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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, 2021
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)

epm-20210630_g1.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 ClassTrading Symbol(s)Name of Each Exchange On Which Registered
Common Stock, $0.001 par valueEPMNYSE 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 filerSmaller 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, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $2.80 on the NYSE American was $86,002,899.
The number of shares outstanding of the registrant's common stock, par value $0.001, as of September 10, 2021, was 33,514,952.


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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant's 2021 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
2021 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
 

We use the terms, “EPM, “Company, “we,“ us, and “our to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.
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FORWARD-LOOKING STATEMENTS


This Form 10-K and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in Part I, Item 1A, “Risk Factors” and elsewhere in this report and as also may be described from time to time in our future reports we file with the Securities and Exchange Commission. You should read such information in conjunction with our consolidated financial statements and related notes and “Management's Discussion and Analysis of Financial Condition and Results of Operations” in this report. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ materially from our expectations.

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

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GLOSSARY OF SELECTED PETROLEUM INDUSTRY TERMS
Term
Definition
Bbls
Barrels of oil or natural gas liquids.
BCFBillion cubic feet.
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.
BOEPDBarrels of oil equivalent per day.
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 oil 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 farmout 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 farmout 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.
MMBBLOne million barrels.
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.
MMCF
One million 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.
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.
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Overriding Royalty Interest or ORRI
A royalty interest that is created out of the operating or working interest. Unlike a royalty interest, an overriding royalty interest terminates with the operating interest from which it was created or carved out of. See Royalty Interest.
Permeability
The measure of ease with which a fluid can move through a reservoir. The unit of measure is a darcy (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 oil, natural gas, and natural gas liquids which geologic 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.
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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”).
Undeveloped Reserves
Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.*
Working Interest
The interest in the oil and gas in place which is burdened with the cost of development and operation of the property. Also called the operating interest.
Workover
A remedial operation on a completed well to restore, maintain, or improve the well's production.

* This definition may be an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X.

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PART I
Item 1.    Business
Note: See Glossary of Selected Petroleum Industry Terms starting on page
General
Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management, and development of producing oil and natural gas properties. The Company's long-term goal is to build a diversified portfolio of oil and natural 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 (“EOR”) project, 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, our interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and overriding royalty interests in two onshore central Texas wells.
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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 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 natural gas company, who owns the vast majority of the remaining working interest in the 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.
On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale consisting of approximately 21,000 net acres held by production across nine North Texas counties in the Barnett Shale (the “Barnett Shale Acquisition”). The acreage has an average working interest of 17.3% and associated average revenue interest of 14.2% (inclusive of overriding royalty interests). At the time of the Barnett Shale Acquisition, approximately 90% of the wells acquired were operated by Blackbeard Operating LLC (“Blackbeard”), while the remaining 10% were operated by seven other operators. After the closing of the Barnett Shale Acquisition, Blackbeard announced the sale of its interests to Diversified Energy Company PLC (“Diversified Energy”), which subsequently closed in July of 2021. At present, Blackbeard is still the operator of the assets
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under a transition services agreement with Diversified Energy. However, after the transition, Diversified Energy will take over operations of the assets.
Significant Activity in Fiscal 2021
Closed the Barnett Shale Acquisition on May 7, 2021, which included total proved reserves of 13.1 MMBOE as of June 30, 2021 as estimated by DeGolyer & MacNaughton (“D&M”), an independent reservoir engineering firm.
Returned to shareholders $4.3 million in cash dividends in fiscal 2021. The Company has paid out to shareholders more than $74.5 million in cash dividends since inception of the dividend program in December 2013.
Generated $3.7 million in operating income before impairments.
Funded our operations, development capital expenditures, and dividends out of operating cash flow.
Proved oil equivalent reserves at June 30, 2021, were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021.
Primarily driven by proved oil and gas property impairments of $9.6 million and $15.2 million recorded during the first and second fiscal quarters of 2021, respectively, we recognized a net loss of $16.4 million, or $(0.49) per common share.
We completed the NYMEX WTI oil swaps entered into during fiscal year 2020, and have not entered into any new oil and natural gas derivatives as of June 30, 2021.
Denbury, whose subsidiary operates the Delhi field, emerged from bankruptcy on September 18, 2020, and returned to conformance projects with a refreshed capital budget after a period of no conformance spending.
Delhi Field - Enhanced Oil Recovery CO2 Flood - Onshore Louisiana

The Company purchased the Delhi field in September 2003. In May 2006, the Company conveyed its working interest in the field to Denbury for $50 million for the purpose of installing an EOR project; we retained a 23.9% reversionary working interest upon payout of the project, as defined in the purchase and sale agreements. Today, our interests include a 23.9% working interest and a 7.2% royalty interest with a total net revenue interest of 26.2%. Delhi field is located in northeast Louisiana in Franklin, Madison, and Richland parishes and encompasses approximately 13,600 unitized acres.

The Delhi field was discovered in the mid-1940s and has had a prolific production history totaling approximately 195 MMBbls of oil through primary and limited secondary recovery operations. Since EOR production began in March 2010, the Unit has produced over 23.0 MMBbls of oil. For fiscal 2021, average gross daily oil production at Delhi was 4,281 BOPD and 977 bbls NGLs per day (5,258 BOEPD).

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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, 2021, and two remain undeveloped. One of
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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 due to distant location and oil price.
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, and has isolated that part of the field with a water curtain, thus removing the area from the CO2 flood.
An NGL extraction plant was completed and began processing in December 2016. The plant allows for the sale of NGLs, improves CO2 flood efficiency, and provides the extracted methane as a source of power for plant reducing operating expenses.

Phase V development started in fiscal 2017 with the water curtain and related infrastructure program. The first pad commenced injections in fiscal 2019 with the second pad starting in the second quarter of fiscal 2020. Additional Delhi Phase V development has been delayed due to Denbury’s restructuring in fiscal 2021.

The total gross purchased CO2 volume was 18 BCF for fiscal 2021. 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 October 2020. During the pipeline repairs, the CO2 recycle facilities continued to operate providing approximately 80% of the historic total injected CO2 volumes to Delhi. The decrease in production within the field was primarily a result of lower injection volumes reducing reservoir pressure. CO2 purchases resumed in November 2020 at a limited level, and resumption of desired purchase volumes is expected during fiscal 2022 which is projected to increase reservoir pressure.

At June 30, 2021, the Company had total proved reserves of 8.5 MMBOE at Delhi, which was comprised of 6.5 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, 2021. For additional reserve information see Note 20 to our consolidated financial statements in Item 8.
Reserve Category - Delhi fieldOil
(MBbls)
NGLs
(MBbls)
Natural Gas
(MMcf)
Total Reserves
(MBOE)*
PROVED
Developed Producing (79% of Proved)4,879 1,784 — 6,663 
Undeveloped (21% of Proved)1,605 209 — 1,814 
TOTAL PROVED6,484 1,993 — 8,477 
Product Mix76 %24 %— %100 %
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs 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.
Hamilton Dome - Historical, Low Decline Waterflood - Hot Springs County, Wyoming
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.
Our interest includes a 23.5% working interest and an associated 19.7% revenue interest (inclusive of a small overriding royalty interest) in the approximately 3,160 acre unitized field. The Hamilton Dome field has been operated by Merit since 1995. Under Merit's operations, the wells in the Hamilton Dome field are produced using secondary recovery water flood methods via electric submersible pumps (ESP) and rod pumps. Typical workovers in the field include rod repair, ESP repair, injector acid jobs, and wellbore cleanouts.

The Hamilton Dome field was discovered in 1918 and has produced over 160 MMBO. Production from this field is 100% oil and is currently averaging low single-digit decline rates. The primary producing reservoirs in the field are the Tensleep and Phosphoria with an approximate depth of 3,000 feet. Average gross daily production was 1,987 BOPD for the year ended June 30, 2021. Produced oil from the field is subject to Western Canadian Select pricing.

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At June 30, 2021, the Company has total net proved reserves of 1.9 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, 2021 for our Hamilton Dome field. For additional reserve information see Note 20 to our consolidated financial statements in Item 8.
Reserve Category - Hamilton Dome fieldOil
(MBbls)
NGLs
(MBbls)
Natural Gas
(MMcf)
Total Reserves
(MBOE)*
PROVED
Developed Producing (100% of Proved)1,851 — — 1,851 
Undeveloped (0% of Proved)— — — — 
TOTAL PROVED1,851 — — 1,851 
Product Mix100 %— %— %100 %
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs 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.
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Barnett Shale - Mature, Low Decline Natural Gas Production - North Texas
On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale from TG Barnett Resources, LP, a wholly owned subsidiary of Tokyo Gas Americas, Ltd. The acquired assets consist of approximately 21,000 net acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant) in the Barnett Shale.

