(76,832
)
 

Deferred income taxes
(261,668
)
 
767,256

Net loss on derivative contracts
1,383,204