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Our interest includes an average working interest of 17.3% and associated average revenue interest of 14.2%. At the time of acquisition, approximately 90% of the wells acquired were operated by Blackbeard, while the remaining 10% were operated by seven other operators. After the close of the Barnett Shale Acquisition, Blackbeard announced the sale of its interests to Diversified Energy, which closed in July 2021.

The Barnett Shale was discovered as a natural gas resource play in the Newark East field in 1981; following completions of technology advancements in the 1990s, development of the Barnett Shale began in earnest in 1998. The majority of the wells included in our Barnett Shale assets were completed between 2007 and 2010 and are horizontals. The assets are characterized by mature, low-decline production. Average net daily production from the acquisition date of May 7, 2021 to June 30, 2021, was 4.3 MBOE per day. Commodities produced from our Barnett Shale assets include natural gas, oil and NGLs that are sold to Gulf Coast markets.

At June 30, 2021, the Company has total net proved reserves of 13.1 MMBOE in the Barnett Shale which is comprised of natural gas and NGLs with a small amount of oil, as estimated by our independent reservoir engineering firm. The following table sets forth our estimated proved reserves as of June 30, 2021 for our Barnett Shale assets. For additional reserve information, see Note 20 to our consolidated financial statements in Item 8.
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Reserve Category - Barnett Shale fieldOil
(MBbls)
NGLs
(MBbls)
Natural Gas
(MMcf)
Total Reserves
(MBOE)*
PROVED
Developed Producing (100% of Proved)85 4,879 48,571 13,059 
Undeveloped (0% of Proved)— — — — 
TOTAL PROVED85 4,879 48,571 13,059 
Product Mix%37 %62 %100 %
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 natural gas proved reserves by significant geographic area, using the trailing 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.
There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2021
Our proved reserves at June 30, 2021, denominated in barrels of oil equivalent (BOE) using six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio, were estimated by our independent reservoir engineer, DeGolyer and MacNaughton (“D&M”) 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, 2021. For additional reserve information, see Note 20 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 $49.72 per barrel of oil and $2.46 per MMBtu of natural gas. The net price per barrel of NGLs was $19.81, 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, 2021
Reserve Category - CombinedOil
(MBbls)
NGLs
(MBbls)
Natural Gas
(MMcf)
Total Reserves
(MBOE)*
PROVED
Developed Producing (92% of Proved)6,815 6,663 48,571 21,573 
Undeveloped (8% of Proved)1,605 208 — 1,813 
TOTAL PROVED8,420 6,871 48,571 23,386 
Product Mix36 %29 %35 %100 %
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs 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.
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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, MBOEMBOE
June 30, 20208,746 
Purchases— 
Production(504)
Revisions (a)235 
Sales of minerals in place— 
Improved recovery, extensions and discoveries— 
June 30, 20218,477 
(a) Positive revisions of 235 MBOE at Delhi field reflect operating cost reductions and improved NGL differential extending the reserves life of the field.
Hamilton Dome Field Proved
Total
Proved reserves, MBOEMBOE
June 30, 20201,473 
Purchases— 
Production(143)
Revisions (a)521 
Sales of minerals in place— 
Improved recovery, extensions and discoveries— 
June 30, 20211,851 
(a) Positive revisions of 521 MBOE reflect improved trailing twelve month SEC pricing and differentials, reactivation of shut-in production throughout the year, and reduced operating expenses. These factors resulted in wells remaining economic longer, extending the reserves life of the field.
Barnett Shale Field Proved
Total
Proved reserves, MBOEMBOE
June 30, 2020— 
Purchases13,299 
Production(240)
Revisions — 
Sales of minerals in place— 
Improved recovery, extensions and discoveries— 
June 30, 202113,059 
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
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Business at the University of Notre Dame. Such reserves estimates comply 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. The person responsible for the preparation of the reserve report is a Senior Vice President and Division Manager of North America at D&M. He received a Bachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 10 years of experience in oil and gas reservoir studies and evaluations.
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 1,813 MBOE at June 30, 2021, 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 or Barnett Shale asset.
During the year ended June 30, 2021 our proved undeveloped reserves changed as follows:
Oil
(MBbls)
NGLs
(MBbls)
Natural Gas
(MMcf)
Total Reserves
(MBOE)
June 30, 20201,648 216 — 1,864 
Revisions to previous estimates(43)(8)— (51)
Conversion to proved developed reserves— — — — 
June 30, 20211,605 208 — 1,813 
Fiscal year 2020 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. 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 project. During fiscal year 2021, we experienced reductions in expenses and improvement of the NGL differential at Delhi which extended the economic life of the PDP reserves. This caused a revision to PUD reserves by shifting them from PUD to PDP. Additionally, changes to Phase V development timing, as further discussed below, have slightly decreased PUD reserves.

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 original development plans for the field to be completed by June 30, 2015, within five years from the initial recording of such proved reserves, has not proceeded as originally scheduled 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. 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 but was electively deferred by the operator shortly thereafter due to reductions 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.

Authorization for construction of the NGL plant project occurred in fiscal 2015 and was completed in December 2016. 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, including construction of the six-well water curtain program and related infrastructure required to precede the development of Phase V. All injection wells have been completed and injections from the second pad began in second quarter of fiscal 2020.
As of June 30, 2021, we have estimated total future net capital expenditures of approximately $8.6 million for remaining development of Phase V in the eastern part of the field, which we expect to commence in fiscal year 2023, however the timing is dependent on the field operator's available funds, capital spending plans, and priorities within its portfolio of properties.
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
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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, 2021, 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 oil, NGLs, and natural gas for the periods indicated:
 Year Ended 
 
June 30, 2021
Year Ended 
 
June 30, 2020
Year Ended 
 
June 30, 2019
ProductVolumePriceVolumePriceVolumePrice
Oil (Bbls)554,888 $47.60 638,464 $44.76 626,879 $65.05 
NGL (Bbls)171,451 $21.36 106,159 $9.59 112,013 $21.87 
Natural gas (Mcf)963,496 $2.73 1,087 $1.90 459 $2.64 
Average price per BOE*886,922 $36.87 744,804 $39.74 738,968 $58.50 
Production costsAmountper BOEAmountper BOEAmountper BOE
Production costs, excluding ad valorem and production taxes$15,414,166 $17.38 $12,966,923 $17.41 $14,027,461 $18.98 
Total production costs, including ad valorem and production taxes$16,587,052 $18.70 $13,505,502 $18.13 $14,266,784 $19.31 
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs 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 at Delhi field during the past three fiscal years ended June 30, 2021, was limited to five (1.2 net) producer wells completed in fiscal 2019. We completed one (0.24 net) CO2 injection well during fiscal 2019. No dry wells were drilled in the past three fiscal years. There were no new wells drilled in fiscal 2020 or fiscal 2021.
In connection with establishing a six-well water curtain on two pads in advance of Phase V site development, during fiscal 2019 our operator drilled two (0.48 net) wells and completed three (0.72 net) wells. A pad consists of one gross water source well and two gross water injector wells. The northern pad commenced injection during fiscal 2019 and the southern pad became fully operational late in the second quarter of fiscal 2020 when capital expenditures for completion work concluded.
Barnett Shale acreage contains potential drilling locations; however, they are not included within our proved reserves as of June 30, 2021. Diversified Energy has recently acquired the assets and has not yet formalized a capital drilling budget for fiscal year 2022.
Hamilton Dome field is considered fully developed. No wells were drilled in fiscal 2021, and there are no plans to drill wells in fiscal 2022.
Present Activities
Starting in late third quarter 2021, the operator of the Delhi field resumed some capital conformance work to recomplete existing wells into different production zones, including recompleting a temporarily abandoned well in Test Site V. This work is still ongoing and too early to quantify the impact of these projects on the patterns. There are no significant drilling plans until Phase V development, expected to commence in 2023.
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The Hamilton Dome operator is performing expense workovers within the field to maintain production and expects to plug four wells in first half of fiscal year 2022. There are currently no capital projects proposed within the field for fiscal year 2022.

The primary Barnett Shale operator has recently taken over as operator and has yet to formalize a budget, however they have expressed interest in identifying and performing remedial workovers to maintain and restore production.
For further discussion, see “Highlights for our fiscal year 2021” and “Capital Expenditures” within Item 7.
Delivery Commitments
As of June 30, 2021, we were not committed to provide a fixed and determinable quantity of oil, NGLs, or natural gas under existing agreements, nor do we currently intend to enter into any such agreements.
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, 2021.
Company OperatedNon-OperatedTotal
GrossNetGrossNetGrossNet
Oil— — 326 77 326 77 
Natural gas— — 1,074 186 1,074 186 
Total— — 1,400 263 1,400 263 
Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2021. 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 AcreageUndeveloped AcreageTotal
GrossNetGrossNetGrossNet
Delhi Field, Louisiana9,126 2,180 4,510 1,077 13,636 3,257 
Hamilton Dome Field, Wyoming5,908 1,389 — — 5,908 1,389 
Barnett Shale, Texas123,777 20,918 — — 123,777 20,918 
Total(2)138,811 24,487 4,510 1,077 143,321 25,564 
(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 methods 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, due to the transition to using tertiary recovery methods. 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.
At the Delhi field, our interests include all depths from the ground surface to the top of the Massive Anhydride. These depth rights include the Delhi Holt Bryant Unit (Tuscaloosa and Paluxy formations) 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, non-productive or undrilled acreage is held by existing production as long as continuous production is maintained in the unit.
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When the Company acquired its interests in the Hamilton Dome field on November 1, 2019, the field had been fully developed through primary recovery and therefore 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 in 1995. 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. As Hamilton Dome is unitized, all acreage is held by existing production as long as continuous production is maintained in the unit.

The Company acquired the Barnett Shale field on May 7, 2021, which is currently being developed through primary recovery. The Company estimates that our developed acreage includes 123,777 gross (20,918 net) acres in the Barnett Shale field, with no acres attributable as undeveloped.
For more complete information regarding current year activities, including 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, oil, natural gas, and NGLs are readily transportable and marketable. We do not currently market our share of oil, natural gas, or NGLs production from the Delhi field, the Barnett Shale or from the Hamilton Dome field 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, and in the case of the Barnett Shale where there is a sole buyer for approximately all of the natural gas.
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 oil production sells at Louisiana Light Sweet (“LLS”) pricing which generally trades at a premium to West Texas Intermediate (“WTI”) oil pricing. However, due to global market conditions, this premium was reduced during fiscal year ended 2021 versus fiscal year 2020. The LLS Gulf Coast average price differential over WTI, as quoted daily on the New York Mercantile Exchange (“NYMEX”), was approximately $1.75 during our fiscal year ended June 30, 2021, compared to $3.70 for the prior year. In the current fiscal year, the differential was impacted by market conditions over the fiscal year. NGL production is sold to a midstream processing company that fractionates the stream and sells the resulting hydrocarbons. The NGL revenues we receive are substantially reduced when the field oil realized price falls below $60 due to a capital recovery agreement with the operator; however, the impact is partially offset by corresponding reduced gas plant operating expense.
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 oil which is the sole component of the field’s reserves. 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 oil trades at a discount to WTI, averaging $9.60 lower for the year ended June 30, 2021, and $17.62 lower for the eight months ended June 30, 2020. 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.
On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale field in North Texas. The asset's production has various zones of wet and dry gas. The wet gas is gathered and transported by pipeline to a processing facility to process the wet gas into NGL components, oil condensate, and residue gas. Although we have the option of taking our production in-kind, we have elected to have the operator market our share of production.
The following table sets forth purchasers of our oil, natural gas, and NGL production for the years indicated:
 Year Ended June 30,
Customer20212020
Plains Marketing L.P. (Delhi field oil)62 %87 %
Merit Energy Company (Hamilton Dome field oil)19 %10 %
All others19 %%
Total100 %100 %
As the purchase of the Barnett Shale occurred on May 7, 2021, the Company expects purchases of our natural gas and NGL production from the Barnett Shale to represent a larger percentage of total sales in fiscal year 2022 and beyond. The loss of a purchaser at the Delhi field, Barnett Shale, or the Hamilton Dome field or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.
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Market Conditions
Prices we receive for oil, natural gas, and NGLs 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, weather, and actions of major foreign producers.
Oil prices over the past few years have fluctuated widely and been extremely volatile. For example, average daily prices for WTI oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel over our last two fiscal years. The price of oil per barrel dropped substantially in fiscal 2020 as a result of the impact of the COVID-19 pandemic and geopolitical factors but recovered to average above $66 per barrel during the fiscal fourth quarter of 2021. The severe drop in oil price during the pandemic and market share competition between OPEC+ members in the Spring of 2020 substantially and adversely impacted oil, gas, and NGL prices during the balance of 2020, thus impacted the trailing twelve-month commodity prices required for reserves and ceiling tests for asset carrying value which in turn led to substantial impairments during our first and second quarters of fiscal 2021. Worldwide factors such as global health pandemics, geopolitical, international trade disruptions and tariffs, macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, influence prices for oil, natural gas, and NGLs. Local factors also influence prices for oil, natural gas, and NGLs 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 oil and natural gas companies, numerous independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staff 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 geologic systems and the ability to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves, and obtain capital at rates that 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 swaps 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.
During fiscal 2020, we entered into NYMEX WTI oil swaps that covered 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. As of June 30, 2021, we did not have any open fixed-price swaps or costless collars. 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. For the year ended June 30, 2021, 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 18 to our consolidated financial statements in Item 8 for additional information.
Government Regulation
Numerous federal and state laws and regulations govern the oil and natural 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
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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 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 natural 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, 2021, we had five full-time employees, not including contract personnel and outsourced service providers. None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees. Our team is broadly experienced in oil and natural 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.
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Item 1A.    Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider to be immaterial also may adversely affect us.
Risks related to the oil and natural gas industry and our Company
A substantial or extended decline in oil and natural gas 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 and natural gas significantly influences our revenue, profitability, access to capital, and future rate of growth. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, average daily prices for WTI oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel, and Henry Hub natural gas prices ranged from a high of $23.86 to a low of $1.33 per MMBTU over our last two fiscal years. Historically, the markets for oil, natural gas, 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 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 natural 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;
governmental, scientific, and public concern over the threat of climate change arising from greenhouse emissions;
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, natural disasters, and seasonal trends;
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, natural gas, and NGL 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, natural gas, and NGL prices may also reduce the amount of oil, natural gas, and NGL that we can produce economically, which could lead to a decline in our oil, natural gas and NGL reserves. At June 30, 2021, approximately 36% of our proved reserves are oil reserves, 35% are natural gas and 29% are NGL reserves. As such, we are heavily impacted by movements in natural gas and oil prices, the latter also influencing NGL 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, natural gas, and NGL prices may adversely affect our financial position.
Our revenues are concentrated in three 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, the Hamilton Dome field in Wyoming, and the Barnett Shale in Texas and thus our current revenues are concentrated from these fields. Any significant downturn in production, oil, natural gas, 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.
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In general, the volumes of production from 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 naturally decline. Our production is heavily dependent on our interests in EOR production that began during March 2010 in the Delhi field and our interests in the Hamilton Dome field in Wyoming and Barnett Shale in Texas. Environmental or operating problems or lack of extended future investment in any of these assets could cause our net production of oil, natural gas, and NGLs to decline significantly over time, which could have a material adverse effect on our financial condition. In fiscal 2021, our production was impacted by the operators of the Delhi and Hamilton Dome 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, 2021, Merit has reactivated the inventory of shut-in wells capable of supporting their expenses 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 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 consist of our interests in Delhi field, Hamilton Dome field, and the Barnett Shale. A materially negative change in any of our operator’s financial condition could negatively affect operations (or timing thereof) in these assets, and consequently our income (or timing thereof) from these assets as well as the value of our interests in these assets.
Any significant downturn in production or other events beyond our control which impact our assets 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 Inc. (“DNR”), an independent oil and gas company specializing in tertiary recovery with CO2. Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
Further, our CO2 - Enhanced Oil Recovery (“CO2-EOR”) project in the Delhi field requires significant amounts of CO2 reserves and technical expertise, the sources of which have been committed by the operator. Additional capital remains to be invested to fully develop this project, further increase production, and maximize the value of this asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial, and logistical matters could cause ultimate enhanced recoveries from the planned CO2 - EOR project to fall short of our expectations in volume and/or timing. Such occurrences could have a material adverse effect on us, and our results of operations and financial condition. 
Our economic success is thus materially dependent upon the Delhi field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome source, (ii) secure its share of capital necessary to fund development and operating commitments with respect to the field, and (iii) successfully manage related technical, operating, environmental, strategic, and logistical risks, among other things. 
In July 2020, Denbury announced that it had entered into a Restructuring Support Agreement 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 substantially reduced its debt, strengthened its balance sheet, and positioned Denbury to free up capital for investment in properties such as Delhi again.
We are not the operator of the Hamilton Dome field. It is operated by Merit, a private oil and natural gas company. Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
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We are not the operator of the Barnett Shale assets. At the time of acquisition, approximately 90% of the wells in the Barnett Shale field were operated by Blackbeard, and the remaining 10% of wells were operated by seven other operators. Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
In May 2021, Blackbeard announced an agreement to sell its interest in the Barnett Shale assets to Diversified Energy. The transaction closed in July 2021, with Diversified Energy taking over as operator. Our revenues and future growth are heavily dependent on a smooth transition of operations from Blackbeard to Diversified Energy and the success of operations under Diversified Energy, which we do not control.
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, while our Barnett Shale assets produce from deeper reservoirs. Shallower reservoirs usually have lower pressure, which generally translates into lower reserve volumes in place. Deeper reservoirs have higher pressures and usually more reserve volumes, but capturing those reserves often comes at increased drilling and completion cost and risk. Low permeability reservoirs require more wells and substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient un-depleted 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 Denbury, 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 ultimately cause 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.
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 partially dependent upon the success of our future development program. Drilling for oil and natural gas and extracting NGLs and re-working existing wells involve numerous risks. The risk that no commercially productive 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 and production techniques such as horizontal drilling or CO2 injection, do not guarantee that we will find and produce 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 ensure that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas.
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The loss of a large single purchaser of our oil and natural gas could reduce the competition of our production.
For the year ended June 30, 2021, one purchaser accounted for approximately 62% of our total oil revenues. We do not currently market our share of oil, natural gas, and NGLs production from the Delhi field, the Hamilton Dome field, or the Barnett Shale. 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, natural gas and NGLs. 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.
Our oil and natural gas reserves are only estimates and may prove to be inaccurate.
There are numerous uncertainties inherent in estimating 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 oil and natural gas that cannot always be measured in an exact manner. Estimates of economically recoverable 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 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 and different engineers preparing reserves estimates.
Accordingly, reserve estimates may be subject to downward or upward adjustments. 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 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 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 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 oil and natural gas properties when 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 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 NGLs, we have, and may in the future, enter into derivative arrangements for a portion of our oil, natural gas, and NGLs production. Derivative arrangements may include costless collars and fixed-price swaps. We have not historically 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 future derivative instruments. Derivative arrangements may also expose us to the risk of financial loss in some circumstances, including, but not limited to, if:
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production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contract obligations; or
there is a change in the expected differential between the underlying price in the derivative instrument and actual price received.
In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs 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 ensure 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.
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 natural 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
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necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Moreover, in the event of such an acquisition, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations, or cash flows.
Significant acquisitions and other strategic transactions may involve other risks, including, but not limited to:
our 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 natural gas operations and environmental matters may adversely affect our business and results of operations.
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 oil and natural gas from wells below actual production capacity in order to conserve supplies of 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 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 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.
The risks arising out of concerns regarding the threat of climate change, including regulatory, political, litigation, and financial risks may adversely affect our business and results of operations.
The Company’s operations are subject to a number of risks arising out of concerns regarding the threat of climate change, including regulatory, political, litigation, and financial risks, that could result in increased operating costs and costs of compliance, limit the areas in which oil and natural gas production may occur and reduce the demand for oil and natural gas.
The threat of climate change continues to attract considerable attention. Numerous initiatives have been proposed and more are expected to come that focus on monitoring and limiting existing sources of greenhouse gas emissions as well as to restrict or eliminate emissions from new sources. As a result, the Company is subject to numerous risks associated with the production and processing of fossil fuels and emission of greenhouse gas.

Governmental, scientific, and public concern over the threat of climate change arising from greenhouse emissions has resulted in increasing political risks in the United States. Proposals to ban hydraulic fracturing of oil and natural gas wells and ban new leases for production of minerals on federal properties, including onshore lands and offshore waters have already been made. Other actions that could be pursued may include more restrictive requirements for drilling or construction permits, the reversal of the United States’ withdrawal from the Paris Agreement in November 2020, and reinstatement of the ban on oil exports. Litigation risks are also increasing as a number of suits against oil and natural gas exploration and production companies have
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been brought in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects.

There are also financial risks for the energy industry as it may become more difficult to access the capital markets as the threat of climate change may impact decisions made by potential investors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for the energy industry could result in the restriction, delay or cancellation of drilling programs or development or production activities.
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 natural 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 natural gas distribution systems in the United States of America and abroad. Computers are necessary to transport our oil and natural gas production to market. A cyber-attack directed at oil and natural 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-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 oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of 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 Ryan Stash, Senior Vice President, Chief Financial Officer, and Treasurer, to source, evaluate, and close deals, raise capital, and oversee our development activities and operations. Presently, the Company is not a beneficiary of any key man life insurance.
Oil field service and materials prices may increase, and the availability of such services and materials may be inadequate to meet our needs.
Our business plan to develop or redevelop 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 natural 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 oil and natural gas fields for any reason or we may not be able to source the materials
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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 oil and natural gas that we produce without the assistance of third-parties.
The marketability of the 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 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 oil and natural gas companies, numerous larger independent 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 oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment, and acquiring the existing and changing technologies that we believe are, and will be, increasingly important to attaining success in our industry.
We have been, and in the future may become, involved in legal proceedings related to our 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, natural gas, and mineral properties is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, natural 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”) and subsequent variants, 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 have a material impact globally. 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 subsequent variants in addition to 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
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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 natural 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 ended June 30, 2021, our stock price as traded on the NYSE American ranged from $2.75 to $5.15. The variance in our stock price makes it difficult to forecast with certainty the stock price at which an investor may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as:
actual or anticipated variations in our results of operations;
naked short selling of our common stock and stock price manipulation;
changes or fluctuations in the commodity prices of oil and natural gas;
general conditions and trends in the 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, 2021 our executive officers and directors, in the aggregate, beneficially owned approximately 2.7 million shares, or approximately 8.0% of our beneficial common stock base. Blackrock Fund Advisors, et al controlled approximately 2.0 million shares or approximately 6.1% of our outstanding common stock, Arrowmark Colorado Holdings, LLC controlled approximately 2.0 million shares or approximately 6.1% of our outstanding common stock and Renaissance Technologies, LLC controlled approximately 2.2 million shares or approximately 6.5% 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 stock exchange. Trading volume in our common stock is relatively low compared to larger companies. During the fiscal year ended June 30, 2021, the daily trading volume in our common stock ranged from a low of 38,100 shares to a high of 4,596,300 shares, with average daily trading volume of 169,054 shares compared to average daily volume of 155,691 in fiscal 2020. Our holders may find it more difficult to sell their shares, should they desire to do so, based on the trading volume and price of our stock at that time relative to the quantity of shares to be sold.
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If securities or industry analysts do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.
Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge, three independent analysts cover our company. The limited number of published reports by independent securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.
The issuance of additional common stock and preferred stock could dilute existing stockholders.
We currently have in place an effective registration statement which allows the company to publicly issue up to $500 million of additional securities, including debt, common stock, preferred stock, and warrants. At any time we may make private offerings of our securities. The shelf registration is intended to provide greater flexibility to the company in financing growth or changing our capital structure. We are authorized to issue up to 100,000,000 shares of common stock. To the extent of such authorization, our board of directors has the ability, without seeking stockholder approval, to issue additional shares of common stock in the future for such consideration as our board may consider sufficient. The issuance of additional common stock in the future would reduce the proportionate ownership and voting power of the common stock now outstanding. We are also authorized to issue up to 5,000,000 shares of preferred stock, the rights and preferences of which may be designated in series by our Board of Directors. Such designation of any new series of preferred stock may be made without stockholder approval and could create additional securities which would have dividend and liquidation preferences over the common stock now outstanding. Preferred stockholders could adversely affect the rights of holders of common stock by:
exercising voting, redemption, and conversion rights to the detriment of the holders of common stock;
receiving preferences over the holders of common stock regarding our surplus funds in the event of our dissolution, liquidation, or the payment of dividends to preferred stockholders;
delaying, deferring, or preventing a change in control of our company; and
discouraging bids for our common stock.
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. The quarterly dividend was $0.05 for the fourth quarter of fiscal 2021 as a result of an improving financial and industry outlook. 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.
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PART II

Item 5.  Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
Our common stock is currently traded on the NYSE American stock exchange under the ticker symbol “EPM”. The following table shows, for each quarter of the fiscal years ended June 30, 2021 and 2020, the high and low sales prices for EPM as reported by the NYSE American stock exchange.
NYSE American: EPM
2021:HighLow
Fourth quarter ended June 30, 2021$5.15 $3.13 
Third quarter ended March 31, 2021$4.35 $2.75 
Second quarter ended December 31, 2020$3.15 $2.14 
First quarter ended September 30, 2020$2.93 $2.24 

2020:HighLow
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 

Shares Outstanding and Holders
As of June 30, 2021, there were 33,514,952 shares of common stock issued and outstanding. As of September 1, 2021, there were approximately 216 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,
20212020
Fourth quarter ended June 30,$0.050$0.025
Third quarter ended March 31,$0.030$0.100
Second quarter ended December 31,$0.025$0.100
First quarter ended September 30,$0.025$0.100
`
As of June 30, 2021, we have paid 31 consecutive quarterly dividends on our common stock. In September 2021, the Company declared a $0.075 per share dividend payable on September 30, 2021. 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.
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, 2016 to June 30, 2021 with the cumulative total return of the S&P 500 Index and the S&P Oil & Gas Exploration and Production Index of publicly traded companies over the same period. The graph assumes that $100 was invested on June 30, 2016 in our common stock at the closing market price at the beginning of this period and in each of
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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.
epm-20210630_g6.jpg
Securities Authorized For Issuance Under Equity Compensation Plans
Plan categoryNumber 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 shares323,080 (1)— 
  Total323,080 $— 2,206,294 
Equity compensation plans not approved by security holders— — — 
Total323,080  $ 2,206,294 
(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. On December 9, 2020, an amendment to the 2016 Plan was approved by our stockholders that increased the number of shares available for issuance by 2,500,000 shares. As of June 30, 2021, the Company has granted 1,444,230 awards under the 2016 Plan and 2,206,294 shares of common stock remain available for future grants.

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Issuer Purchases of Equity Securities
During the fourth quarter ended June 30, 2021, 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,
 20212020201920182017
Income Statement Data     
Revenues$32,702,354 $29,599,296 $43,229,621 $40,773,527 $34,253,681 
Lease operating costs16,587,052 13,505,502 14,266,784 11,685,817 10,604,594 
Depreciation, depletion and amortization5,166,626 5,761,498 6,253,083 6,102,288 5,779,069 
Net loss on derivative contracts614,645 1,383,204 — — — 
General and administrative expenses6,754,532 5,259,659 5,072,931 6,773,781 4,985,408 
Impairment of proved property24,792,079 — — — — 
Impairment of Well Lift Inc. - related assets146,051 — — — — 
Restructuring charges— — — — 4,488 
Income (loss) from operations(21,358,631)3,689,433 17,636,823 16,211,641 12,880,122 
Other income (expense)(63,564)66,643 1,222,604 (25,126)4,855 
Income tax provision (benefit)(4,984,261)(2,180,996)3,482,361 (3,431,969)4,840,664 
Net income (loss) attributable to the Company(16,437,934)5,937,072 15,377,066 19,618,484 8,044,313 
Dividends on preferred stock— — — — 250,990 
Deemed dividend on preferred shares called for redemption— — — — 1,002,440 
Net income (loss) attributable to common shareholders$(16,437,934)$5,937,072 $15,377,066 $19,618,484 $6,790,883 
Earnings per common share: 
Basic$(0.49)$0.18 $0.46 $0.59 $0.21 
Diluted$(0.49)$0.18 $0.46 $0.59 $0.21 

June 30, 2021June 30, 2020June 30, 2019June 30, 2018June 30, 2017
Balance Sheet Data     
Total current assets$18,108,374 $25,316,698 $35,178,927 $32,147,556 $26,142,527 
Total assets76,705,662 92,138,236 95,761,844 93,662,544 88,268,668 
Total current liabilities6,594,160 4,278,859 2,752,694 4,430,214 2,718,894 
Total liabilities22,110,859 18,013,754 15,635,986 16,373,065 19,798,813 
Total stockholders' equity54,594,803 74,124,482 80,125,858 77,289,479 68,469,855 
Number of common shares outstanding33,514,952 32,956,496 33,183,730 33,080,543 33,087,308 
Working capital11,514,214 21,037,839 32,426,233 27,717,342 23,423,633 
Common stock dividends4,342,082 10,740,754 13,272,058 11,594,541 8,432,435 

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Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview
Liquidity and Capital Resources
Results of Operations
Critical Accounting Policies
Executive Overview
General
Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of oil and natural gas properties. In support of that objective, the Company's long-term goal is to build a diversified portfolio of oil and natural 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, 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, our interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and overriding royalty interests in two onshore central 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, a subsidiary of Denbury, Inc.
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 natural gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field. Our acquired interest in this field aligns with the Company's strategy of adding long-lived, low decline reserves expected to be supportive of our dividend over the long-term.
On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale consisting of approximately 21,000 net acres held by production across nine North Texas counties in the Barnett Shale. The acreage has an average working interest of 17.3% and associated average revenue interest of 14.2%. At the time of the Barnett Shale acquisition, approximately 90% of the wells acquired were operated by Blackbeard, while the remaining 10% were operated by the seven other operators. After the close of the Barnett Shale Acquisition, Blackbeard announced the sale of its interest to Diversified Energy, which closed in July of 2021. At present, Blackbeard is still the operator of the assets under a transition services agreement with Diversified Energy. However, after the transition, Diversified Energy will take over operations of the assets.
Highlights for our Fiscal Year 2021 and Operations Update
Closed the Barnett Shale Acquisition on May 7, 2021 which included total proved reserves of 13.1 MMBOE as of June 30, 2021 as estimated by DeGolyer & MacNaughton (“D&M”), an independent reservoir engineering firm.
Returned to shareholders $4.3 million in cash dividends in fiscal 2021. The Company has paid out to shareholders more than $74.5 million in cash dividends since inception of the dividend program in December 2013.
Generated $3.7 million in operating income before impairments.
Funded our fiscal year operations, capital expenditures, and dividends out of operating cash flow.
Proved oil equivalent reserves at June 30, 2021 were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021.
We completed the NYMEX WTI oil swaps entered into during fiscal year 2020, and we have not entered into any new oil and gas derivatives as of June 30, 2021.
Denbury, whose subsidiary operates the Delhi Field, emerged from bankruptcy on September 18, 2020 and returned to conformance projects with a refreshed capital budget after a period of no conformance spending.
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Oil & Natural Gas Liquids Reserves (based on SEC NYMEX WTI oil price of $49.72 per barrel)
Proved oil equivalent reserves at June 30, 2021 were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021. The Standardized Measure for proved reserves increased 40% to $87.6 million, primarily due to the acquisition of interests in the Barnett Shale and an increase in the SEC mandated trailing twelve month average first day of the month net oil price from $46.37 per barrel of oil and $9.00 per barrel of natural gas liquids (we did not have natural gas reserves as of June 30, 2020) at June 30, 2020 to $49.72 per barrel of oil, $19.81 per barrel of natural gas liquids and $2.46 per MMBtu of natural gas at June 30, 2021. Our proved reserves consist of 36% oil, 29% natural gas liquids and 35% natural gas, 92% are classified as proved developed producing and 8% are proved undeveloped.
The following table is a summary of our proved reserves as of June 30, 2021 and 2020:
Proved Reserves
20212020Change
Reserves MMBOE23.4 10.2 129 %
% Developed92 %82 %12 %
Liquids %65 %100 %(35)%
Standardized Measure ($MM)$87.6 $62.5 40 %
Additional property and project information is included under Item 1 and in Note 6 and Note 20 to our consolidated financial statements in Item 8, and in Exhibit 99.1 of this Form 10-K.
Delhi Field
At June 30, 2021, we had total net proved reserves of 8.5 MMBOE compared to the prior year's 8.7 MMBOE, or a 3% decline in proved oil reserves. Fiscal year 2021 production of 0.5 MMBOE was partially offset by 0.3 MMBOE positive revisions primarily due to price increases.
Gross production at Delhi in the fourth quarter of fiscal 2021 was 5.1 MBOEPD, a 2% increase compared to 5.0 MBOEPD in the third fiscal quarter. Oil production was 4.1 MBOPD, which was flat compared to the third fiscal quarter’s 4.1 MBOPD. NGL production in the fourth quarter was 1.0 MBOEPD, an increase of 9% compared to third fiscal quarter's 0.9 MBOEPD. Annual oil production was significantly impacted by cessation of CO2 purchases when the CO2 purchase pipeline, upstream of the Delhi field, was shut-in for repairs in late February until October 2020 combined with constrained purchase volumes after the pipeline was returned to service. The loss of CO2 purchases, coupled with the decline in oil prices and bankruptcy filing, led to the operator electing to freeze non-essential capital projects through the end of calendar year 2020. During the fourth quarter of fiscal 2021, the operator resumed limited capital conformance projects within the field. We continue to monitor and evaluate the effectiveness of these projects.
The average oil price realized by Evolution at the Delhi field during the fourth quarter of fiscal 2021 was $64.68 compared to $56.02 during the previous quarter, an increase of 15%. The average NGL price realized by Evolution at the Delhi field during the fourth quarter of fiscal 2021 was $28.69 per barrel compared to $26.00 during the previous quarter, an increase of 10%. The increase was attributable to the broad recovery of commodity prices in fiscal fourth quarter. The uncertain demand outlook due to the ongoing COVID-19 pandemic has resulted in continued volatility in benchmark oil prices, with prices ranging from a low of a price of $58.73 per Bbl to a high of $74.21 per Bbl during our fiscal fourth quarter.
We historically have benefited from the premium that the Delhi field oil receives selling under Louisiana Light Sweet (“LLS”) pricing, as compared to the more widely known West Texas Intermediate (“WTI”) price. The LLS index correlates more closely to the Brent Crude oil price index (“Brent”) and, as such typically trades at a premium to the WTI index. Among other factors, the impacts of the COVID-19 pandemic caused global demand reduction and resulted in the Brent to WTI price spread to tighten, thus also resulting in a lower LLS to WTI price spread. In the fiscal fourth quarter 2021, the Delhi field realized a discount to WTI of $1.51, after deducting marketing and transportation costs. Oil produced from the Delhi field is shipped to market directly by pipeline, the most cost-effective means of transportation from the field. In addition, our received NGL price for royalty production varies because our royalty interests are 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 per BOE for the year were $18.80 per BOE, which increased 14% from $16.50 per BOE in the prior year. Gross CO2 purchase volume rates for fiscal 2021 averaged 49.1 MMcf per day, compared to 51.9 MMcf per day in the prior year, a 5% decrease primarily due to the Delhi CO2 purchase pipeline shut-in for repairs. This decrease together with a 8% lower price per MCF resulted in a 13% decrease in CO2 cost compared to the prior year. Our cost of purchased CO2, the largest
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single component of operating costs at Delhi, is directly tied to the price of oil sold from the field. Other lease operating expenses for fiscal 2021 decreased 10% compared to the prior year, primarily due to lower fuel gas, parts and workover expenses. The decrease in CO2 cost and other lease operating expenses, paired with a decrease in production of 22% for the current year, resulted in the increase in lifting costs per BOE.
For fiscal 2021, our gross NGL production was 1.0 MBOEPD, which sold at an average price of $21.36 per barrel, compared to prior year gross production of 1.1 MBOEPD for which we realized $9.59 per barrel. In addition, the previously mentioned the capital recovery charge affects the NGL price in that if oil prices are below a realized NGL price of $60, the Company's royalty interests in Delhi do not benefit from NGL sales, partially offset by a reduction in the plant operating costs representing our working interest share of the cost recovery fee. This contributed to a lower price per barrel in the prior fiscal year, and the higher price per barrel in fiscal year 2021. 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. 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 a gas turbine driven generator 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, 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 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 $6.44 per BOE of PUD reserves 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 but is projected to occur in the next few years. Development of unquantified volumes is dependent upon the timing of excess capacity within the processing plant and oil price. Over the past decade, we, along with the operator, have invested significant resources and capital demonstrating our commitment to the development of the Delhi field and believe that we will collectively continue to do so.
Hamilton Dome
At June 30, 2021, we had total net proved reserves of 1.9 MMBOE, entirely comprised of oil, compared to prior year net proved reserves of 1.5 MMBOE. The positive revision of 0.4 MMBOE, or 26%, in proved oil reserves is primarily related to improved oil pricing, decreased expenses and restoration of shut-in production from the global pandemic.
Gross oil production at Hamilton Dome in the fourth quarter of fiscal 2021 was 2,035 BOPD, a 3% increase compared to 1,985 BOPD in the third fiscal quarter due to the operator restoring previously shut-in production and maintenance within the field. There were limited capital expenditures in the field during fiscal 2021 due primarily to the decrease in oil prices. Most projects in the field focused on maintenance or restoring shut-in production.
The average oil price realized by Evolution at Hamilton Dome during the fourth quarter was $55.93 compared to $46.61 during the previous quarter, an increase of 20% attributable to the recovery in commodity prices in the fiscal fourth quarter. Production from this field is transported by pipeline to customers and is priced on the Western Canadian Select index, which generally trades at a discount to WTI. In the fourth quarter, our realized price reflected a $7.58 per barrel discount from the WTI price. For fiscal 2021, realized oil price averaged $42.28 compared to $29.19 for the prior year. For this fiscal year, our lifting costs at Hamilton Dome averaged $28.57 per barrel.
Barnett Shale

At June 30, 2021, we had total net proved reserves of 13.1 MMBOE, comprised of 62% natural gas, 37% natural gas liquids, and 1% oil as estimated by our independent petroleum engineering firm D&M. The Barnett Shale asset was acquired on May 7, 2021.

Blackbeard, the primary Barnett Shale operator has yet to formalize a budget, as they are currently under a transition services agreement with Diversified Energy following the sale of their interests to Diversified Energy in July 2021. Diversified Energy has expressed interest in identifying and performing remedial workovers to maintain and restore production.

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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 continue to recommend social distancing, imposed quarantine and isolation measures, as well as periodic business closures on large portions of the population as the Delta variant of COVID-19 has emerged in the current fiscal year. These measures, while intended to protect human life, are expected to have continued impacts on domestic and foreign economies, potentially resulting in the volatility of commodity prices. The effectiveness of economic stabilization efforts, including government payments to affected citizens and industries, is uncertain.
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, 2021, we had $5.3 million in cash and cash equivalents, primarily impacted by the $18.3 million purchase (net of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) of certain mineral interests in the Barnett Shale in May 2021, compared to $19.7 million of cash and cash equivalents at June 30, 2020.
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 $30 million borrowing base, with $4 million drawn as of June 30, 2021. The borrowing base does not yet include any portion of the Barnett Shale properties. There are $4 million in borrowings outstanding under the Facility, which matures on April 9, 2024. The Facility is secured by substantially all of the reserves associated with the Company's assets.
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 current ratio of not less than 1.0 to 1.0, and (iii) a consolidated tangible net worth of not less than $40 million, each as defined in the Facility. The Facility also contains other customary affirmative and negative covenants and events of default. As of June 30, 2021, the Company was in compliance with all covenants contained in the Facility.
On August 5, 2021, and effective as of June 30, 2021, we entered into the seventh amendment of our Senior Secured Credit Facility which added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the Consolidated Tangible Net Worth was reduced to $40 million from $50 million.
The Company has historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced oil, natural gas, 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 and Barnett Shale assets 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 access to the undrawn portion of the 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.
During the fiscal year ended June 30, 2021, the Company funded operations, capital expenditures, and cash dividends with cash generated from operations resulting in a decrease of $14.4 million in cash. Uses of cash included the acquisition of the Barnett Shale assets ($18.3 million) and cash dividends on common shares ($4.3 million). As of June 30, 2021, working capital was $11.5 million, a decrease of $9.5 million from working capital of $21.0 million at June 30, 2020.
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The Board of Directors instituted a cash dividend on common stock in December 2013. The Company has since paid 31 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of the Company’s financial strategy, and it is the Company's long-term goal to increase dividends over time, as appropriate. During the industry downturn, effective in the quarter ended June 30, 2020, the Board of Directors adjusted the quarterly dividend rate from $0.10 per share to $0.025 per share. The reduction in the dividend rate at that time allowed the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield of approximately 3% at stock price levels. On February 2, 2021, considering an improving industry outlook, the Board of Directors increased the dividend rate from $0.025 per share to $0.03 per share effective in the quarter ended March 31, 2021. On May 7, the Board of Directors further increased the dividend rate to $0.05 per share effective in the quarter ended June 30, 2021 due to improved industry conditions and the Barnett Shale acquisition. As in the past, the Company intends to consider higher dividend levels as warranted by industry conditions and any future accretive acquisitions.
Capital Expenditures
For the year ended June 30, 2021, we incurred $21.7 million on capital projects consisting of $21.1 million for the acquisition of Barnett Shale assets (gross of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) and $0.6 million at the Delhi field (primarily for plugging costs and capital conformance work).
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 at Delhi and will resume projects at Hamilton Dome. Such amounts are not known or approved but we expect such expenditures to be in the range of $0.9 million to $1.5 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 2023. Phase V development expenditures are expected to total $8.6 million with $3.7 million to be incurred in fiscal 2024 and the remainder over the following two years.
Our proved undeveloped reserves are associated only with the Delhi field. At June 30, 2021, our proved undeveloped reserves 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 Delhi field. Such development requires participation by both the operator and the Company. Although we expect drilling to commence in fiscal 2023, the timing of Phase V is dependent on the field operator's available funds, 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 June 30, 2021, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if current price levels worsen. Lower oil prices would reduce the excess, or cushion, of our valuation ceiling over our capitalized costs and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural 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 natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the 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, 2021 were $49.72 per barrel of oil, $2.46 per MMBtu of natural gas and $19.81 per barrel of natural gas liquids. At December 31, 2020 and September 30, 2020, the Company recorded ceiling test impairment charges of $15.2 million and $9.6 million, respectively. The ceiling test impairments were driven by decreases in the first-day-of-the-month average for oil used in the ceiling test calculation as outlined below. As of June 30, 2021, a 10% decrease in commodity prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties.
Twelve-Month Period Ended:
6/30/20209/30/202012/31/20203/31/20216/30/2021
Crude Oil47.3743.6339.5439.9549.72
Natural Gas2.122.022.032.182.46
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Overview of Cash Flow Activities
The table below compares a summary of our consolidated statements of cash flows for year ended June 30, 2021 and 2020.
 June 30,
Increases (Decreases) in Cash:20212020Difference
(In Millions)
Net cash provided by operating activities$4.7 $12.4 $(7.7)
Net cash used in investing activities(18.8)(11.1)(7.7)
Net cash used in financing activities(0.3)(13.2)12.9 
Change in cash, cash equivalents and restricted cash$(14.4)$(11.9)$(2.5)
Cash provided by operating activities in the current year decreased $7.7 million compared to fiscal 2020. The difference is primarily the result of a decrease in revenues compared to the prior year and the payments related to realized hedge settlement losses of $2.5 million.
Cash used in investing activities increased $7.7 million primarily due to the acquisition of the Barnett Shale assets in May 2021 for $18.3 million (net of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) compared to the acquisition of Hamilton Dome field in November 2019 for $9.3 million. The increase is partially offset by a reduction in capital expenditures of $1.3 million in fiscal 2021 due to the decrease in conformance workover activities from lower oil prices.
Cash used in financing activities decreased year over year primarily related to the net borrowing of $4 million on the Senior Secured Credit Facility during fiscal 2021, and the reduction in cash paid for cash dividends as the Company paid $4.3 million in fiscal year 2021 and $10.7 million in fiscal year 2020. In addition, the Company paid $2.5 million more in fiscal year 2020 compared to fiscal year 2021 related to the Company's common share repurchase program.
Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2021, 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
TotalLess than
1 Year
1 - 3 Years3 - 5 YearsMore than 5 Years
Contractual Obligations
AFE purchase commitments in connection with joint interest agreements$329,827 $329,827 $— $— $— 
Operating lease$84,978 59,103 25,875 — — 
Asset retirement obligations$5,583,272 $44,520 $168,377 $158,378 $5,211,997 
Total Obligations$5,998,077 $433,450 $194,252 $158,378 $5,211,997 

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Results of Operations
Years Ended June 30, 2021 and 2020
Revenues
The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the years ended June 30, 2021 and 2020. Fiscal 2020 includes eight months of Hamilton Dome production. Fiscal 2021 includes approximately two months of Barnett Shale production.
 Years Ended June 30,
 20212020VarianceVariance %
Oil and gas production
Revenues
  Oil $26,411,132 $28,578,879 $(2,167,747)(7.6)%
  Natural gas liquids3,662,478 1,018,349 2,644,129 259.6 %
  Natural gas 2,628,744 2,068 2,626,676 n.m.
  Total revenues$32,702,354 $29,599,296 $3,103,058 10.5 %
  
Volumes
  Oil (Bbl)554,888 638,464 (83,576)(13.1)%
  Natural gas liquids (Bbl)171,451 106,159 65,292 61.5 %
  Natural gas (Mcf)963,496 1,087 962,409 n.m.
Equivalent volumes (BOE)886,922 744,804 142,118 19.1 %
  Oil (BOPD, net)1,520 1,744 (224)(12.8)%
  NGLs (BOEPD, net)470 290 180 62.1 %
  Natural gas (BOEPD, net)440 — 440 n.m.
 Equivalent volumes (BOEPD, net)2,430 2,034 396 19.5 %
  Oil average realized price per Bbl$47.60 $44.76 $2.84 6.3 %
  NGL average realized price per Bbl21.36 9.59 11.77 122.7 %
  Natural gas average realized price per Mcf2.73 1.90 0.83 43.7 %
   Equivalent price per BOE$36.87 (a)$39.74 $(2.87)(7.2)%
(a) Equivalent price per BOE has decreased in the current fiscal year despite a 6.3% increase in oil price per Bbl and a 122.7% increase in NGL price per Bbl. With the Barnett Shale Acquisition, the Company added significant natural gas sales compared to the prior year. Natural gas sales are realized at a lower price per BOE than oil and NGLs, and the Company’s total weighted average price per BOE declined by approximately 7% from the prior year.

n. m. Not meaningful.

Fiscal year 2021 revenues increased 10% compared to the prior fiscal year primarily due to increased realized commodity prices and the addition of the Barnett Shale Acquisition, which primarily drove the increase in natural gas and NGL sales revenues and production volumes compared to the prior fiscal year. This increase was partially offset by an 8% decrease in oil revenues primarily driven by an expected temporary increase in production decline and weaker price differentials in the Delhi field. The shut-in of the CO2 supply pipeline from late February 2020 through the end of October 2020, as discussed in “Lease Operating Costs” below, as well as a suspension of field conformance capital expenditures drove the expected temporary increase in production declines in the Delhi field. Purchased CO2 is necessary to maintain reservoir pressure and therefore achieve normal field performance. The shut-in of purchased CO2 volumes resulted in a decline in reservoir pressure and a temporary exacerbated production decline. The resumption of CO2 purchases during the current fiscal year is expected to gradually restore reservoir pressure and lead to a gradual increase in oil production rates. Also contributing to the decrease of production in the current fiscal year was the loss of production associated with the severe winter storm in February 2021. The Company’s average realized oil price was higher primarily due to the recovery of WTI pricing in 2021, as the demand for oil has begun to recover primarily as a result of the roll-out of the COVID -19 vaccines and concerns surrounding the perceived surplus of oil supplies has begun to retract.
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(Gain) Loss on Derivative Contracts
Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in 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. No positions remain outstanding as of June 30, 2021.
 Years Ended June 30,
 20212020VarianceVariance %
Oil Derivative Contracts
Realized (gain) loss on derivatives, net$2,525,988 $(528,139)$3,054,127 (578.3)
Unrealized (gain) loss on derivatives(1,911,343)1,911,343 (3,822,686)(200.0)
Loss on derivatives$614,645 $1,383,204 $(768,559)(55.6)
Oil price per Bbl (including impact of realized derivatives)$43.05 $45.59 

Lease Operating Costs
Lease operating costs (also referred to as production expenses) are presented in two components: (i) CO2 purchase costs for the Delhi field and (ii) other lease operating costs for both the Delhi, Hamilton Dome, and Barnett Shale fields.
 Years Ended June 30,
 20212020VarianceVariance %
CO2 costs (a)
$3,061,598 $3,501,507 $(439,909)(12.6)%
Other lease operating costs13,525,454 10,003,995 3,521,459 35.2 %
Total lease operating costs$16,587,052 $13,505,502 $3,081,550 22.8 %
CO2 costs per BOE
$3.45 $4.70 $(1.25)(26.6)%
All other lease operating costs per BOE15.25 13.43 1.82 13.6 %
Lease operating costs per BOE$18.70 $18.13 $0.57 3.1 %
(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,
 20212020VarianceVariance %
CO2 costs per mcf
$0.71 $0.77 $(0.06)(7.8)%
CO2 volumes (MMcf per day, gross)
49.1 51.9 (2.8)(5.4)%
The $0.4 million decrease in CO2 costs was due to a 5.4% decrease in rate of purchased volumes together with a 7.8% 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 suspended until October 2020 for pipeline repairs. 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 Inc, and the Company does not have any ownership in the portion of the pipeline that was repaired.
Compared to fiscal 2020, “Other lease operating costs” increased 35.2% primarily due to the additional four months of production costs at the Hamilton Dome field in fiscal 2021 compared to eight months of production costs in fiscal 2020 following acquisition in November 2019 and, to a lesser extent, the closing of the Barnett Shale Acquisition in May 2021. The Delhi field's “Other lease operating costs” decreased 10.5% impacted by cost control measures resulting from lower oil prices.
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Compared to fiscal 2020, Delhi field costs increased 14% to $18.80 per BOE of Delhi current year production primarily due to lower production volumes.
For fiscal 2021, Hamilton Dome field costs per BOE were $28.57, a decrease of 1.3% from fiscal year 2020 due to increased production and cost control measures implemented following the pandemic resulting from lower prices.

For fiscal 2021, Barnett Shale field costs per BOE were $12.61 compared to no field costs in the prior year as the Company completed the Barnett Shale Acquisition in the current fiscal year.
Depletion, Depreciation and Amortization (“DD&A”)
Total DD&A expense was 10.3% lower compared to the same one year-ago period due to an 12.3% decrease in the oil and natural gas DD&A amortization rate. The integration of the Barnett Shale assets together with the ceiling test impairments contributed to an overall lower composite DD&A per BOE rate. Additionally, accretion of asset retirement obligations increased 43.5% in the current fiscal year as a result of the asset retirement obligation additions from Barnett Shale Acquisition. Amortization of intangibles increased as a result of amortization of $37.3 thousand of our Well Lift, Inc. (“WLI”) assets during fiscal year 2021.
 Years Ended June 30,
 20212020VarianceVariance %
DD&A of proved oil and gas properties$4,901,969 $5,592,651 $(690,682)(12.3)%
Depreciation of other property and equipment7,000 8,779 (1,779)(20.3)%
Amortization of intangibles47,474 13,564 33,910 250.0 %
Accretion of asset retirement obligations210,183 146,504 63,679 43.5 %
Total DD&A$5,166,626 $5,761,498 $(594,872)(10.3)%
Oil and gas DD&A per BOE$5.53 $7.51 $(1.98)(26.4)%
General and Administrative Expenses
Total general and administrative expenses for fiscal 2021 increased $1.5 million, or 28.4%, to $6.8 million from the same year-ago period. The increase is primarily due to higher legal and professional fees of $0.8 million related to consulting on various potential business transactions, an increase in accrued bonus expense of $0.5 million and an increase in salaries of $0.2 million due to additional employees.
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Other Income and Expenses
Interest income is lower in fiscal year 2021 compared to fiscal year 2020 primarily due to the decrease in cash as a result of the closing of the Barnett Shale Acquisition in May 2021 and lower realized oil prices.
 Years Ended June 30,
 20212020VarianceVariance %
Interest and other income39,401 177,418 (138,017)(77.8)%
Interest expense(102,965)(110,775)7,810 (7.1)%
Total other income (expense), net$(63,564)$66,643 $(130,207)(195.4)%
Net Income
Net income available to common stockholders for the year ended June 30, 2021 decreased $22.4 million, to a loss of $16.4 million compared to the last fiscal year primarily driven by proved oil and gas property impairments of $9.6 million and $15.2 million recorded during the first and second fiscal quarters of 2021, respectively. Our income tax benefit increased primarily due to a pre-tax loss in the current period compared to pre-tax income in the prior year. During the fiscal year 2020, 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 compared to a $0.3 million EOR credit benefit in fiscal 2021.
Years Ended June 30,
20212020VarianceVariance %
Income (loss) before income tax provision(21,422,195)3,756,076 (25,178,271)(670.3)%
Income tax provision (benefit)(4,984,261)(2,180,996)(2,803,265)128.5 %
Net income (loss) available to common shareholders$(16,437,934)$5,937,072 $(22,375,006)(376.9)%
Income tax provision (benefit) as a percentage of income before income tax23 %(58)%

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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 natural 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 natural 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, 2021, we had no unevaluated property costs. Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic 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 geologic, 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 geologic 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, 2021 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, 2021 of 5%, 10% and 15% would affect depreciation, depletion, and amortization expense by approximately $64,500, $136,000, and $216,000, respectively.
On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and natural 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 natural 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 natural 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. 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.
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As of June 30, 2021, we have recorded a valuation allowance for the portion of our net operating loss that is limited by Internal Revenue Code Section 382.
Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making the assessment of the ultimate realization of deferred tax assets. The Company establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods, 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. At the time of this report, we have recorded a valuation allowance for our expected inability to realize the future benefits of certain federal and state deferred tax assets as further discussed in Note 13 - Income Taxes. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would change in the period it is determined that recovery is 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 for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards Board.
Off-Balance Sheet Arrangements
The Company had no off-balance sheet arrangements as of June 30, 2021.
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. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either LIBOR plus 2.75%, subject to a minimum LIBOR of 0.25%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. LIBOR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. 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 per barrel. The fixed price swap contracts significantly reduced 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. For the derivative contracts settled during fiscal 2021, we did not post collateral as it was 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 19 to our consolidated financial statements for more details.

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Item 8.    Consolidated Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Shareholders and the Board of Directors of        
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, 2021 and 2020, 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, 2021 and 2020, 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 audit 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.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Oil and Natural Gas Reserves on Depreciation, Depletion and Amortization (“DD&A”) and Full Cost Ceiling Test Impairment Calculation (“Ceiling Test”)

As described in Note 2, the Company follows the full cost method of accounting, pursuant to which oil and natural gas properties are amortized using the unit-of-production method over total proved reserves. The Company’s proved oil and natural gas properties are evaluated for impairment by the Ceiling Test, utilizing the Company’s proved oil and natural gas reserves in accordance with accounting principles generally accepted in the United States of America and SEC guidelines. For the year ended June 30, 2021, the Company recorded DD&A related to its proved oil and natural gas properties of approximately $4.9 million and a ceiling test impairment of approximately $24.8 million.

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The Company engages an independent reservoir engineering firm, to serve as a management specialist, to assist with the estimation of proved oil and natural gas reserves. To estimate the volume of proved oil and natural gas reserves and associated future net cash flows, management and their specialist make significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties (“PUDs”). The estimation of proved oil and natural gas reserves is impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required. Changes in significant assumptions or engineering data could have a significant impact on the amount of DD&A and impairment recorded for the Company’s proved oil and natural gas properties.

We identified the impact of proved oil and natural gas reserves on DD&A and the Ceiling Test as a critical audit matter due to use of significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the significant assumptions used in developing those estimates of proved oil and natural gas reserves.

The primary procedures we performed to address this critical audit matter included:
Evaluated significant assumptions used by management and its specialist in developing the estimates of proved oil and natural gas reserves, including pricing differentials, future operations costs, future production rates and capital expenditures. The procedures performed included:
tests of the data inputs used by specialist for completeness and accuracy,
an evaluation of the specialist’s findings,
testing specialist’s findings for mathematical accuracy and
analytical procedures on pricing, reserve quantities and cost estimates developed by management and its specialist. Those procedures entailed comparisons of:
(i) prices to historical benchmark prices, adjusted for pricing differentials,
(ii) production forecasts to recent historical actual production,
(iii) projections of lease operating costs to fiscal year end costs, and
(iv) projected production taxes to recent historical taxes incurred and to statutory tax rates.
Evaluated the experience, qualifications and objectivity of management’s specialist, an independent reservoir engineering firm.
Evaluated the accuracy of revenue and working interest percentages used in the reserve report by comparing a sample of such interests to the land records.
Evaluated the Company’s evidence supporting the amount of PUDs reflected in the reserve report by (i) considering the field operator’s intent to develop PUDs and (ii) testing the Company’s financial capability to participate in development of those reserves by comparing estimated development costs to the sources of capital available to the Company.
Performed retrospective review of historical estimates of proved oil and natural gas reserves to identify potential management bias in estimates.

/s/    Moss Adams LLP

Houston, Texas
September 14, 2021

We have served as the Company’s auditor since 2017.
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Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
June 30, 2021June 30, 2020
Assets  
Current assets  
Cash and cash equivalents$5,276,510 $19,662,528 
Receivables from oil and gas sales8,686,967 $1,919,213 
Receivables for federal and state income tax refunds3,107,638 3,243,271 
Prepaid expenses and other current assets1,037,259 491,686 
Total current assets18,108,374 25,316,698 
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 amortization58,515,860 66,512,281 
Other property and equipment, net10,639 17,639 
Total property and equipment, net58,526,499 66,529,920 
Other assets, net70,789 291,618 
Total assets$76,705,662 $92,138,236 
Liabilities and Stockholders' Equity  
Current liabilities  
Accounts payable$5,609,367 $1,471,679 
Accrued liabilities and other947,045 716,648 
Derivative contract liabilities 1,911,343 
State and federal taxes payable37,748 179,189 
Total current liabilities6,594,160 4,278,859 
Long term liabilities  
Senior secured credit facility4,000,000  
Deferred income taxes5,957,202 11,061,023 
Asset retirement obligations5,538,752 2,588,894 
Operating lease liability20,745 84,978 
Total liabilities22,110,859 18,013,754 
Commitments and contingencies
Stockholders' equity  
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,514,952 and 32,956,469 shares as of June 30, 2021 and 2020, respectively
33,515 32,956 
Additional paid-in capital42,541,224 41,291,446 
Retained earnings12,020,064 32,800,080 
Total stockholders' equity54,594,803 74,124,482 
Total liabilities and stockholders' equity$76,705,662 $92,138,236 

   See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
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 Years Ended June 30,
 20212020
Revenues
Oil$26,411,132 $28,578,879 
Natural gas liquids3,662,478 1,018,349 
Natural gas2,628,744 2,068 
Total revenues32,702,354 29,599,296 
Operating costs  
Lease operating costs16,587,052 13,505,502 
Depreciation, depletion, and amortization5,166,626 5,761,498 
Impairment of proved property24,792,079  
Impairment of Well Lift Inc. - related assets146,051  
Net loss on derivative contracts614,645 1,383,204 
General and administrative expenses*6,754,532 5,259,659 
Total operating costs54,060,985 25,909,863 
Income (loss) from operations(21,358,631)3,689,433 
Other  
Interest and other income39,401 177,418 
Interest expense(102,965)(110,775)
Income (loss) before income tax provision(21,422,195)3,756,076 
Income tax expense (benefit)(4,984,261)(